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Table of Contents

As filed with the Securities and Exchange Commission on January 8, 2016

Registration No. 333-207537

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Amendment No. 2

to

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

ATLAS GROWTH PARTNERS, L.P.

(Exact Name of Registrant as Specified in its Charter)

 

 

 

Delaware   1311   80-0906030
(State or other jurisdiction of
incorporation or organization)
  (Primary standard industrial
classification code number)
 

(I.R.S. Employer

Identification No.)

Park Place Corporate Center One

1000 Commerce Drive, Suite 410

Pittsburgh, PA 15275

(800) 251-0171

(Address, including zip code, and telephone number, including area code, of registrants’ principal executive offices)

 

 

Edward E. Cohen

Atlas Growth Partners GP, LLC

Park Place Corporate Center One

1000 Commerce Drive, Suite 410

Pittsburgh, PA 15275

(800) 251-0171

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

Copies to:

 

Gislar R. Donnenberg

Douglas V. Getten

Paul Hastings LLP

600 Travis Street, Suite 5800

Houston, TX 77002

Telephone: (713) 860-7300

Telecopy: (713) 353-3100

 

Wallace W. Kunzman

Kunzman & Bollinger, Inc.

5100 N. Brookline

Suite 600

Oklahoma City, OK 73112

Telephone: (405) 942-3501

Telecopy: (405) 942-3527


Table of Contents

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of

Securities to be Registered

 

Amount

to be

Registered(1)

 

Proposed

Maximum

Offering Price

Per Unit

 

Proposed

Maximum

Aggregate

Offering Price(2)

 

Amount of

Registration Fee

Primary Offering, Class A Common Units Representing Limited Partner Interests(3)

  70,000,000   $10.00   $700,000,000.00   $70,490.00

Primary Offering, Class T Common Units Representing Limited Partner Interests(4)

  30,000,000   $10.00   $300,000,000.00   $30,210.00

Warrants to purchase Common Units(5)(6)

  —     —     —     —  

Post-Listing Common Units underlying Warrants(7)

  12,330,041   $10.00   $123,300,410.00   $12,416.35

Distribution Reinvestment Plan, Class A Common Units

  21,505,376(8)   $9.30   $199,999,997.00   $20,140.00

Post-Listing Common Units(5)

  100,000,000   —     —     —  

Total

  133,835,417   $10.00   $1,323,300,407.00   $133,256.35(9)

 

 

(1)  Pursuant to Rule 416(a) under the Securities Act of 1933, as amended, this Registration Statement shall also cover any additional common units that become issuable by reason of any dividends payable in common units, unit splits, combinations or reclassifications affecting the common units or other similar transaction effected without receipt of consideration.
(2)  Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.
(3) “Class A Common Units” means up to 70,000,000 limited partner interests offered to investors.
(4)  “Class T Common Units” means up to 30,000,000 limited partner interests offered to investors.
(5)  No fee pursuant to Rule 457(g) under the Securities Act of 1933, as amended.
(6)  “Common Units” means Class A common units and Class T common units.
(7)  Registration fee calculated based on estimated exercise price for the purpose of paying the registration fee.
(8)  Represents Class A common units to be issued pursuant to the distribution reinvestment plan, or DRIP. The offering price per unit for purposes of calculating the registration fee is $9.30 per unit for Class A common units, or 93.00% of the current offering price. We reserve the right to reallocate the common units we are offering between the classes of common units offered hereby and between our primary offering and the distribution reinvestment plan.
(9)  Amount previously paid on October 20, 2015.

 

 

Approximate date of commencement of proposed sale of the securities to the public: From time to time after the Registration Statement becomes effective.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  x

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. Please read the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   x  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

 

 

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


Table of Contents

ATLAS GROWTH PARTNERS, L.P.

CROSS REFERENCE SHEET

 

Item of Form S-1

  

Caption in Prospectus

Item 1.

   Forepart of the Registration Statement and Outside Front Cover Page of Prospectus    Front Page of Registration Statement and Outside Front Cover Page of Prospectus

Item 2.

   Inside Front and Outside Back Cover Pages of Prospectus    Inside Front and Outside Back Cover Pages of Prospectus

Item 3.

   Summary Information, Risk Factors and Ratio of Earnings to Fixed Charges    Summary; Risk Factors

Item 4.

   Use of Proceeds    Source of Funds and Estimated Use of Proceeds

Item 5.

   Determination of Offering Price    Terms of the Offering

Item 6.

   Dilution    Dilution

Item 7.

   Selling Security Holders    The program does not have any selling security holders.

Item 8.

   Plan of Distribution    Plan of Distribution

Item 9.

   Description of Securities to be Registered    Summary; Summary of the Partnership Agreement; Description of the Common Units; Description of the Warrants

Item 10.

   Interests of Named Experts and Counsel    Legal Opinions; Experts

Item 11.

   Information with respect to the Registrant   
  

(a)    Description of Business

   Summary; Business and Properties
  

(b)    Description of Property

   Business and Properties—Our Properties
  

(c)    Legal Proceedings

   Business and Properties—Legal Proceedings
  

(d)    Market Price of and Dividends on the Registrant’s  Common Equity and Related Stockholder Matters

   The partnership composing the program has no markets in which its units are being traded; for a description of historical distributions, please read Summary—Distributions; Cash Distribution Policy and Restrictions on Distributions; Management and Description of the Common Units
  

(e)    Financial Statements

   Summary Historical Financial Data; Summary Historical Reserve and Operating Data; Selected Historical Financial Data; Index to Financial Statements; Audited Financial Statements for Years ended December 31, 2014 and December 31, 2013; Unaudited Financial Statements for Nine Months Ended September 30, 2015 and 2014
  

(f)     Selected Financial Data

   Selected Historical Financial Data
  

(g)    Supplementary Financial Information

   Index to Financial Statements


Table of Contents

Item of Form S-1

  

Caption in Prospectus

  

(h)    Management’s Discussion and Analysis of Financial  Condition and Results of Operations

   Management’s Discussion and Analysis of Financial Condition and Results of Operations
  

(i)     Changes in and Disagreements with Accountants on  Accounting and Financial Disclosure

   There have been no changes in and disagreements with accountants on accounting and financial disclosure.
  

(j)     Quantitative and Qualitative Disclosures about Market  Risk

   Management’s Discussion and Analysis of Financial Condition and Results of Operations
  

(k)    Directors and Executive Officers

   Management
  

(l)     Executive Compensation

   Management
  

(m)   Security Ownership of Certain Beneficial Owners and  Management

   Security Ownership of Certain Beneficial Owners; Management
  

(n)    Certain Relationships and Related Transactions

   Management; Certain Relationships and Related Transactions

Item 12A.

   Disclosure of Commission Position on Indemnification for Securities Act Liabilities    Item 17. Undertakings


Table of Contents

The information in this prospectus is a part is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

 

Subject to Completion, Preliminary Prospectus dated January 8, 2016

ATLAS GROWTH PARTNERS, L.P.

Common Units Representing Limited Partner Interests

Minimum Offering: 100,000 Class A Common Units and Class T Common Units

Maximum Offering: 100,000,000 Class A Common Units and Class T Common Units

Warrants to Purchase Post-Listing Common Units Representing Limited Partner Interests

Distribution Reinvestment Plan: up to 21,505,376 Class A Common Units

 

 

Atlas Growth Partners, L.P. is offering in the aggregate up to 100,000,000 Class A common units and Class T common units, each representing limited partner interests in the partnership, with a minimum offering amount of 100,000 common units. We are offering to sell the common units at a price of $10.00 per common unit with an initial quarterly distribution of $0.175 per unit. Class A common units are sold for a cash purchase price of $10.00 and Class T common units are sold for a cash purchase price of $9.60, with the remaining $0.40 constituting the Class T common unitholders’ deferred payment obligation to us. Assuming our initial quarterly distribution is $0.175 per unit per quarter and we withhold $0.025 per unit per quarter, the holders of Class T common units will receive net quarterly distribution of $0.15 per unit until the deferred payment obligation is fulfilled or the Class T common units convert into Class A common units or are redeemed (for a maximum of up to 16 quarters). Investors who purchase common units in this offering will also receive, for no additional consideration, warrants to purchase, upon the occurrence of a liquidity event, additional common units equal to 10.00% of such investor’s aggregate purchase of common units at an exercise price of $10.00 per common unit. We anticipate that a liquidity event will occur within five years. However, our partnership agreement does not require that a liquidity event will occur within a specified timeframe or at all. We will also distribute warrants on the same terms to our existing unitholders. We also are offering up to 21,505,376 Class A common units to owners of our common units pursuant to our distribution reinvestment plan, or DRIP, initially at a 7.0% discount from the primary offering price of the Class A common units. Our DRIP offering will be made to both our existing common unit holders and to new investors purchasing common units in this offering.

We may increase the price per common unit following any material change to our business, assets or operations that increases the value of our partnership, as determined by an independent expert in the valuation of oil and gas assets.

We expect to terminate the offering upon the first to occur of (i) the sale of all of the common units offered by this prospectus, (ii)                     , 2018, which is the two-year anniversary of the effectiveness of the registration statement of which this prospectus is a part (subject to extension by us for up to six months, in order to achieve the maximum offering of 100,000,000 common units) and (iii) our failure to sell at least 100,000 common units ($1,000,000) on or before                     , 2018. Until we satisfy the 100,000 common units ($1,000,000) minimum offering requirement set forth in this prospectus, we will deposit subscription payments in an escrow account held by the escrow agent, UMB Bank, N.A., or UMB Bank, in trust for the subscriber’s benefit, pending release to us.

Our common units will initially not be listed on any national securities exchange.

 

 

Investing in our common units involves a high degree of risk. Before subscribing for common units you should carefully read the discussion of material risks of investing in our common units in “Suitability Standards” on page iii and in “Risk Factors” on page 28. These risks include the following:

 

    We may not have sufficient available cash to pay the full target distribution, or any distribution at all, on our common units and there is no guaranty that we will pay distributions to our unitholders in any quarter. Any distributions from us may be a return of capital rather than a return on your investment.

 

    There is no guarantee of return of investment or rate of return of investment because of the speculative nature of drilling of oil and gas wells.

 

    Holders of our common units have limited voting rights and are not entitled to elect our general partner or its board of directors.

 

    The common units are not liquid and your ability to resell your common units will be limited by the absence of a public trading market and substantial transfer restrictions.

 

    The fiduciary duties of our general partner’s officers and directors may conflict with those they may have to affiliates of our general partner.

 

    Our tax treatment depends on our status as a partnership for federal and state income tax purposes. If we were to become subject to entity-level taxation for federal or state income tax purposes, taxes paid would reduce the amount of cash available for distribution.

 

    You may owe taxes in excess of your cash distributions from us.

The common units will be offered on a “best efforts” basis. The participating broker/dealers must sell at least 100,000 common units for this offering to close, and they must use only their best efforts to sell the remaining common units up to a maximum of 100,000,000 common units.

 

     Price To Public(3) (5)      Commissions(4)      Dealer
Manager Fee(4)
     Proceeds to Atlas
Growth Partners, L.P.
 

Primary Offering(1)(2)

           

Class A Common Units

           

Per Unit

   $ 10.00       $ 0.70       $ 0.30       $ 9.00   

Total Class A Common Units

   $ 700,000,000.00       $ 49,000,000.00       $ 21,000,000.00       $ 630,000,000.00   

Class T Common Units

           

Per Unit

   $ 10.00       $ 0.30       $ 0.30       $ 9.40   

Total Class T Common Units

   $ 300,000,000.00       $ 9,000,000.00       $ 9,000,000.00       $ 282,000,000.00 (5) 

Total Minimum Offering

   $ 1,000,000.00       $ 58,000.00       $ 30,000.00       $ 912,000.00   

Total Maximum Offering

   $ 1,000,000,000.00       $ 58,000,000.00       $ 30,000,000.00       $ 912,000,000.00   
  

 

 

    

 

 

    

 

 

    

 

 

 

Distribution Reinvestment Plan(1)

           

Per Class A Common Unit

   $ 9.30       $ —         $ —         $ 9.30   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Maximum

   $ 199,999,997       $ —         $ —         $ 199,999,997   
  

 

 

    

 

 

    

 

 

    

 

 

 

Post-Listing Common Units underlying Warrants

           

Per Common Unit

   $ 10.00       $ —         $ —         $ 10.00   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Maximum

   $ 123,300,410.00       $ —         $ —         $ 123,300,410.00   
  

 

 

    

 

 

    

 

 

    

 

 

 

Post-Listing Common Units(6)

   $ —         $ —         $ —         $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)  We may reallocate the units offered hereby between Class A common units and Class T common units and between the primary offering and our DRIP.
(2)  Does not include warrants to be issued with the common units because such warrants will be issued at no additional cost to investors.
(3)  Units may be sold at a discounted price to certain classes of investors and in connection with the sale of a certain number of Units, as described in “Plan of Distribution.”
(4)  In determining the amount of sales commissions and dealer manager fees, we have assumed this offering will consist of the sale of 70,000,000 Class A common units and 30,000,000 Class T common units at a purchase price of $10.00 per unit. The total amount of all items of compensation from any source, payable to our dealer manager or the participating broker-dealers, including non-cash compensation and the distribution and unitholder servicing fee, will not exceed an amount that equals 10.00% of the gross proceeds of the offering, excluding securities purchased through the DRIP, as set forth in FINRA Rule 2310(b)(4)(B)(ii).
(5)  With respect to Class T common units, we will pay to the dealer manager a distribution and unitholder servicing fee in the aggregate amount of 4.00% of the gross proceeds from the sale of Class T common units. Class T common units are sold for a cash purchase price of $9.60 with the remaining $0.40 constituting the distribution and unitholder servicing fee, which will be withheld from cash distributions otherwise payable to the purchasers of Class T common units at a rate of $0.025 per quarter per unit until the obligation is fulfilled or the Class T common units convert or are redeemed.
(6)  Upon a listing event, Class A common units and any remaining Class T common units will automatically convert to Post-Listing common units, the rights of which are set forth in the Post-Listing Partnership Agreement, for no additional, as converted into Class A common units, consideration.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

 

ANTHEM SECURITIES, INC.—DEALER MANAGER

The date of this prospectus is                     , 2016.


Table of Contents

TABLE OF CONTENTS

 

INDUSTRY AND MARKET DATA

     ii   

SUITABILITY STANDARDS

     iii   

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     vi   

SUMMARY

     1   

ATLAS GROWTH PARTNERS, L.P.

     1   

RISK FACTORS

     28   

SOURCE OF FUNDS AND ESTIMATED USE OF PROCEEDS

     56   

CAPITALIZATION

     59   

DILUTION

     60   

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     61   

ATLAS’ PRIOR EXPERIENCE WITH DRILLING PROGRAMS AND MASTER LIMITED PARTNERSHIPS

     74   

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

     76   

COMPENSATION

     87   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     96   

TERMS OF THE OFFERING

     99   

SELECTED HISTORICAL FINANCIAL DATA

     101   

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     104   

BUSINESS AND PROPERTIES

     119   

MANAGEMENT

     152   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     164   

CAPITAL CONTRIBUTIONS

     166   

UNITS ELIGIBLE FOR FUTURE SALE

     168   

MATERIAL FEDERAL INCOME TAX CONSEQUENCES

     169   

INVESTMENT BY TAX-EXEMPT ENTITIES AND ERISA CONSIDERATIONS

     184   

SUMMARY OF THE PARTNERSHIP AGREEMENT

     189   

DESCRIPTION OF THE COMMON UNITS

     230   

DESCRIPTION OF THE WARRANTS

     234   

DISTRIBUTION REINVESTMENT PLAN

     236   

REPORTS TO INVESTORS

     239   

TRANSFERABILITY OF INTERESTS

     240   

PLAN OF DISTRIBUTION

     241   

HOW TO SUBSCRIBE

     252   

SALES MATERIAL

     253   

LEGAL OPINIONS

     254   

EXPERTS

     255   

 

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Table of Contents

ELECTRONIC DELIVERY OF DOCUMENTS

     256   

WHERE YOU CAN FIND MORE INFORMATION

     257   

GLOSSARY

     258   

INDEX TO FINANCIAL STATEMENTS

     F-1   

 

APPENDIX A:

   CALCULATION OF DISTRIBUTION UPON A SALE OR MERGER   

EXHIBIT A:

   PRE-LISTING PARTNERSHIP AGREEMENT   

EXHIBIT B:

   POST-LISTING PARTNERSHIP AGREEMENT   

EXHIBIT C:

   SUBSCRIPTION AGREEMENT   

EXHIBIT D:

   WARRANT AGREEMENT   

EXHIBIT E:

   FORM OF DISTRIBUTION REINVESTMENT PLAN   

EXHIBIT F:

   LONG-TERM INCENTIVE PLAN   

EXHIBIT G:

   TRANSFER ON DEATH FORM   

EXHIBIT H:

   LETTER OF DIRECTION   

EXHIBIT I:

   NOTICE OF REVOCATION   

You should rely only on the information contained in this prospectus, any free writing prospectus prepared by or on behalf of us or any other information to which we have referred you in connection with this offering. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus. Neither the delivery of this prospectus nor sale of our common units means that information contained in this prospectus is correct after the date of this prospectus. This prospectus is not an offer to sell or solicitation of an offer to buy our common units in any circumstances under which the offer or solicitation is unlawful.

INDUSTRY AND MARKET DATA

This prospectus includes industry data and forecasts that we obtained from internal company sources, publicly available information and industry publications and surveys. Our internal research and forecasts are based on management’s understanding of industry conditions, and such information has not been verified by independent sources. Industry publications, surveys and forecasts generally state that the information contained therein has been obtained from sources believed to be reliable. There can be no assurance as to the accuracy or completeness of the information presented herein derived from third party sources. Statements as to the industry or operator estimates and future activities are based on independent industry publications, government publications, third-party forecasts, public statements by our operators, management’s estimates and assumptions about our markets and our internal research. While we are not aware of any misstatements regarding such estimates or the market, industry or similar data presented herein, such estimates and data involve risks and uncertainties and are subject to change based on various factors, including those discussed under the headings “Risk Factors” and “Forward-Looking Statements” in this prospectus, most of which are not within our control.

 

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Table of Contents

SUITABILITY STANDARDS

In General

An investment in us involves significant risk and is suitable only for persons who have adequate financial means, desire a long-term investment and do not need immediate liquidity from their investment. Persons who meet this standard and seek to diversify their personal portfolios with an investment in an oil and natural gas partnership, which among its benefits may provide portfolio diversification, generate cash distributions, provide tax benefits, and hedge against inflation, and are able to hold their investment for the long-term, are most likely to benefit from an investment in us. On the other hand, an investment in us is not appropriate for persons who require immediate liquidity or guaranteed income, or who seek a short-term investment. Notwithstanding these investor suitability standards, potential investors should note that investing in our common units involves a high degree of risk and all the information contained in this prospectus should be considered, including the “Risk Factors” section, in determining whether an investment in our common units is appropriate.

It is the obligation of Atlas Growth Partners GP, LLC, a Delaware limited liability company and our general partner, and the persons selling the common units to make every reasonable effort to ensure that the common units are suitable for you based on your investment objectives and financial situation, regardless of your income or net worth, and that you have the apparent understanding of: the fundamental risks of an investment in us; the risk that you may lose your entire investment; the lack of liquidity and the restrictions on transferability of the common units; and the background and qualifications of our general partner and the tax consequences of the investment.

Our general partner or each person selling the common units will make this determination on the basis of information it has obtained from you. Relevant information for this purpose will include at least your age, investment objectives, investment experience, income, net worth, financial situation and other investments, as well as any other pertinent factors. However, you should invest in us only if you are willing to assume the risk of a speculative, illiquid and long-term investment.

Generally, you are required to execute your own subscription agreement, and our general partner will not accept any subscription agreement that has been executed by someone other than you. The only exception is in the case of fiduciary accounts if you have given someone else the legal power of attorney to sign on your behalf and you meet all of the conditions in this prospectus.

The decision to accept or reject your subscription will be made by our general partner, in its sole discretion, and is final. Our general partner will not accept your subscription until it has reviewed your apparent qualifications, and the suitability determination must be maintained by our general partner during our term and for at least six years thereafter.

General Suitability Requirements for Purchasers of Common Units Representing Limited Partners Interests

Common units representing limited partner interests may be sold to you if you meet either of the following requirements:

 

    a net worth of not less than $330,000, exclusive of home, home furnishings and automobiles; or

 

    a net worth of not less than $85,000, exclusive of home, home furnishings and automobiles, and had during the last tax year gross income of at least $85,000.

California Residents: IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY, OR ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION THEREFORE, WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN THE COMMISSIONER’S RULES.

 

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Idaho Residents: Your total investment in Atlas Growth Partners, L.P. may not exceed 10% of your net worth.

Kansas Residents: It is recommended by the Office of the Kansas Securities Commissioner that Kansas investors limit their aggregate investment in the securities of the issuer and other non-traded oil and gas programs to not more than 10% of their liquid net worth (total assets minus total liabilities) that is comprised of cash, cash equivalents and readily marketable securities.

Maine Residents: The Maine Office of Securities recommends that your aggregate investment in Atlas Growth Partners, L.P. and similar direct participation investments not exceed 10% of your net worth. For this purpose, “liquid net worth” is defined as that portion of net worth that consists of cash, cash equivalents and readily marketable securities.

North Dakota Residents: You must represent that, in addition to the stated net income and net worth standards you have a net worth of at least ten times your investment in Atlas Growth Partners, L.P.

Oregon Residents: You must not make an investment in Atlas Growth Partners, L.P. greater than 10% of your liquid net worth, exclusive of home, home furnishings and automobiles.

Suitability Requirements for Qualified Plans and IRAs

An investment retirement account, or IRA, can purchase common units if the IRA owner meets both the basic suitability standard and any relevant standard applicable in the owner’s state of residence. Pension, profit-sharing or stock bonus plans, including Keogh Plans, that meet the requirements of Section 401 of the Internal Revenue Code of 1986, as amended, or the Code, are called qualified plans in this prospectus. Qualified plans that are self-directed may purchase common units if the plan participant meets both the basic suitability standard and any relevant standard applicable in the participant’s state of residence. Qualified plans that are not self-directed may purchase common units if the plan itself meets both the basic suitability standard and any relevant state standard.

Fiduciary Accounts

If there is a sale of common units to a fiduciary account other than an IRA or a qualified plan, such as a trust, both the general suitability standards and any applicable state suitability standards must be met by the beneficiary of the fiduciary account, the fiduciary account itself or the donor or grantor who directly or indirectly supplies the funds to purchase the common units if the donor or grantor is the fiduciary.

Generally, you are required to execute your own subscription agreement, and our general partner will not accept any subscription agreement that has been executed by someone other than you. The only exception is if you have given someone else the legal power of attorney to sign on your behalf and you meet all of the conditions in this prospectus.

Additional Considerations for IRAs, Qualified Plans and Tax-Exempt Organizations

An investment in the common units will not automatically create an IRA or qualified plan. To form an IRA, an investor must comply with all applicable provisions of the Code, and the Employee Retirement Income Security Act of 1974, or ERISA. IRAs, qualified plans and tax-exempt organizations should consider the following when deciding whether or not to invest:

 

    most, if not all, income or gain realized will be unrelated business taxable income, or UBTI;

 

    for IRAs and qualified plans, ownership of the common units may cause a pro rata share of our assets to be considered plan assets for the purposes of ERISA and the excise taxes imposed by the Code;

 

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    any entity that is exempt from federal income taxation will be unable to take full advantage of any tax benefits generated by us; and

 

    charitable remainder trusts that have any UBTI will be subject to an excise tax equal to 100.00% of such UBTI.

Although the common units may represent suitable investments for some IRAs, qualified plans and tax-exempt organizations, the common units may not be suitable for your plan or organization due to the particular tax rules that apply to your plan or organization. Furthermore, the investor suitability standards represent minimum requirements, and the fact that your plan or organization satisfies them does not mean that an investment would be suitable. You should consult your plan’s tax, financial, legal and other advisors to determine whether this investment would be appropriate for you. Please read “Risk Factors” and “Material Federal Income Tax Consequences.”

If you are a fiduciary or investment manager of a qualified plan or IRA, or if you are a fiduciary of another tax-exempt organization, you should consider all risks and investment concerns, including those related to tax considerations, in deciding whether this investment is appropriate and economically advantageous for your plan or organization. Please read “Risk Factors,” “Material Federal Income Tax Consequences” and “Investment by Tax-Exempt Entities and ERISA Considerations.”

Restrictions Imposed by the USA PATRIOT Act and Related Acts

In accordance with the Uniting and Strengthening America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism Act of 2001, as amended, or the USA PATRIOT Act, the common units offered hereby may not be offered, sold, transferred or delivered, directly or indirectly, to any “Prohibited Shareholder,” which means anyone who is:

 

    a “designated national,” “specially designated national,” “specially designated global terrorist,” “foreign terrorist organization,” or “blocked person” within the definitions set forth in the Foreign Assets Control Regulations of the U.S. Treasury Department;

 

    acting on behalf of, or an entity owned or controlled by, any government against whom the U.S. maintains economic sanctions or embargoes under the Regulations of the U.S. Treasury Department;

 

    within the scope of Executive Order 13224—Blocking Property and Prohibiting Transactions with Persons who Commit, Threaten to Commit, or Support Terrorism, effective September 24, 2001;

 

    subject to additional restrictions imposed by the following statutes or regulations, and executive orders issued thereunder: the Trading with the Enemy Act, the Iraq Sanctions Act, the National Emergencies Act, the Antiterrorism and Effective Death Penalty Act of 1998, the International Emergency Economic Powers Act, the United National Participation Act, the International Security and Development Corporation Act, the Nuclear Proliferation Prevent Act of 1994, the Foreign Narcotics Kingpin Designation Act, the Iran and Libya Sanctions Act of 1998, the Cuban Democracy Act, the Cuban Liberty and Democratic Solidarity Act and the Foreign Operations, Export Financing and Related Programs Appropriation Act or any other law of similar import as to any non-U.S. country, as each such act or law has been or may be amended, adjusted, modified or revised from time to time; or

 

    designated or blocked, associated or involved in terrorism, or subject to restrictions under laws, regulations, or executive orders as may apply in the future similar to those set forth above.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements. You can identify forward-looking statements by the use of forward-looking terminology such as “assume,” “forecast,” “position,” “believes,” “expects,” “may,” “will,” “would,” “could,” “should,” “seeks,” “continue,” “intends,” “plans,” “projects,” “estimates,” “anticipates,” “predicts,” “strategy,” “budget” or “potential,” or by the negative of these words and phrases, or by similar words or phrases. You can also identify forward-looking statements by discussions of strategy, plans or intentions. Statements regarding the following subjects may be impacted by a number of risks and uncertainties which may cause our actual results, performance or achievements to be materially different from any future results, performances or achievements expressed or implied by the forward-looking statements:

 

    our use of the proceeds of this offering, especially as it impacts our ability to fund the target distribution;

 

    our business and investment strategy;

 

    our ability to make acquisitions and other investments in a timely manner or on acceptable terms;

 

    our ability to pay the full target distribution, or any distribution at all;

 

    current credit market conditions and our ability to obtain long-term financing for our property acquisitions and drilling activities in a timely manner and on terms that are consistent with what we project when we invest in a property;

 

    the effect of general market, oil and gas market (including volatility of realized price for oil, natural gas and natural gas liquids), economic and political conditions, including the recent economic slowdown in the oil and gas industry;

 

    uncertainties with respect to identified drilling locations and estimates of reserves;

 

    our ability to generate sufficient cash flows to make distributions to our unitholders;

 

    the degree and nature of our competition;

 

    the availability of qualified personnel at our general partner and Atlas Energy Group, LLC, or ATLS; and

 

    other factors referenced in this prospectus, including those set forth under the caption “Risk Factors.”

The forward-looking statements contained in this prospectus reflect our beliefs, assumptions and expectations of our future performance, taking into account all information currently available to us. These beliefs, assumptions and expectations are subject to risks and uncertainties and can change as a result of many possible events or factors, not all of which are known to us. If a change occurs, our business, financial condition, liquidity and results of operations may vary materially from those expressed in our forward-looking statements. You should carefully consider these risks before you make an investment decision with respect to our common units.

For more information regarding risks that may cause our actual results to differ materially from any forward-looking statements, please read “Risk Factors.”

 

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SUMMARY

The following information is a summary about this offering and may not contain all of the detailed information that is important to you. Accordingly, we urge you to read this summary together with all the information contained in this prospectus, including the information under the caption “Risk Factors” on page 28.

We include definitions of certain terms used to describe oil and gas properties and operations under the caption “Glossary” in this prospectus. Additional definitions of terms used in this prospectus are set forth in Section 2.01 of the First Amended and Restated Partnership Agreement of Atlas Growth Partners, L.P., or our Partnership Agreement (also referred to as the Pre-Listing Partnership Agreement), which is included as Exhibit A to this prospectus. As used in this prospectus, the terms “we,” “us,” “our” or the “Partnership” refer to Atlas Growth Partners, L.P. and our consolidated subsidiaries, unless the context otherwise requires. In addition, the term “general partner” refers to our general partner, Atlas Growth Partners GP, LLC. The term “common units” refers to our common units, which may, but are not required to be, delineated as Class A common units and Class T common units, in each case representing limited partner interests. The term “unitholders” refers to the holders of our common units collectively, unless the context otherwise requires. The term “Post-Listing Partnership Agreement” refers to the Second Amended and Restated Agreement of Limited Partnership, the form of which is attached as Exhibit B to this prospectus. The terms “the offering,” “this offering” and “the primary offering” refer to the offering of Class A common units and Class T common units on a “best efforts” basis and excludes common units offered pursuant to our distribution reinvestment program, or our DRIP.

ATLAS GROWTH PARTNERS, L.P.

Overview

We are a Delaware limited partnership formed in February 2013 to acquire oil and gas assets in North America. Through the conclusion of our private placement on June 30, 2015, we issued 23,300,410 common units in exchange for net proceeds of approximately $203.4 million. Our operations are substantially focused on the Eagle Ford Shale in South Texas. Additionally, we are focused on opportunistically acquiring energy-related assets including additional undeveloped assets, developed assets, gathering, processing and pipeline assets and securities of energy companies.

Although the common units will initially not be traded on a national securities exchange, the Partnership is treated as a pass through entity for income tax purposes and the Partnership intends to pay regular distributions. In this regard, the Partnership is similar to other yield-oriented investment vehicles, such as master limited partnerships, or MLPs. Unlike the Partnership, however, MLPs are traded on a national securities exchange.

As a result of the technological and operational advances in oil and gas production and other domestic and global factors, oil prices have fallen significantly since November 2014. We believe that we are well positioned to take advantage of opportunities generated by the volatility of, and significant decline in, oil prices. We are managed by an experienced and entrepreneurial management team, supported by highly qualified energy professionals based out of Fort Worth, Texas. We believe our management has demonstrated recurring success in growing value to all stakeholders during the creation and eventual sale of several energy companies, including Atlas Energy, Inc., Atlas Energy L.P., or Atlas Energy, and Atlas Pipeline Partners L.P., or APL.

 



 

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Our Properties

Our oil and natural gas properties are located in Texas and Oklahoma. The following table sets forth certain information with regard to our total estimated proved reserves and the estimated proved reserves attributable to the Eagle Ford properties, discussed further below, as of September 30, 2015. Please read “Certain Relationships and Related Party Transactions—Related Party Agreements—Eagle Ford Acquisition—Assignment to ARP.”

 

    Reserves at
September 30, 2015
    Eagle Ford
Reserves at
September 30, 2015
 

Reserve data:

   

Estimated net proved reserves(1):

   

Natural gas reserves (MMcf):

   

Proved developed reserves

    705        547   

Proved undeveloped reserves

    2,259        2,259   
 

 

 

   

 

 

 

Total proved reserves of natural gas

    2,964        2,806   

Oil reserves (MBbl):

   

Proved developed reserves

    1,589        1,569   

Proved undeveloped reserves

    5,766        5,765   
 

 

 

   

 

 

 

Total proved reserves of oil

    7,355        7,334   

NGL reserves (MBbl)(1):

   

Proved developed reserves

    112        90   

Proved undeveloped reserves

    373        373   
 

 

 

   

 

 

 

Total proved reserves of NGL

    485        463   
 

 

 

   

 

 

 

Total proved reserves (MMcfe)

    50,001        49,590   
 

 

 

   

 

 

 

 

(1)  Oil and NGLs are converted to gas equivalent basis at the rate of one barrel of oil or NGLs to six Mcf of natural gas. This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value.

Eagle Ford

As of September 30, 2015, we own oil and NGL interests in approximately 2,835 net acres, of which 596 are undeveloped, non-producing net acres and 2,239 are developed net acres, in the Eagle Ford Shale in Atascosa County, Texas. We estimate the undeveloped reserves attributable to our Eagle Ford Shale properties are approximately 85% oil at that date. As of September 30, 2015, we have six producing wells, four wells awaiting completion and 26 identified potential drilling locations.

Marble Falls

As of September 30, 2015, we own oil and natural gas liquid interests in approximately 2,208 net acres, of which 896 are undeveloped, non-producing net acres and 1,312 are developed net acres in the Marble Falls formation and the Barnett Shale, in Jack County, Texas with 17 identified potential drilling locations. Through September 30, 2015, we have drilled 11 wells on the acreage acquired in the Marble Falls formation. For the year ended December 31, 2014 and the nine months ended September 30, 2015, average Marble Falls production was 1,783 Mcfe/d and 992 Mcfe/d, respectively.

 



 

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Mississippi Lime

As of September 30, 2015, we own a non-operated 11.76% working interest in two wells being developed in the Mississippi Lime formation in Garfield County, Oklahoma, operated by SandRidge Energy, Inc., or SandRidge. SandRidge commenced drilling on the first well in December 2013 and the well began producing in commercial quantities in May 2014. Drilling on the second well commenced in August 2014 and the well began producing in commercial quantities in October 2014.

Our Property Acquisition Strategy

We intend to target for acquisition energy-related assets, including producing oil and gas assets, undeveloped oil and gas assets with development potential, gathering, processing and pipeline assets and securities of energy companies. When we acquire a property, we will estimate the capital required to develop the property and plan to reserve a portion of our capital contributions, or a portion of any borrowing capacity available to us, to fund all or a portion of these estimated costs of development. We also plan to use our cash flow, after the payment of target distributions to our unitholders, to further develop our properties and to fund future acquisitions.

We do not expect to conduct a material amount of exploratory drilling on any non-producing properties we acquire.

Our general partner will have the ability to acquire properties and conduct operations that vary from the parameters described in this prospectus. Please read “Conflicts of Interest and Fiduciary Duties.”

Our Investment Objective

Our primary investment objective is to generate an attractive total return, consisting of current distributions and capital appreciation, through the acquisition of oil and gas assets in North America. We intend to generate stable and sustainable quarterly distributions to unitholders and to create liquidity for the unitholders in the future through a listing of the Post-Listing common units (into which the Class A common units and any remaining Class T common units, as converted into Class A common units, will automatically convert) on a national stock exchange, a merger of the Partnership with an existing publicly traded entity or the sale of all or substantially all of our assets (please read “—Our Liquidity Strategy,” below). To achieve our general investment objective, we expect to:

 

    use the expertise of personnel of our general partner and its parent company, Atlas Energy Group, LLC, or ATLS, a publicly traded MLP, to identify and acquire energy-related assets, including producing oil and gas assets, undeveloped oil and gas assets with development potential, gathering, processing and pipeline assets, and securities of energy companies;

 

    provide a targeted 7.00% per year distribution per Unit (calculated based upon a $10.00 per Unit purchase price), paid quarterly to unitholders (at least 1.75% of the common unit purchase price per quarter), or the target distribution;

 

    invest cash flow above the target distribution to acquire additional properties and assets as described in the first bullet point;

 

    generate for each period an amount of taxable income that is expected to be less than the quarterly distributions paid for such period by offsetting allocations of income to the unitholders with deductions for intangible drilling costs, depletion and depreciation;

 

    where our general partner deems it appropriate and in our best interest, use hedging strategies to fix pricing on some portion of the Partnership’s production in an effort to mitigate commodity price volatility;

 



 

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    where our general partner deems it appropriate and in our best interest, use debt to expand the Partnership’s operations. Prior to a liquidity event, as defined below under “—Our Liquidity Strategy,” total debt may not exceed total capital contributions made to us; and

 

    seek to provide liquidity by June 30, 2020 through a listing of our common units on a national securities exchange, a merger of the Partnership with an existing publicly traded entity or the sale of all or substantially all of our assets.

Our Business Strategies

We expect to achieve our investment objective through the acquisition of oil and gas assets in North America. There is a wide range of forecasted prices for oil, creating uncertainty for the acquisition market and oilfield service market. The Partnership believes that this uncertainty will provide attractive opportunities to acquire undervalued assets in several targeted markets. While oil prices were relatively high, the Partnership believed it could generate the most attractive returns for limited partners from the acquisition and subsequent development of undeveloped oil and gas properties enhancing the value of the sites. With lower and more volatile prices, the Partnership believes it is in a position to benefit from the:

 

    acquisition of additional undeveloped properties;

 

    acquisition of low-risk, developed properties at attractive valuations from distressed sellers;

 

    drilling of wells for significantly lower costs on acreage previously acquired;

 

    delaying of sustained development on held acreage until projected drilling returns meet required levels;

 

    acquisition of other energy-related assets including gathering, processing and pipeline properties; and

 

    acquisition of securities of energy companies.

For a more detailed description of our business strategies, please read “Business and Properties—Our Investment Strategies.”

Our Liquidity Strategy

In order to provide liquidity for our unitholders, we intend to, before the end of the Partnership’s term, effect one of the following, each of which is referred to as a liquidity event:

 

    list the common units on a national securities exchange, or a listing event; or

 

    consolidate or merge with or into an existing publicly traded entity, or a merger; or

 

    sell all or substantially all of our assets, or a sale.

We will seek to provide a liquidity event by June 30, 2020. We cannot assure you, however, and our Pre-Listing Partnership Agreement does not require, that a liquidity event will occur within a specified time frame or at all.

If the proposed liquidity event is a merger or sale, we will be deemed to have fulfilled our undertaking to provide a liquidity event if the proposed merger or sale is voted upon but disapproved by the unitholders. Our general partner thereafter may, but is not obligated to, propose other liquidity events.

The decision by our general partner to undertake a merger or sale, and our ability to undertake such transactions, will depend on a number of factors, many of which will be beyond the control of our general partner, including:

 

    the market for oil and gas assets;

 

    the price of oil, gas and other hydrocarbons that our assets produce;

 



 

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    general economic conditions; and

 

    whether we have finished the planned development of the assets we acquire.

The decision by our general partner to apply to list our common units on a national securities exchange, and the ability of our general partner to list the common units, will depend on a number of factors, some of which will be beyond the control of our general partner, including:

 

    the amount of assets, revenues and earnings that we have at the time of our listing;

 

    the then existing market for oil and gas MLPs; and

 

    our ability to meet the applicable listing standards of the various national securities exchanges.

We may not be able to undertake a merger, sale or listing event. At this time it is impossible for us to determine the amounts we will be able to distribute if we undertake a merger or sale or the price at which the common units will trade if we are able to undertake a listing event.

Our general partner will be entitled to various distributions upon the occurrence of a liquidity event. We anticipate that a liquidity event will occur within five years. However, our Pre-Listing Partnership Agreement does not require that a liquidity event will occur within a specified timeframe or at all. Please read “The Partnership Agreement—Distributions Upon Sale,” “—Distributions Upon Merger,” “—Common Unit Issuance in lieu of IDRs to our General Partner at a Listing Event,” “—Distributions of Cash Upon Liquidation” and “—Distributions In-Kind Upon Liquidation.”

Our Potential Competitive Strengths

We believe that the following potential competitive strengths will allow us to successfully execute our business strategies and achieve our objectives of generating stable cash flows available for distribution, reinvesting excess cash flow and creating liquidity for our unitholders:

 

    our general partner’s management team’s experience in the acquisition, development and successful integration of oil and natural gas assets;

 

    our general partner’s management team’s experience with publicly traded companies and MLPs, which have similar tax treatment and investment characteristics to the Partnership;

 

    our diversified asset portfolio characterized by proved undeveloped reserves and long-lived reserves with low geologic risk;

 

    our substantial inventory of identified drilling locations;

 

    our relationships with our general partner, ATLS, Atlas Resource Partners, L.P., or ARP, and their respective affiliates, which we believe help us with access to and in the evaluation and execution of future acquisitions; and

 

    our competitive cost of capital and financial flexibility.

For a more detailed description of our potential competitive strengths, please read “Business and Properties—Our Potential Competitive Strengths.”

Our Principal Business Relationships

Our general partner, Atlas Growth Partners GP, LLC, a Delaware limited liability company, is responsible for the management and administration of the Partnership’s operations and projects and owns 100.00% of our GP units and all of the incentive distribution rights, which will entitle our general partner to certain financial

 



 

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incentives following a liquidity event. Our general partner is indirectly owned 80.01% by Atlas Energy Group, LLC, or ATLS, a publicly traded Delaware MLP, and 19.99% by current and former members of ATLS management. Therefore, ATLS controls our general partner. ATLS is focused on the production of natural gas and oil in the continental United States. ATLS currently conducts a majority of its natural gas and oil production activities through its publicly traded subsidiary, ARP.

The officers of our general partner are employees of ATLS, and have experience in managing oil and gas companies. Please read the discussion below and “Management—Directors and Officers of our General Partner.” The board of directors of our general partner consists of seven directors, three of whom are independent within the meaning of the applicable rules of the Securities and Exchange Commission, or the SEC, and New York Stock Exchange, or NYSE. The board of directors has established a conflicts committee, which is composed of the independent directors, for purposes of reviewing potential conflicts of interest between us and our general partner.

Management of our general partner has extensive experience with public MLPs. In 2000, management took APL public. From inception through its merger with a subsidiary of Targa Resource Partners LP in February 2015, APL expanded geographically from a small set of natural gas gathering assets in the Appalachian basin to one of the largest independent gathering and processing companies in the country, with processing capacity of approximately 1.2 Bcf/d. APL returned to its unitholders 421.30% (11.90% annual average) through unit price appreciation and distributions from inception through October 13, 2014 when APL announced its merger with a subsidiary of Targa Resources Partners LP. In 2006, management of our general partner took public Atlas Pipeline Holdings, L.P., or AHD. In conjunction with the sale of Atlas Energy, Inc. to Chevron Corporation, or Chevron, in 2011, AHD purchased certain exploration and production assets from Atlas Energy, Inc. and was subsequently renamed Atlas Energy, L.P., or Atlas Energy. Atlas Energy, Inc. returned to its unitholders 930.5% from inception through 2011 when it announced the acquisition by Chevron. From inception through its announced merger with a subsidiary of Targa Resources Corp. in October 2014, AHD and its successor, ATLS, returned 108.10% (9.30% annual average) through unit price appreciation and distributions. In 2006, management took public Atlas Energy Resources, LLC, or ATN, an exploration and production MLP with assets largely in the Appalachian basin and Michigan. ATN was merged into Atlas Energy, Inc. in a unit-for-share exchange in September 2009. From inception through the sale of Atlas Energy, Inc. to Chevron, ATN returned 178.30% (27.70% annual average) through unit price appreciation and distributions. In February 2012, Atlas Energy contributed the exploration and production assets that it had acquired from Atlas Energy, Inc. prior to the Chevron acquisition into a new exploration and production MLP, ARP. In connection with the Targa mergers, Atlas Energy transferred all of its assets and liabilities, other than those related to its midstream assets (including APL), to ATLS and effected a pro rata distribution to Atlas Energy’s unitholders of 100.00% of ATLS’s common units. For a discussion of major adverse business developments experienced by management of our general partner, please read “Atlas’ Prior Experience with Drilling Programs and Master Limited Partnerships.”

Our general partner receives an annual management fee equal to the product of 1.00% multiplied by total capital contributions made by our unitholders (other than our general partner and its affiliates), payable quarterly.

In addition, pursuant to the Partnership Agreement, we may issue additional limited partner interests and options, rights, warrants and appreciation rights relating to such limited partner interests for any Partnership purposes at any time on such terms and conditions as our general partner determines appropriate, all without the approval of any unitholders. Upon issuance of any common units, we will automatically issue to our general partner, for no additional consideration and without further requirement of capital contribution by our general partner, an additional number of GP units so that the total number of outstanding GP units after such issuance equals 2.00% of the sum of the total number of common units and GP units outstanding after such issuance. After a listing event, our general partner will have the right, not the obligation, to purchase or subscribe for common units whenever we issue common units to any persons on the same terms, to keep our general partner’s percentage interest in the Partnership the same as prior to such issuances.

 



 

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In addition, if a liquidity event occurs, our general partner will be entitled to receive a one-time incentive performance participation amount equal to 20.00% of profits in the form of common units (or cash, if the consideration payable in such transaction is cash), subject to our limited partners receiving an aggregate amount equal to their contributed capital plus a 7% non-compounded annual return, subject to a catch-up for our general partner. Please read “Summary of the Partnership Agreement—The Partnership Agreement—Distributions Upon Sale,” “—Distributions Upon Merger” and “—Common Unit Issuance in lieu of IDRs to our General Partner at a Listing Event.”

The success of our business will depend in large part on the services to be rendered to us by our general partner. For more information regarding our management by our general partner, please read “Management.”

Our Operations

General

As of September 30, 2015, we, our general partner or our affiliates operated 90% of the wells and properties containing our proved reserves on our behalf. Our general partner provides management, administrative and operating services to us to manage and operate our business and assets.

Hedging Arrangements

Pricing for natural gas and oil has been volatile and uncertain for many years. To limit exposure to changes in natural gas and oil prices in the future, our general partner and its affiliates, including ATLS and ARP, have used in the past and will continue to use financial hedges through contracts such as regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. Pursuant to our credit facility, we and our subsidiaries have the ability to enter into derivative contracts to manage our exposure to commodity price movements that will benefit from the collateral securing the credit facility. Please read “Business and Properties—Credit Facility” for more information. They may also use physical hedges through their natural gas and oil purchasers as discussed below. The futures contracts employed by our general partner and its affiliates are commitments to purchase or sell natural gas and oil at future dates and generally cover one-month periods for up to 60 months in the future. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, we will establish a risk management committee to assure that all financial trading is done in compliance with our hedging policies and procedures. We do not intend to contract for positions that we cannot offset with actual production. Any physical hedges require firm delivery of natural gas or oil and, therefore, are considered normal sales of natural gas and oil, rather than hedges, for accounting purposes. The percentages of natural gas and oil that are hedged through either financial hedges, physical hedges or not hedged at all will change from time to time in the discretion of our general partner.

We expect to continue to use similar hedging strategies with respect to the Partnership’s production. However, since the advisability of hedging is subject to numerous economic factors beyond our general partner’s control, there can be no assurance as to the amount of hedging our general partner will cause the Partnership to do, or whether hedging will be done at all.

Our Corporate Information

Our principal offices are located at Park Place Corporate Center One, 1000 Commerce Drive, Suite 410, Pittsburgh, Pennsylvania 15275 and our telephone number is (800) 251-0171.

 



 

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Our Ownership Structure

The following chart shows the ownership structure of the various entities that are affiliated with us, our general partner and our respective affiliates as of January 8, 2016.

 

LOGO

 

(1)  Atlas Energy Group, LLC, or ATLS, a publicly traded Delaware MLP, indirectly owns 80.01% of the interests of our general partner Atlas Growth Partners GP, LLC, and current and former members of ATLS management own 19.99% of our general partner. Therefore, ATLS controls our general partner and is our sponsor. ATLS is focused on the production of natural gas and oil in the continental United States.
(2) Our general partner, Atlas Growth Partners GP, LLC, a Delaware limited liability company, is responsible for the management and administration of our operations and projects. It owns 100.00% of our GP units and all of the incentive distribution rights, which will entitle our general partner to certain financial incentives following a liquidity event.
     Our general partner, its affiliates (including certain operators of our oil and gas properties) and non-affiliates will receive fees and compensation from us, including an annual management fee equal to the product of 1.00% multiplied by total capital contributions made by our unitholders (other than our general partner and its affiliates), payable quarterly. For more information, please read “Compensation.”

 



 

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(3) ATLS sponsors its subsidiary Atlas Resources Partners, L.P., or ARP, a publicly traded MLP, and currently conducts a majority of its natural gas and oil production activities through ARP. We may make payments to ARP in the future under related party agreements. For more information, please read “Certain Relationships and Related Party Transactions—Related Party Agreements.”

Risk Factors

This offering involves numerous risks, including risks related to our ability to identify and acquire oil and gas properties on acceptable terms, operating and environmental risks related to an investment in oil and gas properties, risks related to our structure as a limited partnership and tax risks. You should carefully consider a number of significant risk factors inherent in and affecting the business of the Partnership and this offering.

These risks include the following:

 

    We may not have sufficient available cash to pay the full target distribution, or any distribution at all, on our common units and there is no guaranty that we will pay distributions to our unitholders in any quarter. Any distributions from us may be a return of capital rather than a return on your investment. The payment of distributions from sources other than operating cash flow may decrease the cash available to invest in oil and gas properties, which may decrease our cash available for distributions in the future.

 

    There is no guarantee of return of investment or rate of return of investment because of the speculative nature of drilling of oil and gas wells.

 

    Holders of our common units have limited voting rights and are not entitled to elect our general partner or its board of directors.

 

    The common units are not liquid and your ability to resell your common units will be limited by the absence of a public trading market and substantial transfer restrictions.

 

    The fiduciary duties of our general partner’s officers and directors may conflict with those they may have to affiliates of our general partner.

 

    Our tax treatment depends on our status as a partnership for federal and state income tax purposes. If we were to become subject to entity-level taxation for federal or state income tax purposes, taxes paid would reduce the amount of cash available for distribution.

 

    You may owe taxes in excess of your cash distributions from us.

Please read “Risk Factors” on page 28.

Distributions

The amount of distributions paid under our cash distribution policy and the decision to make any distribution will be determined by our general partner in its discretion, taking into account the terms of the Partnership Agreement. Our board of directors has adopted a cash distribution policy under which we have distributed and intend to continue to distribute to our unitholders and our general partner as the holder of 100.00% of our GP units on a quarterly basis a target distribution of $0.175 per unit, or $0.70 per unit per year, to the extent the Partnership has sufficient available cash after establishing appropriate reserves and paying fees and expenses, including reimbursements of expenses to our general partner and its affiliates. There is no guarantee that we will pay the target distribution, or any distribution, in any quarter. Distributions are generally paid within 45 days of the end of the quarter to unitholders of record on the applicable record date. Unitholders are entitled to

 



 

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receive distributions beginning with the quarter following the quarter in which they are first admitted to the Partnership as limited partners. Distributions declared by the Partnership for the period from November 1, 2013 through September 30, 2015 were as follows (in thousands, except per unit amounts):

 

Date Cash Distribution Paid

  For the Quarter Ended   Cash
Distribution
per
Common
Limited
Partner
Unit
    Total Cash
Distribution
to Common
Limited
Partners
    Total Cash
Distribution
with respect
to General
Partner’s
GP Units
 

February 14, 2014(1)

  December 31, 2013   $  0.1167      $  120.00      $  2.00   

May 15, 2014

  March 31, 2014   $  0.1750      $  223.00      $  6.00   

August 14, 2014

  June 30, 2014   $  0.1750      $  342.00      $  7.00   

November 14, 2014

  September 30, 2014   $  0.1750      $  841.00      $  16.00   

February 13, 2015

  December 31, 2014   $  0.1750      $  1,636.00      $  33.00   

May 15, 2015

  March 31, 2015   $  0.1750      $  2,180.00      $  45.00   

August 14, 2015

  June 30, 2015   $  0.1750      $  2,646.00      $  54.00   

November 13, 2015

  September 30, 2015   $  0.1750      $  4,078.00      $  83.00   

 

(1)  Represents a pro-rated cash distribution of $0.1750 per unit for the period from November 1, 2013 to the date the Partnership commenced operations.

Our ability to make distributions will depend on the success of our business, which is subject to numerous risks, and no assurances can be made as to the amount or timing of any distributions that we will be able to make in the future. Please read “Risk Factors” and “Cash Distribution Policy and Restrictions on Distributions.”

Conflicts of Interest

Although our relationship with our general partner and ATLS and its affiliates may provide significant benefits to us, it may also become a source of potential conflicts. Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including ATLS and its affiliates), on the one hand, and the Partnership and our limited partners, on the other hand. Conflicts may arise as a result of the duties of our general partner to act for the benefit of its owners (including ATLS), which may conflict with the interests of you and other unitholders and the interests of the Partnership. The directors and officers of ATLS have duties to manage ATLS and our general partner in a manner beneficial to their owners. ATLS and its affiliates are not restricted from competing with us. In addition, many of the officers and directors of our general partner serve in similar capacities with ATLS and its affiliates, which may lead to additional conflicts of interest, including conflicts of interest regarding the allocation of their time between ATLS and us.

Our Partnership Agreement limits the liability of and replaces the fiduciary duties owed by our general partner to our unitholders. Our Partnership Agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of duties by our general partner or its directors or executive officers. By purchasing a common unit, the purchaser agrees to be bound by the terms of our Partnership Agreement, and each unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the Partnership Agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law.

 



 

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Whenever a conflict arises between our general partner or its affiliates, on the one hand, and the Partnership or any other partner, on the other hand, our general partner will resolve that conflict subject to restrictions set forth in “Conflicts of Interest and Fiduciary Duties.” Our general partner and its affiliates will not be in breach of any obligations under our Partnership Agreement or any duties to you and other unitholders or to us if the resolution of a conflict is:

 

    approved by the conflicts committee of the board of directors of our general partner;

 

    approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates; or

 

    on terms no less favorable to us than those generally being provided to or available from unrelated third parties.

If, however, a proposed conflict of interest is material to our business and operations, only the resolution procedures in the first two bullet points will be applicable.

The Post-Listing Partnership Agreement, which will not become effective unless a listing event occurs, contains similar provisions regarding the resolution of conflicts of interest, except that the standards of the third bullet point may be applied to all conflicts of interest, without limitation (including those that are material to our business and operations), and that a conflict may be resolved if the resolution is fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be favorable or advantageous to us.

Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors or from you and other unitholders. The existence of all conflicts of interest described herein, including from the transactions described herein, and any actions of our general partner taken in connection with such conflicts of interest, will be deemed approved by all of our limited partners pursuant to our Partnership Agreement and, if a listing event occurs the Post-Listing Partnership Agreement. If our general partner seeks approval by the conflicts committee of the board of directors of our general partner of any such action or resolution, it will be presumed that, in making its decision, the conflicts committee acted in good faith in the best interest of the Partnership. If our general partner does not seek approval from the conflicts committee or from the holders of common units and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies the standard set forth in the third bullet point above (or, alternatively, with respect to the Post-Listing Partnership Agreement, the fairness standard referred to in the previous paragraph), then it will be presumed that, in making its decision, the board of directors acted in good faith in the best interest of the Partnership, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our Partnership Agreement or the Post-Listing Partnership Agreement, our general partner or the conflicts committee may consider any factor it determines in good faith to consider when resolving a conflict. When our Partnership Agreement and the Post-Listing Partnership Agreement require someone to act in good faith, the agreements require that person to believe that he is not acting adversely to the interests of the Partnership.

 



 

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The Offering

 

Securities Offered

The Partnership is offering Class A common units and Class T common units. The Class A common units and Class T common units represent limited partner interests in the Partnership. The Class T common units will convert into Class A common units as described in “—Dealer Manager Fees, Sales Commissions and Distribution and Unitholder Servicing Fee.” The Partnership currently has outstanding 23,300,410 common units representing limited partner interests.

 

  Investors that purchase common units in this offering will also receive, for no additional consideration, warrants to purchase, upon the occurrence of a liquidity event, additional common units equal to 10.00% of such investor’s aggregate purchase of common units at an exercise price of $10.00 per Unit. In addition, upon the effectiveness of the registration statement of which this prospectus is a part, we will distribute to each existing limited partner one warrant to purchase one additional common unit for every 10 common units held by such limited partner. Therefore, with respect to the warrants, we are registering the offer and sale of:

 

    to the holders of our existing 23,300,410 common units representing limited partner interests:

 

    warrants, and

 

    the 2,330,041 Post-Listing common units underlying such warrants; and

 

    to our new investors:

 

    warrants in connection with the issuance of the new common units being registered in this offering, and

 

    up to 10,000,000 Post-Listing common units underlying such warrants.

 

  For additional information about the warrants, please read “—Warrants” below.

 

  We are also offering an aggregate of up to 21,505,376 Class A common units pursuant to our DRIP. Our DRIP offering will be made to both our existing common unit holders and to new investors purchasing common units pursuant to this offering. Investors that purchase common units pursuant to our DRIP will not receive warrants.

 

  We may reallocate the number of common units we are offering between Class A common units and Class T common units and between our primary offering and the DRIP.

 

  We are also offering Post-Listing common units, into which the Class A common units and any remaining Class T common units, as converted into Class A common units, automatically convert upon a listing event for no additional consideration. The rights of the holders of the Post-Listing common units are set forth in the Post-Listing Partnership Agreement.

 



 

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Offering Size

A minimum of $1.0 million, or 100,000 Units, and a maximum of $1.0 billion, or 1,000,000 Units, in aggregate investments in our primary offering. We are also offering an aggregate of up to $199,999,997, or 21,505,376, Class A common units pursuant to our DRIP. All common units purchased by our general partner and its respective affiliates and “Friends” will be applied to satisfying the minimum required subscription proceeds of $1 million. Our general partner may at its sole discretion file an amendment to the registration statement of which this prospectus is a part to increase the maximum offering amount. We may, following the termination of this offering, conduct future offerings of equity or debt securities, or both, to finance or expand our business and operations. “Friends” mean those individuals who have prior business and/or personal relationships with the executive officers or directors of our general partner, the dealer manager, or their respective affiliates, including, without limitation, any service provider.

 

Offering Price

In our primary offering, we are offering to sell the common units at a price of $10.00 per Unit. Class A common units are sold for a cash purchase price of $10.00 and Class T common units are sold for a cash purchase price of $9.60 with the remaining $0.40 constituting the deferred payment obligation of the Class T common unitholders to us. Discounts are also available for specified volume purchases of Class A common units in the primary offering.

 

  We are also offering Class A common units pursuant to our DRIP at a purchase price during this offering at 93.00% of the primary offering price of the Class A common units, or $9.30 per unit.

 

  We may increase the price per Unit following any material change to our business, assets or operations that increases the value of the Partnership, as determined by an independent expert in the valuation of oil and gas assets. If, following such a change, we determine to increase the price per Unit, which will include the dealer manager fees and sales commissions, we will file a post-effective amendment to this registration statement that describes such independent expert’s valuation report that supports such increase in the value of the Partnership.

 

  For information concerning reduction in selling price for certain classes of investors, please read “Plan of Distribution.”

 

Minimum Investment; Subscription Agreement


Investors purchasing common units must purchase an aggregate minimum of $5,000, or 500 common units, but investors who already own our common units may make purchases for less than the minimum investment so long as such purchases are made in $1,000 increments. Larger subscriptions will be accepted in $1,000 increments (100 common units).

 



 

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  Each investor will be required to execute a subscription agreement, a form of which is attached to this prospectus as Exhibit C. By signing the subscription agreement, you will be making the representations and warranties contained in the subscription agreement and will be bound by all of the terms and conditions set forth in the subscription agreement and our Partnership Agreement. Please read “Plan of Distribution.”

 

Warrants

The warrants have an exercise price equal to the price of a common unit in this offering. This allows the warrant holders to purchase 10.00% of such investor’s aggregate purchase of Post-Listing common units at an exercise price of $10.00 per unit. The exercise price and the number of Post-Listing common units underlying the warrants are both subject to adjustment in certain cases referred to below.

 

  The warrants are exercisable upon the occurrence of a liquidity event. When the Partnership expects a liquidity event is likely to occur, the Partnership will notify each holder of a warrant in writing no less than 30 days prior to the liquidity event. Holders of warrants may exercise their warrants at any time during the period beginning with the date of the notice and ending one day prior to the date upon which the liquidity event occurs, except that if the liquidity event is a listing event, holders of warrants may exercise their warrants until the date that is 30 days following the listing event, provided that in each case if the expiration date does not fall on a business day, it shall be the next business day. We anticipate that a liquidity event will occur within five years. However, our Pre-Listing Partnership Agreement does not require that a liquidity event will occur within a specified timeframe or at all.

 

Investment of General Partner and ATLS

Prior to the date of this prospectus, our general partner paid a capital contribution of $1,000 for GP units representing its 2.00% general partner interest. In addition, prior to the date of this prospectus, ATLS has acquired 500,010 Class A common units for a total of $5,000,100.

 

Offering Period and Termination

The offering period will terminate on the earliest of (i) the sale of 100,000,000 common units, (ii)                     , 2018 (the two-year anniversary of the effectiveness of the registration statement of which this prospectus is a part) unless extended by our general partner, but not past                     , 2018, (six months following the two-year anniversary of the effectiveness of the registration statement of which this prospectus is a part) or (iii) the failure to receive the minimum subscriptions on or before                     , 2018, which is two years from the effective date of the registration statement of which this prospectus is a part. If subscriptions for the minimum subscription are not received and accepted by our general partner prior to                     , 2018, each investor’s subscription will be promptly returned along with any interest earned.

 



 

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  Our general partner may terminate the offering without notice at any time prior to the scheduled end of the offering period.

 

Plan of Distribution

The initial closing of the offering will be held after we receive and deposit with the escrow agent subscriptions for at least $1 million, as discussed in “Plan of Distribution.” At that time, subscribers for common units will be admitted as our limited partners.

 

Dealer Manager

Anthem Securities, Inc.

 

Dealer Manager Fees, Sales Commissions     and Distribution and Unitholder     Servicing Fee



The Partnership will pay the dealer manager compensation equal to 3.00% of the gross proceeds of the offering. The dealer manager may reallow up to 1.50% of gross offering proceeds it receives as dealer manager fees to participating broker-dealers, but expects to reallow 1.25% of gross offering proceeds to participating broker-dealers.

 

  The Partnership will pay the dealer manager 7.00% and 3.00% of aggregate gross proceeds from the sale of Class A common units and Class T common units, respectively, as sales commissions. In addition, with respect to Class T common units, the Partnership will pay to the dealer manager a distribution and unitholder servicing fee in the aggregate amount of 4.00% of the gross proceeds from the sale of Class T common units, which distribution and unitholder servicing fee will be withheld from cash distributions otherwise payable to the purchasers of Class T common units at a rate of $0.025 per quarter per unit. Assuming our initial quarterly distribution is $0.175 per unit per quarter and we withhold $0.025 per unit per quarter, the holders of Class T common units will receive net quarterly distribution of $0.15 per unit until the deferred payment obligation is fulfilled or the Class T common units convert into Class A common units or are redeemed (for a maximum of up to 16 quarters).

 

 

We will cease paying the distribution and unitholder servicing fee with respect to any particular Class T common unit and that Class T common unit will convert into Class A common units at the conversion rate described herein on the earliest of (i) a liquidity event and (ii) the end of the month in which the underwriting compensation paid in the primary offering plus the quarterly distribution and unitholder servicing fee paid with respect to that Class T common unit equals 10% of the gross offering price of that Class T common unit. We will further cease paying the quarterly distribution and unitholder servicing fee on any Class T common unit that is redeemed or repurchased, as well as upon our dissolution, liquidation or the winding up of our affairs, or a merger or other extraordinary transaction in which the Partnership is a party and in which the Class T common units as a class are exchanged for cash or other securities. The conversion rate will be equal to the quotient, the numerator of which is the estimated value per Class T common unit

 



 

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(taking into account any reduction for the unpaid portion of the distribution and unitholder servicing fee as described herein) and the denominator of which is the estimated value per Class A common unit. If the Class T common units are converted to Class A common units at a time when there are unpaid distribution and unitholder servicing fees, a Class T common unitholder will likely receive fewer than one Class A common unit in exchange for each Class T common unit.

 

  The dealer manager may reallow all or a portion of the sale commissions and distribution and unitholder servicing fee to participating broker-dealers. We will not pay any sales commissions or distribution and unitholder servicing fee on sales of Class A common units under the DRIP.

 

Compensation of our General Partner, its Affiliates and Certain Non-Affiliates


Our general partner, its affiliates (including certain operators of our oil and gas properties) and non-affiliates will receive fees and compensation from the Partnership. The non-affiliates may include certain operators of our oil and gas properties. Also, please read “Plan of Distribution” for the compensation paid to the dealer manager and participating dealers. These fees and compensation, other than the compensation described above for the dealer manager and other participating dealers, will include the following:

 

    An annual management fee to our general partner equal to the product of 1.00% multiplied by total capital contributions made by our unitholders (other than our general partner and its affiliates), payable quarterly.

 

    The Partnership will reimburse our general partner for organization and offering expenses (excluding the dealer manager fee, sales commission and the distribution and unitholder servicing fee) paid by the general partner or its affiliates that do not exceed 2% of the aggregate proceeds of the primary offering if we raise less than $500 million or 1.5% if we raise $500 million or more, in each case excluding the DRIP.

 

    The Partnership will reimburse our general partner and its affiliates for their administrative costs related to the Partnership, all direct and indirect expenses incurred on behalf of the Partnership and other expenses incurred for managing and operating the Partnership.

 

    Our general partner will receive a credit to its Partnership capital account in an amount equal to its capital contribution to the Partnership, as discussed in “—Investment of General Partner and ATLS” above.

 

   

Our general partner or an affiliate of our general partner will have the right to charge a competitive rate of interest on any loan it may make to or on behalf of the Partnership. If our general partner or

 



 

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any such affiliate provides equipment, supplies or other services to the Partnership, it may do so at competitive industry rates.

 

    The Partnership may enter into contracts with our general partner and its affiliates to drill and complete, or plug if necessary, oil and gas wells at competitive rates for drilling and completing the wells.

 

    The applicable operator(s) of the Partnership’s properties, including certain affiliates of our general partner will (i) receive reimbursement at actual cost for all direct expenses incurred on behalf of the Partnership, including expenses to gather, transport, process, treat and market the Partnership’s oil and natural gas production, and (ii) receive well supervisory fees at competitive rates for maintaining and operating the wells during drilling and producing operations.

 

  Please read “Compensation” for more information about the fees the Partnership will pay our general partner, its affiliates and certain non-affiliates.

 

Estimated use of proceeds

We must receive the minimum offering amount of $1.0 million to break escrow, and the maximum offering amount may not exceed $1.0 billion. Whether we receive minimum offering amount or maximum offering amount or an amount between the minimum and maximum offering amount from you and the other investors, the offering proceeds will be used to pay the following:

 

    the costs to acquire oil and gas properties;

 

    the costs to develop, operate and manage our oil and gas properties, including drilling additional oil and gas wells on the properties; and

 

    the offering expenses, which include sales commissions, the dealer manager fee, the marketing fee and all other expenses such as legal, accounting, printing, travel and similar amounts related to the offering of the common units.

 

  Please read “Source of Funds and Estimated Use of Proceeds.”

 

Escrow

The dealer manager will deposit and hold all subscription amounts in an interest-bearing escrow account at UMB Bank, or the escrow agent. If subscriptions for the minimum offering amount are not received and accepted by our general partner on or before two years from the effective date of the registration statement of which this prospectus is a part, then the offering will be terminated and the subscription amounts will be promptly returned to subscribers with interest (if any) and without deduction of any fees or expenses. Interest will accrue on funds in the escrow account as applicable to the short-term investments in which such funds are invested. During any period in which subscription proceeds are held in escrow, interest earned thereon will be allocated among subscribers on the basis of the respective amounts of their subscriptions and the number of days that such amounts were on deposit. Such interest will be paid to

 



 

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subscribers upon the termination of the escrow period, subject to withholding for taxes pursuant to applicable Treasury Regulations. We will bear all expenses of the escrow and, as such, any interest to be paid to any subscriber will not be reduced for such expense. All common units purchased by our general partner and its respective affiliates and “Friends” will be applied to satisfying the minimum required subscription proceeds of $1 million. “Friends” mean those individuals who have prior business and/or personal relationships with the executive officers or directors of our general partner, the dealer manager, or their respective affiliates, including, without limitation, any service provider. Please read “—Offering Period and Termination” above.

 

  Upon receipt of subscriptions in the minimum offering amount, the Partnership will hold an initial closing pursuant to which the subscription proceeds will be delivered promptly to the Partnership, the accrued interest will be promptly allocated and paid to the investors and the investors will be admitted as limited partners of the Partnership.

 

  Additional closings will take place on a monthly basis, with the first additional closing taking place on the last day of the next calendar month after the calendar month in which the initial closing occurs. Our general partner may, in its sole discretion, decide to hold additional closings on a quarterly, rather than a monthly, basis.

 

Partnership Term

Unless there is a listing event, the term of the Partnership will expire on June 30, 2025, but may be extended for up to a maximum of two years at the election of our general partner. If a listing event occurs, then the Partnership will have an unlimited term, subject to the occurrence of specified terminating events. We anticipate that a liquidity event will occur within five years. However, our Pre-Listing Partnership Agreement does not require that a liquidity event will occur within a specified timeframe or at all.

 

  Please read “Summary of the Partnership Agreement—The Partnership Agreement—Termination and Dissolution.”

 

Pre-Listing Distributions

The Partnership will distribute quarterly available cash from operating surplus and capital surplus, if any, in each case as defined in the Partnership Agreement, 98.00% to the holders of common units and 2.00% to the holders of GP units, each pro rata.

 

  Please read “Cash Distribution Policy and Restrictions on Distributions,” “Compensation,” and “Summary of the Partnership Agreement,” for a more detailed discussion of distributions to our limited partners, our general partner and with respect to incentive distribution rights after a listing event.

 



 

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Distribution upon a Sale

In the event of a sale, the Partnership will pay available cash from such sale:

 

    First, 100.00% to the holders of the common units until they have received an amount equal to their capital contributions plus $0.175 per Unit for each quarter from the date of purchase through the date of sale, less all amounts previously distributed with respect to such interests.

 

    Second, 100.00% to the holder of the GP units until the unitholder has received, including amounts previously received, an amount equal to 2.04% of the excess of (A) amounts distributed to the holders of the common units from operating surplus and clause first above, over (B) the product of $10.00 multiplied by the number of common units outstanding at the time of the sale.

 

    Third, 100.00% to the holder of the incentive distribution rights, or IDRs, until it has received an amount equal to the sum of (A) the product of 25.00% multiplied by the sum of (x) the amount distributed to the common unit holders pursuant to clause first above plus (y) other amounts previously distributed with respect to the common units less (z) the product of $10.00 multiplied by the number of common units then outstanding, plus (B) the sum of all capital contributions with respect to our general partner interest, less (C) amounts previously distributed with respect to our IDRs (the amount of the distribution upon a sale that is distributed to the holder of the IDRs is referred to as the IDR Sales Distribution).

 

    After that, 80.00% to the holders of the common units and 20.00% to the holder of the Incentive Distribution Rights.

 

  For illustrative examples of the calculation of distributions upon a sale, merger or listing event, see Appendix A to this prospectus.

 

Distribution upon a Merger

Consideration to be received in the event of a merger shall be valued based on the price attributed thereto in the merger agreement and be distributed in accordance with the provisions for distributions in the event of a sale.

 

  For illustrative examples of the calculation of distributions upon a sale, merger or listing event, please read Appendix A to this prospectus.

 

Common Unit conversion to Post-Listing Common Units at a Listing Event

Upon the occurrence of a listing event, our Class A common units will automatically convert into Post-Listing common units. The rights of holders of Post-Listing common units will be governed by our Post-Listing Partnership Agreement. Upon the occurrence of a listing event, any Class T common units which have not already converted into Class A common units will convert into Class A common units

 



 

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and then those Class A common units will automatically convert into Post-Listing common units. Please read “Summary of the Partnership Agreement.”

 

Common Unit Issuance in lieu of IDRs to our General Partner at a Listing Event


Upon the occurrence of a listing event, our general partner, as holder of the IDRs, will receive an aggregate number of common units equal to:

 

    the IDR Sales Distribution (as set forth in the third bullet point under “—Distribution upon a Sale” above) that would arise from a deemed sale of all of the Partnership’s assets, divided by

 

    the volume weighted average price of the common units for the initial five days after listing on the exchange on which they are traded, or the initial VWAP.

 

  For purposes of determining the IDR Sales Distribution with respect to a listing event, the available cash from a deemed sale of the Partnership will be calculated as follows:

 

    the number of common units outstanding immediately prior to listing, multiplied by

 

    1.0204, multiplied by

 

    the initial VWAP.

 

  The listing event distribution is designed to provide our general partner a 20% interest in the Partnership following the listing event, but only after the limited partners have received a return of their initial capital contribution together with a 7% non-compounded annual return.

 

  For illustrative examples of the calculation of distributions upon a sale, merger or listing event, please read Appendix A to this prospectus.

 

Common Unit Issuance in lieu of IDRs to our General Partner after a Listing Event


After a listing event, if the Calculated IDR Amount exceeds the Actual IDR Amount (each as defined below) for any quarter following the listing event, then our general partner, as holder of the IDRs, will receive an aggregate number of common units equal to the excess of the Calculated IDR Amount over the Actual IDR Amount, divided by the volume weighted average price of the common units during the five trading days preceding the end of the quarter.

 

  “Actual IDR Amount” means the amount of distributions made pursuant to the IDRs in the fiscal quarter for which the calculation is being made.

 



 

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  “Calculated IDR Amount” means the amount of distributions the holder of the IDRs would have received in the fiscal quarter for which the calculation is being made from the Partnership’s net cash absent the effect of reserves established by our general partner and other related adjustments.

 

These provisions establish what would have been paid to the holder of the IDRs absent reserves established by our general partner for acquisition and drilling operations, utilizing a 1.1x coverage ratio. Please read “Cash Distribution Policy and Restrictions on Distributions.”

 

Allocation of Income, Expenses, Gains and Losses


Income, expenses, gains and losses of the Partnership generally will be allocated among our limited partners by our general partner in a manner consistent with the distribution of proceeds described above. A capital account will be maintained for each limited partner that will reflect, in accordance with U.S. federal income tax rules, all contributions made by that limited partner, all income, expenses, gains and losses allocated to that limited partner and all distributions made to that limited partner.

 

  This prospectus contains a discussion of the material federal income tax consequences pertinent to investors, including whether the Partnership will be taxed as a partnership or as a corporation. Please read “Material Federal Income Tax Consequences” for more information.

 

Voting Rights of Limited Partners

Meetings may be called by our general partner or limited partners holding 10.00% or more of the outstanding common units. Consent of a majority of the outstanding common units is required to:

 

    amend the Partnership Agreement, except for amendments that do not adversely affect the holders of common units in any material respect;

 

    remove our general partner and elect a new general partner;

 



 

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    approve a sale;

 

    approve a merger; or

 

    cancel any contract with our general partner.

 

  Please read “Summary of the Partnership Agreement” for a more detailed discussion of the voting rights of limited partners prior to and after a listing event.

 

Conflicts of Interest

Our general partner and its affiliates may have conflicts of interest in offering the common units and in managing our business. These conflicts of interest may include, among other things, the facts that:

 

    our general partner has determined the compensation and reimbursement it and its affiliates will receive for the management of our business without arm’s-length negotiations;

 

    we may be in competition with other oil and natural gas partnerships that have been and may be formed by our general partner and its affiliates in the future, including competition for properties to be acquired;

 

    we may compete for management’s time and attention with other entities that our general partner and its affiliates may sponsor and/or manage in the future;

 

    we may acquire a substantial portion of our assets from our general partner and its affiliates;

 

    on behalf of the Partnership, our general partner must monitor and enforce its own compliance with the Partnership Agreement and any activities conducted for the Partnership by officers, directors or employees of ATLS or its affiliates, all of whom are affiliates of our general partner;

 

    our general partner will determine the amount and timing of cash distributions from the Partnership and the amount of cash reserved by the Partnership for future operations;

 

    if our general partner, as tax matters partner, represents the Partnership before the Internal Revenue Service, or IRS, there could be a potential conflict between our general partner’s determination of what is in the best interest of the unitholders as a group and the interests of a particular unitholder, including decisions as to whether to expend Partnership funds to contest a proposed adjustment by the IRS, if any; and

 

    the same legal counsel represents our general partner and the Partnership.

 

  Please read “Conflicts of Interest and Fiduciary Duties” for a more detailed discussion.

 



 

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No Market for Our Common Units

There is no public market for the common units and, unless a liquidity event occurs, it is not anticipated that such a market will develop. Investors in the common units may not be able to sell their common units and should be prepared to hold their common units indefinitely. We anticipate that a liquidity event will occur within five years. However, our Pre-Listing Partnership Agreement does not require that a liquidity event will occur within a specified timeframe or at all. Please read “—Listing of the Common Units” below.

 

Listing of the Post-Listing Common Units

The common units are currently not listed on any exchange or over-the-counter market and we may not be able to effect such listing within the expected five-year time frame or at all. The common units have not been approved for quotation or listing on a national securities exchange. However, our general partner will have the right upon the approval of its board of directors to list the Post-Listing common units (into which our common units will automatically convert upon a listing event) on a national securities exchange following the final closing date of this offering. In order to be approved for listing, the common units and the Partnership will be required to meet the listing standards of a national securities exchange. The common units may not be approved for quotation or listing on a national securities exchange.

Emerging Growth Company Status

We are an “emerging growth company” as defined in the Jumpstart our Business Startups, or JOBS, Act of 2012. For as long as we are an emerging growth company, we may take advantage of specified exemptions from reporting and other regulatory requirements that are otherwise applicable generally to other public companies. These exemptions include:

 

    an exemption from providing an auditor’s attestation report on our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002;

 

    an exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board, or PCAOB, requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;

 

    an exemption from compliance with any other new auditing standards adopted by the PCAOB after April 5, 2012, unless the SEC determines otherwise; and

 

    reduced disclosure of executive compensation.

In addition, Section 107 of the JOBS Act also provides that an emerging growth company can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended, or the Securities Act, for complying with new or revised accounting standards. This permits an emerging growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We have elected to take advantage of the benefits of this extended transition period. That is, when a standard is issued or revised and it has different application dates for public or private companies, the

 



 

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Partnership can adopt the new or revised standard at the time private companies adopt the new or revised standard. Our consolidated financial statements may therefore not be comparable to those of companies that comply with such new or revised accounting standards.

We could remain an “emerging growth company” for up to five years, or until the earliest of (i) the last day of the first fiscal year in which we have total annual gross revenue of $1 billion or more, (ii) December 31 of the fiscal year that we become a “large accelerated filer” as defined in Rule 12b-2 under the Exchange Act (which would occur if the market value of our common units held by non-affiliates exceeds $700 million, measured as of the last business day of our most recently completed second fiscal quarter, and we have been publicly reporting for at least 12 months) or (iii) the date on which we have issued more than $1 billion in non-convertible debt during the preceding three-year period.

 



 

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Summary Historical Financial Data

The following table presents our summary historical financial data as of and for the periods indicated.

The statement of operations and cash flow data for the nine months ended September 30, 2015 and 2014 and the balance sheet data as of September 30, 2015 have been derived from our unaudited quarterly financial statements included elsewhere in this prospectus. The balance sheet data as of September 30, 2014 has been derived from our unaudited quarterly financial statements not included in this prospectus. The statement of operations and cash flow data for the years ended December 31, 2014 and 2013, and the balance sheet data as of December 31, 2014 and 2013 are derived from our audited year-end financial statements included elsewhere in this prospectus. The unaudited financial statements have been prepared on the same basis as the audited financial statements and, in the opinion of our management, include all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the information set forth herein.

The selected historical financial and other operating data presented below should be read in conjunction with our audited financial statements and accompanying notes beginning on page F-2, unaudited financial statements and accompanying notes beginning on page F-24 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 104. Among other things, the historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.

 

     Nine Months Ended
September 30,
    Periods Ended
December 31,
 
     2015     2014     2014     2013  
     (unaudited)              
     (in thousands, except per unit data)  

Statement of operations data:

        

Revenues:

        

Gas and oil production

   $ 8,007      $ 4,563      $ 5,707      $ 302   

Gain on mark-to-market derivatives

     760        —         —         —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     8,767        4,563        5,707        302   
  

 

 

   

 

 

   

 

 

   

 

 

 

Costs and expenses:

        

Gas and oil production

     1,684        1,552        2,070        80   

General and administrative

     529        251        627        211   

General and administrative – affiliate

     9,484        6,819        11,119        3,521   

Depreciation, depletion and amortization

     5,095        1,436        2,156        133   

Asset impairment

     7,291        —         6,880        —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

     24,083        10,058        22,852        3,945   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     (15,316     (5,495     (17,145     (3,643

Interest expense

     (14     —         —         —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Net loss

   $ (15,330   $ (5,495   $ (17,145   $ (3,643
  

 

 

   

 

 

   

 

 

   

 

 

 

Other financial data:

        

Adjusted EBITDA(1)

   $ (3,330   $ (4,059   $ (7,856   $ (3,510

Balance sheet data (at period end):

        

Property, plant and equipment, net

   $ 124,640      $ 14,805      $ 155,469      $ 3,913   

Total assets

     171,522        67,442        190,161        12,961   

Total partners’ capital

     158,281        42,267        67,510        4,563   

Cash flow data:

        

Net cash provided by (used in) operating activities

   $ (23,880   $ 492      $ 511      $ 4,147   

Net cash used in investing activities

     (65,643     (12,209     (67,619     (3,594

Net cash provided by financing activities

     94,343        54,533        91,754        8,206   

Capital expenditures

     20,777        12,147        12,873        3,594   

 



 

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(1)  We define Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion and amortization, plus certain non-cash items. Adjusted EBITDA is not a measure of performance calculated in accordance with GAAP. Although not prescribed under GAAP, we believe the presentation of Adjusted EBITDA is relevant and useful because it helps our investors to understand our operating performance and makes it easier to compare our results with other companies that have different financing and capital structures. Adjusted EBITDA should not be considered in isolation of, or as a substitute for, net earnings as an indicator of operating performance or cash flows from operating activities as a measure of liquidity. Adjusted EBITDA, as we calculate it, may not be comparable to Adjusted EBITDA measures reported by other companies. In addition, Adjusted EBITDA does not represent funds available for discretionary use or the payment of distributions. The following reconciles our net loss to Adjusted EBITDA for the periods indicated:

 

     Nine Months Ended
September 30,
     Years Ended
December 31,
 
     2015      2014      2014      2013  
     (unaudited)                
     (in thousands, except per unit data)  

Net loss

   $ (15,330    $ (5,495    $ (17,145    $ (3,643

Interest expense

     14         —          —          —    

Depreciation, depletion and amortization

     5,095         1,436         2,156         133   

Asset impairment

     7,291         —          6,880         —    
  

 

 

    

 

 

    

 

 

    

 

 

 

EBITDA

     (2,930      (4,059      (8,109      (3,510

Acquisition and related costs

     163         —          253         —    

Gain on mark-to-market derivatives

     (563      —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Adjusted EBITDA

   $ (3,330    $ (4,059    $ (7,856    $ (3,510
  

 

 

    

 

 

    

 

 

    

 

 

 

 



 

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Summary Historical Reserve and Operating Data

The following table presents the actual estimated net proved oil and natural gas reserves attributable to our properties as of September 30, 2015 and our estimated net proved oil and natural gas reserves as of December 31, 2014 and 2013 attributable to our properties on a pro forma basis assuming the Eagle Ford assets assigned to ARP on September 21, 2015 had been assigned as of such dates, and the actual standardized measure amounts associated with the estimated proved reserves attributable to our properties as of September 30, 2015, and our standardized measure amounts associated with the estimated proved reserves as of December 31, 2014 and 2013 attributable to our properties on a pro forma basis assuming the Eagle Ford assets assigned to ARP on September 21, 2015 had been assigned as of such dates. The standardized measure amounts shown in the table are not intended to represent the current market value of estimated oil and natural gas reserves.

 

     Historical
Reserves at
September 30,
     Pro Forma Reserves at  
        December 31,  
     2015      2014      2013  

Reserve data:

        

Estimated net proved reserves:

        

Natural gas reserves (MMcf):

        

Proved developed reserves

     705         1,255         241   

Proved undeveloped reserves

     2,259         3,938         —     
  

 

 

    

 

 

    

 

 

 

Total proved reserves of natural gas

     2,964         5,193         241   

Oil reserves (MBbl):

        

Proved developed reserves

     1,589         612         70   

Proved undeveloped reserves

     5,766         6,739         —     
  

 

 

    

 

 

    

 

 

 

Total proved reserves of oil

     7,355         7,351         70   

NGL reserves (MBbl):

        

Proved developed reserves

     112         205         37   

Proved undeveloped reserves

     373         757         —     
  

 

 

    

 

 

    

 

 

 

Total proved reserves of NGL

     485         962         37   
  

 

 

    

 

 

    

 

 

 

Total proved reserves (MMcfe)

     50,001         55,078         884   
  

 

 

    

 

 

    

 

 

 

Standardized measure of discounted future cash flows (in thousands)

   $ 43,597       $ 159,741       $ 3,110   
  

 

 

    

 

 

    

 

 

 

Reserve natural gas and oil prices:

        

Unadjusted prices:

        

Natural gas (per Mcf)

   $ 2.67       $ 4.35       $ 3.67   

Oil (per Bbl)

   $ 50.47       $ 94.99       $ 96.78   

Natural gas liquids (per Bbl)

   $ 13.46       $ 30.21       $ 30.10   

Average Realized Prices, Before Hedge:

        

Natural gas (per Mcf)

   $ 2.65       $ 4.00       $ 3.63   

Oil (per Bbl)

   $ 47.09       $ 88.61       $ 93.16   

Natural gas liquids (per Bbl)

   $ 12.63       $ 28.80       $ 34.88   

 



 

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RISK FACTORS

Our common units are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. If any of the following risks were actually to occur, our business, financial condition or results of operations or cash flows could be materially adversely affected.

Risks Related to an Investment in the Partnership

We may not have sufficient available cash to pay the full target distribution, or any distribution at all, on our common units and there is no guaranty that we will pay distributions to our unitholders in any quarter.

We may not have sufficient available cash each quarter to pay the full target distribution, or any distribution at all, to our unitholders. Furthermore, our Partnership Agreement does not require us to pay distributions on a quarterly basis or otherwise. The amount of cash we have to distribute each quarter principally depends on the revenue we receive for our natural gas, oil and natural gas liquids. In addition, the actual amount of cash we will have available to distribute each quarter under the cash distribution policy that the board of directors of our general partner has adopted will be reduced by working capital, operating expenses, future capital expenditures and credit needs and potential acquisitions that the board of directors may determine is appropriate. The board of directors of our general partner may change our cash distribution policy at any time without the approval of the unitholders or the conflicts committee of the board of directors of our general partner.

We rely exclusively on our general partner and ATLS to provide us with its facilities and personnel and to conduct operations.

We have no employees and no separate facilities. Consequently, we rely exclusively on our general partner and, because our general partner has no direct employees, ultimately upon ATLS, to provide its facilities and personnel and to conduct operations. Our general partner and, through it, ATLS, have significant discretion as to the implementation of our operating policies and investment strategies. Moreover, we believe that our success depends to a significant extent upon the experience of ATLS’s management team. The departure of any of the members of this management team could harm our investment performance.

We may not have results similar to the results obtained by our general partner’s affiliates in their prior activities, and may incur losses.

Our general partner’s affiliates have sponsored numerous drilling and production programs and have actively developed and grown several MLPs (please read “Business and Properties—Our Principal Business Relationships”). Because our activities will be in different geographic areas and geologic formations than many of the prior programs, and because of the different nature of the prior MLPs developed by our general partner’s affiliates, there can be no assurance that our results will be similar to those of the prior programs and MLPs, or that we, as a result of the risks discussed in this “Risk Factors” section, or other factors discussed elsewhere herein, will not incur losses. Our affiliates’ performance of their drilling obligations to us and our financial results may not be as successful as the drilling and financial results of ARP or ATLS’s other sponsored drilling and production programs and MLPs.

As disclosed in this prospectus, ATLS previously sponsored the formation of ARP and other sponsored drilling and production programs and MLPs, and ARP has previously sold limited partnership interests in a separate transaction to investors. The historical results of operations and performance of ARP, ATLS’s other sponsored drilling and production programs and MLPs should not be relied on as an indicator of how we will perform. Please read “Atlas’ Prior Experience With Drilling Programs and Master Limited Partnerships” for additional information.

 

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There is no guarantee of return of investment or rate of return on investment because of the speculative nature of drilling natural gas and oil wells.

Natural gas and oil exploration is an inherently speculative activity. Before the drilling of a well, our general partner cannot predict with absolute certainty:

 

    the volume of natural gas and oil recoverable from the well; or

 

    the time it will take to recover the natural gas and oil.

You may not recover any or all of your investment in us or, if you do recover your investment in us, you may not receive a rate of return on your investment that is competitive with other types of investments that may be available to you. Except in the case of a liquidity event, you will be able to recover your investment only through distributions of our net proceeds from the sale of our natural gas and oil from productive wells. We anticipate that a liquidity event will occur within five years. However, our Pre-Listing Partnership Agreement does not require that a liquidity event will occur within a specified timeframe or at all.

The assumptions underlying the forecast of cash distributions that we include in the section entitled “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause our actual cash distributions to differ materially from our forecast, and we did not use quarter-by-quarter estimates in concluding that there would be sufficient cash available for distribution to pay the target distribution on all of our common units and GP units during the forecast period.

The forecast of cash available for distribution set forth in the section entitled “Cash Distribution Policy and Restrictions on Distributions” includes our forecast of our results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending December 31, 2016. Our ability to pay the full target distribution in the forecast period is based on a number of assumptions that may not prove to be correct and that are discussed in the section entitled “Cash Distribution Policy—Estimated Cash Available for Distribution—Assumptions and Considerations.” Our financial forecast has been prepared by management and we have neither received nor requested an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties, including those discussed in this information statement, which could cause there to be material differences between our forecast and our actual results. In addition, we did not use quarter-by-quarter estimates in concluding that there would be sufficient cash available for distribution to pay the initial quarterly distribution on all of our common units during the forecast period. If the forecasted results are not achieved, we may not be able to make cash distributions on our common units at the quarterly distribution rate, and the market price of our common units may decline materially.

Our quarterly distributions may not be sourced from our cash generated from operations but from offering proceeds, and borrowings, among other sources, and this will decrease our cash available for distributions in the future.

Our general partner intends to cause the Partnership to make the distribution to the holders of common units commencing with the initial closing of the offering of common units. There is no limitation on the amount of our distributions that can be funded from offering proceeds or financing proceeds. Our target distribution may be sourced from offering proceeds and borrowings, among other sources, rather than cash from operations. The payment of distributions from sources other than operating cash flow may decrease the cash available to invest in oil and gas properties, which may decrease our cash available for distributions in the future. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Distributions from us may be a return of capital rather than a return on your investment.

The amount of cash that we have available for distribution will depend on our cash flow, including cash reserves, working capital and borrowings, if any, and not solely on profitability, which will be affected by non-

 

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cash items. As a result, we may make cash distributions during periods when we record losses, and we may not make cash distributions during periods when we record net income.

If a listing event occurs, our Partnership Agreement will automatically be amended and restated, becoming the Post-Listing Partnership Agreement, which will alter some of your rights as a limited partner.

If we undertake a listing event, our Partnership Agreement will automatically be amended and restated to become the Post-Listing Partnership Agreement and the common units will automatically convert into the Post-Listing common units. Some of your rights as a limited partner will be altered as a result of that amendment and restatement, particularly voting rights. For a summary of the material differences between our Partnership Agreement and the Post-Listing Partnership Agreement (and thus the common units and Post-Listing common units), please read “Summary of the Partnership Agreement.” Forms of our Pre-Listing Partnership Agreement and the Post-Listing Partnership Agreement are attached as Exhibit A and Exhibit B, respectively, to this prospectus. We anticipate that a liquidity event will occur within five years. However, our Pre-Listing Partnership Agreement does not require that a liquidity event will occur within a specified timeframe or at all.

We have limited operating history. We may not be able to operate our business successfully or generate sufficient cash flow to maintain distributions at our current level or make distributions at all to our limited partners.

We are a Delaware limited partnership formed in 2013 and are subject to all of the business risks and uncertainties associated with any new business, including the risk that we will not be able to achieve our investment objectives and that the value of an investment in us could decline substantially. Our ability to achieve returns for our limited partners depends on our ability both to continue to generate sufficient cash flow to pay distributions and to expand our operations, and we cannot assure you that we will be able to do either.

Increases in the costs of the wells or cost overruns may adversely affect your return.

Our general partner anticipates that it may use a portion of the net proceeds from this offering, if available, or seek debt financing to pay for any cost overrun in drilling or completing a well or wells. Using offering proceeds to pay for cost overruns may result in us drilling fewer wells or, if debt financing is used, incurring on-going debt service expenses. As a result of either situation, the amount of our cash available for distributions may be less than the amount that otherwise would have been available.

Compensation and fees to our general partner will reduce cash distributions.

Our general partner has received its general partner interest and its IDRs for only nominal consideration. In addition, our general partner will receive an annual management fee equal to 1.00% of total capital contributions to the Partnership (other than those of our general partner and its affiliates), payable quarterly, as well as reimbursement of direct costs regardless of the success of our wells. The amount of reimbursements paid to our general partner are subject to only narrow limits in certain circumstances: (1) the reimbursements of organization and offering costs to our general partner are limited to 2% of the aggregate proceeds of the primary offering if less than $500 million is raised or 1.5% if $500 million or more is raised, in each case excluding the DRIP; and (2) the reimbursements of administrative costs to our general partner are limited to those supportable as to the necessity of such reimbursement and the reasonableness of the amount charged and supported by appropriate invoices or other documentation and other considerations. Otherwise, our Partnership Agreement and the other agreements we have with our general partner do not place meaningful limits on the magnitude of potential reimbursements; specifically, our general partner will determine which costs incurred are reimbursable and there are no limits on the amount of reimbursements on administrative costs to be paid to our general partner. These fees and reimbursements will reduce the amount of cash otherwise available for distribution to our limited partners.

 

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The intended quarterly distributions may be reduced or delayed.

Cash distributions may not be paid each quarter. Distributions may be reduced or deferred, in the discretion of our general partner, due to local, state and federal regulations regarding permitting, fracturing, production, conservation, water disposal and treatment and pipeline construction and transportation of natural gas and oil, or to the extent the Partnership’s revenues are used for any of the following:

 

    repayment of borrowings, if any;

 

    any cost overruns in drilling and completing wells;

 

    remedial work to improve a well’s producing capability, including multiple hydraulic fracturing operations in each horizontal well;

 

    direct costs and general and administrative expenses of the Partnership;

 

    reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells; or

 

    indemnification of our general partner and its affiliates by the Partnership for losses or liabilities incurred in connection with our activities.

In the event we are able to raise a substantial amount of capital, we may have difficulty investing it in properties.

If we are able to raise a substantial amount of capital in the offering, we may have difficulty identifying and purchasing suitable properties on attractive terms, and there could be a delay between the time we receive net proceeds from the sale of common units in this offering and the time we invest the net proceeds. This delay could impact the return on your investment. If we fail to timely invest the net proceeds of this offering or to invest in quality assets, our ability to achieve our investment objectives, could be materially adversely affected. Specifically, our ability to pay the target distribution on all of our outstanding common units following this offering is subject to our ability to make sufficient acquisitions on attractive terms. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Changes in laws or regulations that require an amendment to our Partnership Agreement could limit the rights of our limited partners.

Our general partner may, without the consent of our limited partners, amend our Partnership Agreement to reflect any changes as a result of a change in law or regulation that causes any term or condition set forth in this prospectus or our Partnership Agreement to be no longer viable, as determined by our general partner in its sole discretion. Our general partner expects that any such changes will be made as narrowly as possible in order to effectuate the original intent of this prospectus and our Partnership Agreement. Nevertheless, any such change could limit the rights and obligations of the Partnership or our limited partners.

Our Post-Listing Partnership Agreement will designate the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers or other employees.

Our partnership agreement will provide that, with certain limited exceptions, the Court of Chancery of the State of Delaware will be the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners, (4) asserting a claim arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) or (5) asserting a claim against us governed by the internal affairs doctrine. By purchasing a

 

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common unit, a limited partner is irrevocably consenting to these limitations and provisions and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us and our general partner’s directors and officers.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its board of directors.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders do not elect our general partner or the members of its board of directors on an annual or other continuing basis. The board of directors of our general partner is elected by its unitholders. Furthermore, the vote of the holders of at least a majority of all outstanding common units is required to remove our general partner.

We may issue an unlimited number of common units and other equity securities, including interests that are senior to the common units offered hereby, without approval of our limited partners, which would dilute your ownership interests in the Partnership.

Our Partnership Agreement does not limit the number of common units or other equity securities that we may issue at any time without the approval of our limited partners, including those issued pursuant to our DRIP. In addition, we may issue an unlimited amount of interests that are senior to your interests in right of distribution, liquidation and voting. The issuance by us of equity interests of equal or senior rank will have the following effects:

 

    your proportionate ownership interest in the Partnership will decrease;

 

    your voting rights may be subject to voting rights of the newly issued interests;

 

    the amount of cash available for distribution on your interests may decrease; and

 

    the ratio of taxable income to distributions may increase.

In addition, the payment of distributions on any additional interests may increase the risk that we will not be able to make distributions at prior levels. To the extent new interests are senior to the interests offered hereby, their issuance will increase the uncertainty of the payment of distributions.

The common units are not liquid and your ability to resell your common units will be limited by the absence of a public trading market and substantial transfer restrictions.

If you invest in us, then you must assume the risks of an illiquid investment. The common units generally will not be liquid because there is not a readily available market for the sale of common units, and one is not expected to develop. Furthermore, although our Partnership Agreement contains provisions designed to permit the listing of the common units on a national securities exchange, the common units are currently not listed on any exchange or over-the-counter market and we may not be able to effect such listing within the expected five-year time frame or at all. Please read “Transferability of Interests.” Your inability to sell or transfer your common units increases the risk that you could lose some or all of your investment because, if we are unable to meet our performance goals, you may not have the ability to transfer your common units prior to our winding up and liquidation.

Unitholders will incur immediate and substantial dilution in net tangible book value per common unit.

The assumed offering price of $10.00 per common unit exceeds our pro forma net tangible book value of $8.54 per common unit. Based on the assumed offering price of $10.00 per common unit, unitholders will incur immediate and substantial dilution of $1.46 per common unit. Please read “Dilution.”

 

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We may be unable to sell our properties or list the common units on a national securities exchange within our planned timeline or at all.

We expect to either sell our properties and distribute the proceeds of the sale, after payment of liabilities and expenses, to our partners, with the approval of our general partner, or list the common units on a national securities exchange by June 30, 2020. The decision to sell our properties will be based on a number of factors, including the domestic and foreign supply of and demand for oil, natural gas and other hydrocarbons, commodity prices, demand for oil and natural gas assets in general, the value of our assets, the projected amount of our oil and gas reserves, general economic conditions and other factors that are out of our control. In addition, the ability to list our common units on a national securities exchange will depend on a number of factors, including the state of the U.S. securities markets, our ability to meet the listing requirements of national securities exchanges, securities laws and regulations and other factors. If we are unable to either sell our properties or list the common units on a national securities exchange in accordance with our current plans, you may be unable to sell or otherwise transfer your common units and you may lose some or all of your investment. Our Pre-Listing Partnership Agreement does not require that a liquidity event occur within a specified timeframe or at all.

Investors will be required to make certain ERISA representations.

Generally, a “benefit plan investor” (as defined under ERISA), may acquire the common units and warrants, subject to certain restrictions and considerations. Please read “Material Federal Income Tax Consequences.” An investment in us by a benefit plan investor may raise certain material issues under ERISA or the Code or under the provisions of other state, federal, foreign or other local laws and regulations that are similar to the applicable provisions of the Code or ERISA, collectively, similar laws. The discussion that follows is general in nature and is not all-inclusive. The information discussed herein is neither intended, nor should it be construed, to constitute legal advice. In considering whether to purchase the common units, a benefit plan investor, and any fiduciary purchasing on behalf of a benefit plan investor or any other plan, should consult with their legal counsel regarding the potential consequences of doing so under ERISA, the Code and applicable similar laws.

Under Section 3(42) of ERISA and the regulations issued thereunder, (i) any employee benefit plan (within the meaning of Section 3(3) of ERISA), (ii) any plan described in Section 4975 of the Code and (iii) any entity whose underlying assets include plan assets by reason of a plan’s investment in the entity qualifies as a benefit plan investor, collectively, the benefit plan investors. We intend to use reasonable efforts to provide that investments in us by such benefit plan investors will not qualify as “significant” for purposes of the plan asset rules and regulations issued by the Department of Labor, as amended by ERISA, or plan asset regulations, and for purposes of avoiding the application of Section 406 of ERISA or Section 4975 of the Code, together with plan asset regulations, the prohibited transaction rules, by limiting equity participation in us by benefit plan investors, in the aggregate, to less than 25.00% of the value of each class of units in us, or the 25.00% threshold test.

If the 25.00% threshold test is satisfied, then our underlying assets do not qualify as “plan assets” under the plan asset regulations and therefore, the equity interests held by the benefit plan investors are exempt from the prohibited transaction rules, as well as the duties and obligations usually imposed on fiduciaries of ERISA-covered plans. Meanwhile, any failure to satisfy the 25.00% threshold test will expose us to, and may result in the imposition of, certain penalties and excise taxes upon us (and upon the benefit plan investors), under ERISA, the Code or other similar laws that prohibit certain transactions involving the assets held by and the fiduciaries with respect to any ERISA-covered plan.

Because of the forgoing, each eligible purchaser or subsequent transferee of a common unit may be required to make certain ERISA-related representations, warranties and covenants in a purchaser questionnaire or transfer application, as applicable, in order for our general partner to confirm that:

 

  (a) the eligible purchaser is neither a benefit plan investor nor is acting on behalf of a benefit plan investor; or that

 

  (b)

the purchaser is an eligible purchaser that is or is acting on behalf of a benefit plan investor (or is a direct or indirect subsequent transferee thereof) and is (i) a successor to, or a related trust or partnership

 

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  of, such benefit plan investor, (ii) has so advised our general partner in writing in the related purchaser questionnaire or transfer application, as applicable, and (iii) its acquisition of the common units and warrants, as applicable, does not constitute or result in a violation of the prohibited transaction rules. Note that ERISA exempts governmental, foreign and church plans and any other plans that are not subject to Title I of ERISA or Section 4975 of the Code from the definition of benefit plan investors.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Cash Distribution Policy and Restrictions on Distributions.”

The ability to spread the risks of property acquisitions among a number of properties will be reduced if less than the maximum offering proceeds are received and fewer acquisitions are consummated.

We must receive minimum offering proceeds of $1.0 million to break escrow, and our offering proceeds may not exceed $1.0 billion. There are no other requirements regarding the amount of offering proceeds to be received by us. Generally, the less offering proceeds received, the fewer properties we would acquire with the proceeds of this offering, which would decrease our ability to spread the risks of acquisition and development of our properties.

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, financial condition and cash available for distribution.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European debt crisis, the Chinese economy, the United States mortgage market and a weak real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates further, worldwide demand for petroleum products could diminish, which could impact the price at which oil, natural gas and natural gas liquids produced from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately adversely impact our results of operations, financial condition and cash available for distribution.

We are an “emerging growth company” under the federal securities laws and will be subject to reduced public company reporting requirements.

In April 2012, President Obama signed into law the JOBS Act. We are an “emerging growth company,” as defined in the JOBS Act, and are eligible to take advantage of certain exemptions from, or reduced disclosure obligations relating to, various reporting requirements that are normally applicable to public companies.

We could remain an “emerging growth company” for up to five years, or until the earliest of (i) the last day of the first fiscal year in which we have total annual gross revenue of $1 billion or more, (ii) December 31 of the fiscal year that we become a “large accelerated filer” as defined in Rule 12b-2 under the Exchange Act (which would occur if the market value of our common units held by non-affiliates exceeds $700 million, measured as of the last business day of our most recently completed second fiscal quarter, and we have been publicly reporting for at least 12 months) or (iii) the date on which we have issued more than $1 billion in non-convertible debt during the preceding three-year period. Under the JOBS Act, emerging growth companies are not required to (a) provide an auditor’s attestation report on management’s assessment of the effectiveness of internal control over financial reporting, pursuant to Section 404 of the Sarbanes-Oxley Act, (b) comply with new audit rules adopted by the PCAOB, (c) provide certain disclosures relating to executive compensation generally required for larger public companies or (d) hold shareholder advisory votes on executive compensation.

 

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Additionally, the JOBS Act provides that an “emerging growth company” may take advantage of an extended transition period for complying with new or revised accounting standards that have different effective dates for public and private companies. This means an “emerging growth company” can delay adopting certain accounting standards until such standards are otherwise applicable to private companies. We have elected to take advantage of the benefits of this extended transition period. That is, when a standard is issued or revised and it has different application dates for public or private companies, the Partnership can adopt the new or revised standard at the time private companies adopt the new or revised standard. Our consolidated financial statements may therefore not be comparable to those of companies that comply with such new or revised accounting standards.

Risks Related to Conflicts of Interest

Because other oil and gas programs offered through our dealer manager may conduct offerings concurrently with our offering, our dealer manager may face potential conflicts of interest arising from competition among us and these other programs for investors and investment capital, and such conflicts may not be resolved in our favor.

Anthem Securities, Inc., a subsidiary of ARP that is under common ownership with us, is the dealer manager of several non-traded drilling partnerships that are raising capital in continuous offerings of equity. In addition, ATLS or its affiliates may decide to sponsor future oil and gas investment programs that would seek to raise capital through public or private offerings conducted concurrently with this offering. As a result, ATLS and its affiliates and our dealer manager may face conflicts of interest arising from potential competition with these other programs for investors and investment capital. ATLS generally seeks to avoid simultaneous offerings by programs that have a substantially similar mix of investment attributes, including targeted investment types. Nevertheless, there may be periods during which one or more programs sponsored by ATLS and its affiliates will be raising capital and might compete with us for investment capital. Such conflicts may not be resolved in our favor, and you will not have the opportunity to evaluate the manner in which these conflicts of interest are resolved before or after making your investment.

Our Partnership Agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our Partnership Agreement contains provisions that reduce the fiduciary standards to which our general partner is held. For example, our Partnership Agreement permits our general partner to:

 

    have business interests or activities that may conflict with the Partnership;

 

    devote only so much of its time as is necessary to manage the affairs of the Partnership, as determined by our general partner in its sole discretion;

 

    conduct business with the Partnership in a capacity other than as general partner or sponsor as described in our Partnership Agreement;

 

    with respect to farmouts to our general partner and its affiliates or unaffiliated third parties, our general partner will be subject to the lesser standard of prudent operator;

 

    manage multiple programs simultaneously; and

 

    be indemnified and held harmless as described under “Conflicts of Interest and Fiduciary Duties—Partnership Agreement.”

By purchasing a Unit, you and the other unitholders agree to be bound by the provisions of the Partnership Agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties.”

 

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ATLS, our general partner and the oil and gas and other professionals assembled by our general partner, face competing demands relating to their time, and this may cause our operations and our unitholders’ investments to suffer.

We rely on our general partner for the day-to-day operation of our business and the selection of our oil and gas properties. Certain of the directors and officers of ATLS and our general partner are key executives in other programs sponsored by ATLS and its affiliates. As a result of their interests in other programs sponsored by our sponsor, their obligations to other investors and the fact that they engage in and they will continue to engage in other business activities, these individuals will continue to face conflicts of interest in allocating their time

among us and other programs sponsored by ATLS and its affiliates and other business activities in which they are involved. As a result, the returns on our investments, and the value of our unitholders’ investments, may decline.

The fiduciary duties of our general partner’s officers and directors may conflict with those they may have to affiliates of our general partner.

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including ATLS and its affiliates), on the one hand, and the Partnership and our limited partners, on the other hand. Conflicts may arise as a result of the duties of our general partner to act for the benefit of its owners, which may conflict with our interests and the interests of its unitholders. The directors and officers of ATLS have duties to manage ATLS and our general partner in a manner beneficial to its owners. In addition, many of the officers and directors of our general partner serve in similar capacities with ATLS and its affiliates, which may lead to additional conflicts of interest. At the same time, our general partner has fiduciary duties to us and our limited partners under our Partnership Agreement, the Post-Listing Partnership Agreement and applicable law.

Conflicts of interest between our general partner and our limited partners may not necessarily be resolved in favor of our limited partners.

There are potential conflicts of interest between our limited partners and our general partner and its affiliates. These conflicts of interest include the following:

 

    our general partner has determined the compensation and reimbursement that it and its affiliates will receive in connection with us without arm’s-length negotiations;

 

    we may be in competition with other oil and natural gas partnerships that have been and may be formed by our general partner and its affiliates in the future, including competition for properties to be acquired;

 

    we may compete for management’s time and attention with other entities that our general partner and its affiliates may sponsor and/or manage in the future;

 

    we may acquire projects from our general partner and its affiliates, and it is possible that those projects could constitute a substantial portion of our total projects;

 

    on behalf of the Partnership, our general partner must monitor and enforce its own compliance with our Partnership Agreement and any activities conducted for us by officers, directors or employees of ATLS or its affiliates, all of whom are affiliates of our general partner;

 

    our general partner will determine the amount and timing of cash distributions from us and the amount of cash reserved by us for future operations;

 

    if our general partner, as tax matters partner, represents us before the IRS there could be a potential conflict between our general partner’s determination of what is in the best interest of our limited partners as a group and the interests of a particular limited partner, including decisions as to whether to expend Partnership funds to contest a proposed adjustment by the IRS, if any; and

 

    the same legal counsel represents our general partner and the Partnership.

These conflicts of interest may not be resolved in a way satisfactory to some or all of our limited partners.

 

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We may choose not to retain separate counsel or other service providers for ourselves or for the holders of common units.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee of the board of directors of our general partner and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the conflict committee in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict, although we may choose not to do so.

The Partnership and other partnerships sponsored by affiliates of ATLS may compete with each other for prospects, equipment, subcontractors and personnel.

We and other partnerships sponsored by affiliates of ATLS may have unexpended capital funds at the same time. Thus, these partnerships or joint ventures may compete for suitable prospects, equipment, subcontractors and the services of ATLS’s personnel. This may make it more difficult for us to pursue our acquisition and drilling activities and lessen the ability of us to make distributions.

Lack of an independent underwriter may reduce due diligence investigation of the Partnership and our general partner.

Our dealer manager, which is affiliated with our general partner, serves as the dealer manager of this offering. However, our dealer manager’s due diligence examination concerning us cannot be considered to be independent, and it may not be as comprehensive as an investigation that would have been conducted by an independent underwriter or broker dealer.

Risks Related to the Partnership’s Oil and Gas Operations

Natural gas and oil prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and oil, which have declined substantially. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results and could result in an impairment charge.

Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include but are not limited to the following:

 

    the levels and location of natural gas and oil supply and demand and expectations regarding supply and demand, including the potential long-term impact of an abundance of natural gas and oil on the domestic and global natural gas and oil supply;

 

    the level of industrial and consumer product demand;

 

    weather conditions;

 

    fluctuating seasonal demand;

 

    political conditions or hostilities in natural gas and oil producing regions, including the Middle East, Africa and South America;

 

    the ability of the members of the Organization of Petroleum Exporting Countries and other exporting nations to agree to and maintain oil price and production controls;

 

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    the price level of foreign imports;

 

    actions of governmental authorities;

 

    the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or localized areas that may affect the realized price for natural gas and oil;

 

    inventory storage levels;

 

    the nature and extent of domestic and foreign governmental regulations and taxation, including environmental and climate change regulation;

 

    the price, availability and acceptance of alternative fuels;

 

    technological advances affecting energy consumption;

 

    speculation by investors in oil and natural gas;

 

    variations between product prices at sales points and applicable index prices; and

 

    overall economic conditions, including the value of the U.S. dollar relative to other major currencies.

Any prolonged substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders. We may use various derivative instruments in connection with anticipated oil and natural gas sales to minimize the impact of commodity price fluctuations. However, we may not always be able to hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be diminished.

In addition, lower oil and natural gas prices may also reduce the amount of oil and natural gas that can be produced economically by our operators. This scenario may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate, the successful efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, such operators may abandon any well if they reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities.

Oil prices and natural gas prices have declined substantially from historical highs and may remain depressed for the foreseeable future. Approximately 66% of our 2014 total revenues and 91% of our total revenues in the first nine months of 2015 were derived from oil and condensate sales. Approximately 36% of our 2014 total production and 13% of our total production in the first nine months in 2015 was natural gas. Any additional decreases in prices of oil and natural gas may adversely affect our cash generated from operations, results of operations, financial position, and our ability to pay the minimum quarterly distribution on all of our outstanding common units, perhaps materially.

The spot WTI market price at Cushing, Oklahoma has declined from a high of $61.43 per Bbl to a low of $38.24 per Bbl between January 1, 2015 and November 30, 2015. On November 30, 2015, the WTI oil price at Cushing, Oklahoma was $41.65 per Bbl. The reduction in price has been caused by many factors, including substantial increases in U.S. oil production and reserves from unconventional (shale) reservoirs, without an offsetting increase in demand. The International Energy Agency (“IEA”) forecasts continued U.S. production growth and a slowdown in global demand growth in 2016.

This environment could cause the prices for oil to remain at current levels or to fall to even lower levels. If prices for oil continue to remain depressed for lengthy periods, we may be required to write down the value of

 

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our oil and natural gas properties, and some of our undeveloped locations may no longer be economically viable. In addition, sustained low prices for oil will negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow under our bank credit facility and reduce the amounts of cash we would otherwise have available to pay expenses, fund capital expenditures, make distributions to our unitholders, and service our indebtedness.

During the seven years prior to December 31, 2014, natural gas prices at Henry Hub have ranged from a high of $13.31 per MMBtu in 2008 to a low of $1.82 per MMBtu in 2012. Between January 1, 2015 and November 30, 2015, the Henry Hub spot market price of natural gas ranged from a high of $3.23 per MMBtu to a low of $1.92 per MMBtu. On November 30, 2015, the Henry Hub spot market price was $2.11 per MMBtu. The reduction in prices has been caused by many factors, including increases in natural gas production and reserves from unconventional (shale) reservoirs, without an offsetting increase in demand. The expected increase in natural gas production, based on reports from the IEA, could cause the prices for natural gas to remain at current levels or fall to lower levels. If prices for natural gas continue to remain depressed for lengthy periods, we may be required to write down the value of our oil and natural gas properties, and some of our undeveloped locations may no longer be economically viable. In addition, sustained low prices for natural gas will negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow under our bank credit facility and reduce the amounts of cash we would otherwise have available to pay expenses, make distributions to our unitholders, and service our indebtedness.

Competition in the natural gas and oil industry is intense, which may hinder our ability to acquire natural gas and oil properties and to obtain capital, contract for drilling equipment and secure trained personnel.

We operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital, contracting for drilling equipment and securing trained personnel. Our competitors may be able to pay more for natural gas, natural gas liquids and oil properties and drilling equipment and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Moreover, our competitors for investment capital may have better track records in their programs, lower costs or stronger relationships with participants in the oil and gas investment community than we do. Any of these factors could make it more difficult for us to execute our business strategy. We may not be able to compete successfully in the future in acquiring leasehold acreage or prospective revenues or in raising additional capital.

Furthermore, competition arises not only from numerous domestic and foreign sources of natural gas and oil but also from other industries that supply alternative sources of energy, such as wind or solar power. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. Product availability and price are the principal means of competition in selling natural gas and oil. Many oil and gas companies possess greater financial and other resources than we do, which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than we can.

Shortages of drilling rigs, equipment and crews, or the costs required to obtain the foregoing in a highly competitive environment, could impair our operations and results.

Increased demand for drilling rigs, equipment and crews, due to increased activity by participants in our primary operating areas or otherwise, can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict our ability to drill wells and conduct our operations. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues.

 

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Previous drilling by others may reduce our ability to find economically recoverable quantities of natural gas or oil.

Our primary drilling areas are located in areas where other oil and gas companies have previously drilled wells. As a result, many of the areas to be drilled by us are in locations that have already been partially depleted or drained by earlier drilling. This may reduce our ability to find economically recoverable quantities of natural gas and oil in those areas.

Significant physical effects of climate change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

Climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities either because of climate-related damages to our facilities or our costs of operation potentially rising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

We depend on certain key customers for sales of our natural gas, crude oil and NGLs. To the extent these customers reduce the volumes of natural gas, crude oil and NGLs they purchase or process from us, or cease to purchase or process natural gas, crude oil and NGLs from us, our revenues and cash available for distribution could decline.

We sell natural gas, crude oil and NGLs under contracts to purchasers in the normal course of business. For the period ending September 30, 2015, the north Texas Marble Falls production had two markets for its natural gas and natural gas liquids, ETC Marketing. Ltd. and Enbridge G&P (N. TX) LP. Crude oil was purchased by Enterprise Crude Oil, LLC. In south Texas, the Eagle Ford natural gas and natural gas liquids were marketed to Regency Field Services, LLC. The crude oil was purchased by Enterprise Crude Oil, LLC and Shell Trading Company (US). If one or more of our customers ceased purchasing our natural gas, crude oil and NGLs altogether, the loss of such customer could have a detrimental effect on our production volumes in general and on our ability to find substitute customers to purchase our production volumes, which could in turn reduce our revenue and cash available for distribution.

An increase in the differential between the NYMEX or other benchmark prices of natural gas and oil and the wellhead price that we receive for our production could significantly reduce our cash available for distribution and limit our ability to maintain or expand our operations.

The prices that we receive for our natural gas and oil production sometimes reflect a discount to relevant benchmark prices, such as those on the New York Mercantile Exchange, or NYMEX. The difference between the benchmark price and the price that we receive is called a differential. Increases in the differential between the benchmark prices for natural gas and oil and the wellhead price that we receive could significantly reduce our cash available for distribution and limit our ability to maintain or expand our operations.

Drilling for and producing natural gas and oil are high-risk activities with many uncertainties.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas and oil can be uneconomic, not only because dry holes may be

 

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drilled, but also because productive wells may not produce sufficient revenues to be commercially viable. This risk is exacerbated by the current decline in oil and gas prices. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

 

    higher costs, shortages or delivery delays of equipment and services;

 

    unexpected operational events and drilling conditions;

 

    adverse weather conditions;

 

    facility or equipment malfunctions;

 

    title problems;

 

    pipeline ruptures or spills;

 

    compliance with environmental and other governmental requirements;

 

    unusual or unexpected geological formations;

 

    formations with abnormal pressure;

 

    injury or loss of life and property damage to a well or third-party property;

 

    leaks or discharges of toxic gases, brine, natural gas, oil, hydraulic fracturing fluid and wastewater from a well;

 

    environmental accidents, including groundwater contamination;

 

    fires, blowouts, craterings and explosions; and

 

    uncontrollable flows of natural gas or oil well fluids.

Any one or more of these factors could reduce or delay our receipt of drilling and production revenues and increase our costs, thereby reducing our ability to make distributions to our limited partners. In addition, any of these events can cause substantial losses, which may not fully be covered by insurance, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties, which could reduce our cash flow and our ability to make distributions to our limited partners.

Although we maintain insurance against various losses and liabilities arising from our operations, insurance against all operational risks are not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could reduce our results of operations.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would reduce our cash flows from operations and income.

Producing natural gas and oil reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our natural gas and oil reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our reserves and economically finding or acquiring additional recoverable reserves. Our ability to find and acquire additional recoverable reserves to replace current and future production at acceptable costs depends on our generating sufficient cash flow from operations and other sources of capital, including this offering, all of which are subject to the risks discussed elsewhere in this section.

 

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The recent decrease in natural gas and oil prices, or any further decrease in commodity prices, could subject our oil and gas properties to impairment losses under U.S. generally accepted accounting principles.

U.S. generally accepted accounting principles require oil and gas properties and other long-lived assets to be reviewed for impairment whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. We and our general partner will test our oil and gas properties on a field-by-field basis, by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and estimated abandonment costs is less than the estimated expected undiscounted future cash flows. Expected future cash flows are estimated based on our or our general partner’s own economic interests and our plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. We and our general partner estimate prices based on current contracts in place at the impairment testing date, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. Natural gas and oil prices remain volatile and have recently declined substantially and could continue to decrease in the future. Prolonged depressed prices of natural gas or oil may cause the carrying value of our or our general partner’s oil and gas properties to exceed the expected future cash flows, and require that an impairment loss be recognized. During the year ended December 31, 2014, we recognized $6.9 million of asset impairments related to oil and natural gas properties within property, plant and equipment net on our combined consolidated balance sheet, primarily related to our natural gas wells in the Marble Falls play.

Estimates of reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Underground accumulations of natural gas and oil cannot be measured in an exact way. Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Our estimates of our proved reserves are prepared by our internal engineers. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our reserve estimates were made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we will make certain assumptions regarding future natural gas prices, production levels and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect estimates of reserves, the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Our standardized measure is calculated using natural gas prices that do not include financial hedges. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas and oil we ultimately recover being different from the reserve estimates.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of the estimated natural gas and oil reserves. We base the estimated discounted future net cash flows from proved reserves on historical prices and costs, but actual future net cash flows from our natural gas and oil properties will also be affected by factors such as:

 

    actual prices received for natural gas and oil;

 

    the amount and timing of actual production;

 

    the amount and timing of capital expenditures;

 

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    supply of and demand for natural gas and oil; and

 

    change in governmental regulations or taxation.

The timing of both the production and incurrence of expenses in connection with the development and production of natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10.00% discount factor that we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the company or the natural gas and oil industry in general.

Any significant variance in our assumptions could materially affect the quantity and value of reserves, the amount of standardized measure, and the financial condition and results of operations. In addition, our reserves or standardized measure may be revised downward or upward based upon production history, results of future exploitation and development activities, prevailing natural gas and oil prices and other factors. A material decline in prices paid for our production can reduce the estimated volumes of reserves because the economic life of the wells could end sooner. Similarly, a decline in market prices for natural gas or oil may reduce our standardized measure.

Hedging transactions may limit our potential gains or cause us to lose money.

Pricing for natural gas, NGLs and oil has been volatile and unpredictable for many years. To limit exposure to changing natural gas and oil prices, we may use financial hedges and physical hedges for our production. Physical hedges are not deeded hedges for accounting purposes because they require firm delivery of natural gas and oil and are considered normal sales of natural gas and oil.

In addition, we may enter into financial hedges, which may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties in compliance with the Dodd-Frank Wall Street Reform and Consumer Protection Act. The futures contracts are commitments to purchase or sell natural gas and oil at future dates and generally cover one-month periods for up to six years in the future. The over-the-counter derivative contracts are typically cash settled by determining the difference in financial value between the contract price and settlement price and do not require physical delivery of hydrocarbons.

These hedging arrangements may reduce, but will not eliminate, the potential effects of changing commodity prices on our cash flow from operations for the periods covered by these arrangements. Furthermore, while intended to help reduce the effects of volatile commodity prices, such transactions, depending on the hedging instrument used, may limit our potential gains if commodity prices were to rise substantially over the price established by the hedge. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:

 

    a counterparty is unable to satisfy its obligations;

 

    production is less than expected; or

 

    there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.

In addition, it is not always possible for us to engage in a derivative transaction that completely mitigates our exposure to commodity prices and interest rates. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices and interest rates for which we are unable to enter into a completely effective hedge transaction.

 

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The failure by counterparties to our derivative risk management activities to perform their obligations could have a material adverse effect on our results of operations.

The use of derivative risk management transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. If any of these counterparties were to default on its obligations under our derivative arrangements, such a default could have a material adverse effect on our results of operations, and could result in a larger percentage of our future production being subject to commodity price changes.

Due to the accounting treatment of derivative contracts, increases in prices for natural gas, crude oil and NGLs could result in non-cash balance sheet reductions and non-cash losses in our statement of operations.

We account for our derivative contracts by applying the mark-to-market accounting treatment required for these derivative contracts. We could recognize incremental derivative liabilities between reporting periods resulting from increases or decreases in reference prices for natural gas, crude oil and NGLs, which could result in us recognizing a non-cash loss in our combined statements of operations and a consequent non-cash decrease in our equity between reporting periods. Any such decrease could be substantial. In addition, we may be required to make cash payments upon the termination of any of these derivative contracts.

Regulations promulgated by the Commodities Futures Trading Commission could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The ongoing implementation of derivatives legislation adopted by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The Dodd-Frank Wall Street Reform and Consumer Protection Act, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The legislation requires the Commodities Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the new legislation. The CFTC finalized many of the regulations associated with the reform legislation, and is in the process of implementing position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The financial reform legislation may also require us to comply with margin requirements if our derivatives trading exceeds a yet to be finalized de minimis threshold and if we are unable to qualify for certain hedging exemptions, and with certain clearing and trade-execution requirements in connection with our future derivative activities, in connection with derivative activities in which we previously engaged in unregulated, over-the-counter contracts. The application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties.

The new legislation and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our derivative contracts in existence at that time, and increase our exposure to less creditworthy counterparties. If we reduce or change the way we use derivative instruments as a result of the legislation or regulations, our results of operations may become more volatile and cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial position, results of operations and/or cash flows.

 

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We may not be able to identify suitable oil and gas properties.

Our investment strategy depends on our ability to acquire projects. We may not be able to identify suitable acquisition opportunities or finance and complete any particular acquisition successfully. Furthermore, acquisitions involve a number of risks and challenges, including difficulty in assessing recoverable reserves, future production rates, operating costs, infrastructure requirements, environmental and other liabilities, and other factors beyond our control. As a result, we may not recover our investment in a project from the sale of production from the project, or may not recognize an acceptable return from investments we make. A downturn in the credit markets and a potential lack of available debt could result in a further reduction of suitable investment opportunities and create a competitive advantage to other entities that have greater financial resources than we do. During such times, our ability to borrow monies to finance the purchase of, or other activities related to, oil and gas assets will be negatively impacted. In addition, if we pay fees to lock in a favorable interest rate, falling interest rates or other factors could require us to forfeit these fees. If we acquire properties and other investments at higher prices or by using less-than-ideal capital structures, our returns will be lower and the value of our assets may decrease significantly below the amount we paid for the assets.

Also, the more common units we sell in this offering, the greater our challenge will be to invest all of the net offering proceeds on attractive terms. We can give no assurance that we will be successful in identifying or, even if identified, acquiring suitable properties on financially attractive terms or that our objectives will be achieved. If we are unable to identify and acquire suitable properties promptly, we will hold the proceeds from this offering in an interest-bearing account or invest the proceeds in short-term assets. Any of these factors could adversely affect our ability to achieve our anticipated levels of cash flow from our projects, pay distributions and meet our investment objectives. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Acquired properties may prove to be worth less than we paid, or provide less than anticipated proved reserves or production, because of uncertainties in evaluating recoverable reserves, well performance and potential liabilities, as well as uncertainties in forecasting oil and natural gas prices and future development, production and marketing costs.

Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, development potential, well performance, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Our estimates of future reserves and estimates of future production for our acquisitions are initially based on detailed information furnished by the sellers and subject to review, analysis and adjustment by our or our general partner’s internal staff, typically without consulting independent petroleum engineers. Such assessments are inexact and their accuracy is inherently uncertain; our proved reserves estimates may thus exceed actual acquired proved reserves. In connection with our assessments, we perform a review of the acquired properties that we believe is generally consistent with industry practices. However, such a review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We may not inspect every well. Even when we do inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. As a result of these factors, the purchase price we pay to acquire oil and natural gas properties may exceed the value we realize.

Also, our reviews of the properties included in the acquisitions are inherently incomplete because it is generally not feasible to perform an in-depth review of the individual properties involved in each acquisition given the time constraints imposed by the applicable acquisition agreement. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and potential.

Acquired properties may not produce as projected and we may be unable to determine reserve potential, identify all liabilities associated with the properties or obtain protection from sellers against such liabilities.

One of our investment strategies is to capitalize on opportunistic acquisitions of natural gas reserves. However, reviews of acquired properties are often incomplete because it generally is not feasible to review in

 

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depth every individual property involved in each acquisition. A detailed review of records and properties also may not necessarily reveal existing or potential problems, and may not permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well that we acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we inspect a well. Any unidentified problems could result in material liabilities and costs that negatively affect our financial condition and results of operations.

Even if we are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems. Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable or may be limited by floors and caps, and the financial wherewithal of such seller may significantly limit our ability to recover our costs and expenses. Any limitation on our ability to recover the costs related any potential problem could materially impact our financial condition and results of operations.

Ownership of our oil, gas and natural gas liquids production depends on good title to our property.

Good and clear title to our oil and gas properties is important. Although we will generally conduct title reviews before the purchase of most oil, gas, natural gas liquids and mineral producing properties or the commencement of drilling wells, such reviews do not assure that an unforeseen defect in the chain of title will not arise to defeat our claim, which could result in a reduction or elimination of the revenue received by us from such properties.

We must operate in accordance with comprehensive environmental laws that affect the manner, feasibility and cost of our operations.

Our intended operations will be regulated extensively at the federal, state and local levels. Our operations, wells and other facilities will be subject to stringent and complex federal, state and local environmental laws governing air emissions, water use and wastewater discharge, hazardous waste management and hazardous substance response. In some cases, we may be required to obtain environmental assessments, environmental impact studies, and/or plans of development before commencing drilling and production activities. Our activities may be subject to regulations regarding conservation practices. These regulations affect our operations and may limit the quantity of natural gas and oil we may produce and sell. Compliance with environmental laws will add to the costs of planning, designing, drilling, installing, operating and abandoning natural gas and oil wells.

Our ability to remove, treat, recycle or otherwise dispose of water will affect our production, and the cost of water treatment and disposal may affect our ability to make distributions.

Hydraulic fracturing requires large amounts of water and results in water discharges that must be treated, recycled or otherwise disposed. Environmental regulations governing the injection, withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, and all of which could have an adverse effect on our operations and financial performance. Although not anticipated by our general partner, we may need to drill our own water disposal wells. We anticipate that we will use trucks to transport the water to water disposal wells or water treatment or recycling facilities, in certain areas, and that it will pipe the water to disposal wells in other areas. If, however, we needed to drill our own disposal wells, there is a risk that we could not operate a gas production well at its full capacity until the required permit for the water disposal well was issued. Finally, if the environmental laws governing the management of produced waters become more stringent, they could restrict our ability to conduct hydraulic fracturing or increase our cost.

 

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Rules regulating air emissions from oil and natural gas operations will cause us to incur capital expenditures and operating costs.

The United States Environmental Protection Agency, or EPA, final rules establishing air emission controls for oil and natural gas production and natural gas processing operations require oil and natural gas production facilities to conduct “green completions” for hydraulic fracturing, that is, recovering rather than venting the gas and natural gas liquids that come to the surface during completion of the fracturing process. The rules also establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In January 2015, the Obama administration also announced it was targeting a 45.00% reduction in methane emission from oil and gas production from 2012 levels by 2025. States are also proposing more stringent requirements for air permits for well sites and compressor stations. Compliance with new rules regulating air emissions from our operations could result in significant costs, including increased capital expenditures and operating costs, and could adversely affect the results of our business.

Environmental laws may become more stringent, increasing the financial and managerial costs of compliance and, consequently, reducing our profitability.

The possibility exists that stricter environmental laws, regulations or enforcement policies may be enacted or adopted and could significantly increase our compliance costs. States outside the geographic area in which we intend to initiate our activities have imposed a variety of restrictions on hydraulic fracturing that could be adopted in jurisdictions in which we intend to operate. State restrictions have included permitting, chemical disclosure, siting, seismicity, water withdrawal and disposal, and tank secondary containment requirements. If new restrictions such as these or others are imposed on our operations, we may (i) incur significant additional costs to comply, (ii) experience delays or curtailment in the pursuit of exploration, development or production activities, and (iii) perhaps even be precluded from drilling wells.

The federal government could take a more active role in regulating hydraulic fracturing, which could result in increased costs, operating restrictions or delays.

Presently, the hydraulic fracturing process, unless conducted on federal land, has not generally been subject to regulation at the federal level. Presently, federal interests are primarily in the disclosure of fracturing fluid ingredients where fracturing occurs on federal lands and in air emissions from fracturing wells. The federal government is undertaking a comprehensive review of the environmental, health, and safety of the hydraulic fracturing process, however, and that review could result in increased federal regulation. If hydraulic fracturing becomes regulated at the federal level, our fracturing activities could be significantly affected. Federal restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are able to produce.

If we fail to comply with environmental laws governing our operations, we may incur significant costs or be unable to operate.

Failure to comply with environmental laws may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations.

We may not be able to secure all the authorizations required under environmental law to conduct drilling operations.

A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could inhibit our ability to develop our leases. Under some laws, environmental organizations have the right to challenge production operations on grounds of environmental protection. In recent years, organized opposition has succeeded in curtailing certain drilling projects.

 

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We may incur liability as the result of an accidental release of hazardous substances into the environment.

Our operations create the risk of inadvertent releases of hazardous substances into the environment, despite the exercise of reasonable caution. If such a release were to occur, we will be liable for the costs of responding to any such release, investigating the extent of its impacts and the cost of any remediation that may become necessary. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances. We may not be able to recover remediation costs under our insurance policies.

Laws restricting emissions of greenhouse gases could result in increased operating costs.

The adoption of legislation or regulations limiting emissions of greenhouse gases from our operations could require us to incur costs to reduce emissions of greenhouse gases, and such requirements also could adversely affect demand for the oil and natural gas that we produce. Few would predict adoption of comprehensive federal greenhouse gas legislation in the near term. In the absence of legislation, however, the EPA has adopted regulations under existing statutory authority, and several states (notably California and several Northeast states) have adopted their own greenhouse gas laws. The EPA has issued rules requiring entities that produce certain gases to inventory, monitor and report such gases as well as rules regulating greenhouse gas emissions through traditional construction and operating permit programs. These permitting programs require consideration of and, if deemed necessary, implementation of best available control technology to reduce greenhouse gas emissions. Under California’s Global Warming Solutions Act, also known as AB 32, the California Air Resources Board, or CARB, must develop and issue regulations to reduce greenhouse gas emissions in California to 1990 levels by 2020. To implement AB 32, CARB has issued rules creating a statewide cap-and-trade program for greenhouse gas emissions from large stationary sources and fuels suppliers. The cap-and-trade program began regulating greenhouse gas emissions from refineries in 2013 and fuels suppliers on January 1, 2015. Further development and expansion of regulatory programs like the foregoing could impose additional costs for emissions control and higher costs of doing business on us.

The third parties on whom we rely for gathering and transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.

The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulation. If existing laws and regulations governing such third- party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we will pay for their services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could subject us to liability and, if such failures are material, would require us to make alternative arrangements, which may not be available or which may involve increased costs.

Our credit facility has restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.

The operating and financial restrictions and covenants in our credit facility and any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions to our unitholders. Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our credit facility that are not cured or waived within the appropriate time periods provided in our credit facility, our ability to make distributions to our unitholders will be inhibited. In addition, our obligations under our credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders could seek to foreclose on our assets.

 

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As of September 30, 2015 and November 30, 2015, the lenders under the credit facility have no commitment to lend to us and we have a zero-dollar borrowing base under the credit facility, but we and our subsidiaries have the ability to enter into derivative contracts to manage our exposure to commodity price movements that will benefit from the collateral securing the credit facility. The credit facility may be amended in the future if we request a borrowing base redetermination and the lenders agree to establish the borrowing base and related commitments thereunder. If the borrowing base is redetermined to an amount greater than zero dollars, the credit facility would allow us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semiannually by our lenders in their sole discretion. Once established, our borrowing base will be subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil and natural gas reserves, which takes into account the prevailing oil and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. A future decline in commodity prices could result in a redetermination that lowers our borrowing base at that time and, in such case, we could be required to repay any indebtedness outstanding at that time in excess of the borrowing base. If we borrow under the credit facility and we are unable to repay any borrowings in excess of a decreased borrowing base, we would be in default and no longer able to make any distributions to our unitholders. In addition, any limitations on our ability to borrow under our credit facility could inhibit our ability to make acquisitions, which could prevent us from being able to pay the target distribution. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Economic conditions and instability in the financial markets could negatively impact our business which, in turn, could impact the cash we have to make distributions to our unitholders.

Our operations are affected by the financial markets and related effects in the global financial system. The consequences of an economic recession and the effects of the financial crisis include a lower level of economic activity and increased volatility in energy prices. This may result in a decline in energy consumption and lower market prices for oil and natural gas and has previously resulted in a reduction in drilling activity in our service areas. Any of these events may adversely affect our revenues and ability to fund capital expenditures and, in the future, may impact the cash that we have available to fund our operations and make distributions to our unitholders.

Potential instability in the financial markets, as a result of recession or otherwise, can cause volatility in the markets and may affect our ability to raise capital and reduce the amount of cash available to fund operations. We cannot be certain that additional capital will be available to us to the extent required and on acceptable terms. Disruptions in the capital and credit markets could negatively impact our access to liquidity needed for our businesses and impact flexibility to react to changing economic and business conditions. We may be unable to execute our growth strategies, take advantage of business opportunities or to respond to competitive pressures, any of which could negatively impact our business.

A weakening of the current economic situation could have an adverse impact on producers, key suppliers or other customers, or on our lenders, causing them to fail to meet their obligations. Market conditions could also impact our derivative instruments. If a counterparty is unable to perform its obligations and the derivative instrument is terminated, our cash flow and ability to pay distributions could be impacted which in turn affects the amount of distributions that we are able to make to our unitholders. The uncertainty and volatility surrounding the global financial system may have further impacts on our business and financial condition that we currently cannot predict or anticipate.

A cyber incident or a terrorist attacks could result in information theft, data corruption, operational disruption and/or financial loss.

We have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information,

 

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estimate quantities of oil and gas reserves, as well as other activities related to our businesses. Strategic targets, such as energy-related assets, may be at greater risk of future cyber or terrorist attacks than other targets in the United States. Deliberate attacks on, or security breaches in our systems or infrastructure, or the systems or infrastructure of third parties or the cloud, could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, challenges in maintaining our books and records and other operational disruptions and third party liability. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

If we are unable to obtain funding for future capital needs, cash distributions to our unitholders and the value of our properties could decline.

If we need additional capital in the future to improve or maintain our properties or for any other reason, we may have to obtain financing from sources beyond our funds from operations, such as borrowings. These sources of funding may not be available on attractive terms or at all. If we cannot procure additional funding for capital improvements, our properties may generate lower cash flows or decline in value, or both, which would limit our ability to make distributions to our unitholders and could reduce the value of your investment.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures from our operators than we or they currently anticipate.

As of September 30, 2015, a portion of our total estimated proved reserves were proved undeveloped or proved developed non-producing reserves and may not be ultimately developed or produced by our operators. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations by our operators. Our reserve report assumes that substantial capital expenditures by our operators are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that our operators will develop the properties as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical for our operators. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.

Because some wells may not return their drilling and completion costs, it may take many years to return your investment in cash, if ever.

Even if a well is completed by us and produces natural gas and oil in commercial quantities, it may not produce enough natural gas and oil to pay for the costs of drilling and completing the well, even if tax benefits are considered. Thus, it may take many years to return your investment in cash, if ever.

Horizontal wells are more expensive and difficult to drill and complete than vertical wells.

Our general partner anticipates that some of the wells we will drill will be horizontal wells. Horizontal wells are more expensive to drill and complete than vertical wells because of increased costs associated with the drilling rigs needed to drill a horizontal well, including hydraulically fracturing the wells multiple times and

 

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using more casing in the wells. Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process of hydraulically fracturing wells results in higher costs, which may not result in greater recoverable reserves. In addition, horizontal wells will be more susceptible to mechanical problems associated with completing the wells, such as casing collapse and lost equipment, than vertical wells. Further, fracturing the formation in a horizontal well is more complicated than fracturing the same geological formation in a vertical well.

We may not be paid, or may experience delays in receiving payment, for our natural gas and oil that has already been delivered to the purchaser.

In accordance with industry practice, we typically will deliver natural gas and oil to a purchaser for a period of up to 60 to 90 days before we receive payment. Thus, it is possible that we may not be paid for natural gas and oil that already has been delivered if the purchaser fails to pay for any reason, including bankruptcy. This ongoing credit risk also may delay or interrupt the sale of our natural gas and oil or our negotiation of different terms and arrangements for selling natural gas and oil to other purchasers. Finally, this credit risk may reduce the price benefit derived by us from our general partner’s, its affiliates’ or our anticipated natural gas and oil hedging arrangements as described above in “—Hedging transactions may limit our potential gains or cause us to lose money.”

Increased costs to transport our natural gas and oil to market could decrease our net revenues.

Our net revenues will decrease the farther our natural gas and oil is transported for sale because of increased transportation costs, which may also result in decreases in our distributions to you and the other investors in the Partnership.

Our business depends on third-party natural gas and oil transportation and processing facilities and our ability to contract with those parties.

Our ability to sell our natural gas, NGLs and oil production depends in part on the availability, proximity and capacity of pipeline systems and processing facilities owned by third parties and our ability to contract with those third parties. The lack of available capacity on these systems and facilities could require us to curtail or shut-in one or more producing wells or delay or discontinue drilling wells in an area where it has acquired projects. A curtailment or shut-in of production could materially reduce our cash flow, and if a substantial portion of the production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flow. Also, we may be unable to, or elect not to, purchase firm transportation on third party facilities and, in that event, our production transportation could be interrupted by other developers having firm arrangements. If any third-party pipelines and other facilities become partially or fully unavailable to transport or process our natural gas and oil production, or if the natural gas quality specifications for a natural gas pipeline or facility changes so as to restrict our ability to transport natural gas on those pipelines or facilities, we could be required to curtail or shut-in one or more of our wells and our revenues could decrease. Also, the disruption of third-party facilities due to maintenance and/or weather could limit our ability to market and deliver our natural gas, natural gas liquids and oil production.

Participation with third parties in drilling wells may require us to pay additional costs and could subject our revenues to the claims of the third-party creditors.

Our general partner anticipates that we may participate with third parties in drilling some of our wells. In this regard, additional financial risks exist when the costs of drilling, equipping, completing, and operating wells are shared by more than one person. If we pay our share of the costs, but another interest owner does not pay its share of the costs, then we would have to pay the costs of the defaulting party. In this event, we would receive the defaulting party’s revenues from the well, if any, under penalty arrangements set forth in the operating agreement, which may, or may not, cover all of the additional costs paid by us.

 

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If we are not the actual operator of the well for all of the working interest owners of the well, then there is a risk that our general partner will not be able to supervise the third-party operator closely enough, and that decisions related to the following would be made by the third-party operator, which may not be in our best interests or the best interests of our limited partners:

 

    how the well is operated;

 

    expenditures related to the well; and

 

    possibly the marketing of the natural gas and oil production from the well.

Further, the third-party operator may have financial difficulties and fail to pay for materials or services on the wells it drills or operates, which would cause us to incur extra costs in discharging materialmen’s and workmen’s liens. In this regard, we may not be the operator of a well for all of the working interest owners of the well if we own less than a 50.00% working interest in the well, or if it acquired the working interest in the well from a third party under arrangements that required the third party to be named operator.

Retirement Plan Risks

If the fiduciary of an employee pension benefit plan subject to ERISA (such as a profit-sharing, Section 401(k) or pension plan) or any other retirement plan or account fails to meet the fiduciary and other standards under ERISA or the Code as a result of an investment in our common units, the fiduciary could be subject to criminal and civil penalties.

There are special considerations that apply to employee benefit plans subject to ERISA (such as profit-sharing, Section 401(k) or pension plans) and other retirement plans or accounts subject to Section 4975 of the Code (such as an IRA) that are investing in our common units. Fiduciaries investing the assets of such a plan or account in our common units should satisfy themselves that:

 

    the investment is consistent with their fiduciary obligations under ERISA and the Code;

 

    the investment is made in accordance with the documents and instruments governing the plan or IRA, including the plan’s or account’s investment policy;

 

    the investment satisfies the prudence and diversification requirements of Sections 404(a)(1)(B) and 404(a)(1)(C) of ERISA and other applicable provisions of ERISA and the Code;

 

    the investment will not impair the liquidity of the plan or IRA;

 

    the investment will not produce an unacceptable amount of “unrelated business taxable income” for the plan or IRA;

 

    the value of the assets of the plan can be established annually in accordance with ERISA requirements and applicable provisions of the plan or IRA; and

 

    the investment will not constitute a non-exempt prohibited transaction under Section 406 of ERISA or Section 4975 of the Code.

With respect to the annual valuation requirements described above, we expect to provide an estimated value for our common units prepared by the Partnership annually. If at any time a plan fiduciary or an IRA custodian disputes our internal estimated valuation, we will hire an independent third party valuation expert to review or conduct such valuation. This estimated value is not likely to reflect the proceeds you would receive on our liquidation or on the sale of your common units, if your common units could be sold. Accordingly, we can make no assurances that the estimated value will satisfy the applicable annual valuation requirements under ERISA and the Code. The Department of Labor or the IRS may determine that a plan fiduciary or an IRA custodian is required to take further steps to determine the value of our common units. In the absence of an appropriate determination of value, a plan fiduciary or an IRA custodian may be subject to damages, penalties or other sanctions.

 

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Failure to satisfy the fiduciary standards of conduct and other applicable requirements of ERISA and the Code may result in the imposition of civil and criminal penalties and could subject the fiduciary to equitable remedies. In addition, if an investment in our common units constitutes a non-exempt prohibited transaction under ERISA or the Code, the fiduciary or IRA owner who authorized or directed the investment may be subject to the imposition of excise taxes with respect to the amount invested. In the case of a non-exempt prohibited transaction involving an IRA owner, the IRA may be disqualified and all of the assets of the IRA may be deemed distributed and subject to tax.

Prospective investors with investment discretion over the assets of an IRA, employee benefit plan or other retirement plan or arrangement that is covered by ERISA or Section 4975 of the Code should carefully review the information in the section of this prospectus entitled “Investment by Tax-Exempt Entities and ERISA Considerations” and consult their own legal and tax advisors on these matters.

If you invest in our common units through an IRA or other retirement plan, you may be limited in your ability to withdraw required minimum distributions.

If you establish an IRA or other retirement plan through which you invest in our common units, federal law may require you to withdraw required minimum distributions, or RMDs, from the plan in the future. We have substantial restrictions on your ability to sell your common units. As a result, you may not be able to sell your common units at a time in which you need liquidity to satisfy the RMD requirements under your IRA or other retirement plan. Even if you are able to sell your common units, the sale may be at a price less than the price at which the common units were initially purchased. If you fail to withdraw RMDs from your IRA or other retirement plan, you may be subject to certain tax penalties.

Federal Income Tax Risks

Our tax treatment depends on our status as a partnership for federal and state income tax purposes. If we were to become subject to entity-level taxation for federal or state income tax purposes, taxes paid would reduce the amount of cash available for distribution.

Although the anticipated tax benefits of an investment in us depend largely on us being treated as a partnership for federal income tax purposes, we have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us. In this regard, current law may change so as to cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to entity-level taxation. Also, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced.

Following a listing event, 90.00% or more of our gross income for every taxable year must be qualifying income, as defined in Section 7704 of the Code, in order to avoid being treated as a corporation for federal income tax purposes. Qualifying income is defined as income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil or products thereof) or the marketing of any mineral or natural resource (including fertilizer, geothermal energy and timber). We may not meet this requirement or current law may change so as to cause, in either event, us to be treated as a corporation for federal income tax purposes or otherwise be subject to federal income tax. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35.00%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed as corporate distributions, and none of our income, gain, loss, deduction and credit would flow through to you. If a tax were imposed on us as a corporation, our cash available for distribution could be reduced. Therefore, our treatment as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to you, and therefore result in a substantial reduction in the value of our securities.

 

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Changes in the law may reduce your tax benefits from an investment in us.

Your tax benefits from an investment in us may be affected by changes in the tax laws. For example, President Obama’s administration has proposed, among other tax changes, the repeal of certain oil and gas tax benefits, including the repeal of the percentage depletion allowance, the election to expense intangible drilling costs (including your option to amortize intangible drilling costs over a 60 month period) and the passive activity exception for working interests. These proposals may or may not be enacted into law.

Limited partners need passive income to use their partnership deductions that exceed the income from us.

If you invest in us, your share of our net losses will be passive losses that cannot be used to offset “active” income, such as salary and bonuses, or portfolio income, such as dividends and interest income. Thus, you may not have enough passive income from us or net passive income from your other passive activities, if any, to offset a portion or all of your passive deductions from us. However, any unused passive loss from us may be carried forward indefinitely by you to offset your passive income in subsequent taxable years. Also, except as described below, the passive activity limitations on your share of our losses do not apply to you if you invest in us and you are a corporation taxable under Subchapter C of the Code, which:

 

    is not a personal service corporation or a closely held corporation;

 

    is a personal service corporation in which employee-owners hold 10.00% (by value) or less of the stock, but is not a closely held corporation; or

 

    is a closely held corporation (that is, five or fewer individuals own more than 50.00% by value of the stock), but is not a personal service corporation in which employee-owners own more than 10.00% by value of the stock, in which case you may use your passive losses to offset your net active income (calculated without regard to your passive activity income and losses or portfolio income and losses).

You may owe taxes in excess of your cash distributions from us.

You may become subject to income tax liability for your share of our income in any taxable year in an amount that is greater than the cash you receive from us in that taxable year. For example:

 

    if we borrow money, your share of our revenues used to pay principal on the loan will be included in your income from us and will not be deductible;

 

    income from sales of natural gas and oil may be included in your income from us in one tax year, even though payment is not actually received by us and, thus, cannot be distributed to you, until the next tax year;

 

    if there is a deficit in your capital account, we may allocate income or gain to you even though you do not receive a corresponding distribution of our revenues;

 

    our revenues may be expended by our general partner for nondeductible costs or retained in the Partnership to establish a reserve for future estimated costs, including a reserve for the estimated costs of eventually plugging and abandoning the wells, which will reduce your cash distributions from us without a corresponding tax deduction; and

 

    the taxable disposition of our property or your Units may result in income tax liability to you in excess of the cash you receive from the transaction.

You and the other investors in us may be subject to state and local taxes and tax return filing requirements as a result of investing in us.

In addition to U.S. federal income taxes, you and the other investors will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes and tax return filing requirements that are imposed by the various jurisdictions in which we drill wells or otherwise do business now or in the future, even if you do not reside in any of those jurisdictions. We presently anticipate that

 

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substantially all of our income will be generated in Texas and Oklahoma, although we may drill wells in other states as well. It is your responsibility to file all federal, foreign, state and local tax returns that may be required of you. In this regard, our tax counsel has not rendered an opinion on any foreign, state or local tax consequences of an investment in us.

Your tax benefits from an investment in us are not contractually protected.

An investment in us does not give you any contractual protection against the possibility that part or all of the intended tax benefits of your investment will be disallowed by the IRS. No one provides any insurance, tax indemnity or similar agreement for the tax treatment of your investment in us. You have no right to rescind your investment in us or to receive a refund of any of your investment in us if a portion or all of the intended tax consequences of your investment in us is ultimately disallowed by the IRS or the courts. Also, none of the fees paid by us to our general partner, its affiliates or independent third-parties are refundable or contingent on whether the intended tax consequences of your investment in us are ultimately sustained if challenged by the IRS.

Tax-exempt entities face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and IRAs, raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. If you are a tax-exempt entity, you should consult your tax advisor before investing in common units.

An IRS audit of us may result in an IRS audit of your personal federal income tax returns.

The IRS may audit our annual federal information income tax returns, particularly since our investors will be eligible to claim deductions for intangible drilling costs and, with respect to wells drilled, completed and placed in service by us, depreciation of qualified equipment costs. If we are audited, the IRS also may audit your personal federal income tax returns, including prior years’ returns and items that are unrelated to us. Any adjustments made by the IRS to the federal information income tax returns of us could lead to adjustments on your personal federal income tax returns and could reduce the amount of your deductions from us.

Upon a listing event, we will adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between us and our limited partners. The IRS may challenge this treatment, which could adversely affect the value of your common units.

When we issue additional equity interests or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to such assets to the capital accounts of our limited partners and general partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we may make many of the fair market value estimates ourselves using a methodology based on the market value of our equity interests as a means to measure the fair market value of our assets. The methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain holders of common units and our general partner, which may be unfavorable to you. Moreover, under current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge the valuation methods, or our allocation of Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of the holders of common units.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our limited partners. It also could affect the amount of gain on the sale of equity interests by you and could have a negative impact on the value of our equity interests or result in audit adjustments to the tax returns of our limited partners without the benefit of additional deductions.

 

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SOURCE OF FUNDS AND ESTIMATED USE OF PROCEEDS

Source of Funds

We must receive minimum offering proceeds of $1.0 million to break escrow, and the maximum offering proceeds may not exceed $1.0 billion. There are no other requirements regarding the size of the offering. On completion of the offering of Units, our source of funds will be as follows:

 

    revenue generated by our existing oil and gas operations;

 

    the gross offering proceeds, which will be $1,000,000 if the minimum number of common units are sold and $1,000,000,000 if the maximum number of common units are sold; and

 

    borrowings under our existing credit facility, if we and the lenders agree to increase the borrowing base and the lenders’ commitments thereunder. Prior to any listing event, our Partnership Agreement prohibits us from borrowing, at any one time, more than an amount equal to 100.00% of the capital contributions made to the Partnership. We are in discussions with our lenders to set a borrowing base for our credit facility. Pending market conditions, we currently anticipate our lenders to set a borrowing base during the forecast period. Please read “Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution.”

The net offering proceeds available to us for investment from capital contributions pursuant to this offering are not expected to be less than approximately $880,000 if 100,000 common units are sold and less than approximately $885 million if 100,000,000 common units are sold. Such amounts include the gross offering proceeds (net of commissions and dealer manager fees and estimated offering and organization costs and distribution and unitholder servicing fees of $120,000 if the minimum offering is achieved and approximately $115 million if the maximum offering is achieved). Our repayment of any borrowings would be from our production revenues and would reduce or delay our cash distributions to you and the other investors.

If our general partner loans money to us, which is not required pursuant to the Partnership Agreement, then:

 

    the interest charged to us must not exceed our general partner’s interest cost or the interest that would be charged to us, without reference to our general partner’s financial abilities or guarantees, by unrelated lenders on comparable loans for the same purpose; and

 

    our general partner may not receive points or other financing charges or fees, although the actual amount of the charges incurred from third-party lenders may be reimbursed to our general partner.

Estimated Use of Proceeds

The gross offering proceeds will be used by us to pay the following:

 

    the organization and offering expenses, which include sales commissions, the dealer manager fee and all other expenses such as legal, accounting, printing, travel and similar amounts related to the offering of the common units;

 

    the costs to develop, operate and manage our oil and gas properties, including drilling additional oil and gas wells on the properties;

 

    the costs to acquire oil and gas properties; and

 

    potentially, along with borrowings, among other sources, to pay our target distribution.

Organization and offering costs are composed of the dealer manager fee, sales commissions and costs such as legal, accounting, SEC and Financial Industry Regulatory Authority, or FINRA registration fees, printing and similar costs related to the organization of the Partnership and the offering of the common units.

Based on our current leasehold acreage, we have available identified drilling locations for the deployment of approximately $150 million of the proceeds from this offering. The remainder of the offering proceeds, will be used to pursue our broader business strategy, including potentially acquiring and developing additional oil and gas properties.

 

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Class A Common Units

The following table below represents our current estimates concerning the use of the offering proceeds with respect to Class A common units. Because these are estimates, they may not accurately reflect the actual receipt or application of the offering proceeds. The table assumes the sale of 70,000,000 Class A common units and 30,000,000 Class T common units in the offering. The first scenario assumes that we sell the minimum number of $1.0 million of common units in this offering and the second scenario assumes that we sell the maximum of $1.0 billion of common units in this offering, with both scenarios contemplating a price of $10.00 per unit for Class A common units. We estimate that for each Class A common unit sold in this offering at $10.00, between approximately $8.80 and $8.85 of the purchase price (assuming no units available under our DRIP are sold) will be available for the acquisition of oil and gas properties. We will not pay sales commissions or a dealer manager fee on units sold under our DRIP. Substantially all of the gross offering proceeds available to the Partnership will be expended for the following purposes and in the following manner:

 

     Estimated Use of Proceeds  
     Minimum
Offering
     %      Maximum
Offering
     %  

Gross proceeds

   $ 700,000         100.00       $ 700,000,000         100.00   

Organization and offering costs:

           

Sales commissions(1)

   $ 49,000         7.00       $ 49,000,000         7.00   

Dealer manager fee(1)

   $ 21,000         3.00       $ 21,000,000         3.00   

Estimated reimbursement to general partner for fees and expenses related to offering(2)

   $ 14,000         2.00       $ 10,500,000         1.50   

Amounts available to develop, operate and manage our oil and gas properties, and to acquire oil and gas properties as well as management fees and distributions to unitholders(1)(3)

   $ 616,000         88.00       $ 619,500,000         88.50   

 

(1)  No sales commissions or dealer manager fee will be paid on sales of units under the DRIP. Our dealer manager may reallow all or a portion of sales commissions to participating broker-dealers in this offering attributable to the amount of units sold by them. The amount of sales commissions may be reduced under certain circumstances as described in “Plan of Distribution.” In addition, our dealer manager may reallow up to 50% of the dealer manager fee to participating broker-dealers to be paid to such participating broker-dealers as marketing fees. Our dealer manager anticipates, based on its past experience, that, on average, it will reallow 41.67% of the dealer manager fee to participating broker-dealers. The total amount of all items of compensation from any source, payable to our dealer manager or the participating broker-dealers will not exceed an amount that equals 10.00% of the gross proceeds of our primary offering (excluding common units purchased through the DRIP).
(2)  Assumes no debt is outstanding. We may use capital contributions to pay the management fees, acquisition fees, disposition fees and financing coordination fees to our general partner and to make distributions to unitholders. Please read “Business and Properties—Our Investment Strategies” for a more detailed discussion of our investment objectives and “Compensation” for a more detailed discussion of the fees we will pay our general partner and its affiliates.
(3)  Our general partner will receive an annual management fee equal to the product of 1.00% per annum multiplied by total capital contributions (other than those of our general partner and its affiliates), payable quarterly.

Class T Common Units

The following table below represents our current estimates concerning the use of the offering proceeds with respect to Class T common units. Because these are estimates, they may not accurately reflect the actual receipt or application of the offering proceeds. The table assumes the sale of 70,000,000 Class A common units and 30,000,000 Class T common units in the offering. The first scenario assumes that we sell the minimum number of $1.0 million of common units in this offering and the second scenario assumes that we sell the maximum of $1.0 billion of common units in this offering, with both scenarios contemplating a price of $10.00 per unit for Class T common units. We estimate that for each Class T common unit sold in this offering at $10.00, between

 

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approximately $8.80 and $8.85 of the purchase price (assuming no units available under our DRIP are sold) will be available for the acquisition of oil and gas properties. We will not pay sales commissions or a dealer manager fee on units sold under our DRIP. Substantially all of the gross offering proceeds available to the Partnership will be expended for the following purposes and in the following manner:

 

     Estimated Use of Proceeds  
     Minimum
Offering
     %      Maximum
Offering
     %  

Gross proceeds

   $ 300,000         100.00       $ 300,000,000         100.00   

Organization and offering costs:

           

Sales commissions(1)(2)

   $ 9,000         3.00       $ 9,000,000         3.00   

Dealer manager fee(1)

   $ 9,000         3.00       $ 9,000,000         3.00   

Estimated reimbursement to general partner for fees and expenses related to offering(3)

   $ 6,000         2.00       $ 4,500,000         1.50   

Amounts available to develop, operate and manage our oil and gas properties, and to acquire oil and gas properties as well as management fees and distributions to unitholders(1)(4)

   $ 276,000         92.00       $ 277,500,000         92.50   

 

(1)  No sales commissions or dealer manager fee will be paid on sales of units under the DRIP. Our dealer manager may reallow all or a portion of sales commissions to participating broker-dealers in this offering attributable to the amount of units sold by them. The amount of sales commissions may be reduced under certain circumstances as described in “Plan of Distribution.” In addition, our dealer manager may reallow up to 50% of the dealer manager fee to participating broker-dealers to be paid to such participating broker-dealers as marketing fees. Our dealer manager anticipates, based on its past experience, that, on average, it will reallow 41.67% of the dealer manager fee to participating broker-dealers. The total amount of all items of compensation from any source, payable to our dealer manager or the participating broker-dealers will not exceed an amount that equals 10.00% of the gross proceeds of our primary offering (excluding common units purchased through the DRIP).
(2)  With respect to Class T common units, the Partnership will pay to the dealer manager a distribution and unitholder servicing fee in the aggregate amount of 4.00% of the gross proceeds from the sale of Class T common units, which distribution and unitholder servicing fee will be withheld from cash distributions otherwise payable to the purchasers of Class T common units at a rate of $0.025 per quarter per unit. Assuming our initial quarterly distribution is $0.175 per unit per quarter and we withhold $0.025 per unit per quarter, the holders of Class T common units will receive net quarterly distribution of $0.15 per unit until the deferred payment obligation is fulfilled or the Class T common units convert into Class A common units or are redeemed (for a maximum of up to 16 quarters).
(3)  Assumes no debt is outstanding. We may use capital contributions to pay the management fees, acquisition fees, disposition fees and financing coordination fees to our general partner and to make distributions to unitholders. Please read “Business and Properties—Our Investment Strategies” for a more detailed discussion of our investment objectives and “Compensation” for a more detailed discussion of the fees we will pay our general partner and its affiliates.
(4)  Our general partner will receive an annual management fee equal to the product of 1.00% per annum multiplied by total capital contributions (other than those of our general partner and its affiliates), payable quarterly. The amount of proceeds payable to us as a result of the offering of the Class T common units also includes a distribution and unitholder servicing fee, in the amount of 4% of the gross proceeds, payable to Anthem Securities Inc. in equal installments over 16 quarters funded by withholding $0.025 per unit per quarter from distributions otherwise payable to the holders of Class T common units.

When structuring the Class A common units and Class T common units, management considered the changes to FINRA Rule 2310 and NASD Rule 2340 discussed in FINRA Regulatory Notice 15-02. Because we may use the net investment approach for the per unit value as allowed for under FINRA Rule 2310 and NASD Rule 2340, it was decided that the investors should be allowed to have the option to buy a Class T common unit, which allows for more money to be invested in the activity and reflects a higher net investment value on the customer account statement than a Class A common unit, because the distribution and unitholder servicing fee will not be deducted from the purchase price.

 

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CAPITALIZATION

The following table shows our cash and cash equivalents, total debt, including current position, and capitalization as of September 30, 2015:

 

    on a historical basis; and

 

    on an as adjusted basis to reflect this offering and the application of the net proceeds from this offering as described under “Source of Funds and Estimated Use of Proceeds,” assuming the maximum offering amount is reached.

The historical column of the table is derived from, and should be read together with, the audited historical financial statements and accompanying notes and the unaudited historical financial statements and accompanying notes included elsewhere in this prospectus. The as adjusted column of the table should be read in conjunction with “Source of Funds and Estimated Use of Proceeds” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

     As of September 30, 2015  
     Historical      As adjusted  
     (in thousands)  

Cash and cash equivalents

   $ 38,225       $ 935,225   
  

 

 

    

 

 

 

Total debt, including current position

     —          —    
  

 

 

    

 

 

 

Partners’ Capital:

     

General partner’s interest

     (885      (885

Common limited partners’ interests

     156,370         1,038,574   

Common limited partners’ warrants

     2,796         17,592   
  

 

 

    

 

 

 

Total partners’ capital

     158,281         1,055,281   
  

 

 

    

 

 

 

Total capitalization

   $ 158,281       $ 1,055,281   
  

 

 

    

 

 

 

 

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DILUTION

Purchasers of common units offered by this prospectus will suffer immediate and substantial dilution in net tangible book value per unit. Dilution in net tangible book value per unit represents the difference between the amount per unit paid by purchasers of our common units in this offering and the pro forma net tangible book value per unit immediately after this offering. After giving effect to the maximum sale of common units in this offering at the offering price of $10.00 per unit for Class A common units and $10.00 per unit for Class T common units, and after deduction of the estimated sales commissions, dealer manager fees and estimated offering expenses payable by us, our pro forma net tangible book value as of the conclusion of our private placement offering will be approximately $1.1 billion, or $8.54 per unit. This represents an immediate increase in net tangible book value of $1.83 per unit to our existing common unitholders and an immediate pro forma dilution of $1.46 per unit to purchasers of common units in this offering. The following table illustrates this common unit dilution, assuming no value is attributed to the warrants issued pursuant to this offering, on a per unit basis:

 

Assumed offering price per unit

   $ 10.00   

Pro forma net tangible book value per unit before the offering(1)

   $ 6.71   

Increase in net tangible book value per unit attributable to purchasers of the units being offered

     1.83   
  

 

 

 

Less: Pro forma net tangible book value per unit after the offering(2)

     8.54   
  

 

 

 

Immediate dilution in net tangible book value per unit to purchasers in the offering

   $ 1.46   
  

 

 

 

 

(1) Determined by dividing our historical net tangible book value per common unit by the total number of common units outstanding before this offering.
(2)  Determined by dividing our pro forma net tangible book value, after giving effect to the use of the net proceeds of the offering, by the total number of common units outstanding after this offering.

 

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

Our Partnership Agreement requires that we make distributions of all available cash within 45 days after the end of each quarter to holders of record on the applicable record date.

Our Cash Distribution Policy

The amount of distributions paid under our cash distribution policy and the decision to make any distribution will be determined by our general partner in its discretion, taking into account the terms of the Partnership Agreement. The amount of “available cash,” which is defined in the Partnership Agreement, will be determined by our general partner for each calendar quarter and will be based upon recommendations from the Partnership’s management. “Available cash” is defined as all cash on hand at the end of the quarter plus cash on hand from working capital borrowings made after the end of the quarter less the amount of cash that the board of directors of our general partner in its discretion establishes to provide for the proper conduct of business (including reserves for future capital expenditures and credit needs), to comply with applicable law and any of the Partnership’s debt instruments and for other contracts, and certain other considerations, including reserving funds for future quarterly distributions. For purposes of determining available cash, reserves that are determined to be necessary by our general partner are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When our general partner determines available cash for any calendar quarter, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate distribution level.

The board of directors of our general partner has, since the Partnership’s formation, paid a distribution of $0.175 per common unit each quarter, or the target distribution. The board of directors of our general partner may change this policy at any time without the approval of the unitholders or the conflicts committee of the board of directors of our general partner.

Our general partner expects that the Partnership would raise the quarterly cash distribution only when our general partner believes that:

 

    we have sufficient reserves and liquidity for the proper conduct and expansion of the Partnership’s business; and

 

    we can maintain such an increased distribution level for a sustained period.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that we will make cash distributions to our unitholders. We do not have a legal or contractual obligation to pay distributions quarterly or on any other basis or at our minimum quarterly distribution rate or at any other rate. Our cash distribution policy is subject to certain restrictions and may be changed at any time. The reasons for such uncertainties in our stated cash distribution policy include the following factors:

 

    Our general partner will have the authority to cause us to establish cash reserves for the proper conduct of our business (including reserves for working capital, operating expenses, future capital expenditures and credit needs and potential acquisitions), and the establishment of or increase in those cash reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Our Partnership Agreement and our cash distribution policy do not set a limit on the amount of cash reserves that our general partner may cause us to establish.

 

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    Our Partnership Agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include directors’ fees paid to the independent directors on the board of directors of our general partner and salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf, as well as expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine the expenses that are allocable to us, and our Partnership Agreement does not place any aggregate limit on the amount of such reimbursements.

 

    Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner.

 

    Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

 

    We may lack sufficient cash to pay distributions to the unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our tax expenses, working capital requirements and anticipated cash needs.

 

    If and to the extent our cash available for distribution materially declines, we may reduce our quarterly distribution in order to service or repay our debt or fund capital expenditures.

 

    If we make distributions out of capital surplus, as opposed to operating surplus, any such distributions would constitute a repayment of an investment in its units and would result in a reduction in the minimum quarterly distribution and the target distribution levels. Each of the target distribution levels will be reduced in connection with a distribution of capital surplus to an amount equal to the then-applicable target distribution level multiplied by a fraction, the numerator of which is the unrecovered unit price immediately prior to such distribution of capital surplus, and the denominator of which is the unrecovered unit price immediately after such distribution of capital surplus.

Any distributions paid on our common units with respect to a quarter will be paid within 45 days after the end of such quarter.

We treat all available cash distributed as distributed from operating surplus until the sum of all available cash distributed since we began operations equals its total operating surplus from the date that it began operations until the end of the quarter that immediately preceded the distribution. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. Operating surplus, as defined in the Partnership Agreement, includes up to $60.0 million that does not reflect actual cash on hand that is available for distribution to unitholders. Rather, it is a provision that will enable us, if we so choose, to distribute as operating surplus up to this amount of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and borrowings that would otherwise be distributed as capital surplus. We do not currently anticipate that we will make any distributions from capital surplus.

Please read “Summary of the Partnership Agreement—The Partnership Agreement” for the significant provisions of our Partnership Agreement that relate to cash distributions.

Target Quarterly Distributions

We have distributed, and currently intend to continue to distribute, to the holders of common units and GP units on a quarterly basis a target distribution of $0.175 per unit, or $0.70 per unit per year, to the extent we have sufficient available cash after establishing appropriate reserves and paying fees and expenses, including

 

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payments to our general partner in reimbursement of costs and expenses it incurs on our behalf. There is no guarantee that we will pay the target distribution, or any distribution, in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default or an event of default is existing under our credit facility.

Our general partner expects that we would raise the quarterly cash distribution only when our general partner believes that:

 

    we have sufficient reserves and liquidity for the proper conduct and expansion of our business; and

 

    we can maintain such an increased distribution level for a sustained period.

Our ability to make cash distributions at the applicable target quarterly distribution rate will be subject to the factors described above under “—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.” The table below sets forth the amount of common units that will be outstanding after this offering, assuming the cash generated from operations available for distribution needed to pay the aggregate target quarterly distribution on all of such common units for a single fiscal quarter and a four-quarter period (dollars in thousands):

 

            Distribution  
     Number of Units      One Quarter      Annualized  

Common units not held by our general partner and its affiliates

     122,691,900       $ 21,471,083       $ 85,884,330   

Common units held by our general partner and its affiliates

     608,510         106,489         425,957   
  

 

 

    

 

 

    

 

 

 

Total

     123,300,410       $ 21,577,572       $ 86,310,287   

GP units held by our general partner

     100       $ 431,551       $ 1,726,206   

Distributions declared by the Partnership for the period from November 1, 2013 through September 30, 2015 were as follows (in thousands, except per unit amounts):

 

Date Cash Distribution Paid

  For the Quarter Ended   Cash
Distribution
per
Common
Limited
Partner
Unit
    Total Cash
Distribution
to Common
Limited
Partners
    Total Cash
Distribution
with respect
to General
Partner’s
GP Units
 

February 14, 2014(1)

  December 31, 2013   $  0.1167      $  120.00      $  2.00   

May 15, 2014

  March 31, 2014   $  0.1750      $  223.00      $  6.00   

August 14, 2014

  June 30, 2014   $  0.1750      $  342.00      $  7.00   

November 14, 2014

  September 30, 2014   $  0.1750      $  841.00      $  16.00   

February 13, 2015

  December 31, 2014   $  0.1750      $  1,636.00      $  33.00   

May 15, 2015

  March 31, 2015   $  0.1750      $  2,180.00      $  45.00   

August 14, 2015

  June 30, 2015   $  0.1750      $  2,646.00      $  54.00   

November 13, 2015

  September 30, 2015   $  0.1750      $  4,078.00      $  83.00   

 

(1)  Represents a pro-rated cash distribution of $0.1750 per unit for the period from November 1, 2013 to the date the Partnership commenced operations.

 

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In the sections that follow, we present in detail the basis for our expectation that we will have sufficient cash available from operating surplus to pay the target distribution on our expected outstanding common units and GP units for each quarter during the twelve months ending December 31, 2016. In those sections, we present the following two tables:

 

    “Unaudited cash available for distribution,” in which we present the amount of cash we would have had available for distribution in each of the twelve months ended December 31, 2014 and September 30, 2015, based on our historical financial statements included elsewhere in this prospectus; and

 

    “Estimated cash available for distribution,” in which we present our Estimated Adjusted EBITDA necessary for us to have sufficient cash available for distribution to pay distributions at the target distribution rate on our expected outstanding common units and GP units for each quarter during the twelve months ending December 31, 2016, subject to the significant assumptions and considerations underlying our expectation that we will generate this Estimated Adjusted EBITDA.

Because of the continuous nature of this offering and our investment strategy, the following variables should be considered in connection with this forecast:

 

    The number of common units outstanding will increase from the current 23,300,410 on a continuous basis throughout the offering period, resulting in a related continuous increase in the aggregate amount of target distributions payable.

 

    In addition to the variables generally associated with oil and gas acquisitions, such as uncertainties regarding the timing and volume of production, our ability to make acquisitions and realize cash flow from such acquisitions will depend on the amount of proceeds we are able to raise in the continuous offering during the forecast period and our success in finding and closing suitable acquisitions, combined with the timing of realizing cash flows from such acquisitions.

Unaudited Cash Available for Distribution

If we had issued a number common units aggregating $130.0 million of gross proceeds out of the maximum offering contemplated by this prospectus on January 1, 2014, our cash available for distribution would have been a deficit of $33.8 million for the twelve months ended December 31, 2014. As a result, we would not have been able to pay any distribution on our outstanding common units and GP units.

If we had issued a number of common units aggregating $130.0 million of gross proceeds out of the maximum offering contemplated by this prospectus on October 1, 2014, our cash available for distribution would have been a deficit of $33.3 million for the twelve months ended September 30, 2015. As a result, we would not have been able to pay any distribution on our outstanding common units and GP units.

Cash available for distribution excludes any cash from working capital or other borrowings. As discussed under “—Estimated Cash Available for Distribution,” we may also use cash from these sources or from the proceeds of this offering for distributions in the future. Pursuant to the terms of our Partnership Agreement, our general partner would have had the discretionary authority to cause us to borrow funds under our credit facility, or from other sources, or to use proceeds from this offering to make up a portion of all of these estimated shortfalls.

Because this offering is being made on a continuous basis as opposed to a firm commitment underwritten offering with a one-time issuance of a certain number of units, we have made certain assumptions that we believe to be reasonable about the amount and timing of sales of common units pursuant to this prospectus for the purposes of the table below.

 

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The following table illustrates, for the twelve months ended December 31, 2014 and September 30, 2015, cash available to pay distributions, assuming that we had issued a number of common units aggregating $130.0 million of gross proceeds out of the maximum offering contemplated by this prospectus on January 1, 2014.

 

     Twelve Months Ended  
     December 31, 2014     September 30, 2015  
     (in thousands, except per unit data)  

Net loss

   $ (17,145   $ (26,980

Plus:

    

Interest expense

     —          14   

Depreciation, depletion and amortization

     2,156        5,815   

Asset impairment

     6,880        14,171   

Acquisition and related costs

     253        416   

Gain on mark-to-market derivatives

     —          (760
  

 

 

   

 

 

 

Adjusted EBITDA

   $ (7,856   $ (7,324

Less: cash interest expense

     —          —     
  

 

 

   

 

 

 

Cash available for distribution

   $ (7,856   $ (7,324
  

 

 

   

 

 

 

Annualized target distributions per common unit(1)

   $ 0.70      $ 0.70   

Estimated annual cash distributions:

    

Distributions on common units held by purchasers in this offering(2)

   $ 9,100      $ 9,100   

Distributions on common units held by ATLS and its affiliates(3)

     350        350   

Distributions on common units held by non-affiliate purchasers in the private placement(4)

     15,960        15,960   

Distributions on general partner units

     519        519   
  

 

 

   

 

 

 

Total estimated annual cash distributions

   $ 25,929      $ 25,929   
  

 

 

   

 

 

 

(Shortfall)

   $ (33,785   $ (33,253
  

 

 

   

 

 

 

 

(1)  With respect to Class T common units, the Partnership will pay to the dealer manager a distribution and unitholder servicing fee in the aggregate amount of 4.00% of the gross proceeds from the sale of Class T common units, which distribution and unitholder servicing fee will be withheld from cash distributions otherwise payable to the purchasers of Class T common units at a rate of $0.025 per quarter per unit for a maximum of 16 quarters. As a result, the payment of the distribution and unitholder servicing fee will not impact the total distributions payable by the Partnership.
(2)  Reflects 13,000,000 common units outstanding for the entire period.
(3)  Reflects 500,010 common units outstanding for the entire period.
(4)  Reflects 22,800,400 common units outstanding for the entire period.

Financial Forecast

We do not as a matter of course make public projections of financial information. Our forecast information below presents, to our best knowledge and belief, our expected results of operations and cash flows for the twelve months ending December 31, 2016. Our forecast financial information reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months December 31, 2016.

The assumptions disclosed are those that we believe are significant to our forecasted information, but we cannot assure you that our forecast results will be achieved. Most significantly, we have assumed that we will be able to make acquisitions during the forecast period sufficient to fund the full target distribution, and there can be

 

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no guarantee that we will be able to do so economically or at all. In addition, the specific nature of any potential acquisition, including whether it is of producing or non-producing properties and how quickly we are able to translate an acquisition into cash flows, cannot be determined at this time. However, significant potential risks in connection with any acquisitions exist, including those described in “Risk Factors—We may not be able to identify suitable oil and gas properties,” “—Acquired properties may prove to be worth less than we paid, or provide less than anticipated proved reserves or production, because of uncertainties in evaluating recoverable reserves, well performance and potential liabilities, as well as uncertainties in forecasting oil and natural gas prices and future development, production and marketing costs,” “—Acquired properties may not produce as projected and we may be unable to determine reserve potential, identify all liabilities associated with the properties or obtain protection from sellers against such liabilities,” and “—Our credit facility has restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.”

There will likely be differences between our forecast and actual results, and those differences could be material. If we do not achieve the forecast, we may not be able to pay the target distribution, or any distribution amount on our outstanding units. However, as a result of our small existing asset and production base coupled with our primary investment objective to generate distributions and capital appreciation through the acquisition of oil and gas assets in the United States, the likelihood of a variance between this forecast and our actual results is greater than if we were an issuer with an established asset base. It is our strategy to target for acquisition energy-related assets, including producing oil and gas assets, undeveloped oil and gas assets with development potential, gathering, processing and pipeline assets and securities of energy companies. When we acquire a property, we will estimate the capital required to develop the property and plan to reserve a portion of our capital contributions, or a portion of any borrowing capacity available to us, to fund all or a portion of these estimated costs of development. We also plan to use our cash flow, after the payment of the target distribution to our unitholders, to further develop our properties and to fund future acquisitions. We do not expect to conduct a material amount of exploratory drilling on any non-producing properties we acquire. Taken together, these highly variable aspects of our strategy make predicting our short-term results much less precise.

Our forecast financial information is a forward-looking statement and should be read together with the historical and financial statements and the accompanying notes included elsewhere in this prospectus and together with “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Cautionary Note Regarding Forward-Looking Statements”. In the view of our management, however, such information was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions and considerations on which we base our belief that we can generate the estimated Adjusted EBITDA necessary for us to have sufficient cash available for distribution on the common units at the target distribution rate. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Neither Grant Thornton LLP nor any other independent registered public accounting firms, have examined, compiled nor performed any procedures with respect to the accompanying prospective financial information and, accordingly, neither Grant Thornton LLP nor any other independent registered public accounting firms, express an opinion or any other form of assurance with respect thereto. The reports of Grant Thornton LLP included in this prospectus do not extend to the prospective financial information and should not be read to do so.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date in this prospectus. Therefore, you should not place undue reliance on this information.

 

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As a result of the factors described in “—Estimated Cash Available for Distribution,” we believe we will be able to pay distributions at the target distribution rate of $0.175 per unit per quarter on our expected outstanding common units and GP units for each quarter in the twelve months ending December 31, 2016.

Estimated Cash Available for Distribution

In order to pay the target distribution of $0.175 per common unit and GP unit per quarter for the twelve-month period ending December 31, 2016, our cash available for distribution must be at least approximately $18.9 million over that period. We estimate that our minimum Adjusted EBITDA for the twelve-month period ending December 31, 2016 must be at least $4.3 million in order to generate cash available for distribution to the holders of our common units and GP units of approximately $18.9 million over that period. We believe we will generate estimated Adjusted EBITDA of $23.7 million for the twelve months ending December 31, 2016. We refer to this amount as “Estimated Adjusted EBITDA.” If our estimate is not achieved, we may not be able to pay the target distribution on our units. We may not realize our assumptions or we may not generate the $4.3 million in minimum Adjusted EBITDA required to pay the target distribution on the assumed weighted average number of common units and GP units outstanding during the forecast period. There will likely be differences between our estimates and the actual results we will achieve and those differences could be material.

Adjusted EBITDA is a significant performance metric used by our management to indicate (prior to the establishment of any reserves by the board of directors of our general partner) the cash distributions we expect to pay to our unitholders. We define Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion and amortization, plus certain non-cash items. Adjusted EBITDA is not a measure of performance calculated in accordance with GAAP. Although not prescribed under GAAP, we believe the presentation of Adjusted EBITDA is relevant and useful because it helps our investors to understand our operating performance and makes it easier to compare our results with other companies that have different financing and capital structures. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance calculated in accordance with GAAP, as those items are used to measure our operating performance, liquidity or ability to service debt obligations. Adjusted EBITDA should not be considered in isolation of, or as a substitute for, net earnings as an indicator of operating performance or cash flows from operating activities as a measure of liquidity. Adjusted EBITDA, as we calculate it, may not be comparable to Adjusted EBITDA measures reported by other companies. In addition, Adjusted EBITDA does not represent funds available for discretionary use or the payment of distributions.

In calculating the estimated cash available for distribution for the twelve-month period ending December 31, 2016, we have included amounts for estimated acquisition and capital expenditures, as well as average borrowings of $15.0 million for the period to fund a portion of the consideration for our assumed acquisition. If we do not finance such expenditures with proceeds from this offering, borrowings or issuances of additional common units, we would experience a shortfall in the amount of cash generated from our operations to pay both the aggregate cash distributions on our common units and GP units and make the acquisition and capital expenditures we expect to make.

You should read the information following the table for a discussion of the material assumptions underlying our belief that we will be able to generate Estimated Adjusted EBITDA of approximately $23.7 million. Our belief is based on those assumptions and reflects our judgment, as of the date of this prospectus, regarding the conditions we expect to exist and the course of action we expect to take over the twelve-month period ending December 31, 2016. The assumptions we disclose below are those that we believe are significant to our ability to generate our Estimated Adjusted EBITDA. If our estimates prove to be materially incorrect, we may not be able to pay the target distribution or any amount on our outstanding units during the four calendar quarters ending December 31, 2016. See “—Financial Forecast” for a description of the factors that may cause our actual performance to differ from these estimates.

 

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When considering our Estimated Adjusted EBITDA, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors” and elsewhere in this prospectus. Any of these risk factors or the other risks discussed in this prospectus could cause our financial condition and results of operations to vary significantly from those set forth in the table below.

Because this offering is being made on a continuous basis, we have made certain assumptions that we believe to be reasonable about the amount and timing of sales of common units pursuant to this prospectus for the purposes of the table below. See “—Size of Offering.”

 

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The following table illustrates (i) our Estimated Adjusted EBITDA that we expect to generate for the twelve months ending December 31, 2016 based on the assumptions and considerations described below and (ii) the estimated cash available to pay distributions based on the assumptions and considerations described below. We explain each of the adjustments below. All of the amounts for the twelve-month period ending December 31, 2016 in the table and in the assumptions are estimates.

 

     Twelve Months
Ending

December 31, 2016
 
     (in thousands, except
per unit data)
 

Revenues:

  

Gas and oil production

   $ 58,419   

Gain on mark-to-market derivatives

     550   
  

 

 

 

Total revenues

     58,969   
  

 

 

 

Costs and Expenses:

  

Gas and oil production

     24,177   

General and administrative

     300   

General and administrative — affiliate

     10,756   

Depreciation, depletion and amortization

     14,458   

Asset impairment

     —     
  

 

 

 

Total costs and expenses

     49,691   
  

 

 

 

Operating income

     9,278   

Interest expense

     811   
  

 

 

 

Net income

   $ 8,467   
  

 

 

 

Plus:

  

Interest expense

     811   

Depreciation, depletion and amortization

     14,458   

Asset impairment

     —     

Acquisition and related costs

     —     
  

 

 

 

Estimated Adjusted EBITDA

   $ 23,736   
  

 

 

 

Less:

  

Cash interest expense

     (811

Capital expenditures

     (146,544

Plus:

  

Borrowings and other sources to fund capital expenditures

     146,544   

Additional funds raised in this offering

     15,336   
  

 

 

 

Estimated cash available for distribution

   $ 38,261   
  

 

 

 

Target annual distributions per unit(1)

   $ 0.70   

Estimated annual cash distributions:

  

Distributions on common units held by purchasers in this offering(2)

   $ 2,187   

Distributions on common units held by ATLS and its affiliates(3)

     350   

Distributions on common units held by non-affiliate purchasers in the private placement(4)

     15,960   

Distributions on general partner units

     377   
  

 

 

 

Total estimated cash distributions

   $ 18,874   
  

 

 

 

Excess of cash available for distribution over total annualized target distribution

   $ 19,387   

 

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(1)  With respect to Class T common units, the Partnership will pay to the dealer manager a distribution and unitholder servicing fee in the aggregate amount of 4.00% of the gross proceeds from the sale of Class T common units, which distribution and unitholder servicing fee will be withheld from cash distributions otherwise payable to the purchasers of Class T common units at a rate of $0.025 per quarter per unit for a maximum of 16 quarters. As a result, the payment of the distribution and unitholder servicing fee will not impact the total distributions payable by the Partnership.
(2)  See “—Size of Offering.”
(3)  Reflects 500,010 common units outstanding for the entire period.
(4)  Reflects 22,800,400 common units outstanding for the entire period.

Assumptions and Considerations

Based upon the specific assumptions outlined below with respect to the twelve months ending December 31, 2016, we expect to generate Estimated Adjusted EBITDA sufficient to establish reserves and to pay the target distribution on our assumed number of common units and GP units for the twelve months ending December 31, 2016.

While we believe that these assumptions are reasonable in light of management’s current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions do not materialize, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay quarterly cash distributions equal to our target distribution (absent borrowings under our credit facility), or any amount, on our common units and GP units, in which event the value of our common units may decline substantially.

We did not use quarterly estimates in concluding that there would be sufficient cash available for distribution to pay the target on our assumed number of common units and GP units for the twelve months ending December 31, 2016. Historically, our focus on acquisitions and the substantial growth we expect to undergo make specific timing harder to predict. For more information regarding these factors, see “Risk Factors.” As a result of the inherent difficulty in projecting the precise timing of revenue and expenses, we believe that any estimate of our quarterly cash available for distribution would involve a high degree of potential inaccuracy. To the extent that there is a shortfall of quarterly cash available for distribution compared with the target distribution on our common units and GP units during the year ending December 31, 2016, we believe we will be able to utilize cash on hand, borrowings under our credit facility or proceeds from this offering to fund the shortfall, with such amounts replenished in subsequent quarters.

Size of the Offering

Consistent with our expectations for this offering, we have assumed that (i) we will complete the issuance and sale of common units aggregating $130.0 million of gross proceeds out of the maximum offering contemplated by this prospectus by December 31, 2016, with issuances occurring primarily during the second half of 2016, and (ii) that 50% of the common units outstanding will elect to participate in our DRIP and so will not receive cash distributions. These assumptions result in an assumed an average of 26.5 million common units outstanding for the forecast period. To the extent that the number of common units we actually issue over the forecast period is more or less than this amount, it could materially impact (i) the amount of Estimated Adjusted EBITDA we would need to fund the target distribution and (ii) the amount of proceeds we have available to make acquisitions to fund the target distribution.

 

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Gas, Oil and NGL Production

As reflected in the table below, to generate our Estimated Adjusted EBITDA for the twelve months ending December 31, 2016, we have assumed the following regarding our operations:

 

Net natural gas production volume

     0.6 Bcf   

Average natural gas price

   $ 2.36   

Net crude oil production volume

     1,494 Bbls   

Average crude oil price on hedged volumes

   $ 46.75 per Bbl   

Average crude oil price on unhedged volumes

   $ 38.43 per Bbl   

Percentage of net crude oil production assumed to be hedged

     5%   

Net NGL production volume

     109 Bbls   

Average NGL price

   $ 14.53 per Bbl   

Production costs (per Bbl):

  

Lease operating expenses

   $ 7.68   

Production taxes

   $ 1.60   

Transportation and compression

   $ 0.16   

Total production costs

   $ 9.44   

Our forecasted natural gas, oil and NGL production volumes for the twelve months ending December 31, 2016 assume that currently producing wells will produce at the rates forecasted in our September 30, 2015 reserve report at NYMEX 5-year forward curve pricing as of January 6, 2016. Forecasted production volumes also include new production from an estimated eight additional oil wells on our existing acreage we project to be brought in line during the twelve months ending December 31, 2016. Similarly, we assume that all of these wells will produce at rates consistent with wells of similar characteristics contained in our September 30, 2015 reserve report.

In addition, we expect to make acquisitions of property constituting a substantial amount of proved reserves and production during the forecast period using proceeds from this offering and borrowings under our credit facility. We believe that sufficient acquisition opportunities exist, especially in this price environment, but there can be no guarantee that we will be able to do so economically or at all. While we are constantly considering property acquisitions and have identified several potential acquisition targets, we have not entered into any definitive agreements. In addition, the specific nature of any potential acquisition, including whether it is of producing or non-producing properties and how quickly we are able to translate an acquisition into cash flows, cannot be determined at this time. To the extent that we are unable to monetize the reserves and production associated with an acquisition as efficiently as we have assumed, it would have an adverse effect on our Estimated Adjusted EBITDA. As a result, we may, but are not required to, use proceeds from this offering or borrowings under our credit facility to fund any related shortfall. For purposes of this forecast, we have assumed that we will acquire proved developing producing properties for $100.0 million that will generate an incremental $20.0 million of annualized Adjusted EBITDA, with an assumed effective date of April 1, 2016. We intend to acquire an oil-weighted property with existing production. In the forecast, we have assumed production volumes will be 88% oil, 6% gas and 6% NGLs, declining at 10% on an annualized basis. In order to fund the acquisition consideration, we have assumed that we will use $75.0 million of the proceeds from this offering and $25.0 million of borrowings under our credit facility.

Significant potential risks in connection with any acquisitions exist, including those described in “Risk Factors—We may not be able to identify suitable oil and gas properties,” “—Acquired properties may prove to be worth less than we paid, or provide less than anticipated proved reserves or production, because of uncertainties in evaluating recoverable reserves, well performance and potential liabilities, as well as uncertainties in forecasting oil and natural gas prices and future development, production and marketing costs,” “—Acquired properties may not produce as projected and we may be unable to determine reserve potential, identify all liabilities associated with the properties or obtain protection from sellers against such liabilities,” and

 

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“—Our credit facility has restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.”

Additionally, we have assumed no significant interruptions of production volumes due to mechanical issues such as compressor breakdowns and sales line maintenance. Further, we have assumed no significant logistical issues related to new well hookups, such as delays in pipeline construction, permitting and right-of-ways which we primarily depend on our gathering system service providers to complete.

Commodity Derivative Contracts

We do not expect to, and have not assumed that we will, enter into any hedges on our projected natural gas and NGL production. As a result, we have assumed that all of our natural gas and NGL production will be sold at spot market prices.

Our weighted average oil sales price of $37.42 per Bbl is calculated by taking into account the fact that we have hedge contracts in place for approximately 5% of our forecasted oil production volume for the twelve months ending December 31, 2016 at a weighted average price of approximately $46.75 per Bbl.

Capital Expenditures

In addition to the $100.0 million of acquisition capital expenditures, we expect to incur approximately $46.5 million of capital expenditures during the twelve months ending December 31, 2016 to complete ten Eagle Ford oil and gas wells. We expect to fund these capital expenditures with the proceeds from this offering and cash on hand.

General and Administrative Expenses

We have forecasted general and administrative expense of $11.1 million for the twelve months ending December 31, 2016, as compared to $14.7 million of general and administrative for the twelve months ended September 30, 2015. The decrease in general and administrative expense is due principally to the decrease in fundraising costs associated with our initial private placement and common unit offerings that are not expected to recur in the forecast period.

Depletion, Depreciation and Amortization Expense

We estimate that our depletion, depreciation and amortization expense for the twelve months ending December 31, 2016 will be approximately $14.5 million, as compared to $5.8 million for the twelve months ended September 30, 2015. The forecasted depletion of our oil and natural gas properties is based on the production estimates in our reserve report dated September 30, 2015 as well as additional depletion associated with the properties that we have assumed we will acquire.

Cash Interest Expense

Our estimated cash interest expense is comprised of the following components:

 

    approximately $1.3 million attributable to estimated average borrowings of $15 million under our credit facility during the forecast period at an interest rate of 3.5% to fund the relevant portion of our expected acquisition and capital expenditures; and

 

    approximately $0.2 million attributable to interest income earned on cash held at the business

We are in discussions with our lenders to set a borrowing base for our credit facility. Pending market conditions, we currently anticipate our lenders to set a borrowing base during the forecast period in connection with our acquisition activity.

 

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Sensitivity Analysis

Our ability to generate sufficient cash from our operations to pay distributions to our unitholders of not less than the target distribution per unit for the twelve months ending December 31, 2016 is a function of the following primary variables:

 

    the amount of natural gas, oil and NGLs we produce; and

 

    the price at which we sell our natural gas, oil and NGLs.

In the paragraphs below, we discuss the impact that changes in these variables, holding all other variables constant, would have on our ability to generate sufficient cash from our operations to pay the target distribution on our outstanding units. This sensitivity analysis also assumes that we will be able to identify suitable drilling locations for the number of wells forecasted to be drilled and that we are able to drill that number of wells during the forecast period. In addition, it assumes that we are successfully able to execute on our acquisition strategy during the forecast period.

Production volume changes. For purposes of our estimates set forth above, we have assumed that our net production will total 10.2 Bcfe during the twelve months ending December 31, 2016. If our actual net production realized during such twelve-month period is 10% more (or 10% less) than such estimate (that is, if actual net realized production is 11.3 Bcfe or 9.2 Bcfe), we estimate that our estimated cash available to pay distributions would change by approximately $3.7 million.

Commodity price changes. For purposes of our estimates set forth above, we have assumed that our weighted average net realized commodity price for our net production volumes is $2.36 per Mcf for natural gas, $37.42 per barrel for crude oil and $14.53 per barrel for natural gas liquids. If the average realized commodity price for our net production volumes that are unhedged were to change by 10%, we estimate that our estimated cash available to pay distributions would change by approximately $6 million, assuming no changes in any other variables and inclusive of our commodity derivative contracts.

Regulatory, Industry and Economic Factors

Our forecast for the twelve months ending December 31, 2016 is based on the following significant assumptions related to regulatory, industry and economic factors:

 

    There will not be any new federal, state or local regulation of the relevant portions of the oil and gas industry, or any new interpretation of existing regulations, that will be materially adverse to our business.

 

    There will not be any material adverse change in the oil and gas industry, commodity prices, capital or insurance markets or in general economic conditions.

 

    There will not be any material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events with respect to facilities of third parties on which we depend.

 

    There will not be a shortage of skilled labor.

 

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ATLAS’ PRIOR EXPERIENCE WITH DRILLING PROGRAMS AND

MASTER LIMITED PARTNERSHIPS

ATLS or its affiliates have managed several MLPs since 2000 and created substantial value for their stakeholders. In addition, ATLS or its affiliates have sponsored over 65 tax-advantaged drilling partnerships since 1985. Since that time, investors invested over $2.7 billion of capital into these drilling partnerships and received over $1.0 billion of distributions. For more information, please read “Plan of Distribution—ARP’s History in Connection with Liquidity Events.”

In 2000, management took APL public. From inception through its merger with a subsidiary of Targa Resource Partners LP in February 2015, APL expanded geographically from a small set of natural gas gathering assets in the Appalachian basin to one of the largest independent gathering and processing companies in the country, with processing capacity of approximately 1.2 Bcf/d. APL returned to its unitholders 421.30% (11.90% annual average) through unit price appreciation and distributions from inception through October 13, 2014 when APL announced its merger with a subsidiary of Targa Resources Partners LP.

Additionally, in 2006, management of our general partner took public Atlas Pipeline Holdings, L.P., or AHD. In conjunction with the sale of Atlas Energy, Inc. to Chevron Corporation, or Chevron, in 2011, AHD purchased certain exploration and production assets from Atlas Energy, Inc. and was subsequently renamed Atlas Energy, L.P., or Atlas Energy. Atlas Energy, Inc. returned to its unitholders 930.5% from inception through 2011 when it announced its acquisition by Chevron. From inception through its announced merger with a subsidiary of Targa Resources Corp. in October 2014, AHD and its successor, ATLS, returned 108.10% (9.30% annual average) through unit price appreciation and distributions.

In 2006, management took public Atlas Energy Resources, LLC, or ATN, an exploration and production MLP with assets largely in the Appalachian basin and Michigan. ATN was merged into Atlas Energy, Inc. in a unit-for-share exchange in September 2009. From inception through the sale of Atlas Energy, Inc. to Chevron, ATN returned 178.30% (27.70% annual average) through unit price appreciation and distributions. In February 2012, Atlas Energy contributed the exploration and production assets that it had acquired from Atlas Energy, Inc. prior to the Chevron acquisition into a new exploration and production MLP, ARP. In connection with the Targa mergers, Atlas Energy transferred all of its assets and liabilities, other than those related to its midstream assets (including APL), to ATLS and effected a pro rata distribution to Atlas Energy’s unitholders of 100.00% of ATLS’s common units.

During ATLS and its affiliates’ management of the entities described above, our management team experienced major adverse business developments, including several oil and gas down-cycles and the 2008 financial crisis. For example, the table below presents the high and low oil and natural gas prices during the relevant period, highlighting the price volatility during a period where we believe management was able to succeed.

 

    NYMEX WTI Crude Oil
Price ($/Bbl)
       NYMEX Henry Hub Natural
Gas Price ($/Mmbtu)
 
    High        Low        High        Low  

2015

  $  61.43         $  34.73         $  3.23         $  1.76   

2014

    107.26           53.27           6.15           2.89   

2013

    110.53           86.68           4.46           3.11   

2012

    109.77           77.69           3.90           1.91   

2011

    113.93           75.67           4.85           2.99   

2010

    91.51           68.01           6.01           3.29   

2009

    81.04           33.98           6.10           1.83   

2008

    134.02           42.04           13.11           6.47   

2007

    95.10           51.13           7.59           5.43   

2006

    75.92           56.93           11.43           4.20   

 

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In 2008, management also experienced the financial crisis and related turmoil in the global financial system. The 2008 financial crisis resulted in an economic recession and credit crisis, including a lower overall level of economic activity and increased volatility in energy prices, which resulted in a decline in energy consumption and lower market prices for oil and natural gas. Additionally, the instability of the financial markets in 2008 increased the cost of capital, while the availability of funds from the market diminished significantly over the next several years. Despite these major adverse business conditions in 2008, management was able to continue to manage its operations and provide strong financial results to investors.

As indicated above, our management team’s strong financial and energy industry experience, along with our deep knowledge of AGP and its affiliates resulting from our long tenure with ATLS and its predecessors, enables us to provide valuable leadership through all commodity price cycles. Our experience in founding, operating, and managing public and private companies of varying size and complexity enable us to provide valuable expertise. Our management team has experienced several oil & gas down-cycles and has proven its ability to manage companies and investments during challenging down-cycles as well as competitive high commodity price environments.

 

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Although our relationship with our general partner and ATLS may provide significant benefits to us, it may also become a source of potential conflicts. Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including ATLS and its affiliates), on the one hand, and the Partnership and our limited partners, on the other hand. Conflicts may arise as a result of the duties of our general partner to act for the benefit of its owners, which may conflict with the interests of you and other unitholders and the interests of the Partnership. The directors and officers of ATLS have duties to manage ATLS and our general partner in a manner beneficial to their owners. ATLS and its affiliates are not restricted from competing with us. In addition, many of the officers and directors of our general partner serve in similar capacities with ATLS and its affiliates, which may lead to additional conflicts of interest, including conflicts of interest regarding the allocation of their time between ATLS and us.

Our Partnership Agreement limits the liability of and replaces the fiduciary duties owed by our general partner to our unitholders. Our Partnership Agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of duties by our general partner or its directors or executive officers. By purchasing a common unit, the purchaser agrees to be bound by the terms of our Partnership Agreement, and each unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the Partnership Agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law.

These conflicts include the following situations, among others:

 

    Our general partner is allowed to take into account the interests of parties other than us, such as ATLS and ARP, in exercising certain rights under our Partnership Agreement.

 

    Neither our Partnership Agreement nor any other agreement requires ATLS to pursue a business strategy that favors us.

 

    Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

 

    Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional Partnership securities and the level of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders.

 

    Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

 

    Our Partnership Agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf.

 

    Our general partner intends to limit its liability regarding our contractual and other obligations.

Furthermore, affiliates of our general partner, including ARP and ATLS, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, ATLS may compete with us for investment opportunities and may own an interest in entities that compete with us. ATLS and its affiliates may acquire, develop or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets.

ATLS is an established participant in the oil and natural gas industry and has resources greater than ours, which factors may make it more difficult for us to compete with ATLS with respect to commercial activities as well as for potential acquisitions. As a result, competition from ATLS and its affiliates could adversely impact our results of operations and cash available for distribution to our unitholders.

 

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There are no restrictions applying to our general partner or any of its affiliates, including its executive officers and directors and ATLS regarding business opportunities. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and the Partnership or any other partner, on the other hand, our general partner will resolve that conflict. Subject to restrictions described below, our general partner and its affiliates will not be in breach of any obligations under our Partnership Agreement or any duties to you and other unitholders or to us if the resolution of a conflict is:

 

    approved by the conflicts committee of the board of directors of our general partner;

 

    approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates; or

 

    on terms no less favorable to us than those generally being provided to or available from unrelated third parties.

If, however, a proposed conflict of interest is material to our business and operations, only the resolution procedures in the first two bullet points will be applicable.

The Post-Listing Partnership Agreement, which will not become effective unless a listing event occurs, contains similar provisions regarding the resolution of conflicts of interest, except that the standards of the third bullet point may be applied to all conflicts of interest, without limitation (including those that are material to our business and operations), and that a conflict may be resolved if the resolution is fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be favorable or advantageous to us.

Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors or from you and other unitholders. The existence of all conflicts of interest described herein, including from the transactions described herein, and any actions of our general partner taken in connection with such conflicts of interest, will be deemed approved by all of our limited partners pursuant to our Partnership Agreement and, if a listing event occurs, the Post-Listing Partnership Agreement. If our general partner seeks approval by the conflicts committee of the board of directors of our general partner of any such action or resolution, it will be presumed that, in making its decision, the conflicts committee acted in good faith in the best interest of the Partnership. If our general partner does not seek approval from the conflicts committee or from the holders of common units and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies the standard set forth in the third bullet point above (or, alternatively, with respect to the Post-Listing Partnership Agreement, the fairness standard referred to in the previous paragraph), then it will be presumed that, in making its decision, the board of directors acted in good faith in the best interest of the Partnership, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our Partnership Agreement or the Post-Listing Partnership Agreement, our general partner or the conflicts committee may consider any factor it determines in good faith to consider when resolving a conflict. When our Partnership Agreement and the Post-Listing Partnership Agreement require someone to act in good faith, the agreements require that person to believe that he is not acting adversely to the interests of the Partnership.

 

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Fiduciary Duties

The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, restrict, expand or eliminate any fiduciary duties owed by general partners to other partners and the partnership. Our Partnership Agreement and the Post-Listing Partnership Agreement eliminate any default fiduciary standards owed to us or our limited partners, to the extent described further below.

We have adopted these standards to allow our general partner, ATLS and their affiliates to engage in transactions with us that could otherwise be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage us in good faith and a duty to manage our general partner in a manner beneficial to its owner. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest could be restricted. These modifications also enable our general partner to take into consideration all parties involved in the proposed action. Further, these modifications also strengthen the ability of our general partner to attract and retain experienced and capable directors. However, these modifications disadvantage the holders of common units because they restrict the rights and remedies that would otherwise be available to them for actions that, without such modifications, might constitute breaches of fiduciary duties, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of:

 

    the default fiduciary duties under the Delaware Act; and

 

    the standards contained in our Partnership Agreement and the Post-Listing Partnership Agreement that replace the default fiduciary duties.

State Law Fiduciary Duty Standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require that any action taken or transaction engaged in be entirely fair to the partnership.

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties or of the partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of itself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

Partnership Agreement

Our Partnership Agreement and the Post-Listing Partnership Agreement eliminate any default fiduciary standards owed to us or the other partners. Instead, our general partner, and its directors and officers, will be accountable to us and our limited partners pursuant to the contractual standards set forth in our Partnership Agreement and the Post-Listing Partnership Agreement. In this regard, our Partnership Agreement permits our general partner and its affiliates to:

 

    have business interests or activities that may conflict with the Partnership;

 

    devote only so much of their time as is necessary to manage the affairs of the Partnership, as determined by our general partner in its sole discretion;

 

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    conduct business with the Partnership in a capacity other than as general partner or sponsor as described in our Partnership Agreement;

 

    with respect to farmouts to the general partner and its affiliates or unaffiliated third parties, our general partner will be subject to the lesser standard of prudent operator;

 

    manage multiple programs simultaneously; and

 

    be indemnified and held harmless as described below.

Our Partnership Agreement requires that, when our general partner is acting in its capacity as general partner, as opposed to in its individual capacity, it must act in “good faith in the best interest” of the Partnership, meaning that it believed that the decision was beneficial to our interests. The Post-Listing Partnership Agreement requires that, when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning that it believed that the decision was not adverse to the Partnership’s interests. Moreover, our Partnership Agreement and the Post-Listing Partnership Agreement provide that, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any duty or obligation to us or our limited partners whatsoever other than as set forth below. These contractual standards reduce the obligations to which our general partner would otherwise be held.

In addition to the other more specific provisions limiting the obligations of our general partner, our Partnership Agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner’s or its officers’ and directors’ course of conduct was the result of negligence or misconduct.

In addition, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons, as described in “Summary of The Partnership Agreement—Indemnification.” We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons’ course of conduct was the result of negligence or misconduct. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable.

By accepting or purchasing common units, each limited partner automatically agrees to be bound by the provisions in our Partnership Agreement and the Post-Listing Partnership Agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or transferee to sign a partnership agreement does not render our Partnership Agreement, and will not render the Post-Listing Partnership Agreement, unenforceable against that person.

Procedures to Reduce Conflicts of Interest

Leases Will Be Acquired Only for Stated Purpose of the Partnership

We must acquire only leases that are reasonably expected to meet the stated purposes of the Partnership. Also, no leases may be acquired for the purpose of a subsequent sale, farmout or other disposition unless the acquisition is made after a well has been drilled to a depth sufficient to indicate that the acquisition would be in our best interest.

 

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General Partner May Waive Lease Encroachments by Affiliated Programs and May Waive Lease Encroachments by the Partnership, If Any

It is possible that a horizontal well drilled by us may encroach on lease interests covering a well that was previously drilled by another entity sponsored by or affiliated with our general partner or its affiliates. In that event, the encroachment will be waived and allowed by the other entity without restriction or charge to us unless our general partner determines, in its discretion, that the encroachment by our well results in drainage from the other entity’s well. In that event, we shall compensate the other entity for the drainage, either by a cash payment or the assignment of an overriding royalty interest or a portion of the working interest in the Partnership well that encroaches on the other entity’s well, as determined by our general partner in its discretion, consistent with its or its affiliates’ duties to us and the other entities. On the other hand, these provisions shall also apply to us if there is encroachment on a previously drilled Partnership well as a result of horizontal drilling conducted by an entity sponsored by or affiliated with our general partner or its affiliates, including drilling partnerships sponsored by our general partner in the future.

Transfer of Less than our General Partner’s and its Affiliates’ Entire Interest

Subject to the conflicts of interest provisions, a sale, transfer or a conveyance to the Partnership of less than all of the ownership of our general partner or an affiliate (excluding another program in which the interest of our general partner or its affiliates is substantially similar to or less than their interest in us) in any prospect shall not be made unless:

 

    the interest retained by our general partner or the affiliate is a proportionate working interest;

 

    the respective obligations of our general partner or its affiliates and us are substantially the same after the sale of the interest by our general partner or its affiliates; and

 

    our general partner’s interest in revenues does not exceed the amount proportionate to its retained working interest.

The foregoing does not prevent our general partner or its affiliates from subsequently dealing with their retained interest as they may choose with unaffiliated parties or affiliated entities.

Limitations on Sale of Undeveloped and Developed Leases to our General Partner

Subject to the conflicts of interest provisions, other than as set forth in “—Transfer of Leases Between Affiliated Limited Partnerships,” below, our general partner and its affiliates shall not purchase any undeveloped leases from us other than at the higher of cost or fair market value. However, when a well is plugged and abandoned our lease rights may be assigned by us to our general partner in return for a cash payment, farmout, overriding royalty interest or other interest in the prospect as determined by our general partner, in its sole discretion, consistent with its duties to us. Farmouts to our general partner and its affiliates may be made as set forth in “—Farmouts,” below. Subject to the foregoing, our general partner and its affiliates, other than an income program sponsored by an affiliate of our general partner, shall not purchase any producing natural gas or oil property from us unless the sale is in connection with the liquidation of the Partnership and the sale is at fair market value as supported by an appraisal of an independent expert.

Transfer of Equal Proportionate Interest

Subject to the conflict of interest provisions, when our general partner (excluding another program in which the interest of our general partner is substantially similar to or less than its interest in the Partnership) sells, transfers or conveys any natural gas, oil or other mineral interests or property to us, it must, at the same time, sell, transfer or convey to us an equal proportionate interest in all its other property in the same prospect. Notwithstanding the foregoing, a horizontal well may be drilled on the same prospect on which a vertical well is drilled. If the area constituting a Partnership prospect is subsequently enlarged to encompass any area in which our general partner (excluding another program in which the interest of our general partner is substantially

 

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similar to or less than its interest in us) owns a separate property interest and the activities of the Partnership were material in establishing the existence of proved undeveloped reserves that are attributable to the separate property interest, then the separate property interest or a portion thereof must be sold, transferred or conveyed to us as set forth under “—Transfer of Less than our General Partner’s and its Affiliates’ Entire Interest.” Notwithstanding the foregoing, prospects drilled to the Mississippi Lime formation, the Marble Falls reservoirs, the Eagle Ford Shale or any other formation or reservoir shall not be enlarged or contracted except in our general partner’s discretion if the prospect was limited because the well was being drilled to prove reserves and to protect against drainage.

Transfer of Leases Between Affiliated Limited Partnerships

Subject to the conflicts of interest provisions, the transfer of an undeveloped lease from the Partnership to another entity as supported by an appraisal from an independent expert sponsored or managed by, or affiliated with, our general partner or its affiliates must be made at fair market value if the undeveloped lease has been held by us for more than two years. Any such appraisal must be maintained in our records for at least six years. Otherwise, if our general partner deems it to be in our best interest, the transfer may be made at cost. An income program sponsored by an affiliate of our general partner may purchase a producing natural gas and oil property from us at any time at:

 

    fair market value as supported by an appraisal from an independent expert if the property has been held by us for more than six months or we have made significant expenditures in connection with the property. Any such appraisal of the property must be maintained in our records for at least six years; or

 

    cost, as adjusted for intervening operations, if our general partner deems it to be in our best interest.

However, these prohibitions shall not apply to joint ventures or farmouts among affiliated entities, provided that:

 

    the respective obligations and revenue sharing of all parties to the transaction are substantially the same; and

 

    the compensation arrangement or any other interest or right of either our general partner or its affiliates is the same in each affiliated entity, or, if different, the aggregate compensation of our general partner or the affiliate is reduced to reflect the lower compensation arrangement.

Services

Except as provided in our Partnership Agreement, our general partner shall not be compensated for its services as a general partner or managing member of any subsidiary of the Partnership.

Reimbursement of our General Partner

Our general partner shall be reimbursed by us on a monthly basis, or such other basis as our general partner may determine, for all administrative costs, so long as they are supportable as to the necessity thereof and the reasonableness of the amount charged and are supported by appropriate invoices or other documentation and, in addition, (i) all direct and indirect expenses it incurs or payments it makes on our behalf (including salary, bonus, incentive compensation, employee benefits and other amounts paid to any person, including affiliates of our general partner, to perform services for us or for our general partner in the discharge of its duties to us), (ii) compensation to, and expenses of, the directors of our general partner incurred in connection with the performance of services for us, and (iii) all other expenses allocable to us or otherwise incurred by our general partner in connection with managing and operating our business and affairs (including expenses allocated to our general partner by its affiliates). Our general partner shall determine the expenses that are allocable to us. Reimbursements pursuant to this subsection may be paid out of capital contributions and out of Partnership revenues and shall be in addition to any reimbursement to our general partner as a result of indemnification.

 

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Cost allocations must be audited annually by our general partner’s independent certified public accounting firm. The independent certified public accounting firm must provide written attestation annually, to be included as part of the Partnership’s annual report, that the method used to make allocations was consistent with the method described in the prospectus and that the total amount of costs allocated did not materially exceed the amounts incurred by our general partner. If our general partner subsequently decides to allocate expenses in a manner different from that described in the prospectus, such change must be reported to the unitholders together with an explanation of why such change was made and the basis used for determining the reasonableness of the new allocation method. The amount of reimbursements paid to our general partner are subject to only narrow limits in certain circumstances: (1) the reimbursements of organization and offering costs to our general partner are limited to 2% of the aggregate proceeds of the primary offering if less than $500 million is raised or 1.5% if $500 million or more is raised, in each case excluding the DRIP; and (2) the reimbursements of administrative costs to our general partner are limited to those supportable as to the necessity of such reimbursement and the reasonableness of the amount charged and supported by appropriate invoices or other documentation and other considerations. Otherwise, our Partnership Agreement and the other agreements we have with our general partner do not place meaningful limits on the magnitude of potential reimbursements; specifically, our general partner will determine which costs incurred are reimbursable and there are no limits on the amount of reimbursements on administrative costs to be paid to our general partner.

Our general partner shall bear a percentage of direct costs and administrative costs equal to its percentage of revenue participation.

Our general partner, without the approval of our limited partners (who shall have no right to vote in respect thereof), may propose and adopt on our behalf benefit plans, programs and practices (including plans, programs and practices involving the issuance of Partnership interests or options to purchase or rights, warrants or appreciation rights or phantom or tracking interests relating to Partnership interests), or cause us to issue Partnership interests in connection with, or pursuant to, any benefit plan, program or practice maintained or sponsored by our general partner or any of its affiliates, in each case for the benefit of employees and directors of our general partner or any of its affiliates, in respect of services performed, directly or indirectly, for the benefit of the Partnership. We agree to issue and sell to our general partner or any of its affiliates any Partnership interests that our general partner or such affiliate is obligated to provide to any employees and directors pursuant to any such benefit plans, programs or practices. Expenses incurred by our general partner in connection with any such plans, programs and practices (including the net cost to our general partner or such affiliate of Partnership interests purchased by our general partner or such affiliate from us or otherwise, to fulfill options or awards under such plans, programs and practices) shall be reimbursed in accordance with this section. Any and all obligations of our general partner under any benefit plans, programs or practices adopted by our general partner as permitted by this section shall constitute obligations of our general partner and shall be assumed by any successor general partner or the transferee of or successor to all of our general partner’s general partner interest (represented by GP units).

Competitive Rates

Our general partner and any affiliate shall not render to the Partnership any oil field, equipage, drilling or other services nor sell or lease to the Partnership any equipment or related supplies unless:

 

    except as provided below, the person is engaged, independently of the Partnership and as an ordinary and ongoing business, in the business of rendering the services or selling or leasing the equipment and supplies to a substantial extent to other persons in the natural gas and oil industry in addition to the entities in which our general partner or any of its affiliates has an interest; and

 

    the compensation, price, or rental therefor is competitive with the compensation, price, or rental of other persons in the area engaged in the business of rendering comparable services or selling or leasing comparable equipment and supplies which could reasonably be made available to us.

 

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If the person is not engaged in such a business, then the compensation, price or rental shall be the cost of the services, equipment or supplies to the person or the competitive rate which could be obtained in the area, whichever is less.

Our general partner or its affiliates, as operator or drilling contractor, may not do the following:

 

    receive a rate that is not competitive with the rates charged by unaffiliated operators or contractors in the same geographic region or that is duplicative of any consideration or reimbursements pursuant to our Partnership Agreement;

 

    profit by drilling in contravention of its fiduciary obligations to us;

 

    benefit by interpositioning itself between us and the actual provider of operating or drilling contractor services; and

 

    with respect to serving as drilling contractor, enter into a turnkey drilling contract with us.

If Not Disclosed in our Partnership Agreement, Then Services by our General Partner Must be Described in a Separate Contract and Cancelable

Any services for which our general partner or an affiliate is to receive compensation, other than those described in our Partnership Agreement, shall be set forth in a written contract that precisely describes the services to be rendered and all compensation to be paid. These contracts shall be cancelable without penalty on 60 days’ written notice by unitholders whose common units equal a majority of the outstanding common units. As of September 30, 2015, there is no such written contract regarding services by our general partner or an affiliate. However, we may enter into any such written contract with our general partner or an affiliate in the future.

No Loans from the Partnership

No loans or advances shall be made by us to our general partner or its affiliates.

Farmouts

The decision with respect to making a farmout and the terms of a farmout involve conflicts of interests, as our general partner may benefit from the cost savings and reduction of risk. Our general partner shall not enter into a farmout to avoid paying its share of costs, if any, related to drilling a well on an undeveloped lease. The Partnership shall not farmout an undeveloped lease or well activity to our general partner or its affiliates, except that this restriction shall not apply to farmouts between us and another entity managed by our general partner or its affiliates, either separately or jointly, provided that the respective obligations and revenue sharing of all parties to the transactions are substantially the same and the compensation arrangement or any other interest or right of our general partner or its affiliates is the same in each entity, or, if different, the aggregate compensation of our general partner and its affiliates is reduced to reflect the lower compensation agreement. We may farmout an undeveloped lease or well activity only if our general partner, exercising the standard of a prudent operator, determines that:

 

    we lack the funds to complete the oil and gas operations on the lease or well and cannot obtain suitable financing;

 

    drilling on the lease or the intended well activity would concentrate excessive funds in one location, creating undue risks to us;

 

    the leases or well activity have been downgraded by events occurring after assignment to us so that development of the leases or well activity would not be desirable; or

 

    the farmout is in our best interests.

 

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If we farmout a lease or well activity, our general partner must retain on our behalf the economic interests and concessions as a reasonably prudent oil and gas operator would or could retain under the circumstances prevailing at the time, consistent with industry practices. If we acquire an undeveloped lease pursuant to a farmout or joint venture from an entity affiliated with our general partner or its affiliates, our general partner’s and its affiliates’ aggregate compensation associated with the property and any direct and indirect ownership interest in the property may not exceed the lower of the compensation and ownership interest our general partner and/or its affiliates could receive if the property were separately owned or retained by either us or the affiliated entity.

No Compensating Balances

Neither our general partner nor any affiliate shall use the Partnership’s funds as compensating balances for its own benefit.

Future Production

Neither our general partner nor any affiliate shall commit the future production of a well developed by the Partnership exclusively for its own benefit.

Marketing Arrangements

All benefits from marketing arrangements or other relationships affecting the property of our general partner or its affiliates, including its affiliated partnerships and the Partnership, shall be fairly and equitably apportioned according to the respective interests of each in the property.

Disclosure

Any agreement or arrangement that binds the Partnership must be fully disclosed in this prospectus.

Participation in Other Partnerships

If the Partnership participates in other partnerships or joint ventures (multi-tier arrangements), then the terms of any of these arrangements shall not result in the circumvention of any of the requirements or prohibitions contained in our Partnership Agreement, including the following:

 

    there shall be no duplication or increase in organization and offering costs, our general partner’s compensation, Partnership expenses or other fees and costs;

 

    there shall be no substantive alteration in the fiduciary and contractual relationship between our general partner and the unitholders; and

 

    there shall be no diminishment in the voting rights of the unitholders.

Organization and Offering Expenses

All organization and offering expenses incurred in order to sell common units shall be reasonable. Additionally, the total reimbursements of organization and offering expenses that may be charged to the Partnership, plus any management fee in connection with the organization of the offering paid from offering proceeds shall not exceed 15.00% of the gross proceeds received by us.

Acquisition from Unaffiliated Person

During a period of five years from the date of formation of the Partnership, if our general partner or any of its affiliates proposes to acquire an interest from an unaffiliated person in a prospect in which we possess an

 

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interest or in a prospect in which our interest has been terminated without compensation within one year preceding such proposed acquisition, and (i) none of our general partner or its affiliates owns property in the prospect separately from us, then none of our general partner or its affiliates shall be permitted to purchase an interest in the prospect; and (ii) if our general partner or its affiliates currently own a proportionate interest in the prospect separately from us, then the interest to be acquired shall be divided between us and our general partner or its affiliates, as applicable, in the same proportion as is the other property in the prospect; provided, however, if cash or financing is not available to us to enable us to consummate a purchase of the additional interest to which we are entitled, then none of our general partner or its affiliates shall be permitted to purchase any additional interest in the prospect.

Rebates

Our general partner and its affiliates may not accept any rebates or give-ups or participate in any reciprocal business arrangements that would circumvent the provisions of our Partnership Agreement.

Safekeeping of Funds

Our general partner may not employ, or permit another to employ, the funds or assets of the Partnership in any manner except for our exclusive benefit. Our general partner has a fiduciary responsibility for the safekeeping and use of all our funds and assets whether or not in our general partner’s possession or control.

Advance Payments

Advance payments by us to our general partner and its affiliates are prohibited except when advance payments are required to secure the tax benefits of prepaid drilling costs. These payments, if any, shall not include nonrefundable payments for completion costs prior to the time that a decision is made that the well or wells warrant a completion attempt.

Cost of Leases

Subject to the conflicts of interest provisions of our Partnership Agreement, all leases sold to us by our general partner or its affiliates, including those from our general partner’s or an affiliate’s existing inventory, if any, shall be sold on terms that are fair and reasonable to the unitholders. All leases sold to us by our general partner or its affiliates shall be sold at the cost of the lease, unless the general partner has cause to believe that such cost is materially more than the fair market value of the lease, in which case the lease must be sold to us at a price not in excess of the fair market value. However, if the transfer is from an affiliated partnership that has held the lease for more than two years, then the transfer may be made at fair market value if our general partner’s interest is substantially similar to, or less than, its interest in the Partnership. Also, our general partner may average the cost of the leases by area or type of drilling to arrive at an average cost of the leases per prospect for each area which our general partner believes is less than fair market value. A determination of fair market value must be supported by an appraisal from an independent expert.

Provisions Regarding “Roll-Ups” in the Partnership Agreement

It is possible at some indeterminate time in the future that we may become involved in a “roll-up” as defined in our Partnership Agreement. In general, a “roll-up” means a transaction involving the acquisition, merger, conversion or consolidation of the Partnership with or into another partnership, corporation or other entity, and the issuance of securities by the “roll-up” entity to you and the other investors. A “roll-up” will also include any change in the rights, preferences and privileges of you and the other investors in the Partnership. These changes could include the following:

 

    increasing the compensation of our general partner;

 

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    amending your voting rights;

 

    changing the fundamental investment objectives; or

 

    materially altering our duration.

If a “roll-up” should occur in the future, our Partnership Agreement provides various policies that include the following:

 

    an independent expert must appraise all of our assets as discussed in §4.03(d)(15)(a) of our Partnership Agreement and you must receive a summary of the appraisal;

 

    if you vote “no” on the “roll-up” proposal, then you will be offered a choice of:

 

    accepting the securities of the “roll-up” entity; or

 

    one of the following:

 

    remaining a partner in the Partnership and preserving your common units in the Partnership on the same terms and conditions as existed previously; or

 

    receiving cash in an amount equal to your pro rata share of the appraised value of our net assets;

 

    we will not participate in a proposed “roll-up”:

 

    unless approved by unitholders whose common units equal a majority of the total common units;

 

    that would result in the diminishment of your voting rights under the “roll-up” entity’s chartering agreement;

 

    that includes provisions that would operate to materially impede or frustrate the accumulation of shares by you of the securities of the “roll-up” entity;

 

    in which your right of access to the records of the “roll-up” entity would be less than those provided by our Partnership Agreement; or

 

    in which any of the transaction costs would be borne by the Partnership if the proposed “roll-up” is not approved by unitholders whose common units equal a majority of the total common units.

A “roll-up” does not include:

 

    a transaction involving our securities that have been listed for at least 12 months on a national securities exchange; or

 

    a transaction involving the conversion to corporate, trust or association form of only us if, as a consequence of the transaction, there will be no significant adverse change in any of the following:

 

    voting rights;

 

    our term of existence;

 

    our general partner’s compensation; and

 

    our investment objectives; or

 

    a transaction involving the issuance of securities of any entity where securities of the same class have been listed for at least 12 months on a national securities exchange.

 

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COMPENSATION

The following table summarizes the compensation to be paid to our general partner and the other persons listed below.

Compensation Related to the Organization of the Partnership and Offering of Units

 

Type of Compensation

  

Method of Compensation

  

Estimated Dollar Amount

Offering Stage
Dealer manager fee (payable to Anthem Securities, Inc., an affiliate of our general partner)(1)    3.00% of the gross proceeds from the sale of Class A common units and Class T common units. We will not pay a dealer manager fee with respect to sales under the DRIP. Our dealer manager may reallow up to 50% of the dealer manager fee to participating broker-dealers. Our dealer manager anticipates, based on its past experience, that, on average, it will reallow 41.67% of the dealer manager fee to participating broker-dealers.   

Because dealer manager fees are based on the aggregate offering proceeds, the total amount of dealer manager fees cannot be determined until this offering is complete.

 

Dealer manager fees of $30,000 will be paid if the minimum of 100,000 common units is sold in the offering, and dealer manager fees of $30,000,000 will be paid if the maximum of 100,000,000 common units is sold in the offering.

Sales commissions (payable to Anthem Securities, Inc., an affiliate of our general partner)(1)    7.00% and 3.00% of the gross proceeds from the sale of Class A common units and Class T common units, respectively. We will not pay any sales commissions on sales of units under the DRIP. Our dealer manager may reallow all or a portion of sales commissions to participating broker-dealers.   

Because sales commissions are based on the aggregate offering proceeds and the distribution of sales between Class A common units and Class T common units, the total amount of sales commissions cannot be determined until this offering is complete.

 

Assuming 70% of the common units sold in this offering are Class A common units and 30% of the common units sold in this offering are Class T common units, sales commissions of $58,000 will be paid if the minimum of 100,000 common units is sold in the offering, and sales commissions of $58,000,000 will be paid if the maximum of 100,000,000 common units is sold in the offering. Our estimate that 70% of the common units sold in this offering will be Class A common units and 30% of the common units sold in this offering will be Class T common units was based on discussions with Anthem Securities Inc., our

 

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Type of Compensation

  

Method of Compensation

  

Estimated Dollar Amount

     

broker-dealer. Based on our discussions with Anthem Securities, Inc., we believe our estimate that 70% of the common units sold in this offering are Class A common units and 30% of the common units sold in this offering are class T common units is reasonable. Because this may not accurately reflect the actual number of Class A common units and Class T common units sold as the offering progresses, we may revise respective percentages of Class A common units and Class T common units of the total common units sold during the continuing offering period.

 

Organization and offering expenses (reimbursable to our general partner)    Any out-of-pocket organization and offering expenses (other than the dealer manager fee, sales commission and distribution and unitholder servicing fee) paid by our general partner relating to the offering of the Partnership, including legal costs, filing fees and similar costs, which our general partner incurs on our behalf, up to a maximum expense cap that ranges from 1.5%–2% of the gross proceeds from our primary offering, depending on the gross proceeds from common units sold. Our general partner and its affiliates will not be reimbursed for the direct payment of any organization and offering expenses (other than the dealer manager fee, sales commission and distribution and unitholder servicing fee) that exceed 2.0% of the aggregate gross proceeds of our primary offering over the life of the offering if we raise less than $500 million or 1.5% if we raise $500 million or more, in each case excluding DRIP.    Cannot be estimated at this time.

 

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Type of Compensation

  

Method of Compensation

  

Estimated Dollar Amount

Operational Stage
Distribution and unitholder servicing fee (payable to Anthem Securities, Inc., an affiliate of our general partner)   

We will pay to our dealer manager a distribution and unitholder servicing fee in the aggregate amount of 4.00% of the gross proceeds from the sale of Class T common units, which distribution and unitholder servicing fee will be withheld from cash distributions otherwise payable to the purchasers of Class T common units at a rate of $0.025 per quarter per unit. Assuming our initial quarterly distribution is $0.175 per unit per quarter and we withhold $0.025 per unit per quarter, the holders of Class T common units will receive net quarterly distribution of $0.15 per unit until the deferred payment obligation is fulfilled or the Class T common units convert into Class A common units or are redeemed (for a maximum of up to 16 quarters). Our dealer manager may reallow all or a portion of the distribution and unitholder servicing fees to participating broker-dealers.

 

We will cease paying the distribution and unitholder servicing fee with respect to any particular Class T common unit and that Class T common unit will convert into Class A common units at the conversion rate described herein on the earliest of (i) a liquidity event and (ii) the end of the month in which the underwriting compensation paid in the primary offering plus the quarterly distribution and unitholder servicing fee paid with respect to that Class T common unit equals 10% of the gross offering price of that Class T common unit. We will further cease paying the quarterly distribution and unitholder servicing fee on any Class T

  

Because the distribution and unitholder servicing fees are based on the aggregate offering proceeds, the total amount of the distribution and unitholder servicing fees cannot be determined until this offering is complete.

 

Assuming 70% of the common units sold in this offering are Class A common units and 30% of the common units sold in this offering are Class T common units, sales commissions of $58,000 will be paid if the minimum of 100,000 common units is sold in the offering, and sales commissions of $58,000,000 will be paid if the maximum of 100,000,000 common units is sold in the offering. Our estimate that 70% of the common units sold in this offering will be Class A common units and 30% of the common units sold in this offering will be Class T common units was based on discussions with Anthem Securities Inc., our broker-dealer. Based on our discussions with Anthem Securities, Inc., we believe our estimate that 70% of the common units sold in this offering are Class A common units and 30% of the common units sold in this offering are class T common units is a reasonable estimate on which to base our calculations. Because this may not accurately reflect the actual number of Class A common units and Class T common units sold, we may revise the respective percentages of Class A common units and Class T common units of the total common units sold during the continuing offering period.

 

 

 

 

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Type of Compensation

  

Method of Compensation

  

Estimated Dollar Amount

  

common unit that is redeemed or repurchased, as well as upon our dissolution, liquidation or the winding up of our affairs, or a merger or other extraordinary transaction in which the Partnership is a party and in which the Class T common units as a class are exchanged for cash or other securities. The conversion rate will be equal to the quotient, the numerator of which is the estimated value per Class T common unit (taking into account any reduction for the unpaid portion of the distribution and unitholder servicing fee as described herein) and the denominator of which is the estimated value per Class A common unit. If the Class T common units are converted to Class A common units at a time when there are unpaid distribution and unitholder servicing fees, a Class T common unitholder will likely receive fewer than one Class A common unit in exchange for each Class T common unit.

 

The distribution and unitholder servicing fee is an ongoing fee that is not paid at the time of purchase.

  

General partner’s interest in available cash from operations (payable to our

general partner as holder of GP units when the board makes cash distributions)

  

Prior to a listing event, 2.00% to the holder of the GP units and

98.00% to the holders of the common units.

 

At and after a listing event:

 

First, 2% to the holder of the GP units and 98% to the holders of the common units, until each unitholder has received a $0.175 per common unit quarterly distribution;

 

Second, 2% to the holder of the GP units, 85% to the common units and 13% to the holder of the IDRs, which will initially be our general

  

Not determinable as of the date hereof.

 

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Type of Compensation

  

Method of Compensation

  

Estimated Dollar Amount

  

partner, until each unitholder has received a $0.20125 per common unit quarterly distribution;

Third, 2% to the holder of the GP units, 75% to the common units and 23% to the holder of the IDRs, until each common unitholder has received a $0.21875 quarterly distribution; and

 

After that, 2% to the holder of the GP units, 50% to the common units and 48% to the holder of the IDRs.

 

The cash amounts received by the general partner with respect to its IDRs are in addition to the common units issued to our general partner after a listing event. Please read “—Common unit issuance in lieu of IDRs to our general partner after a listing event” below.

  
General partner’s interest in cash from capital surplus    First, 2.00% of the holder of the GP units and 98.00% to the holders of common units until holders of common units have received an aggregate amount equal to the initial common units price, as the same may be adjusted pursuant to the Partnership Agreement, and, thereafter, as with available cash from operating surplus.    Not determinable as of the date hereof.
Management fee (payable quarterly to general partner)    1.00% of total capital contributions.   

Management fee on minimum offering amount: $10,000 per year.

Management fee on maximum offering amount: $10,000,000 per year. For information regarding historical management fee payments, please read Note 8 of the Notes to Consolidated Financial Statements for Periods ended December 31, 2014 and 2013.

Direct costs (reimbursable to our general partner, ATLS or their affiliates)    Expenses incurred by our general partner, ATLS or their affiliates in connection with the management    Assuming the maximum offering amount is received, our general partner estimates that the

 

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Type of Compensation

  

Method of Compensation

  

Estimated Dollar Amount

   and operation of the Partnership’s business. Direct costs will be determined by our general partner, in its sole discretion. Direct costs will be billed directly to and paid by the Partnership to the extent practicable.   

maximum amount of direct costs to be borne annually by the Partnership will be $735,000, composed of:

 

•       $50,000 for external legal costs;

     

 

•       $250,000 for accounting fees for audit and tax preparations;

 

•       $35,000 for independent engineering reports; and

 

•       $400,000 for transfer agent fees.

Directors’ fees and costs (payable or reimbursable to our general partner)    Annual directors’ fees and costs for directors of general partner in connection with services to the Partnership.    $100,000 per year plus annual grants of rights to receive common units upon a liquidity event. Please read “Management—Director Compensation.”
Common unit issuance in lieu of IDRs to our general partner at a listing event   

Upon the occurrence of a listing event, our general partner, as holder of the IDRs, will receive an aggregate number of common units equal to:

 

•    the IDR Sales Distribution (as set forth in the third section of “—General partner’s interest in proceeds of a sale (payable to our general partner)” below), divided by

 

•    the volume weighted average price of the common units for the initial five days after listing on the exchange on which they are traded, or the initial VWAP.

 

For purposes of determining the IDR Sales Distribution with respect to a listing event, the available cash from a sale of the Partnership will be calculated as follows:

 

•    the number of common units outstanding

   Not determinable as of the date hereof.

 

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Type of Compensation

  

Method of Compensation

  

Estimated Dollar Amount

  

immediately prior to listing, multiplied by

 

•    1.0204, multiplied by

 

•    the initial VWAP.

 

The listing event distribution is designed to provide our general partner a 20% interest in the Partnership following the listing event, but only after the limited partners have received a return of their initial capital contribution together with a 7% non-compounded annual return.

  
Common unit issuance in lieu of IDRs to our general partner after a listing event   

After a listing event, if the Calculated IDR Amount exceeds the Actual IDR Amount (each as defined below) for any quarter following the listing event, then our general partner, as holder of the IDRs, will receive an aggregate number of common units equal to the excess of the Calculated IDR Amount over the Actual IDR Amount, divided by the volume weighted average price of the common units during the five trading days preceding the end of the quarter.

 

“Actual IDR Amount” means the amount of distributions made pursuant to the IDRs in the fiscal quarter for which the calculation is being made.

 

“Calculated IDR Amount” means the amount of distributions the holder of the IDRs would have received in the fiscal quarter for which the calculation is being made from the Partnership’s net cash absent the effect of reserves established by our general partner and other related adjustments.

 

These provisions establish what would have been paid to the holder of the IDRs absent reserves

   Not determinable as of the date hereof.

 

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Type of Compensation

  

Method of Compensation

  

Estimated Dollar Amount

  

established by our general partner for acquisition and drilling operations, utilizing a 1.1x coverage ratio. Please read “Cash Distribution Policy and Restrictions on Distributions.”

  
Liquidating Stage
General partner’s interest in proceeds of a sale (payable to our general partner)   

In the event of a sale, the Partnership will pay available cash:

 

First, 100.00% to the holders of the common units until they have received an amount equal to their capital contributions plus the target distribution per Unit for each quarter from the date of purchase through the sale, less all amounts previously distributed with respect to such interests.

   Not determinable as of the date hereof.

 

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Type of Compensation

  

Method of Compensation

  

Estimated Dollar Amount

  

 

Second, 100.00% to the holder of the GP units until they have received, including amounts previously received, an amount equal to 2.04% of the excess of (A) amounts distributed to the holders of the common units from operating surplus and clause first above, over (B) the product of $10.00 multiplied by the number of common units outstanding at the time of the sale.

 

Third, 100.00% to the holder of the incentive distribution rights, or IDRs, until it has received an amount equal to the sum of (A) the product of 25.00% multiplied by the sum of (x) the amount distributed to the common unit holders pursuant to clause first above plus (y) other amounts previously distributed with respect to the common units less (z) the product of $10.00 multiplied by the number of common units then outstanding, plus (B) the sum of all capital contributions with respect to our general partner interest, less (C) amounts previously distributed with respect to our IDRs (the amount of the distribution upon a sale that is distributed to the holder of the IDRs is referred to as the IDR Sales Distribution).

 

After that, 80.00% to the holders of the common units and 20.00% to the holder of the Incentive Distribution Rights.

  
General partner’s interest in proceeds of a merger (payable to our general partner)    Consideration to be received in the event of a merger shall be valued based upon the price attributable thereto in the merger agreement and be distributed in accordance with the provisions for distributions in the event of a sale.    Not determinable as of the date hereof.

 

(1)  Dealer manager compensation and sales commissions may be reduced in certain circumstances. Please read “Plan of Distribution—Volume Discounts for Class A Common Units.”

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

ATLS controls our general partner and, as of the conclusion of the private placement offerings, owns approximately 2.19% of our outstanding common units. ATLS also indirectly owns 80.01% of the voting membership interests in our general partner, and current and former members of ATLS management own the remaining 19.99% membership interest in our general partner. Our general partner owns a 2.00% general partner interest in us.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, were not the result of arm’s-length negotiations.

Formation Stage and Initial Offering

 

The consideration (excluding units purchased by our general partner and ATLS) received by our general partner and ATLS prior to or in connection with the prior offering    Approximately $4.6 million in cash (in organizational and offering expense reimbursement).
The fees received by Anthem Securities, Inc. with respect to the initial offering   

•       $6.9 million dealer manager fees; and

 

•       $16.2 million sales commission.

Development Stage and Current Offering

  
For information regarding fees to be paid to Anthem Securities, Inc. in connection with this offering, please read “Compensation—Compensation Related to the Organization of the Partnership and Offering of Units.”   

Operational Stage

  
For information regarding distributions of available cash from operations to our general partner and its affiliates, please read “Compensation—Compensation Related to the Organization of the Partnership and Offering of Units.”   
Withdrawal or removal of our general partner    If our general partner is removed under circumstances where cause exists or withdraws and such withdrawal violates our Partnership Agreement, a successor general partner will have the option to purchase 20.00% of the departing general partner’s general partner interest in us, but not as a limited partner, for the value determined by an independent expert.

 

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Liquidation Stage

  
Liquidation    Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Related Party Agreements

We and certain of our affiliates have entered into various documents and agreements. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations.

Eagle Ford Acquisition

On September 24, 2014, the Partnership, together with ARP, entered into a purchase and sale agreement for the acquisition of oil and natural gas liquid interests in the Eagle Ford Shale in Atascosa County, Texas from Cinco Resources, Inc., or Cinco, and Cima Resources, LLC, a wholly owned subsidiary of Cinco, for an aggregate purchase price of $342.0 million, after all customary closing conditions. On November 5, 2014, the Partnership and ARP closed on the Eagle Ford Acquisition. Approximately $183.1 million was paid in cash by ARP and $19.9 million was paid by the Partnership at closing. In accordance with the terms of the purchase and sale agreement and a shared acquisition and operating agreement that we entered into with ARP, ARP agreed to pay approximately $23.4 million as deferred purchase price, and we agreed to pay approximately $115.6 million in the aggregate as deferred purchase price, in each case over the five quarters following closing.

Assignment to ARP

On September 21, 2015, we and ARP, in accordance with the terms of the shared acquisition and operating agreement, agreed that ARP will fund the remaining two deferred purchase price installments of $16.2 million and $20.1 million to be paid on September 30, 2015 and December 31, 2015, respectively. In conjunction with this agreement, we assigned ARP a portion of our non-operating Eagle Ford assets that have an allocated value (as such value was agreed upon by the sellers and the buyers in connection with the Eagle Ford Acquisition) equal to both installments to be paid by ARP. The transaction was approved by our and ARP’s respective independent conflicts committees. As a result, our share of the aggregate purchase price was $99.2 million. The Eagle Ford Acquisition had an effective date of July 1, 2014.

Sale of Oil and Natural Gas Properties

On July 8, 2015, we sold to ARP a portion of the wells we acquired in the Eagle Ford acquisition for a purchase price of $1.36 million, which represented AGP’s cost for the properties.

Registration Rights in Partnership Agreement

In the Post-Listing Partnership Agreement, we will agree to register for resale under the Securities Act and applicable state securities laws any common units or other partnership securities proposed to be sold by our general partner, ATLS or any of their respective affiliates if an exemption from the registration requirements is not otherwise available. There is no limit on the number of times that we may be required to file registration statements pursuant to this obligation. We will also agree to include any securities held by our general partner, ATLS or any of their respective affiliates in any registration statement that we file to offer securities for cash, other than an offering relating solely to an employee benefit plan. These registration rights continue for two years following any withdrawal or removal of our general partner. We must pay all expenses incidental to the registration, excluding underwriting discounts and commissions. No registration rights will be given to the dealer manager.

 

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Review, Approval or Ratification of Transactions with Related Parties

Because the Partnership does not employ any persons, the Partnership relies on the code of business conduct and ethics adopted by ATLS that applies to the executive officers, employees and other persons performing services for ATLS and its affiliates generally. You may obtain a copy of this code of business conduct and ethics without charge at www.atlasenergy.com.

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our Partnership Agreement. Please read “Conflicts of Interest and Fiduciary Duties—Conflicts of Interest” for additional information regarding the relevant provisions of our Partnership Agreement.

 

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TERMS OF THE OFFERING

Subscription to the Partnership

We are currently offering for sale a minimum of 100,000 common units for gross proceeds of $1.0 million and a maximum of 100,000,000 common units for gross proceeds of $1.0 billion. We are offering common units representing limited partner interests at a price of $10.00 per unit until the final termination date, as described below. Investors generally must purchase an aggregate minimum of $5,000, or 500 common units, but investors who already own our common units may make purchases for less than the minimum investment so long as such purchases are made in $1,000 increments. Payment in full for the total purchase price must be made at the time of subscription, and a deferred payment option is not available. Also, some classes of investors, including our general partner and its executive officers and directors and others as described in “Plan of Distribution,” may buy common units at discounted prices because sales commissions and dealer manager fees will not be paid for those sales. Thus, investors who pay discounted prices for their common units may receive higher returns on their investments in the Partnership as compared to investors who pay the entire $10.00 per Unit.

The offering period will terminate on the earliest of (i) the sale of 100,000,000 common units, (ii)                     , 2018 (the two-year anniversary following the effectiveness of the registration statement of which this prospectus is a part) unless extended by our general partner, but not past                     , 2018 (six months following the two-year anniversary of the effectiveness of the registration statement of which this prospectus is a part) or (iii) the failure to receive the minimum subscriptions on or before                     , 2018, which is two years from the effective date of the registration statement of which this prospectus is a part. If subscriptions for the minimum subscription are not received and accepted by our general partner prior to                     , 2018, each investor’s subscription will be promptly returned along with any interest earned. Please read “—Partnership Closings and Escrow,” below. Our general partner may terminate the offering without notice at any time prior to the scheduled end of the offering period.

Partnership Closings and Escrow

You and the other investors should make your checks for common units payable to “UMB Bank, N.A., escrow agent for Atlas Growth Partners, L.P.” and give your check to your broker/dealer for submission to the dealer manager and escrow agent. Offering proceeds for the Partnership will be held in an interest bearing escrow account at the escrow agent until we have received offering proceeds of at least $1 million within the time frame required above in “—Subscription to the Partnership,” including any subscriptions by our general partner and its affiliates. If we do not receive such amount in such time frame, all subscriptions will be promptly returned along with interest earned, if any. Interest will accrue on funds in the escrow account as applicable to the short-term investments in which such funds are invested. During any period in which subscription proceeds are held in escrow, interest earned thereon will be allocated among subscribers on the basis of the respective amounts of their subscriptions and the number of days that such amounts were on deposit. Such interest will be paid to subscribers upon the termination of the escrow period, subject to withholding for taxes pursuant to applicable Treasury Regulations. We will bear all expenses of the escrow and, as such, any interest to be paid to any subscriber will not be reduced for such expense. Investors who invest prior to the minimum offering being achieved will receive, upon admission to the Partnership, a one-time distribution of interest for the period their funds were held in escrow. During our escrow period, offering proceeds will be invested only in institutional investments composed of, or secured by, securities of the United States government. After the funds are transferred to our account and before they are used in our operations, they may be temporarily invested in income producing short-term, highly liquid investments, in which there is appropriate safety of principal, such as U.S. Treasury Bills. Any such income shall be allocated pro rata to the unitholders providing such capital contributions. If our general partner determines that we may be deemed to be an investment company under the Investment Company Act of 1940, then we will take steps necessary to avoid being deemed such an investment company.

 

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On receipt of the minimum offering proceeds and written instructions to the escrow agent from our general partner and the dealer manager, our general partner, on behalf of the Partnership, will break escrow and transfer the escrowed offering proceeds (other than any accrued interest) to our account, which will be a separate account maintained for the Partnership, and begin operations for the Partnership. Our funds will not be commingled with the funds of any other entity. If the minimum offering proceeds are not received by the offering termination date, then the offering proceeds deposited in the escrow account will be promptly returned to you and the other subscribers in the Partnership with interest and without deduction for any fees.

Acceptance of Subscriptions

Your execution of the subscription agreement constitutes your offer to buy common units in the Partnership and to hold the offer open until either:

 

    your subscription is accepted or rejected by our general partner; or

 

    you withdraw your offer.

To withdraw your subscription agreement, you must give written notice to our general partner before your subscription agreement is accepted by our general partner.

Also, our general partner will:

 

    not complete a sale of Units to you until at least five business days after the date you receive a final prospectus; and

 

    send you a confirmation of purchase.

Subject to the foregoing, your subscription agreement will be accepted or rejected by the Partnership within 30 days of its receipt. Our general partner’s acceptance of your subscription is discretionary, and our general partner may reject your subscription for any reason without incurring any liability to you for this decision. If your subscription is rejected, then all of your funds will be promptly returned to you together with any interest earned on your subscription proceeds and without deduction for any fees.

When you will be admitted to the Partnership as a partner depends on whether your subscription is accepted before or after the Partnership breaks escrow. If your subscription is accepted:

 

    before breaking escrow, then you will be admitted to the Partnership not later than 15 days after the release from escrow of the investors’ subscription proceeds to the Partnership; or

 

    after breaking escrow, then you will be admitted to the Partnership not later than the last day of the calendar month in which your subscription was accepted by the Partnership.

Your execution of the subscription agreement and our general partner’s acceptance also constitute your:

 

    execution of the Partnership Agreement and acceptance of its terms and conditions as a limited partner; and

 

    grant of a special power of attorney to our general partner to file amended certificates of limited partnership and governmental reports, and perform certain other actions on behalf of you and the other unitholders as partners of the Partnership.

 

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SELECTED HISTORICAL FINANCIAL DATA

The following table presents our selected historical financial data, as of and for the periods indicated.

The statement of operations and cash flow data for the nine months ended September 30, 2015 and 2014 and the balance sheet data as of September 30, 2015 have been derived from our unaudited quarterly financial statements included elsewhere in this prospectus. The balance sheet data as of September 30, 2014 has been derived from our unaudited quarterly financial statements not included in this prospectus. The statement of operations and cash flow data for the periods ended December 31, 2014 and 2013, and the balance sheet data as of December 31, 2014 and 2013 are derived from our audited year-end financial statements included elsewhere in this prospectus. The unaudited financial statements have been prepared on the same basis as the audited financial statements and, in the opinion of our management, include all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the information set forth herein.

The selected historical financial and other operating data presented below should be read in conjunction with our audited financial statements and accompanying notes beginning on page F-2, unaudited financial statements and accompanying notes beginning on page F-24 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 104. Among other things, the historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.

 

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The following table should be read together with our combined consolidated financial statements and notes beginning on page F-2.

 

     Nine Months Ended
September 30,
    Periods Ended
December 31,
 
     2015     2014     2014     2013  
     (unaudited)              
     (in thousands, except per unit data)  

Statement of operations data:

        

Revenues:

        

Gas and oil production

   $ 8,007      $ 4,563      $ 5,707      $ 302   

Gain on mark-to-market derivatives

     760        —         —         —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     8,767        4,563        5,707        302   
  

 

 

   

 

 

   

 

 

   

 

 

 

Costs and expenses:

        

Gas and oil production

     1,684        1,552        2,070        80   

General and administrative

     529        251        627        211   

General and administrative – affiliate

     9,484        6,819        11,119        3,521   

Depreciation, depletion and amortization

     5,095        1,436        2,156        133   

Asset impairment

     7,291        —         6,880        —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

     24,083        10,058        22,852        3,945   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     (15,316     (5,495     (17,145     (3,643

Interest expense

     (14     —         —         —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Net loss

   $ (15,330   $ (5,495   $ (17,145   $ (3,643
  

 

 

   

 

 

   

 

 

   

 

 

 

Other financial data:

        

Adjusted EBITDA(1)

   $ (3,330   $ (4,059   $ (7,856   $ (3,510
  

 

 

   

 

 

   

 

 

   

 

 

 

Balance sheet data (at period end):

        

Property, plant and equipment, net

   $ 124,640      $ 14,805      $ 155,469      $ 3,913   

Total assets

     171,522        67,442        190,161        12,961   

Total partners’ capital

     158,281        42,267        67,510        4,563   

Cash flow data:

        

Net cash provided by (used in) operating activities

   $ (23,880   $ 492      $ 511      $ 4,147   

Net cash used in investing activities

     (65,643     (12,209     (67,619     (3,594

Net cash provided by financing activities

     94,343        54,533        91,754        8,206   

Capital expenditures

     20,777        12,147        12,873        3,594   

Operating data:

        

Net production

        

Natural gas (Mcfd)

     594        656        691        21   

Oil (Bpd)

     566        121        117        7   

NGLs (Bpd)

     84        85        88        3   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total (Mcfed)

     4,497        1,887        1,920        79   
  

 

 

   

 

 

   

 

 

   

 

 

 

Average sales price:

        

Natural gas (per Mcf):

        

Total realized price, after hedge

   $ 2.65      $ 4.22      $ 4.00      $ 3.63   

Total realized price, before hedge

   $ 2.65      $ 4.22      $ 4.00      $ 3.63   

Oil (per Bbl):

        

Total realized price, after hedge

   $ 48.39      $ 93.52      $ 88.61      $ 93.16   

Total realized price, before hedge

   $ 47.09      $ 93.52      $ 88.61      $ 93.16   

NGLs (per Bbl):

        

Total realized price, after hedge

   $ 12.63      $ 31.45      $ 28.80      $ 34.88   

Total realized price, before hedge

   $ 12.63      $ 31.45      $ 28.80      $ 34.88   

Production costs (per Mcfe):

        

Lease operating expenses

   $ 0.99      $ 2.51      $ 2.47      $ 2.32   

Production taxes

     0.32        0.50        0.48        0.45   
  

 

 

   

 

 

   

 

 

   

 

 

 

Transportation and compression

     0.06        —         —         —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Total production costs

   $ 1.37      $ 3.01      $ 2.95      $ 2.77   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 

We define Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion and amortization, plus certain non-cash items. Adjusted EBITDA is not a measure of performance calculated in accordance with GAAP. Although not

 

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  prescribed under GAAP, we believe the presentation of Adjusted EBITDA is relevant and useful because it helps our investors to understand our operating performance and makes it easier to compare our results with other companies that have different financing and capital structures. Adjusted EBITDA should not be considered in isolation of, or as a substitute for, net earnings as an indicator of operating performance or cash flows from operating activities as a measure of liquidity. Adjusted EBITDA, as we calculate it, may not be comparable to Adjusted EBITDA measures reported by other companies. In addition, Adjusted EBITDA does not represent funds available for discretionary use or the payment of distributions. The following reconciles our net loss to Adjusted EBITDA for the periods indicated:

 

     Nine Months Ended
September 30,
     Years Ended
December 31,
 
     2015      2014      2014      2013  
     (unaudited)                
     (in thousands, except per unit data)  

Net loss

   $ (15,330    $ (5,495    $ (17,145    $ (3,643

Interest expense

     14         —          —          —    

Depreciation, depletion and amortization

     5,095         1,436         2,156         133   

Asset impairment

     7,291         —          6,880         —    
  

 

 

    

 

 

    

 

 

    

 

 

 

EBITDA

     (2,930      (4,059      (8,109      (3,510

Acquisition and related costs

     163         —          253         —    

Gain on mark-to-market derivatives

     (563      —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Adjusted EBITDA

   $ (3,330    $ (4,059    $ (7,856    $ (3,510
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

We are a Delaware limited partnership formed in February 2013 to acquire oil and gas assets in North America. Our operations are substantially focused on the Eagle Ford Shale in South Texas. Additionally, we are focused on opportunistically acquiring energy-related assets including additional undeveloped assets, developed assets, gathering, processing and pipeline assets, and securities of energy companies.

Although the common units will not immediately be traded on a national securities exchange, the Partnership is treated as a pass through entity for federal income tax purposes and the Partnership intends to pay regular distributions. In this regard, the Partnership is similar to other yield-oriented investment vehicles, such as MLPs. Unlike the Partnership, however, MLPs are traded on a national securities exchange.

Recent Developments

On September 24, 2014, we, together with Atlas Resource Partners, L.P., or ARP, entered into a purchase and sale agreement for the acquisition of oil and natural gas liquids interests in approximately 6,076 undeveloped non-producing net acres to be purchased by the Partnership, and 4,000 net developed acres to be purchased by ARP in the Eagle Ford Shale in Atascosa County, Texas from Cinco Resources, Inc., or Cinco, and Cima Resources, LLC, a wholly owned subsidiary of Cinco, for an aggregate purchase price of $342.0 million, after all customary closing adjustments, which we refer to as Eagle Ford Acquisition. The purchase price for the assets acquired by the Partnership was $135.5 million.

On November 5, 2014, we, together with ARP, closed on the Eagle Ford Acquisition. Approximately $183.1 million was paid in cash by ARP and $19.9 million was paid by us at closing. In accordance with the terms of the purchase and sale agreement and a shared acquisition and operating agreement that we entered into with ARP, ARP agreed to pay approximately $23.4 million in the aggregate as deferred purchase price, and we agreed to pay approximately $115.6 million in the aggregate as deferred purchase price following the closing. We have paid $79.3 million of the deferred portion of the purchase price as of September 30, 2015. As a result, our share of the aggregate purchase price was $99.2 million. The Eagle Ford Acquisition had an effective date of July 1, 2014.

Prior to the March 31, 2015 installment, we, ARP and Cinco amended the purchase and sale agreement to alter the timing and amount of the quarterly payments beginning with the March 31, 2015 payment and ending December 31, 2015, with no change to the overall purchase price. On March 31, 2015, we paid $28.3 million and ARP issued $20.0 million of its Class D ARP Preferred Units to satisfy the second installment related to the Eagle Ford Acquisition. On June 30, 2015, we paid $16.0 million and ARP paid $0.6 million to satisfy the third installment related to the Eagle Ford Acquisition.

On September 21, 2015, we and ARP, in accordance with the terms of the Eagle Ford shared acquisition and operating agreement agreed that ARP will fund the remaining two deferred purchase price installments of $16.2 million and $20.1 million to be paid on September 30, 2015 and December 31, 2015, respectively. In conjunction with this agreement, we assigned ARP a portion of our non-operating Eagle Ford assets that have an allocated value (as such value was agreed upon by the sellers and the buyers in connection with the Eagle Ford Acquisition) equal to both installments to be paid by ARP. The transaction was approved by our and ARP’s respective conflicts committees.

We estimated that undeveloped reserves for the undeveloped acres acquired in the Eagle Ford Acquisition were approximately 85% oil. As of September 30, 2015, 10 wells had been drilled on the acreage, six were producing, four were awaiting completion and 26 potential identified drilling locations remained undeveloped.

On July 8, 2015, we sold to ARP, for a purchase price of $1.36 million, our interest in a portion of the acreage we acquired in the Eagle Ford Acquisition.

 

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Subsequent Events

Cash distributions. On November 5, 2015, we declared a quarterly distribution of $0.175 per common unit for the quarter ended September 30, 2015. The aggregate $4.2 million distribution, including $0.1 million to our general partner, was paid on November 13, 2015 to holders of record as of September 30, 2015.

Private Placement Fundraising.

Through of our private placement offering on June 30, 2015, we issued 23,300,410 of our common limited partner units in exchange for proceeds to us, net of dealer manager fees and commissions and expenses, of $203.4 million. ATLS purchased 500,010 common limited partner units for $5.0 million during the offering.

Contractual Revenue Arrangements

Natural Gas and Oil Production

Natural Gas. We market the majority of our natural gas production to gas marketers directly or to third party plant operators who process and market our gas. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The pricing index for our Eagle Ford production is primarily Transco Zone 1 and for our Marble Falls production is primarily Waha.

We attempt to sell the majority of natural gas produced at monthly, fixed index prices and a smaller portion at index daily prices.

Crude Oil. Crude oil produced from our wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. The crude oil is typically sold at the prevailing spot market price for each region, less appropriate trucking/pipeline charges. We do not have delivery commitments for fixed and determinable quantities of crude oil in any future periods under existing contracts or agreements.

Natural Gas Liquids. NGLs are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas to meet pipeline specifications for transport or sale to end users or marketers operating on the receiving pipeline. The resulting plant residue natural gas is sold as indicated above and our NGLs are generally priced and sold using the Mont Belvieu (TX) or Conway (KS) regional processing indices. The cost to process and fractionate the NGLs from the gas stream is typically either a volumetric fee for the gas and liquids processed or a percentage retention by the processing and fractionation facility. We do not have delivery commitments for fixed and determinable quantities of NGLs in any future periods under existing contracts or agreements.

General Trends and Outlook

We expect our businesses to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Natural gas, oil and natural gas liquids commodity prices have suffered significant declines during the fourth quarter of 2014 and the first three quarters of 2015. The causes of these declines are based on a number of factors, including, but not limited to, a significant increase in natural gas, oil and NGL production in the United States. While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments in the development of new natural gas, oil and NGL reserves.

Our future gas and oil reserves, production, cash flow, the ability to make payments on obligations and the ability to make distributions to unitholders depend on our success in producing current reserves efficiently, developing existing acreage and acquiring additional proved reserves economically. We face the challenge of

 

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natural production declines and volatile natural gas, oil and NGL prices. As initial reservoir pressures are depleted, natural gas and oil production from particular wells decrease. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than produced.

Results of Operations

Gas and Oil Production

Production Profile. Currently, our gas and oil production revenues and expenses consist of our gas and oil production activities derived from our wells drilled in the Eagle Ford, Marble Falls and Mississippi Lime plays. We have established production positions in the following operating areas:

 

    the Eagle Ford Shale in southern Texas, an oil-rich area, in which we acquired acreage in November 2014;

 

    the Marble Falls play in the Fort Worth Basin in northern Texas, in which we own acreage and producing wells, contains liquids rich natural gas and oil, and;

 

    the Mississippi Lime play in northwestern Oklahoma, an oil and NGL-rich area.

There were no gross or net dry wells drilled during the periods presented below. The following table presents the number of wells we drilled and the number of wells we turned in line, both gross and net during the nine months ended September 30, 2015 and 2014 and the years ended December 31, 2014 and 2013:

 

     Nine Months Ended
September 30,(1)
     Year Ended
December 31,(1)
 
    

2015

    

2014

    

2014

    

2013

 

Gross wells drilled(2):

           

Eagle Ford(3)

                           

Marble Falls

            11.0         11.0         2.0   

Mississippi Lime

            2.0         2.0          
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

            13.0         13.0         2.0   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net wells drilled(2):

           

Eagle Ford(3)

                           

Marble Falls

            11.0         11.0         2.0   

Mississippi Lime

            0.4        0.4          
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

            11.4         11.4         2.0   
  

 

 

    

 

 

    

 

 

    

 

 

 

Gross wells turned in line:

           

Eagle Ford(3)

     4.0                2.0          

Marble Falls

            10.0         11.0         2.0   

Mississippi Lime

            1.0         2.0          
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     4.0         11.0         15.0         2.0   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net wells turned in line:

           

Eagle Ford(3)

     4.0                2.0          

Marble Falls

            10.0         11.0         2.0   

Mississippi Lime

            0.2         0.4          
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     4.0         10.2         13.4         2.0   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)  Wells turned in line refers to wells that have been drilled, completed and connected to a gathering system.
(2)  There were no exploratory wells drilled during the nine months ended September 30, 2015 and 2014, and the years ended December 31, 2014 and 2013.
(3)  The drilling activity related to Eagle Ford was included effective November 5, 2014, the date of acquisition. Ten wells were drilled by the prior owner, Cinco, but not yet turned in line, at the date of acquisition.

 

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Production Volumes. The following table presents total net natural gas, crude oil and NGL production volumes and production per day for the nine months ended September 30, 2015 and 2014 and the years ended December 31, 2014 and 2013:

 

     Nine Months Ended
September 30,
     Year Ended December 31,  
     2015      2014      2014      2013  

Production:(1)

           

Eagle Ford:

           

Natural gas (MMcf)

     32         —          1         —    

Oil (000’s Bbls)

     142         —          2         —    

NGLs (000’s Bbls)

     7         —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total (MMcfe)

     928         —          15         —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Marble Falls:

           

Natural gas (MMcf)

     116         173         239         8   

Oil (000’s Bbls)

     11         31         37         3   

NGLs (000’s Bbls)

     15         23         31         1   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total (MMcfe)

     271         498         651         29   
  

 

 

    

 

 

    

 

 

    

 

 

 

Mississippi Lime:

           

Natural gas (MMcf)

     14         6         12         —    

Oil (000’s Bbls)

     2         1         3         —    

NGLs (000’s Bbls)

     1         —          1         —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total (MMcfe)

     29         17         35         —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total production:

           

Natural gas (MMcf)

     162         179         252         8   

Oil (000’s Bbls)

     155         33         43         3   

NGLs (000’s Bbls)

     23         23         32         1   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total (MMcfe)

     1,228         515         701         29   
  

 

 

    

 

 

    

 

 

    

 

 

 

Production per day:(1)

           

Eagle Ford:

           

Natural gas (Mcfd)

     118         —          1         —    

Oil (Bpd)

     521         —          6         —    

NGLs (Bpd)

     25         —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total (Mcfed)

     3,397         —          42         —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Marble Falls:

           

Natural gas (Mcfd)

     425         635         656         21   

Oil (Bpd)

     40         115         102         7   

NGLs (Bpd)

     55         83         85         3   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total (Mcfed)

     992         1,826         1,783         79   
  

 

 

    

 

 

    

 

 

    

 

 

 

Mississippi Lime:

           

Natural gas (Mcfd)

     50         20         34         —    

Oil (Bpd)

     6         5         8         —    

NGLs (Bpd)

     4         2         3         —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total (Mcfed)

     107         61         95         —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total production per day:

           

Natural gas (Mcfd)

     594         656         691         21   

Oil (Bpd)

     566         121         117         7   

NGLs (Bpd)

     84         85         88         3   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total (Mcfed)

     4,497         1,887         1,920         79   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)  Oil and NGLs are converted to gas equivalent basis at the rate of one barrel of oil or NGLs to six Mcf of natural gas. This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value.

 

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Production Revenues, Prices and Costs. Production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for oil, which comprised 80% of our proved reserves on an energy equivalent basis at December 31, 2014. The following table presents production revenues and average sales prices for our direct interest natural gas, oil and NGL production for the nine months ended September 30, 2015 and 2014 and the years ended December 31, 2014 and 2013, along with average production costs, which include lease operating expenses, taxes and transportation and compression costs, in each of the reported periods:

 

    Nine Months Ended September 30,     Year Ended December 31,  
        2015             2014             2014             2013      

Production revenues (in thousands):

       

Natural gas revenue

  $ 430      $ 756      $ 1,009      $ 28   

Oil revenue

    7,287        3,081        3,770        241   

NGLs revenue

    290        726        928        33   
 

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

  $ 8,007      $ 4,563      $ 5,707      $ 302   
 

 

 

   

 

 

   

 

 

   

 

 

 

Average sales price:

       

Natural gas (per Mcf):(1)

       

Total realized price, after hedge

  $ 2.65      $ 4.22      $ 4.00      $ 3.63   

Total realized price, before hedge

  $ 2.65      $ 4.22      $ 4.00      $ 3.63   

Oil (per Bbl):(1)

       

Total realized price, after hedge

  $ 48.39      $ 93.52      $ 88.61      $ 93.16   

Total realized price, before hedge

  $ 47.09      $ 93.52      $ 88.61      $ 93.16   

NGLs (per Bbl):(1)

       

Total realized price, after hedge

  $ 12.63      $ 31.45      $ 28.80      $ 34.88   

Total realized price, before hedge

  $ 12.63      $ 31.45      $ 28.80      $ 34.88   

Production costs (per Mcfe):

       

Eagle Ford:

       

Lease operating expenses

  $ 0.54      $ —       $ 1.63      $ —    

Production taxes

    0.34        —         0.39        —    

Transportation and compression

    0.07        —         —         —    
 

 

 

   

 

 

   

 

 

   

 

 

 
  $ 0.95      $ —       $ 2.02      $ —    
 

 

 

   

 

 

   

 

 

   

 

 

 

Marble Falls:

       

Lease operating expenses

  $ 2.42      $ 2.56      $ 2.56      $ 2.32   

Production taxes

    0.29        0.51        0.50        0.45   

Transportation and compression

    —          —         —         —    
 

 

 

   

 

 

   

 

 

   

 

 

 
  $ 2.71      $ 3.07      $ 3.06      $ 2.77   
 

 

 

   

 

 

   

 

 

   

 

 

 

Mississippi Lime:

       

Lease operating expenses

  $ 1.91      $ 1.01      $ 1.09      $ —    

Production taxes

    0.07        0.24        0.12        —    

Transportation and compression

    0.44        —         0.09        —    
 

 

 

   

 

 

   

 

 

   

 

 

 
  $ 2.42      $ 1.25      $ 1.30      $ —    
 

 

 

   

 

 

   

 

 

   

 

 

 

Total production costs:

       

Lease operating expenses

  $ 0.99      $ 2.51      $ 2.47      $ 2.32   

Production taxes

    0.32        0.50        0.48        0.45   

Transportation and compression

    0.06        —         —         —    
 

 

 

   

 

 

   

 

 

   

 

 

 
  $ 1.37      $ 3.01      $ 2.95      $ 2.77   
 

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)  Oil and NGLs are converted to gas equivalent basis at the rate of one barrel of oil or NGLs to six Mcf of natural gas. This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value.

 

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Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014. Total production revenues were $8.0 million for the nine months ended September 30, 2015, an increase of $3.4 million from $4.6 million for the nine months ended September 30, 2014. This increase consisted of a $6.8 million increase attributable to production from our Eagle Ford acquisition, partially offset by a $3.4 million decrease attributable to our Marble Falls operations.

Total production costs were $1.7 million, an increase of $0.1 million from $1.6 million for the nine months ended September 30, 2014. This increase primarily consisted of $0.8 million attributable to the Eagle Ford assets and $0.1 million attributable to our Mississippi Lime assets, partially offset by a decrease of $0.8 million attributable to our Marble Falls assets. Total production costs per Mcfe decreased to $1.37 per Mcfe for the nine months ended September 30, 2015 from $3.01 per Mcfe for the comparable prior year period primarily as a result of the decrease in our oil production in Marble Falls and the addition of production in the Eagle Ford Shale, which has lower production costs per Mcfe.

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Total production revenues were $5.7 million for the year ended December 31, 2014, an increase of $5.4 million from $0.3 million for the year ended December 31, 2013. This increase consisted of a $5.4 million increase primarily attributable to new wells drilled, consisting of a $5.0 million increase attributable to our Marble Falls operations, a $0.3 million increase attributable to our Mississippi Lime assets, and a $0.1 million increase attributable to our newly acquired Eagle Ford Shale assets.

Total production costs were $2.1 million for the year ended December 31, 2014, an increase of $2.0 million from $0.1 million for the year ended December 31, 2013. This increase was due primarily to a $2.0 million increase associated with our new wells drilled in the Marble Falls play. Total production costs per Mcfe increased to $2.95 per Mcfe for the year ended December 31, 2014 from $2.77 per Mcfe for the comparable prior year period primarily as a result of the increase in our oil and natural gas liquids volumes during the current year period.

Other Costs and Expenses

General and Administrative Expenses

Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014. Total general and administrative expenses increased to $10.0 million for the nine months ended September 30, 2015 from $7.1 million for the nine months ended September 30, 2014. Our $10.0 million of general and administrative expenses for the nine months ended September 30, 2015 represents a $2.9 million increase from the comparable prior year period due to a $2.7 million increase in salaries, wages and other corporate activities due to the growth of our business and a $0.2 million increase in professional fees.

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Total general and administrative expenses increased to $11.7 million for the year ended December 31, 2014 from $3.7 million for the year ended December 31, 2013. Our $11.7 million of general and administrative expenses for the year ended December 31, 2014 represents an $8.0 million increase from the comparable prior year period due to a $7.6 million increase in salaries, wages and other corporate activities and a $0.4 million increase in third-party services.

Depreciation, Depletion and Amortization

Total depreciation, depletion and amortization increased to $5.1 million for the nine months ended September 30, 2015, compared with $1.4 million for the comparable prior year period, which was primarily due to a $3.6 million increase in our depletion expense resulting from the acquisitions consummated during 2014.

Total depreciation, depletion and amortization increased to $2.2 million for the year ended December 31, 2014 compared with $0.1 million for the comparable prior year period, which was due to a $2.1 million increase in our depletion expense resulting from the acquisitions consummated during 2014.

 

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The following table presents our depletion expense per Mcfe for our operations for the respective periods (in thousands, except per Mcfe data):

 

     Nine Months Ended September 30,      Years Ended December 31,  
         2015              2014              2014              2013      

Depletion expense:

           

Total

   $ 4,958       $ 1,436       $ 2,156       $ 133   

Depletion expense as a percentage of gas and oil production revenue

     60%         31%         38%         44%   

Depletion per Mcfe

   $ 4.04       $ 2.79       $ 3.08       $ 4.60   

Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014. Depletion expense was $5.0 million for the nine months ended September 30, 2015, an increase of $3.6 million compared with $1.4 million for the nine months ended September 30, 2014. Depletion expense of gas and oil properties as a percentage of gas and oil revenues increased to 60% for nine months ended September 30, 2015, compared with 31% for the nine months ended September 30, 2014, which was primarily due to an increase in our depletion expense associated with the Eagle Ford assets, partially offset by a decrease in oil volumes associated with the Marble Falls assets. Depletion expense per Mcfe was $4.04 for the nine months ended September 30, 2015, an increase of $1.25 per Mcfe from $2.79 per Mcfe for the nine months ended September 30, 2014, which was primarily due to an increase in our depletion expense associated with the Eagle Ford assets, partially offset by a decrease in our oil volumes on the Marble Falls assets.

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Depletion expense was $2.2 million for the year ended December 31, 2014, an increase of $2.1 million compared with $0.1 million for the year ended December 31, 2013. Depletion expense of gas and oil properties as a percentage of gas and oil revenues decreased to 38% for the year ended December 31, 2014, compared with 44% for the year ended December 31, 2013, which was primarily due to an increase in production volumes between the periods. Depletion expense per Mcfe was $3.08 for the year ended December 31, 2014, a decrease of $1.52 per Mcfe from $4.60 per Mcfe for the year ended December 31, 2013, which was primarily related to the increase in our overall production between the periods.

Asset Impairment

Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014. For the nine months ended September 30, 2015, we recognized $7.3 million of asset impairment related to our proved oil and gas properties in the Marble Falls and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices. There were no impairments of proved gas and oil properties recorded for the nine months ended September 30, 2014. There were no impairments of unproved gas and oil properties recorded for the nine months ended September 30, 2015 and 2014.

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. During the year ended December 31, 2014, we recognized $6.9 million of asset impairments related to gas and oil properties within property, plant and equipment, net on our consolidated balance sheet, primarily related to our natural gas and oil wells in the Marble Falls play. These impairments related to the carrying amount of these gas and oil properties being in excess of our estimate of their fair values at December 31, 2014. The estimate of fair values of these gas and oil properties was impacted by, among other factors, the decrease of natural gas and oil prices in comparison to their carrying values at December 31, 2014.

 

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Liquidity and Capital Resources

General

Historically, our primary sources of liquidity have been cash generated from operations and financing activities, including our recent private placement. Following the effectiveness of the registration statement of which this prospectus is a part, we intend to make cash distributions to our unitholders at an initial distribution rate of $0.175 per common unit per quarter ($0.70 per common unit on an annualized basis). Please read “Cash Distribution Policy and Restrictions on Distributions” for more information about our cash distributions. Our primary cash requirements, in addition to normal operating expenses, are for capital expenditures, and quarterly distributions to our unitholders, which we expect to fund through operating cash flow.

Cash Flows—Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014

Net cash used in operating activities of $23.9 million for the nine months ended September 30, 2015 represented an unfavorable movement of $24.4 million from net cash used in operating activities of $0.5 million for the comparable prior year period. The $24.4 million unfavorable movement was derived principally from a $25.0 million unfavorable movement in working capital, an unfavorable movement of $9.8 million in net loss and a $0.6 million unfavorable movement in gain on mark-to-market derivatives, partially offset by a $7.3 million asset impairment charge in the current year period and a $3.7 million favorable movement in depreciation, depletion and amortization. The movement in working capital was due to a $24.8 million unfavorable movement in advances from affiliates and a $1.0 million unfavorable movement in accounts receivable and prepaid expenses and other, partially offset by a favorable movement of $0.8 million in accounts payable and accrued liabilities.

Net cash used in investing activities of $65.6 million for the nine months ended September 30, 2015 represented an unfavorable movement of $53.4 million from net cash used in investing activities of $12.2 million for the comparable prior year period. This unfavorable movement was principally due to a $44.7 million increase in net cash paid for our acquisitions and an $8.6 million increase in capital expenditures. Please read further discussion of capital expenditures under “—Capital Requirements.”

Net cash provided by financing activities of $94.3 million for the nine months ended September 30, 2015 represented a favorable movement of $39.8 million from net cash provided by financing activities of $54.5 million for the comparable prior year period. This favorable movement was principally due to a $57.0 million increase in net proceeds from the issuance of our common units and warrants, partially offset by a $11.3 million decrease in deferred capital contributions and an increase of $5.9 million in distributions paid to our unitholders.

Cash Flows—Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013

Net cash provided by operating activities of $0.5 million for the year ended December 31, 2014 represented an unfavorable movement of $3.6 million from net cash provided by operating activities of $4.1 million for the comparable prior year period. The $3.6 million unfavorable movement was derived principally from an unfavorable movement of $13.5 million in net loss, partially offset by a $6.9 million increase in asset impairment, a $2.0 million increase in depletion, and a $1.0 million favorable movement in working capital. The movement in working capital was due to a $0.6 million unfavorable movement in accounts receivable, prepaid expenses and other, partially offset by a favorable movement of $2.2 million for advances from affiliates and an unfavorable movement of $0.6 million in accounts payable and accrued liabilities.

Net cash used in investing activities of $67.6 million for the year ended December 31, 2014 represented an unfavorable movement of $64.0 million from net cash used in investing activities of $3.6 million for the comparable prior year period. This unfavorable movement was principally due to a $54.7 million increase in net cash paid for our acquisitions and a $9.3 million increase in capital expenditures. Please read further discussion of capital expenditures under “—Capital Requirements.”

 

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Net cash provided by financing activities of $91.8 million for the year ended December 31, 2014 represented a favorable movement of $83.6 million from net cash provided by financing activities of $8.2 million for the comparable prior year period. This favorable movement was principally due to a $73.4 million increase in net proceeds from the issuance of our common units and warrants and an $11.8 million increase in deferred capital contributions, partially offset by an increase of $1.6 million distributions paid to our unitholders.

Capital Requirements

Our capital expenditures primarily relate to our well drilling and leasehold acquisition costs. During the nine months ended September 30, 2015 and 2014, our capital expenditures were approximately $20.8 million and $12.1 million, respectively. During the years ended December 31, 2014 and 2013, our capital expenditures were approximately $12.9 million and $3.6 million.

As of September 30, 2015, we did not have any commitments for drilling and completion expenditures.

Off-Balance Sheet Arrangements

As of September 30, 2015, we did not have any off-balance sheet arrangements.

Cash Distributions

We have a cash distribution policy under which we intend to distribute to holders of common units and GP units on a quarterly basis a target distribution of $0.175 per common unit, or $0.70 per common unit per year, to the extent we have sufficient available cash after establishing appropriate reserves and paying fees and expenses, including reimbursements of expenses to the general partner and its affiliates. Distributions are generally paid within 45 days of the end of the quarter to unitholders of record on the applicable record date. Unitholders are entitled to receive distributions from us beginning with the quarter following the quarter in which we first admit them as limited partners. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Credit Facility

On May 1, 2015, we entered into a secured credit facility agreement with Wells Fargo. As of September 30, 2015, the lenders under the credit facility have no commitment to lend to us and we have a zero-dollar borrowing base under the credit facility, but we and our subsidiaries have the ability to enter into derivative contracts to manage our exposure to commodity price movements that will benefit from the collateral securing the credit facility. The credit facility may be amended in the future if we request a borrowing base redetermination and the lenders agree to establish the borrowing base and related commitments thereunder. We may request a borrowing base redetermination under our secured credit facility. We are in discussions with our lenders to set a borrowing base for our credit facility. Pending market conditions, we currently anticipate our lenders to set a borrowing base during the forecast period. Please read “Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution.” If the borrowing base is redetermined to an amount greater than zero dollars, the credit facility would allow us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semiannually by our lenders in their sole discretion. Once established, our borrowing base will be subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil and natural gas reserves, which takes into account the prevailing oil and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. A future decline in commodity prices could result in a redetermination that lowers our borrowing base at that time and, in such case, we could be required to repay any indebtedness outstanding at that time in excess of the borrowing base. If we borrow under the credit facility and we are unable to repay any borrowings in excess of a decreased borrowing base, we would be in default and no longer able to make any distributions to our unitholders.

In addition, our credit facility includes customary events of default, including failure to timely pay, breach of covenants, bankruptcy, cross-default with other material indebtedness (including obligations under swap agreements in excess of any agreed upon threshold amount), and change of control.

 

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Contractual Obligations and Commercial Commitments

The following tables summarize our contractual obligations at December 31, 2014 (in thousands):

 

     Total      Payments Due By Period  
        Less than
1 Year
     Total      More than
1 Year
     Total  

Contractual cash obligations:

              

Eagle Ford deferred payment(1)

   $ 80,789       $ 80,789       $ —        $ —        $ —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual cash obligations

   $ 80,789       $ 80,789       $ —        $ —        $ —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)  In connection with the Eagle Ford acquisition, ARP guaranteed our deferred purchase obligation, whereby ARP provided a guaranty of timely payment of the deferred portion of the purchase price that is to be paid by us. On September 21, 2015, we and ARP, in accordance with the terms of the Eagle Ford shared acquisition and operating agreement (as further described above under “—Recent Developments”), agreed that ARP will fund the remaining two deferred purchase price installments of $16.2 million and $20.1 million to be paid on September 30, 2015 and December 31, 2015, respectively. In conjunction with this agreement, , we assigned ARP a portion of our non-operating Eagle Ford assets that have an allocated value (as such value was agreed upon by the sellers and the buyers in connection with the Eagle Ford Acquisition) equal to both installments to be paid by ARP (please read “—Subsequent Events”). The transaction was approved by our and ARP’s respective conflicts committees. As of September 30, 2015, we have no contractual obligations.

Equity Offerings

Through our private placement offering on June 30, 2015, we issued 23,300,410 of our common units in exchange for proceeds to us, net of dealer manager fees and commissions and expenses, of $203.4 million. ATLS purchased 500,010 common units for $5.0 million during the offering.

During the nine months ended September 30, 2015, we sold an aggregate of 12,623,500 of our common units at a gross offering price of $10.00 per unit, resulting in proceeds of $112.7 million to the Partnership, net of dealer manager fees and commissions and expenses of $12.7 million. Of such amount, ATLS purchased $2.7 million, or 300,000 common units, during the nine months ended September 30, 2015.

In connection with the issuance of common units during the nine months ended September 30, 2015, unitholders received warrants to purchase 1,262,350 common units at an exercise price of $10.00 per unit.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a publicly registered company with reporting obligations under the Exchange Act, we will be required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal controls over financial reporting. Though we will be required to disclose changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal controls over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a publicly registered company with reporting obligations under the Exchange Act, we will need to implement additional internal controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

 

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Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting and will not be required to do so for as long as we remain an “emerging growth company” under the JOBS Act or a non-accelerated filer. If it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed or operating. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future.

We have no history operating as a publicly registered company. As a publicly registered company with reporting obligations under the Exchange Act, we will need to comply with new laws, regulations and requirements, including certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will require a significant amount of time from our board of directors and management and will significantly increase our legal and financial compliance costs and make such compliance more time-consuming and costly. We will need to:

 

    institute a more comprehensive compliance function;

 

    design, establish, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;

 

    prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

 

    establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;

 

    involve and retain to a greater degree outside counsel and accountants in the above-listed activities; and

 

    establish an investor relations function.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point in time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include revenue and expense accruals, depletion, depreciation and amortization, asset impairment, fair value of derivative instruments and the allocation of purchase price to the fair value of assets acquired.

The accounting policies and estimates which we have identified as critical are discussed below.

Depreciation and Impairment of Long-Lived Assets

Long-Lived Assets. The cost of property, plant and equipment, less estimated salvage value, is generally depreciated on a straight-line basis over the estimated useful lives of the assets. Useful lives are based on historical experience and are adjusted when changes in planned use, technological advances or other factors indicate that a different life would be more appropriate. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively.

 

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Long-lived assets, other than goodwill and intangibles with infinite lives, generally consist of natural gas and oil properties and pipeline, processing and compression facilities and are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. A long-lived asset, other than goodwill and intangibles with infinite lives, is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. The undiscounted net cash flows expected to be generated by the asset are based upon our estimates that rely on various assumptions, including natural gas and oil prices, and production and operating expenses. Any significant variance in these assumptions could materially affect the estimated net cash flows expected to be generated by the asset. Declines in natural gas prices may result in impairment charges in future periods.

For the nine months ended September 30, 2015, we recognized $7.3 million of asset impairment related to our proved oil and gas properties in the Marble Falls and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices. There were no impairments of unproved gas and oil properties recorded for the nine months ended September 30, 2015 and 2014. There were no impairments of proved gas and oil properties recorded for the nine months ended September 30, 2014. During the year ended December 31, 2014, we recognized $6.9 million of asset impairments related to gas and oil properties within property, plant and equipment, net on our combined consolidated balance sheet primarily related to our natural gas wells in the Marble Falls play. These impairments related to the carrying amounts of the gas and oil properties being in excess of our estimates of their fair values at September 30, 2015 and December 31, 2014. The estimates of fair values of these gas and oil properties were impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. Additional factors impacting the economic viability of long-lived assets are discussed under the section “Forward-Looking Statements”.

Fair Value of Financial Instruments

We have established a hierarchy to measure our financial instruments at fair value, which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

We use a fair value methodology to value the assets and liabilities of our outstanding derivative contracts. Our commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements.

Liabilities that are required to be measured at fair value on a nonrecurring basis include our asset retirement obligations that are defined as Level 3. Estimates of the fair value of asset retirement obligations are based on discounted cash flows using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our credit-adjusted risk-free rate and inflation rates.

 

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Reserve Estimates

Estimates of proved natural gas, oil and natural gas liquids reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas, oil and natural gas liquids prices, drilling and operating expenses, capital expenditures and availability of funds. The accuracy of these reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. As discussed in “Business and Properties—Our Oil and Natural Gas Data,” we internally prepared a report of our proved reserves.

Any significant variance in the assumptions utilized in the calculation of reserve estimates could materially affect the estimated quantity of reserves. As a result, estimates of proved natural gas, oil and natural gas liquids reserves are inherently imprecise. Actual future production, natural gas, oil and natural gas liquids prices, revenues, development expenditures, operating expenses and quantities of recoverable natural gas, oil and natural gas liquids reserves may vary substantially from our estimates or estimates contained in the reserve reports. In addition, proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas, oil and natural gas liquids prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control. Reserves and their relation to estimated future net cash flows impact the calculation of impairment and depletion of oil and gas properties. Adjustments to quarterly depletion rates, which are based upon a units of production method, are made concurrently with changes to reserve estimates. Generally, an increase or decrease in reserves without a corresponding change in capitalized costs will have a corresponding inverse impact to depletion expense.

Asset Retirement Obligations

We estimate the cost of future dismantlement, restoration, reclamation and abandonment of our operating assets and recognize an estimated liability for the plugging and abandonment of gas and oil wells and related facilities. We also recognize a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. We also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Since there are many variables in estimating asset retirement obligations, we attempt to limit the impact of management’s judgment on certain of these variables by developing a standard cost estimate based on historical costs and industry quotes updated annually. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. We do not have any assets legally restricted for purposes of settling asset retirement obligations. Except for gas and oil properties, there are no other material retirement obligations associated with our tangible long-lived assets.

Delay in Adoption of Certain Accounting Standards

Section 102(b)(1) of the JOBS Act provides that an “emerging growth company” may take advantage of an extended transition period for complying with new or revised accounting standards that have different effective dates for public and private companies. This means an “emerging growth company” can delay adopting certain accounting standards until such standards are otherwise applicable to private companies. We have elected to take advantage of the benefits of this extended transition period. That is, when a standard is issued or revised and it

 

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has different application dates for public or private companies, the Partnership can adopt the new or revised standard at the time private companies adopt the new or revised standard. Our consolidated financial statements may therefore not be comparable to those of companies that comply with such new or revised accounting standards.

Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and commodity prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of the market risk-sensitive instruments were entered into for purposes other than trading.

General

All of our assets and liabilities are denominated in U.S. dollars, and as a result, we do not have exposure to currency exchange risks.

We are exposed to various market risks, principally changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We manage these risks through regular operating and financing activities and periodic use of derivative financial instruments such as forward contracts and swap agreements. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on September 30, 2015. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our business.

Current market conditions elevate our concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us, if any. The counterparties related to our commodity derivative contracts are banking institutions or their affiliates, who also participate in ARP’s revolving credit facilities. The creditworthiness of our counterparties is constantly monitored, and we currently believe them to be financially viable. We are not aware of any inability on the part of our counterparties to perform under their contracts and believe our exposure to non-performance is remote.

Commodity Price Risk. Our market risk exposures to commodities are due to the fluctuations in the commodity prices and the impact those price movements have on our financial results. To limit the exposure to changing commodity prices, we use financial derivative instruments, including financial swap and option instruments, to hedge portions of future production. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under these swap agreements, we receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not the obligation, to purchase or sell commodities at a fixed price for the relevant period.

Holding all other variables constant, including the effect of commodity derivatives, a 10% change in average commodity prices would result in a change to our consolidated operating income for the twelve-month period ending September 30, 2016 of approximately $1.8 million.

Realized pricing of natural gas, oil, and natural gas liquids production is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas, oil and natural gas liquids production. Pricing for natural gas, oil and natural gas liquids production has been volatile and unpredictable for many years. To limit our exposure to changing natural gas, oil and natural gas liquids prices, we enter into natural gas and oil swap, put option and costless collar option contracts. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter, or

 

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OTC, futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. OTC contracts are generally financial contracts which are settled with financial payments or receipts and generally do not require delivery of physical hydrocarbons. Crude oil contracts are based on a West Texas Intermediate, or WTI, index. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while other natural gas liquids contracts are based on an OPIS Mt. Belvieu index. These contracts have qualified and been designated as cash flow hedges and been recorded at their fair values.

As of September 30, 2015, we had the following commodity derivatives:

Crude Oil Fixed Price Swaps

 

Production Period Ending December 31,

   Volumes      Average Fixed
Price
 
     (Bbl)      (per Bbl)  

2015

     13,500       $ 61.000   

2016

     18,000       $ 63.150   

2017

     9,000       $ 65.000   

 

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BUSINESS AND PROPERTIES

The following Business and Properties discussion should be read in conjunction with the financial statements and related notes beginning on page F-2 of this prospectus.

Overview

We are a Delaware limited partnership formed in February 2013 to acquire oil and gas assets in North America. Through the conclusion of our private placement offering on June 30, 2015, we issued 23,300,410 common units in exchange for net proceeds of approximately $203.4 million. Our operations are substantially focused on the Eagle Ford Shale in South Texas. Additionally, we are focused on opportunistically acquiring energy-related assets including additional undeveloped assets, developed assets, gathering, processing and pipeline assets, and securities of energy companies.

Although the common units will initially not be traded on a national securities exchange, the Partnership is treated as a pass through entity for federal income tax purposes and the Partnership intends to pay regular distributions. In this regard, the Partnership is similar to other yield-oriented investment vehicles, such as MLPs. Unlike the Partnership, however, MLPs are traded on a national securities exchange.

As a result of the technological and operational advances in oil and gas production and other domestic and global factors, oil prices have fallen significantly since November 2014. We believe that we are well positioned to take advantage of opportunities generated by the volatility of oil prices. We are managed by an experienced and entrepreneurial management team, supported by highly qualified energy professionals based out of Fort Worth, Texas. We believe our management has demonstrated recurring success in growing value to all stakeholders during the creation and eventual sale of several energy companies, including Atlas Energy, Inc., Atlas Energy L.P., or Atlas Energy, and Atlas Pipeline Partners L.P., or APL.

Our Properties

Our properties are located in Texas and Oklahoma and consist of oil and natural gas reservoirs. Please read below for a description of each area in which we operate.

Eagle Ford

On September 24, 2014, we, together with Atlas Resource Partners, L.P., or ARP, entered into a purchase and sale agreement for the acquisition of oil and natural gas liquids interests in approximately 6,076 undeveloped non-producing net acres to be purchased by the Partnership, and 4,000 net developed acres to be purchased by ARP in the Eagle Ford Shale in Atascosa County, Texas from Cinco Resources, Inc., or Cinco, and Cima Resources, LLC, a wholly owned subsidiary of Cinco, for an aggregate purchase price of $342.0 million, after all customary closing adjustments, which we refer to as Eagle Ford Acquisition.

On November 5, 2014, we, together with ARP, closed on the Eagle Ford Acquisition. Approximately $183.1 million was paid in cash by ARP and $19.9 million was paid by us at closing. In accordance with the terms of the purchase and sale agreement and a shared acquisition and operating agreement that we entered into with ARP, ARP agreed to pay approximately $23.4 million in the aggregate as deferred purchase price, and we agreed to pay approximately $115.6 million in the aggregate as deferred purchase price following the closing. We have paid $79.3 million of the deferred portion of the purchase price as of September 30, 2015. As a result, our share of the aggregate purchase price was $99.2 million. The Eagle Ford Acquisition had an effective date of July 1, 2014.

We estimated that undeveloped reserves for the undeveloped acres acquired in the Eagle Ford Acquisition were approximately 85% oil. As of September 30, 2015, we have six producing wells, four wells awaiting completion and 26 potential identified drilling locations remained undeveloped. On July 8, 2015, we sold for a purchase price of $1.36 million to ARP our interest in a portion of the acreage we acquired in the Eagle Ford Acquisition.

 

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On September 21, 2015, we and ARP, in accordance with the terms of the shared acquisition and operating agreement, agreed that ARP will fund the remaining two deferred purchase price installments of $16.2 million and $20.1 million to be paid on September 30, 2015 and December 31, 2015, respectively. In conjunction with this agreement, we assigned ARP a portion of our non-operating Eagle Ford assets that have an allocated value (as such value was agreed upon by the sellers and the buyers in connection with the Eagle Ford Acquisition) equal to both installments to be paid by ARP. The transaction was approved by our and ARP’s respective conflicts committees.

Marble Falls

On July 9, 2013, we acquired approximately 1,300 undeveloped acres in the Marble Falls formation and the Barnett Shale, in Jack County, Texas for $1.72 million with 17 potential identified drilling locations. The acquisition was funded with a $1.8 million capital contribution from Atlas Energy in exchange for 200,000 common units. By December 31, 2013, we had drilled two wells, funded primarily through capital contributed by Atlas Energy with an average daily production rate of approximately 123 barrel of oil equivalents per day (boe/d).

On November 23, 2013, we acquired an additional 890 net acres in the Marble Falls formation for approximately $1.0 million.

Through September 30, 2015, we have drilled 11 wells on the acreage acquired in the Marble Falls formation, the total cost of which was $13.2 million. For the year ended December 31, 2014 and the nine months ended September 30, 2015, average Marble Falls production was 1,783 mcfe/d and 992 mcfe/d, respectively.

Mississippi Lime

In January 2014, we acquired a non-operated 11.76% working interest in a well being developed in the Mississippi Lime formation in Garfield County, Oklahoma, operated by SandRidge Energy, Inc., or SandRidge, for approximately $373,000. As of August, 2014, we had agreed to participate in a second well with SandRidge under the same terms for approximately $347,000. Drilling on the first well commenced in December 2013 (prior to our acquisition of our working interest) and the well began producing in commercial quantities in May 2014. Drilling on the second well commenced in August 2014 and it began producing in commercial quantities in October 2014.

Our Property Acquisition Strategy

We intend to target for acquisition energy-related assets including producing oil and gas assets, undeveloped oil and gas assets with development potential, gathering, processing and pipeline assets and securities of energy companies. When we acquire a property, we will estimate the capital required to develop the property and plan to reserve a portion of our capital contributions, or a portion of any borrowing capacity available to us, to fund all or a portion of these estimated costs of development. We also plan to use our cash flow, after the payment of targeted distributions to our unitholders, to further develop our properties and to fund future acquisitions.

We do not expect to conduct a material amount of exploratory drilling on any non-producing properties we acquire.

Our Investment Objective

Our primary investment objective is to generate an attractive total return, consisting of current distributions and capital appreciation, through the acquisition of oil and gas assets in North America. We intend to generate stable and sustainable quarterly distributions to unitholders and to create liquidity for the unitholders in the future through a listing of the common units on a national stock exchange, a merger of the Partnership with an existing publicly traded entity, or the sale of all or substantially all of our assets (please read “—Our Liquidity Strategy,” below). To achieve our general investment objective, we expect to:

 

    use the expertise of personnel of our general partner and its parent company, ATLS, to identify and acquire energy-related assets including: producing oil and gas assets; undeveloped oil and gas assets with development potential; gathering, processing and pipeline assets; and securities of energy companies;

 

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    provide a targeted 7.00% per year distribution per Unit (calculated based upon a $10.00 per Unit purchase price), paid quarterly to unitholders (at least 1.75% of the common unit purchase price per quarter), or the target distribution;

 

    invest cash flow above the target distribution to acquire additional properties and assets as described in the first bullet point;

 

    generate for each period an amount of taxable income that is expected to be less than the quarterly distributions paid for such period by offsetting allocations of income to the unitholders with deductions for intangible drilling costs, depletion and depreciation;

 

    where our general partner deems it appropriate and in our best interest, use hedging strategies to fix pricing on some portion of our production in an effort to mitigate commodity price volatility;

 

    where our general partner deems it appropriate and in our best interest, use debt to expand our operations. Prior to a liquidity event, as defined below under “—Our Liquidity Strategy,” total debt may not exceed total capital contributions made to us; and

 

    seek to provide liquidity by June 30, 2020 through a listing of our common units on a national securities exchange, a merger of the Partnership with an existing publicly traded entity, or the sale of all or substantially all of our assets.

Our Investment Strategies

We expect to achieve our investment objective through the acquisition of oil and gas assets in North America. There is a wide range of forecasted prices for oil, creating uncertainty for the acquisition market and oilfield service market. We believe that this uncertainty will provide attractive opportunities to acquire undervalued assets in several markets. While oil prices were relatively high, we believed we could generate the most attractive returns for limited partners from the acquisition and subsequent development of undeveloped oil and gas properties enhancing the value of the sites. With lower and more volatile prices, we believe we are in a position to benefit from the:

 

    acquisition of additional undeveloped properties;

 

    acquisition of low-risk, developed properties at attractive valuations from distressed sellers;

 

    drilling of wells for significantly lower costs on acreage previously acquired;

 

    delaying of sustained development on held acreage until projected drilling returns meet required levels;

 

    acquisition of other energy-related assets including gathering, processing and pipeline properties; and

 

    acquisition of securities of energy companies.

Our Liquidity Strategy

In order to provide liquidity for our unitholders, we intend to, before the end of the Partnership’s term, effect one of the following, each of which is referred to as a liquidity event:

 

    a listing event; or

 

    a merger; or

 

    a sale.

We will seek to provide a liquidity event by June 30, 2020. We cannot assure you, however, that we will be able to meet this target, if at all.

If the proposed liquidity event is a merger or sale, we will be deemed to have fulfilled our undertaking to provide a liquidity event if the proposed merger or sale is voted upon but disapproved by the unitholders. Our general partner thereafter may, but is not obligated to, propose other liquidity events.

 

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Our general partner will be entitled to various distributions upon the occurrence of a liquidity event. We anticipate that a liquidity event will occur within five years. However, our Pre-Listing Partnership Agreement does not require that a liquidity event will occur within a specified timeframe or at all. Please read “Summary of the Partnership Agreement—The Partnership Agreement—Distributions Upon Sale,” “—Distributions Upon Merger,” “—Common Unit Issuance in lieu of IDRs to our General Partner at a Listing Event,” “—Common Unit Issuance in lieu of IDRs to our General Partner after a Listing Event,” “—Distributions of Cash Upon Liquidation” and “—Distributions In-Kind Upon Liquidation.”

Market Overview

Over the past decade, U.S. producers of oil and natural gas have unlocked significant oil and gas production following decades of declining domestic supply through the use of hydraulic fracturing, a revolutionary drilling technique. The American energy renaissance has created significant economic growth, adding jobs for skilled workers, increasing gross domestic product, or GDP, and strengthening the ability of U.S. producers of oil and natural gas to meet domestic energy demands.

 

LOGO

 

Source: Energy Information Administration of the U.S. Department of Energy, or the EIA

The increase in domestic production has outpaced supply growth from the Organization of Petroleum Exporting Countries, or OPEC, and other top producing nations. From 2005 to 2014, domestic oil & liquids production grew 68%. Over the same period, production from Saudi Arabia, the largest oil exporter in the world and largest producing nation in OPEC, grew only 1%.

 

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LOGO

 

Source: EIA

 

LOGO

Source: EIA

Increased supply from U.S. producers coupled with weakening demand from China and emerging markets have created an oversupplied energy market. As a result, the NYMEX West Texas Intermediate, or WTI, price for a barrel of crude oil has declined 64% from its peak on June 20, 2014 of $107.95 to $38.50 as of August 26, 2015.

 

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LOGO

 

Source: EIA

In order for prices to rebound, OPEC, U.S. producers or other international producers must decrease supply or demand must increase. To date, OPEC has maintained its production in order to maintain its market share, thus driving the price of oil lower.

As a result of the sustained decline in commodity prices, the U.S. energy market is now responding to the oversupply by:

 

    Oil and/or natural gas exploration and production companies, or E&P companies, significantly decreasing their capital budgets, as many U.S. basins are now uneconomic to drill;

 

    Reduced U.S. rig activity;

 

    Decreasing oilfield service costs significantly; and

 

    Selling assets to generate liquidity.

E&P Companies Reduced Capital Spending

U.S. E&P companies have decreased capital spending to control costs as well as conserve cash flow and liquidity. Companies with lower credit ratings, higher costs of capital and liquidity concerns as well as smaller operators focused in shale plays tend to experience a bigger impact when prices drop putting additional pressure on capital spending.

 

LOGO

 

Source: Public filings available via SEC’s EDGAR database

 

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U.S. Rig Activity

In response to the sustained decline in oil and prices, rig activity dropped significantly in the first quarter of 2015 from 2014 highs. While the impact to supply is delayed, lower rig count will be the biggest driver in reducing U.S. supply.

 

LOGO

 

Source: Baker Hughes North America Rotary Rig Count (January 2000 to current), December 31, 2015

Oil Field Service Costs

Reduced rig activity has put significant pressure on oil field service companies. In order to incentivize drillers to continue development, these service providers are rapidly reducing the costs for drilling services at a rapid pace. For example, between September 2014 and January 2015, the bids received by the Partnership for completion services in the Eagle Ford dropped by 25–40%.

As a result of cost reductions, we expect that we will be able to drill wells for significantly lower costs than those paid before the commodity price decline on newly acquired acreage and acreage already in our inventory.

 

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Energy Companies Facing Commodity Price Related Constraints

Strong growth in U.S. production has been driven by energy companies’ access to capital, in particular debt capital. Since 2008, energy companies borrowing and issuance of debt securities have far outpaced those in other sectors.

 

LOGO

 

Source: BIS Quarterly Review, March 2015

 

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As a result of lower commodity prices, many energy companies may not be able to maintain their debt at current levels once their hedges expire. Without the benefit of higher realized prices from hedges, cash flow from operations will decline, while a company’s debt level and interest expense obligation remains constant or increases. As a result, the risk of default rises, as evidenced by credit spreads below.

 

LOGO

 

Source: BIS Quarterly Review, March 2015

Acquisition Market

In order to service debt or create liquidity, many energy companies are selling assets to generate cash proceeds. This trend has already begun to materialize and is expected to increase the longer commodity prices remain distressed. We believe the Partnership is well positioned to take advantage of acquisition opportunities as they come to market, given typical buyers such as public exploration and production MLPs are facing commodity price driven constraints. Acquiring assets at the bottom of the commodity cycle may generate significant returns for us once prices rebound.

Lack of Consensus on Oil Price Creates Dislocation and Uncertainty Across Energy Markets

We believe that the drop in oil and gas prices has created an opportunity for the Partnership to seek a number of investment types to generate an attractive total return for its limited partners, including:

 

    Acquiring additional undeveloped properties;

 

    Acquiring low-risk, developed properties at attractive valuations from distressed sellers;

 

    Drilling wells for significantly lower costs on acreage already acquired; and

 

    Delaying sustained development on acreage already acquired until projected drilling returns reach economic levels.

 

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Our Potential Competitive Strengths

We believe that the following potential competitive strengths will allow us to successfully execute our business strategies and achieve our objectives of generating stable cash flows available for distribution, reinvest excess cash flow and to create liquidity for our unitholders:

 

    Our management team’s experience in the acquisition, development and successful integration of oil and natural gas assets. Our management team has decades of industry experience, most of which were focused on acquiring and managing operated and non-operated oil and gas interests in North America. This team has a proven track record of executing and integrating property acquisitions. We believe our management team’s collective knowledge of the industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions will provide us with opportunities to continue to grow through strategic and accretive acquisitions that complement or expand our existing operations.

 

    Our management team’s significant experience with publicly traded companies and MLPs. Management of our general partner has extensive experience with public MLPs. In 2000, management took APL public. From inception through its merger with a subsidiary of Targa Resource Partners LP in February 2015, APL expanded geographically from a small set of natural gas gathering assets in the Appalachian basin to one of the largest independent gathering and processing companies in the country, with processing capacity of approximately 1.2 Bcf/d. APL returned to its unitholders 421.30% (11.90% annual average) through unit price appreciation and distributions from inception through October 13, 2014 when APL announced its merger with a subsidiary of Targa Resources Partners LP. In 2006, management of our general partner took public Atlas Pipeline Holdings, L.P., or AHD. In conjunction with the sale of Atlas Energy, Inc. to Chevron Corporation, or Chevron, in 2011, AHD purchased certain exploration and production assets from Atlas Energy, Inc. and was subsequently renamed Atlas Energy, L.P., or Atlas Energy. Atlas Energy, Inc. returned to its unitholders 930.5% from inception through 2011 when it announced its acquisition by Chevron. From inception through its announced merger with a subsidiary of Targa Resources Corp. in October 2014, AHD and its successor, ATLS, returned 108.10% (9.30% annual average) through unit price appreciation and distributions. In 2006, management took public Atlas Energy Resources, LLC, or ATN, an exploration and production MLP with assets largely in the Appalachian basin and Michigan. ATN was merged into Atlas Energy, Inc. in a unit-for-share exchange in September 2009. From inception through the sale of Atlas Energy, Inc. to Chevron, ATN returned 178.30% (27.70% annual average) through unit price appreciation and distributions. In February 2012, Atlas Energy contributed the exploration and production assets that it had acquired from Atlas Energy, Inc. prior to the Chevron acquisition into a new exploration and production MLP, ARP. In connection with the Targa mergers, Atlas Energy transferred all of its assets and liabilities, other than those related to its midstream assets (including APL), to ATLS and effected a pro rata distribution to Atlas Energy’s unitholders of 100.00% of ATLS’s common units.

 

    Our diversified asset portfolio characterized by proved undeveloped reserves and long-lived reserves with low geologic risk. Since our formation in 2013, we have acquired over 7,000 net acres consisting of proved undeveloped reserves and proved developed not producing reserves. As of July 2015, we have turned in line 21 wells on such acreage. In the future, we plan to target for acquisition producing and non-producing oil and gas properties that we expect will require additional drilling and other development activities to fully develop their potential.

 

    Our substantial inventory of identified drilling locations. We have a substantial inventory of identified drilling locations. As of our year end 2014 reserves based on SEC mandated pricing of $92.89 per barrel of oil and $4.15 per MMBtu of natural gas, our properties included approximately 102 Bcfe of estimated proved undeveloped reserves and had 70 identified drilling locations.

 

   

Our relationships with our general partner, ATLS, ARP and their respective affiliates, which we believe help us with access to and in the evaluation and execution of future acquisitions. ATLS and

 

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its affiliates have long histories of acquiring producing properties and developing properties into mature, long-lived producing assets. We believe that our ability to use the industry relationships and broad expertise of our general partner, ATLS, ARP and their respective affiliates in expanding our access to acquisitions and evaluating oil and natural gas assets expands our opportunities and differentiates us from many of our competitors. Further, we believe we may have additional opportunities to work jointly with ARP, similar to the Eagle Ford Acquisition discussed above under “—Our Properties,” to pursue acquisitions of oil and natural gas properties that we would not otherwise be able to pursue on our own or that may not otherwise be attractive acquisition candidates for either of us individually.

 

    Our competitive cost of capital and financial flexibility. Unlike our corporate competitors, we are not currently and do not expect to be subject to federal income taxation at the entity level. We believe that this attribute should provide us with a lower cost of capital compared to many of our competitors, thereby enhancing our ability to compete for future acquisitions. We also expect that our ability to issue additional common units and other Partnership interests in connection with acquisitions will enhance our financial flexibility. Further, we intend to utilize a modest amount of debt to provide flexibility in our capital structure.

Our Principal Business Relationships

Our Relationship with Our General Partner

Our general partner is Atlas Growth Partners GP, LLC, a Delaware limited liability company. Our general partner is responsible for the management and administration of the Partnership’s operations and projects. Our general partner is indirectly owned 80.01% by ATLS, and 19.99% by current and former members of ATLS management. Therefore, ATLS controls our general partner. ATLS is focused on the production of natural gas and oil in the continental United States. ATLS currently conducts a majority of its natural gas and oil production activities through its publicly traded subsidiary, ARP.

The officers of our general partner are employees of ATLS, and have experience in managing oil and gas companies. Please read “Management—Directors and Officers of our general partner.” The board of directors of our general partner consists of seven directors, three of whom are independent within the meaning of the applicable rules of the SEC and NYSE. The board of directors has established a conflicts committee, which is composed of the independent directors, for purposes of reviewing potential conflicts of interest between us and our general partner.

Management of our general partner has extensive experience with public MLPs. In 2000, management took APL public. From inception through its merger with a subsidiary of Targa Resource Partners LP in February 2015, APL expanded geographically from a small set of natural gas gathering assets in the Appalachian basin to one of the largest independent gathering and processing companies in the country, with processing capacity of approximately 1.2 Bcf/d. APL returned to its unitholders 421.30% (11.90% annual average) through unit price appreciation and distributions from inception through October 13, 2014 when APL announced its merger with a subsidiary of Targa Resources Partners LP. In 2006, management of our general partner took public AHD. In conjunction with the sale of Atlas Energy, Inc. to Chevron Corporation, or Chevron, in 2011, AHD purchased certain exploration and production assets from Atlas Energy, Inc. and was subsequently renamed Atlas Energy. Atlas Energy, Inc. returned to its unitholders 930.5% from inception through 2011 when it announced its acquisition by Chevron. From inception through its announced merger with a subsidiary of Targa Resources Corp. in October 2014, AHD and its successor, ATLS, returned 108.10% (9.30% annual average) through unit price appreciation and distributions. In 2006, management took public ATN, an exploration and production MLP with assets largely in the Appalachian basin and Michigan. ATN was merged into Atlas Energy, Inc. in a unit-for-share exchange in September 2009. From inception through the sale of Atlas Energy, Inc. to Chevron, ATN returned 178.30% (27.70% annual average) through unit price appreciation and distributions. In February 2012, Atlas Energy contributed the exploration and production assets that it had acquired from Atlas Energy, Inc. prior

 

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to the Chevron acquisition into a new exploration and production MLP, ARP. In connection with the Targa mergers, Atlas Energy transferred all of its assets and liabilities, other than those related to its midstream assets (including APL), to ATLS and effected a pro rata distribution to Atlas Energy’s unitholders of 100.00% of ATLS’s common units.

Our general partner receives an annual management fee equal to the product of 1.00% multiplied by total capital contributions made by our unitholders (other than our general partner and its affiliates), payable quarterly.

In addition, pursuant to our Partnership Agreement, we may issue additional limited partner interests and options, rights, warrants and appreciation rights relating to such limited partner interests for any Partnership purposes at any time on such terms and conditions as our general partner determines appropriate, all without the approval of any unitholders. Upon issuance of any common units, we will automatically issue to our general partner, for no additional consideration and without further requirement of capital contribution by our general partner, an additional number of GP units so that the total number of outstanding GP units after such issuance equals 2.00% of the sum of the total number of common units and GP units outstanding after such issuance. After the listing of common units on a national securities exchange, or listing event, our general partner will have the right to purchase or subscribe for common units whenever we issue common units to any persons on the same terms, to keep our general partner’s percentage interest of the Partnership the same as prior to such issuances.

In addition, if we sell all or substantially all of our properties, merge with or into an existing publicly traded entity or our common units become listed on a national securities exchange, our general partner will be entitled to receive a one-time incentive performance participation amount equal to 20.00% of profits in the form of common units (or cash if the consideration payable in such transaction is cash), subject to our limited partners receiving an aggregate amount equal to their contributed capital plus an amount equal to the target distribution per Unit for each quarter from the date of purchase through the date of sale. Please read “Capital Contributions” and “Cash Distribution Policy and Restrictions on Distributions.”

The success of our business will depend in large part on the services to be rendered to us by our general partner. For more information regarding our management by our general partner, please read “Management.”

Our Relationship with ATLS and ARP

ATLS is a Delaware limited liability company formed in October 2011. Prior to February 2015, ATLS was wholly owned by Atlas Energy, a then publicly traded Delaware MLP. On February 27, 2015, Atlas Energy transferred its assets and liabilities, other than those related to its midstream assets, to ATLS, and effected a pro rata distribution to its unitholders of common units representing a 100.00% interest in ATLS. ATLS’s common units began trading “regular-way” under the ticker symbol “ATLS” on the NYSE on March 2, 2015. Concurrently with the distribution of the units, Atlas Energy and its midstream subsidiaries merged with subsidiaries of Targa Resources Corp., or Targa (NYSE: TRGP) and ceased trading.

Today, ATLS is a publicly traded MLP focused on the production, transportation and processing of natural gas and oil in the United States. ATLS conducts business through its subsidiaries, including the Partnership, ARP, and Lightfoot Capital Partners. ATLS’s assets consist of the following:

 

    80.01% interest in our general partner and approximately 500,010 common units representing limited partner interests in the Partnership;

 

    100.00% of our GP units, all of the IDRs, and an approximate 27.5 million limited partner interest (consisting of 20,962,485 common and 3,749,986 preferred limited partner units) in ARP, a publicly traded Delaware MLP and an independent developer and producer of natural gas, crude oil and NGLs, with operations in basins across the United States. ARP sponsors and manages tax-advantaged investment partnerships, in which it coinvests, to finance a portion of its natural gas and oil production activities;

 

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    15.90% general partner interest and 12.00% limited partner interest in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, its general partner, which incubate new MLPs and invest in existing MLPs. As of December 31, 2012, Lightfoot’s principal asset was a company that provides storage and delivery services for customers in Alabama, Illinois, Maryland, North Carolina, Ohio, South Carolina, Virginia and Wisconsin for crude oil, refined petroleum products, asphalt and chemicals, with a capacity of approximately 3.6 MMBbl; and

 

    direct natural gas development and production assets in the Arkoma Basin, which Atlas Energy acquired in July 2013.

Management was involved in the formation and initial public offering of ARP, a publicly traded exploration and production MLP. In connection with the formation of ARP, Atlas Energy conveyed substantially all of the assets and liabilities associated with its natural gas and oil development and production assets and its partnership management business to ARP in exchange for approximately 5.24 million common units representing an approximately 19.6% limited partner interest in ARP. Atlas Energy distributed such common units to its unitholders on March 13, 2012, effecting ARP’s initial public offering.

ARP develops and produces natural gas and oil in some of the most prolific basins across the United States, including the Marcellus, Utica, Niobrara, Barnett Shale and the Marble Falls. ARP also continues to sponsor and manage tax-advantaged drilling investment partnerships in which it co-invests and that it uses to finance a portion of its natural gas and oil production activities.

As of December 31, 2014, based on SEC mandated pricing of $94.99 per barrel of oil and $4.35 per MMBtu of natural gas, the estimated proved reserves for ARP were 1,429 Bcfe. Of its estimated proved reserves, approximately 77% were proved developed and approximately 71% were natural gas. For the year ended December 31, 2014, ARP’s average daily net production was approximately 270.0 MMcfe. As of December 31, 2014, ARP owns production positions in the following geographic areas:

 

    ARP’s Barnett Shale and Marble Falls play in the Fort Worth Basin in northern Texas where it has ownership interests in approximately 715 wells and 399 Bcfe of total proved reserves with average daily production of 79.9 MMcfe for the year ended December 31, 2014;

 

    ARP’s coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama, the Central Appalachian Basin in southern West Virginia and southwestern Virginia, and the County Line area of Wyoming where it has ownership interests in approximately 3,440 wells and 523 Bcfe of total proved reserves with average daily production of 120.8 MMcfe for the year ended December 31, 2014;

 

    ARP’s Appalachia Basin where it has ownership interests in approximately 8,127 wells and 144 Bcfe of total proved reserves with average daily production of 40.7 MMcfe for the year ended December 31, 2014, including 280 wells in the Marcellus and Utica Shales;

 

    ARP’s Eagle Ford Shale in southern Texas where it has ownership interests in approximately 24 wells and 64 Bcfe of total proved reserves with average daily production of 2.1 Bcfe for the year ended December 31, 2014;

 

    ARP’s Rangely field in northwest Colorado where it has non-operated ownership interests in approximately 400 wells in the Rangely field and 176 Bcfe of total proved reserves with average daily production of 8.3 Bcfe for the year ended December 31, 2014;

 

    ARP’s Mississippi Lime and Hunton plays in northwestern Oklahoma where it owns 109 Bcfe of total proved reserves with average daily production of 12.7 MMcfe for the year ended December 31, 2014; and

 

    ARP’s other operating areas, including the Chattanooga Shale in northeastern Tennessee, the New Albany Shale in southwestern Indiana and the Niobrara Shale in northeastern Colorado in which ARP has an aggregate 15 Bcfe of total proved reserves with average daily production of 5.4 MMcfe for the year ended December 31, 2014.

 

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ARP has actively engaged in the acquisition of natural gas and oil interests. During 2012, ARP acquired approximately 700 Bcfe of proved reserves, 19,800 undeveloped acres in Oklahoma’s Mississippi Lime play and approximately 75,000 net acres in the Marble Falls play in the Fort Worth Basin of Texas.

As a result of its significant ownership interests in us and our general partner, we believe ATLS will be motivated to support the successful execution of our business strategy and will provide us with opportunities to pursue acquisitions that will be accretive to unitholders. ATLS views us as part of its growth strategy, and we believe that ATLS and its affiliates will be incentivized to contribute or sell assets to us and to pursue acquisitions jointly with us in the future. For example, in October 2014 we completed the Eagle Ford Acquisition, discussed in “—Our Properties—Eagle Ford,” which was the result of a joint bid with ARP. However, ATLS regularly evaluates acquisitions and dispositions and may elect to acquire or dispose of properties in the future without offering us the opportunity to participate in those transactions. Although we believe ATLS is incentivized to offer properties to us for purchase, none of ATLS, ARP or any of their respective affiliates has any obligation to sell or offer properties to us. Please read “Conflicts of Interest and Fiduciary Duties.”

Our Oil and Natural Gas Data

Our Reserves

The preparation of our natural gas, oil and NGL reserve estimates was completed in accordance with our prescribed internal control procedures by our reserve engineers. The accompanying reserve information was derived from the reserve reports prepared internally as of September 30, 2015 and December 31, 2014 and 2013. The reserve information includes natural gas, oil and NGL reserves which are all located in Texas and Oklahoma. Our internal control procedures include verification of input data as well as a multi-functional management review. The preparation of reserve estimates was overseen by our Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 16 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our senior engineering staff and management, with final approval by the Executive Vice President of Operations.

Qualifications of Responsible Technical Persons

Internal Engineers

Mark Schumacher, Dave E. Leopold, Trevor Mallernee, Nikki Morris and Rene St. Pierre are the technical persons employed by our general partner primarily responsible for operations and preparing the reserve report for our properties.

Mark D. Schumacher has been Senior Vice President of ATLS and President of ARP. Since April 2015, Mr. Schumacher has overseen all of our oil and natural gas operations. Mr. Schumacher has served as Chief Operating Officer of our general partner since October 2013 and served as Executive Vice President of our general partner from July 2012 to October 2013. From August 2008 to July 2012, Mr. Schumacher served as President of Titan Operating, LLC, which was acquired by ATLS in July 2012. From November 2006 until August 2008, Mr. Schumacher served as President of Titan Resources, LLC, which built an acreage position in the Barnett Shale that it sold to XTO Energy in October 2008. From February 2005 to November 2006, Mr. Schumacher served as the Team Lead of EnCana Oil & Gas (USA) Inc. where he was responsible for Encana’s Barnett Shale development. Mr. Schumacher was an engineer with Union Pacific Resources from 1984 to 2000.

Dave E. Leopold has recently served as Senior Vice President of Operations at ARP. Prior to joining ATLS and its affiliates, Mr. Leopold was Operations Manager for Chesapeake Energy where he led the Barnett Shale operations team to help develop the second largest position in the basin. In addition, Mr. Leopold previously served in management roles at Anadarko Petroleum.

 

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Trevor Mallernee has served as the Director of Reservoir Engineering for ATLS and its affiliates for the last 10 years. During this time he has been directly involved with several shale plays throughout the country including the Marcellus, Utica, Barnett, and Eagle Ford plays as well as many other conventional and unconventional oil and gas plays. The reservoir engineering group led by Mr. Mallernee is responsible for all aspects of reservoir engineering for ATLS and its affiliates including SEC reporting, budget forecasting, corporate development, reservoir engineering support, and operating team reservoir engineering support. Prior to joining ATLS Mr. Mallernee served as Reservoir Engineer for Great Lakes Energy and Range Resources. Prior to that he worked as an offshore drilling engineer for Chevron in both the Gulf of Mexico and in West Africa.

Nikki Morris has been the Geoscience Manager since July 2015. Nikki joined ATLS in 2014, bringing with her several years of industry experience in prospect analysis and resource development of multiple plays across the U.S. through her tenures with XTO, Plains E&P and FireWheel Energy. She has worked multiple basins throughout the U.S. including the Appalachian Basin, Permian Basin, West Texas; Santa Maria Basin, CA; Eagle Ford Shale, South Texas; and the Big Horn Basin, WY. Nikki received her Bachelor of Science and Masters of Science in Geology from Texas Christian University in 2008 and 2010. She has also received her MBA from Rice University in May 2014.

Rene St. Pierre has been employed in the oil and natural gas industry for nearly 40 years. Mr. St Pierre has been the Vice President of Drilling for ATLS since December 2014. Prior to joining ATLS, Mr. St Pierre was the Vice President Drilling—Northern Division for Chesapeake Energy for seven years. He has been involved in drilling and completion activities in nearly every producing basin in the domestic U.S. and Gulf of Mexico including an international assignment in Oman. Mr. St. Pierre has been very active in American Association of Drilling Engineers, serving as an officer in several different chapters and on the national level board of directors for several terms. Mr. St. Pierre has also served as the National AADE President on multiple occasions. He has been registered as a Professional Engineer in the States of California & Wyoming.

 

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Estimated Proved Reserves

The following table summarizes information regarding our estimated proved natural gas and oil reserves as of December 31, 2014 and 2013. The following table presents the historical proved oil and natural gas reserves attributable to our properties as of December 31, 2014 and 2013, giving effect to the Eagle Ford assets acquired effective July 1, 2014 and excluding the pro forma adjustment assuming the Eagle Ford assets were sold during the period presented.

 

     Historical Proved
Reserves at
December 31,
 
     2014      2013  

Reserve data:

     

Estimated net proved reserves(1):

     

Natural gas reserves (MMcf):

     

Proved developed reserves

     1,255         241   

Proved undeveloped reserves

     7,238         —     
  

 

 

    

 

 

 

Total proved reserves of natural gas

     8,493         241   

Oil reserves (MBbl):

     

Proved developed reserves

     612         70   

Proved undeveloped reserves

     14,319         —     
  

 

 

    

 

 

 

Total proved reserves of oil

     14,931         70   

NGL reserves (MBbl):

     

Proved developed reserves

     205         37   

Proved undeveloped reserves

     1,417         —     
  

 

 

    

 

 

 

Total proved reserves of NGL

     1,622         37   
  

 

 

    

 

 

 

Total proved reserves (MMcfe)

     107,815         884   
  

 

 

    

 

 

 

Standardized measure of discounted future cash flows (in thousands)

   $ 290,416       $ 3,110   
  

 

 

    

 

 

 

Reserve natural gas and oil prices:

     

Unadjusted prices(2):

     

Natural gas (per Mcf)

   $ 4.35       $ 3.67   

Oil (per Bbl)

   $ 94.99       $ 96.78   

Natural gas liquids (per Bbl)

   $ 30.21       $ 30.10   

Average Realized Prices, Before Hedge:

     

Natural gas (per Mcf)

   $ 4.00       $ 3.63   

Oil (per Bbl)

   $ 88.61       $ 93.16   

Natural gas liquids (per Bbl)

   $ 28.80       $ 34.88   

 

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The following table presents the actual estimated net proved oil and natural gas reserves attributable to our properties as of September 30, 2015 and our estimated net proved oil and natural gas reserves as of December 31, 2014 and 2013 attributable to our properties on a pro forma basis assuming the Eagle Ford assets assigned to ARP on September 21, 2015 had been assigned as of such dates, and the actual standardized measure amounts associated with the estimated proved reserves attributable to our properties as of September 30, 2015, and our standardized measure amounts associated with the estimated proved reserves as of December 31, 2014 and 2013 attributable to our properties on a pro forma basis assuming the Eagle Ford assets assigned to ARP on September 21, 2015 had been assigned as of such dates. The standardized measure amounts shown in the table are not intended to represent the current market value of estimated oil and natural gas reserves.

 

     Historical
Reserves at
September 30,
     Pro Forma Reserves at  
        December 31,  
     2015      2014      2013  

Reserve data:

        

Estimated net proved reserves(1):

        

Natural gas reserves (MMcf):

        

Proved developed reserves

     705         1,255         241   

Proved undeveloped reserves

     2,259         3,938         —     
  

 

 

    

 

 

    

 

 

 

Total proved reserves of natural gas(2)

     2,964         5,193         241   

Oil reserves (MBbl):

        

Proved developed reserves

     1,589         612         70   

Proved undeveloped reserves

     5,766         6,739         —     
  

 

 

    

 

 

    

 

 

 

Total proved reserves of oil

     7,355         7,351         70   

NGL reserves (MBbl):

        

Proved developed reserves

     112         205         37   

Proved undeveloped reserves

     373         757         —     
  

 

 

    

 

 

    

 

 

 

Total proved reserves of NGL(2)

     485         962         37   
  

 

 

    

 

 

    

 

 

 

Total proved reserves (MMcfe)

     50,001         55,078         884   
  

 

 

    

 

 

    

 

 

 

Standardized measure of discounted future cash flows (in thousands)

     43,597       $ 159,741       $ 3,110   
  

 

 

    

 

 

    

 

 

 

 

Reserve natural gas and oil prices:

        

Unadjusted prices:

        

Natural gas (per Mcf)

   $ 2.67       $ 4.35       $ 3.67   

Oil (per Bbl)

   $ 50.47       $ 94.99       $ 96.78   

Natural gas liquids (per Bbl)

   $ 13.46       $ 30.21       $ 30.10   

Average Realized Prices, Before Hedge:

        

Natural gas (per Mcf)

   $ 2.65       $ 4.00       $ 3.63   

Oil (per Bbl)

   $ 47.09       $ 88.61       $ 93.16   

Natural gas liquids (per Bbl)

   $ 12.63       $ 28.80       $ 34.88   

 

(1)  Oil and NGLs are converted to gas equivalent basis at the rate of one barrel of oil or NGLs to six Mcf of natural gas. This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value.
(2)  The reduction in total natural gas and NGL historical reserves at September 30, 2015 compared to the pro forma reserves at December 31, 2014 was driven primarily by a substantial decrease in natural gas and NGL prices (based on SEC pricing) at September 30, 2015 as compared to December 31, 2014. This decrease made a portion of our natural gas and NGL volumes fall out of the proved reserves category due to the reduced economics.

 

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The data in the table above represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. For a discussion of risks associated with internal reserve estimates, please read “Risk Factors—Risks Related to Our Oil and Gas Operations—Estimates of reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure amounts shown above should not be construed as the current market value of our estimated oil and natural gas reserves. The 10.00% discount factor used to calculate standardized measure, which is required by the FASB, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Development of Proved Undeveloped Reserves (“PUDs”)

None of our proved undeveloped reserves as of September 30, 2015 are scheduled to be developed on a date more than five years from the date of the initial disclosure of the reserves as proved undeveloped reserves. Historically, Atlas Energy Group, LLC’s drilling and development programs were substantially funded from its cash flow from operations. Our adopted drilling and development program consists of expansion capital expenditures including the drilling of our current inventory of proved undeveloped locations and our expansions in the next five years with our cash flows from operations and available external capital sources (including the proceeds from this proposed offering and our credit facility. Maintenance capital expenditures constitute a small portion of our total capital expenditures and will be funded from our cash flows from operations. For a more detailed discussion of our liquidity position, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Changes in PUDs. Changes in PUDs that occurred from January 1, 2014 through December 31, 2014 were due to the following:

 

    addition of approximately 1.4 Net Bcfe due to our drilling activity in Marble Falls; and

 

    addition of approximately 98.4 Net Bcfe due to our acquisition of acreage in the Eagle Ford Shale.

Changes in PUDs that occurred from January 1, 2015 through September 30, 2015 were due to the following:

 

    addition of approximately 6.2 Net Bcfe due to our drilling activity in the Eagle Ford Shale;

 

    negative revisions of approximately 52.7 Net Bcfe in PUDs primarily due to our assignment of Eagle Ford PUDs to ARP; and

 

    negative revisions of approximately 3.3 Net Bcfe in PUDs primarily due to SEC five year booking rule constraints.

Development Costs. Costs incurred related to the development of PUDs were approximately $14.0 million for the nine months ended September 30, 2015. There were no costs incurred related to the development of PUDs for the years ended December 31, 2014 and 2013. During the nine months ended September 30, 2015, approximately 12.0 Net Bcfe of our reserves were converted from PUDs to proved developed reserves. All of the 12.0 Net Bcfe of our reserves converted from PUDs to proved developed reserves during the nine months ended September 30, 2015 is related to PUDs acquired and developed during the year. During the years ended December 31, 2014 and 2013, none of our reserves were converted from PUDs to proved developed reserves. As of December 31, 2014 and September 30, 2015, there were no PUDs that had remained undeveloped for five years or more.

 

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Production, Revenue and Price History

The following table sets forth information regarding combined net production of oil and natural gas and certain price and cost information (i) of us on a historical basis and (ii) of the Eagle Ford properties (which are non-operating assets) on a historical basis for each of the periods presented:

 

     Atlas Growth Partners, L.P.      Eagle Ford  
     Year
Ended December 31,
     Year to Date
September 30th,
     Year Ended
December 31,
     Year to Date
September 30th,
 
     2013      2014      2015      2013      2014      2015  

Production and operating data:

                 

Net production volumes:

                 

Oil (MBls)

     3         43         928         —           2         142   

NGLs (MBbls)

     1         32         138         —           1         7   

Natural Gas (MMcf)

     8         252         162         —           —           32   

Total (MMcfe)

     29         701         1,228         —           15         928   

Average net production (Mcfe/d)

     79         1,920         4,497         —           42         3,397   

Average realized sales price:

                 

Oil (per Bbl)

   $ 93.16       $ 88.61       $ 48.39       $ —         $ 56.64       $ 48.16   

NGLs (per Bbl)

   $ 34.88       $ 28.80       $ 12.63       $ —         $ 16.26       $ 14.42   

Natural Gas (per Mcf)

   $ 3.63       $ 4.00       $ 2.65       $ —         $ 3.76       $ 3.04   

Average unit costs per Mcfe:

                 

Lease operating expenses

   $ 2.32       $ 2.47       $ 0.99       $ —         $ 1.63       $ 0.54   

Production taxes

   $ 0.45       $ 0.48       $ 0.32       $ —         $ 0.39       $ 0.34   

Transportation

   $ —         $ —         $ 0.06       $ —         $ —         $ 0.07   

General and administrative expenses

   $ 111.81       $ 16.76       $ 8.16            

Depreciation, depletion and amortization

   $ 4.60       $ 3.08       $ 4.15            

Acreage

Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. As of September 30, 2015, 100% of our leasehold acreage was held by production. The following table sets forth information about our developed and undeveloped natural gas and oil acreage as of September 30, 2015:

 

     Developed acreage (1)      Undeveloped acreage(2)  
     Gross (3)      Net (4)      Gross (3)      Net (4)  

Eagle Ford

     2,239         2,239         596         596   

Marble Falls

     1,319         1,311         942         896   

Mississippi Lime

     76         9         76         9   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     3,634         3,559         1,614         1,501   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)  Developed acres are acres spaced or assigned to productive wells.
(2)  Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves.
(3)  A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.
(4)  Net acres are the sum of the fractional working interests owned in gross acres. For example, a 50% working interest in an acre is one gross acre but is 0.5 net acres.

 

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Drilling Activities

Our drilling activities are conducted mostly on undeveloped acreage. There were no gross or net dry wells drilled during the periods presented below. The following table presents the number of wells we drilled and the number of wells we turned in line, both gross and net during the nine months ended September 30, 2015 and 2014 and the years ended December 31, 2014 and 2013:

 

     Nine Months Ended
September 30,
     Year Ended
December 31,
 
     2015      2014      2014      2013  

Gross wells drilled(2):

           

Eagle Ford(3)

     —          —          —          —    

Marble Falls

     —          11.0         11.0         2.0   

Mississippi Lime

     —          2.0         2.0         —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     —          13.0         13.0         2.0   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net wells drilled(2):

           

Eagle Ford(3)

     —          —          —          —    

Marble Falls

     —          11.0         11.0         2.0   

Mississippi Lime

     —          0.4        0.4        —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     —          11.4         11.4         2.0   
  

 

 

    

 

 

    

 

 

    

 

 

 

Gross wells turned in line:

           

Eagle Ford(3)

     4.0         —          2.0         —    

Marble Falls

     —          10.0         11.0         2.0   

Mississippi Lime

     —          1.0         2.0         —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     4.0         11.0         15.0         2.0   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net wells turned in line:

           

Eagle Ford(3)

     4.0         —          2.0         —    

Marble Falls

     —          10.0         11.0         2.0   

Mississippi Lime

     —          0.2        0.4        —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     4.0         10.2         13.4         2.0   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)  Wells turned in line refers to wells that have been drilled, completed and connected to a gathering system.
(2)  There were no exploratory wells drilled during the nine months ended September 30, 2015 and 2014, and the years ended December 31, 2014 and 2013.
(3)  The drilling activity related to Eagle Ford was included effective November 5, 2014, the date of acquisition. Ten wells were drilled by the prior owner, Cinco, but not yet turned in line, at the date of acquisition.

 

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The following table sets forth information regarding productive natural gas and oil wells in which we have a working interest as of September 30, 2015. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of productive wells in which we have an interest and net wells are the sum of our fractional working interests in gross wells:

 

     Number of Productive Wells(1)  
     Gross      Net  

Marble Falls:

     

Gas wells

     9.0         9.0   

Oil wells

     4.0         4.0   
  

 

 

    

 

 

 

Total

     13.0         13.0   
  

 

 

    

 

 

 

Mississippi Lime:

     

Gas wells

     2.0         0.4   

Oil wells

               
  

 

 

    

 

 

 

Total

     2.0         0.4   
  

 

 

    

 

 

 

Eagle Ford:

     

Gas wells

               

Oil wells(2)

     8.0         8.0   
  

 

 

    

 

 

 

Total

     8.0         8.0   
  

 

 

    

 

 

 

Total:

     

Gas wells

     11.0         9.2   

Oil wells

     12.0         12.0   
  

 

 

    

 

 

 

Total

     23.0         21.2   
  

 

 

    

 

 

 

 

(1)  There were no exploratory wells drilled during the nine months ended September 30, 2015; there were no gross or net dry wells within our operating areas during the nine months ended September 30, 2015.
(2) The eight productive wells include the six producing wells and two wells (of the four wells awaiting completion) that were capable of production as of September 30, 2015. The two wells that were capable of production as of September 30, 2015 were subsequently turned in line on October 10, 2015 and therefore meet the definition of a productive well at that date.

Our Operations

General

As of September 30, 2015, we, our general partner or our affiliates operated 90% of the wells and properties containing our proved reserves on our behalf. Our general partner provides management, administrative and operating services to us to manage and operate our business and assets.

During drilling operations, our general partner designs and manages the development, recompletion and/or workover operations, and supervises other operation and maintenance activities, for all of the wells we operate. Our general partner will complete each well if there is a reasonable probability of obtaining commercial quantities of natural gas or oil. The determination to complete, or to plug and abandon, any well is in the discretion of our general partner. Our general partner expects to subcontract the actual drilling and completion of most, if not all, of the Partnership’s wells to third parties selected by our general partner who will be subject to our general partner’s supervision.

During producing operations, our general partner manages all field operations, maintains the wells, makes technical decisions in operating and supervises other operation and maintenance activities. Our general partner will also provide all services that may be needed with respect to any water disposal wells, injection wells,

 

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transportation of wastewater or similar matters as provided in the drilling and operating agreement. Our general partner will subcontract the actual day-to-day operation of most, if not all, of the wells, to third parties subject to its supervision.

Use of Consultants and Subcontractors

The Partnership Agreement authorizes our general partner to use the services of independent outside consultants and subcontractors on behalf of the Partnership. The services normally will be paid on a per diem or other cash fee basis and will be charged to the Partnership as either a direct cost or as a direct expense. These charges will be in addition to the costs of subcontractor services provided by our general partner’s affiliates, which will be charged at competitive rates.

Marketing and Major Customers

We sell natural gas, crude oil and natural gas liquids under contracts to purchasers in the normal course of business. For the period ending September 30, 2015, the north Texas Marble Falls production had two markets for its natural gas and natural gas liquids, ETC Marketing. Ltd. and Enbridge G&P (N. TX) LP. Crude oil was purchased by Enterprise Crude Oil, LLC. In south Texas, the Eagle Ford natural gas and natural gas liquids were marketed to Regency Field Services, LLC. The crude oil was purchased by Enterprise Crude Oil, LLC and Shell Trading Company (US).

We generally sell natural gas, crude oil and NGLs through production sales agreements with customary terms and conditions for the oil and natural gas industry at prevailing market prices. Typically, our sales contracts are based on pricing provisions that are tied to a market index or postings, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas, as well as trucking options for the crude oil. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibilities of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which we have an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty. Production operated by third parties is typically marketed by that third party with allocated proceeds coming to us for our interest in that production. We have no commitments to deliver a fixed or determinable quantity of our oil or natural gas production in the near future under our existing contracts.

If we were to lose any of our markets, the loss could temporarily delay production and sale of a portion of our natural gas, crude oil and NGLs in the related producing region until alternate marketing arrangements could be made. While not a high probability, the loss of one or more markets could have a detrimental effect on our production volumes until remedied.

Title to Properties

Title to all leases acquired by us ultimately will be held in the name of the Partnership. However, to facilitate our acquisition of the leases the title to the leases may initially be held in the name of our general partner, the operator, their affiliates, or any nominee designated by our general partner. Title to our leases will be transferred to us and filed for record from time to time after the wells are drilled and completed.

Our general partner will take the steps it deems necessary to assure that we have acceptable title for our purposes. However, it is not the practice in the natural gas and oil industry to warrant title or obtain title insurance on leases and our general partner will provide neither for the leases it assigns to us. Our general partner will obtain a favorable formal title opinion for the leases before each well is drilled, but will exercise its discretion as to whether or not to obtain a division order title opinion after the well is completed. Our general partner may use its own judgment in waiving title requirements and will not be liable for any failure of title of the

 

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leases transferred to us. Also, we may experience losses from title defects excluded from, or not disclosed by, the formal title opinion that is provided to our general partner before a well is drilled or that would have been disclosed by a division order title opinion after the well is drilled, if we obtained division order title opinions, which we generally will not do. Although past performance is no guarantee of future results, the previous drilling partnerships sponsored by our general partner and its affiliates have participated in drilling more than 6,000 wells since 1985, and none of the wells have been lost because of title failure.

Well Operations and Drilling and Completion Activities

Our general partner and its affiliates may serve as operator of some of our properties. Generally, the existing operating agreement will be used in instances where a property being acquired is already subject to an operating agreement, and in all other cases, our general partner anticipates that a model form operating agreement issued by the American Association of Petroleum Landmen or other form agreement that is customary and usual for the geographic area in which the property is located will be used. Under the applicable operating agreement for a property, our general partner or a third party operator will act as operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest. As operator, our general partner or the third-party operator will design and manage the operations for production from and drilling and completion of our wells and manage the day-to-day operating and maintenance activities for our well.

Under the applicable operating agreements, our general partner or a third-party operator will establish a joint account for each well in which we have an interest. We are required to pay our working interest share of amounts charged to the joint account. The joint account is charged with well supervisory fees and all direct expenses incurred in the operation of our wells and related gathering systems and production facilities. Our general partner anticipates that the determination of which direct expenses can be charged to the joint account and the manner of charging direct expenses to the joint account for our wells generally will be done in accordance with the Council of Petroleum Accountants Societies, or COPAS, model form of accounting procedure.

Under the COPAS model form, direct expenses include the costs of third-party services performed on our properties and wells, as well as gathering and other equipment used on our properties. In addition, direct expenses include the allocable share of the cost of services performed on our properties and wells by employees of our general partner or a third-party operator. The allocation of the costs incurred by our general partner or a third-party operator who perform services on our properties will be based on the applicable provisions of the relevant operating agreement.

Our general partner and its affiliates may serve as the general drilling contractor of some of our wells. If our general partner serves as operator and general drilling contractor, its duties will include:

 

    making the necessary arrangements for drilling and completing wells owned by the Partnership and related facilities for which it has responsibility, such as determining the exact location where the wellbore will be drilled after reviewing geologic and/or geophysical information it has compiled, and selecting the provider of the drilling rig;

 

    managing and conducting all field operations in connection with drilling, testing and equipping the wells, which includes receiving and paying invoices from the subcontractors, confirming that the invoices are reasonable and monitoring compliance by each subcontractor with its contract; and

 

    making the technical decisions required in drilling and completing the wells, such as:

 

    determining how much casing should be placed in the well, which in turn depends primarily on the depth of the well and whether the well will be drilled horizontally;

 

    designing the fracturing program for the well, which includes how much and what kind of fluid or gel to pump into the wellbore, whether sand or foam should be pumped into the wellbore and, if so, how much, and whether or not nitrogen should be pumped into the wellbore;

 

    designing the cementing program for the well, including a plan to contain any water that may be encountered in the wellbore, such as cementing certain formations in the well;

 

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    designing the completion program for the well, which includes reviewing and analyzing the wells’ logs, and determining which formations to perforate, and how and where to shoot holes in the formation, which generally means treating separately all potentially productive geological formations in vertical wells, if any, and multiple fracks at intervals along the lateral in horizontal wells in an attempt to enhance the natural gas and oil production from the well; and

 

    designing water disposal plans, including using, drilling or purchasing salt water disposal wells or transporting the wastewater by trucks or water pipelines to salt water disposal wells or recycling or treatment centers, if needed, for the wells and obtaining required state permits.

Hedging Arrangements

Pricing for natural gas and oil has been volatile and uncertain for many years. To limit exposure to changes in natural gas and oil prices in the future, our general partner and its affiliates, including AGP, ATLS and ARP, have used in the past and will continue to use financial hedges through contracts such as regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. They may also use physical hedges through their natural gas and oil purchasers as discussed below. The futures contracts employed by our general partner and its affiliates are commitments to purchase or sell natural gas and oil at future dates and generally cover one-month periods for up to 60 months in the future. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, we will establish a risk management committee to assure that all financial trading is done in compliance with our hedging policies and procedures. We do not intend to contract for positions that it cannot offset with actual production. Any physical hedges require firm delivery of natural gas or oil and, therefore, are considered normal sales of natural gas and oil, rather than hedges, for accounting purposes. The percentages of natural gas and oil that are hedged through either financial hedges, physical hedges or not hedged at all will change from time to time in the discretion of our general partner.

The natural gas and oil produced by us is being sold at contract prices in the month produced or at spot market prices. The prices under most of ours and our affiliates’ natural gas and oil sales contracts are negotiated on an annual basis and are index-based. As discussed above, to limit exposure to natural gas or oil price changes, our general partner and its affiliates have used hedges in the past, and we expects that we will do so in the future, to lock in a range of pricing for a significant portion of the Partnerships’ production during the periods covered by the hedges. However, since the advisability of hedging is subject to numerous economic factors beyond our general partner’s control, there can be no assurance as to the amount of hedging our general partner will cause the Partnership to do, or whether hedging will be done at all.

Although entering into hedging arrangements may provide the Partnership some protection against changing prices, these activities also could reduce the potential benefits of price increases and the Partnership could incur liability on the financial hedges. For example, the Partnership would be exposed to the risk of a financial loss if any of the following occur:

 

    the Partnership’s production is substantially less than expected;

 

    the counterparties to the futures contracts fail to perform under the contracts, the risk of which is increased because of the current tight credit market in the United States; or

 

    there is a sudden, unexpected event materially impacting natural gas and oil prices.

Credit Facility

On May 1, 2015, we entered into a secured credit facility agreement with Wells Fargo. As of September 30, 2015 and November 30, 2015, the lenders under the credit facility have no commitment to lend to us and we have a zero-dollar borrowing base under the credit facility, but we and our subsidiaries have the ability to enter into derivative contracts to manage our exposure to commodity price movements that will benefit from the collateral

 

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securing the credit facility. The credit facility may be amended in the future if we request a borrowing base redetermination and the lenders agree to establish the borrowing base and related commitments thereunder. If the borrowing base is redetermined to an amount greater than zero dollars, the credit facility would allow us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semiannually by our lenders in their sole discretion. We are in discussions with our lenders to set a borrowing base for our credit facility. Pending market conditions, we currently anticipate our lenders to set a borrowing base during the forecast period. Please read “Cash Distribution Policy and Restrictions on Distributions — Estimated Cash Available for Distribution.” Once established, our borrowing base will be subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil and natural gas reserves, which takes into account the prevailing oil and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. A future decline in commodity prices could result in a redetermination that lowers our borrowing base at that time and, in such case, we could be required to repay any indebtedness outstanding at that time in excess of the borrowing base. If we borrow under the credit facility and we are unable to repay any borrowings in excess of a decreased borrowing base, we would be in default and no longer able to make any distributions to our unitholders.

In addition, our credit facility includes customary events of default, including failure to timely pay, breach of covenants, bankruptcy, cross-default with other material indebtedness (including obligations under swap agreements in excess of any agreed upon threshold amount), and change of control.

Competition

The oil and natural gas industry is highly competitive. We will encounter strong competition from independent oil and gas companies, MLPs and from major oil and gas companies in acquiring properties, contracting for drilling equipment and arranging for the services of trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or other resources will permit.

Competition is strong for attractive oil and natural gas properties and there can be no assurances that we will be able to compete satisfactorily when attempting to make acquisitions. In general, sellers of producing properties are influenced primarily by the price offered for the property, although a seller also may be influenced by the financial ability of the purchaser to satisfy post-closing indemnifications, plugging and abandoning operations and similar factors.

We also may be affected by competition for drilling rigs, human resources and the availability of related oilfield services and equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and have caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas where we may acquire producing properties. In addition, it is possible that we will acquire oil and gas properties that are subject to flooding, drought or tornados. These seasonal anomalies can pose challenges for meeting our drilling objectives and increase competition for equipment, supplies and personnel during the drilling season, which could lead to shortages and increased costs or delay our operations. Generally demand for natural gas is higher in summer and winter months. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter natural gas requirements during off-peak months. This can also lessen seasonal demand fluctuations.

 

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Environmental, Health and Safety Matters and Regulation

Our operations will be subject to stringent and complex federal, state and local laws and regulations that govern the protection of the environment as well as the discharge of materials into the environment. These laws and regulations may, among other things:

 

    require the acquisition of various permits before drilling commences;

 

    require the installation of pollution control equipment in connection with operations;

 

    place restrictions or regulations upon the use or disposal of the material utilized in our operations;

 

    restrict the types, quantities and concentrations of various substances that can be released into the environment or used in connection with drilling, production and transportation activities;

 

    limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;

 

    require remedial measures to mitigate pollution from former and ongoing operations, and may also require site restoration, pit closure and plugging of abandoned wells; and

 

    require the expenditure of significant amounts in connection with worker health and safety.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as waste handling, permitting, or cleanup for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry has recently been the subject of increased legislation and regulatory attention with respect to environmental matters.

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

National Environmental Policy Act

Oil and natural gas drilling and production activities on federal lands, or that require federal approvals, may be subject to the National Environmental Policy Act, or NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All proposed drilling and development plans on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

Endangered Species Act

The Endangered Species Act, or the ESA, was established to protect endangered and threatened species. Pursuant to the act, if a species is listed as threatened or endangered, restrictions may be imposed on activities that would harm the species or that would adversely affect that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may conduct operations on land inhabited by species that are listed, or species that could be listed, as threatened or endangered under the ESA. The U.S. Fish and Wildlife Service designates the species’ protected habitat as part of the effort to protect the species. A protected habitat designation or the mere presence of threatened or endangered species could result in material restrictions to our use of the land and may materially delay or prohibit land access for oil and natural gas development. It

 

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also may adversely impact the value of the affected properties that we acquire. The designation of previously unprotected species as threatened or endangered in areas where we might conduct operations could result in limitations or prohibitions on our activities and could adversely impact the value of our projects.

Oil Pollution Act

The primary federal law for oil spill liability is the Oil Pollution Act, or OPA, which amends and augments oil spill provisions of the Clean Water Act, as defined below, and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge on properties we acquire, we may be liable for costs and damages.

CERCLA

The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, imposes joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so-called potentially responsible parties, or PRPs, include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third-parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.

Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our expected operations, we will generate wastes that may fall within CERCLA’s definition of hazardous substance and may dispose of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum, and there is no guarantee that federal law will not adopt more stringent requirements with respect to the petroleum substances. We may also be the owner or operator of sites on which hazardous substances have been released. If contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages. Further, we could be required to suspend or cease operations in contaminated areas.

We may acquire producing properties that have been used for oil and natural gas drilling, development and production for many years. Hazardous substances, wastes or hydrocarbons may have been released on or under the properties to be acquired by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of the properties we acquire may have been operated by third-parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA (please read below) and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

 

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Resource Conservation and Recovery Act

The federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and solid waste. Although oil and natural gas waste generally is exempt from regulation as “hazardous waste” under RCRA, we expect to generate waste as a routine part of our operations that may be subject to RCRA. Although a substantial amount of the waste expected to be generated in our operations is regulated as non-hazardous solid waste rather than hazardous waste, there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous or exempt waste or categorize some non-hazardous or exempt waste as hazardous in the future. Any such change could result in substantial costs to manage and dispose of waste, which could have a material adverse effect on our results of operations and financial position.

Clean Water Act

The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Under its Clean Water Act authority, on April 7, 2015, the EPA published proposed effluent limitation guidelines that may impose federal pre-treatment standards on oil and gas operators discharging wastewater arising from fracturing activities to publicly owned treatment works.

The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, we may be liable for penalties and cleanup and response costs.

Safe Drinking Water Act and State Laws Regulating Hydraulic Fracturing

Most, if not all, of the properties we expect to acquire will require additional drilling operations to fully develop the reserves attributable to the properties. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing activities are typically regulated by state oil and gas commissions but not at the federal level, as the federal Safe Drinking Water Act expressly excludes regulation of these fracturing activities (except for fracturing activities involving the use of diesel). EPA is also considering using federal statutory authority (the Toxic Substances Control Act) to compel disclosure of additives to hydraulic fracturing fluids, something already required for fracturing operations conducted on federal lands and under several states’ laws.

Congress has considered legislation to amend the federal Safe Drinking Water Act to remove the exemption for hydraulic fracturing operations and require reporting and disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Sponsors of these bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. A number of states, local and regional regulatory authorities have or are considering hydraulic fracturing regulation and other regulations imposing new or more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations.

Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, there have been recent developments at the federal, state, regional and local levels that could result in regulation of hydraulic fracturing becoming more stringent and costly. EPA studied the potential environmental impacts of hydraulic fracturing activities. On June 5, 2015, EPA released the results of its study, generally concluding that

 

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hydraulic fracturing does not pose widespread contamination risks to drinking water if producers adhere to state regulations.

If new laws or regulations imposing significant restrictions or conditions on hydraulic fracturing activities are adopted in areas where we acquire properties that require additional drilling, we could incur substantial compliance costs and such requirements could adversely delay or restrict our ability to conduct fracturing activities on our properties.

Clean Air Act

Our operations are subject to the federal Clean Air Act, or CAA, and analogous state laws and local ordinances governing the control of emissions from sources of air pollution. The CAA and analogous state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (or toxic) air pollutants, might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or seek injunctive relief, requiring us to forego construction, modification or operation of certain air emission sources.

EPA rules subject oil and natural gas production, processing, transmission and storage operations to regulation. The EPA rules include standards for completions of hydraulically fractured natural gas wells. These standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring, using a completion combustion device, or by capturing the natural gas using green completions with a completion combustion device. Operators must capture the natural gas and make it available for use or sale, which can be done through the use of “green completions.” The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the regulations also establish specific new requirements for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. In response to industry requests for clarification and court challenges, on December 19, 2014, EPA finalized updates and clarifications to these rules. On August 18, 2015, the EPA proposed to revise its rules for reducing greenhouse gases emissions—most notably methane—from the oil and gas industry. The EPA proposed to require owners/operators of hydraulically fractured oil wells to capture the natural gas that currently escapes into the air by “reduced emissions completion” or “green completion.” In a green completion, special equipment separates gas and liquid hydrocarbons from the flowback that comes from the well as it is being prepared for production. These rules could undergo further revision in the future and impose additional costs on our operations.

Climate Change Laws

More stringent laws and regulations relating to climate change and greenhouse gases, or GHGs, may be adopted in the future and could cause us to incur material expenses in complying with them. In past years, both houses of Congress have considered legislation to reduce emissions of GHGs, but no legislation has passed. In the absence of comprehensive federal legislation, EPA has adopted rules under its existing CAA authority to regulate GHGs as pollutants. EPA adopted a mandatory GHG emissions reporting program that imposes reporting and monitoring requirements on various industries and, after its initial adoption, was expanded to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. Significant financial expenditures could be required to comply with the monitoring, recordkeeping and reporting requirements under the EPA’s GHG reporting program.

Using existing CAA authority, EPA also adopted the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, which phases in permitting requirements for stationary sources of GHGs. EPA’s rule “tailored” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step

 

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process, with the largest sources first subject to permitting. On June 23, 2014, the U.S. Supreme Court vacated EPA’s “tailoring” rule. The Court also ruled, however, that EPA could permissibly find that sources already required to obtain a permit for pollutants of conventional pollutants could be required to install the “best available control technology” to control GHG emissions. EPA has initiated steps to come into compliance with the Court’s decision.

In the absence of comprehensive federal legislation, there remains substantial uncertainty as to how and when federal regulation of GHGs might take place. Some members of Congress have introduced legislation to curb EPA from trying to use existing CAA authority to control GHG emissions. EPA rules adopted without express statutory authorization will continue to be challenged in court. Depending on how the on-going public policy debate restricting the emission of GHGs resolves itself, we could incur significant costs to control our GHG emissions and comply with new EPA and/or state, regional or local rules.

OSHA and Other Laws and Regulation

We will be subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state, local and tribal authorities. Rules and regulations affecting the oil and natural gas industry are under constant review for amendment or expansion, which could increase the regulatory burden and the potential for financial sanctions for noncompliance. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Drilling and Production

Statutes, rules and regulations affecting oil and natural gas drilling and production activities undergo constant review and often are amended, expanded and reinterpreted, making difficult the prediction of future costs or the impact of regulatory compliance attributable to new laws and statutes. The regulatory burden on the oil and natural gas industry increases the cost of doing business and, consequently, affects its profitability. Our drilling and production operations will be subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states and some counties and municipalities in which we operate also regulate one or more of the following:

 

    the location of wells;

 

    the method of drilling, completing and operating wells;

 

    the surface use and restoration of properties upon which wells are drilled;

 

    the plugging and abandoning of wells;

 

    notice to surface owners and other third-parties; and

 

    produced water and waste disposal.

 

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State and federal regulations are generally intended to prevent waste of oil and natural gas, protect correlative rights to produce oil and natural gas between owners in a common reservoir or formation, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines and natural gas plants operated by other companies that provide midstream services to us are also subject to the jurisdiction of various federal, state and local authorities, which can affect our operations. State laws also regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties.

States generally impose a production, ad valorem or severance tax with respect to the production and sale of oil and natural gas within their respective jurisdictions. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation, but there can be no assurance they will not do so in the future.

In addition, a number of states and some tribal nations have enacted surface damage statutes, or SDAs. These laws are designed to compensate for damage caused by oil and natural gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain bonding requirements and require specific payments to be made in connection with drilling and producing activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

We will not control the availability of transportation and processing facilities that may be used in the marketing of our production. For example, we may have to shut-in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.

If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various non-discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management, Bureau of Ocean Energy Management, Bureau of Safety and Environmental Enforcement, Bureau of Indian Affairs, tribal or other appropriate federal, state and/or Indian tribal agencies.

The Mineral Leasing Act of 1920, or the Mineral Act, prohibits ownership of any direct or indirect interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign entity except through equity ownership in a corporation formed under the laws of the United States or of any U.S. state or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or entities of the United States. If these restrictions are violated, the oil and natural gas lease can be canceled in a proceeding instituted by the United States Attorney General. We qualify as an entity formed under the laws of the United States or of any U.S. state or territory. Although the regulations promulgated and administered by the Bureau of Land Management pursuant to the Mineral Act provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. It is possible that our unitholders may be citizens of foreign countries and do not own their common units in a U.S. corporation or even if such interest is held through a U.S. corporation, their country of citizenship may be determined to be non-reciprocal countries under the Mineral Act. In such event, any federal onshore oil and natural gas leases held by us could be subject to cancellation based on such determination.

Federal Natural Gas Regulation

The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas are subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. FERC’s regulations for interstate natural gas transmission in some

 

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circumstances may also affect the intrastate transportation of natural gas. FERC regulates the rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines under the Natural Gas Act as well as under Section 311 of the Natural Gas Policy Act.

Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, nondiscriminatory basis. FERC has announced several important transportation related policy statements and rule changes, including a statement of policy and final rule issued February 25, 2000, concerning alternatives to its traditional cost-of-service rate-making methodology to establish the rates interstate pipelines may charge for their services. The final rule revises FERC’s pricing policy and current regulatory framework to improve the efficiency of the market and further enhance competition in natural gas markets.

FERC has also issued several other generally pro-competitive policy statements and initiatives affecting rates and other aspects of pipeline transportation of natural gas. On May 31, 2005, FERC generally reaffirmed its policy of allowing interstate pipelines to selectively discount their rates in order to meet competition from other interstate pipelines. On June 15, 2006, FERC issued an order in which it declined to establish uniform standards for natural gas quality and interchangeability, opting instead for a pipeline-by-pipeline approach. On June 19, 2006, in order to facilitate development of new storage capacity, FERC established criteria to allow providers to charge market-based (i.e., negotiated) rates for storage services. On June 19, 2008, the FERC removed the rate ceiling on short-term releases by shippers of interstate pipeline transportation capacity. On November 17, 2011, FERC issued a final rule prohibiting anticompetitive behavior by multiple affiliates of the same entity in the natural gas capacity release market. On April 16, 2015, FERC issued a policy statement providing natural gas pipelines a cost-recovery mechanism to recoup capital expenditures made to modernize pipeline infrastructure. The same day, FERC issued a final rule adopting reforms to its scheduling rules to improve coordination between the natural gas and electric markets.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the properties we may acquire. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

Federal Oil Pipeline Regulation

FERC also regulates oil pipelines transportation rates and practices and has implemented rules to facilitate competition and streamline oil pipeline ratemaking policies. FERC’s jurisdiction over oil pipelines derives from a 1906 amendment to the Interstate Commerce Act making oil pipelines common carriers subject to federal regulation. FERC has regulated oil pipelines under this authority since 1977, when legislation transferred jurisdiction to FERC from the Interstate Commerce Commission, or the Commission. The Energy Policy Act of 1992 directed the Commission to establish a simplified and generally applicable ratemaking methodology for oil pipelines, consistent with FERC’s statutory mandate to ensure that oil pipelines’ rates are just and reasonable.

In response to this directive, the Commission issued a series of orders that adopted methodologies for oil pipelines to change the rates that they charge, established streamlined filing requirements for information required of pipelines, and implemented filing procedures for pipelines proposing rates based on competitive market forces. These orders became effective on January 1, 1995. In the years following, FERC issued several orders refining aspects of these orders relating to pricing and pipeline reporting requirements. On February 20, 2014, the Commission issued an order that clarified the criteria that an oil pipeline must meet in order to charge rates based on market forces. Like natural gas, domestic oil prices are not currently subject to price controls, though future legislation may affect oil prices in ways that we cannot predict.

 

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Other Regulation

In addition to the regulation of oil and natural gas pipeline transportation rates, the oil and natural gas industry generally is subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon our proposed operations.

Employees

We have no officers, directors or employees. Instead, our general partner will manage our day-to-day affairs and all aspects of our oil and gas operations. As of September  25, 2015, ATLS had 621 employees. Please read “Management” for more information.

Offices

Our principal executive offices are located at Park Place Corporate Center One, 1000 Commerce Drive, Suite 410, Pittsburgh, Pennsylvania 15275, and our telephone number is (800) 251-0171. Our website is located at www.atlasgrowthpartners.com. We expect to make our periodic reports and other information filed with or furnished to the SEC, available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

 

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MANAGEMENT

We have no officers, directors or employees. Instead, our general partner will manage our day-to-day affairs and all aspects of our oil and gas operations. Our general partner will have full authority to conduct and manage our business, including the following:

 

    the acquisition, development and disposition of oil and gas properties and other assets by us;

 

    the entering into and performance of all hedge contracts;

 

    the making of all expenditures by us;

 

    the making of all tax and other regulatory filings by us;

 

    the negotiation, execution and performance of contracts by us;

 

    the determination of the amount and timing of distributions to our unitholders;

 

    the selection and dismissal of employees and officers and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring on our behalf;

 

    the selection and retention of insurance coverage by us;

 

    the indemnification of any person against liabilities and contingencies to the extent permitted by law and our Partnership Agreement;

 

    the control of any matters relating to our rights and obligations, including the bringing and defending of law suits; and

 

    the acquisition of common units or other interests issued by us.

All decisions regarding the management of the Partnership made by our general partner will be made by the board of directors of our general partner and its officers.

Directors and Officers of our General Partner

The board of directors of our general partner consists of seven persons, as set forth below. Our general partner has determined that Messrs. Bagnell, Karis and Mesznik are independent directors within the meaning of SEC and NYSE rules.

The current directors of our general partner are:

 

Name

  

Age

    

Position or Office with our General Partner

Edward E. Cohen

     76       Chairman of the Board and Chief Executive Officer

Jonathan Z. Cohen

     45       Executive Vice Chairman of the Board

William R. Bagnell

     52       Director

William G. Karis

     67       Director

Joel R. Mesznik

     70       Director

Daniel C. Herz

     39       President and Director

Freddie M. Kotek

     59       Executive Vice President and Director

 

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The current executive officers of our general partner are:

 

Mark D. Schumacher

     53       Executive Vice President of Operations

John Crook

     56       Vice President of Environmental, Health and Safety

Brad Eubanks

     58       Vice President of Land

Daniel J. Kortum

     66       Vice President of Energy Marketing

Dave E. Leopold

     51       Vice President of Operations

Jeffrey M. Slotterback

     33       Chief Financial Officer

Matthew Finkbeiner

     35       Chief Accounting Officer

Lisa Washington

     48       Chief Legal Officer and Secretary

Julie H. Wilson

     40       Assistant General Counsel and Assistant Secretary

Justin T. Atkinson

     42       Assistant Treasurer

Marci F. Bleichmar

     45       Vice President

Jack L. Hollander

     59       Vice President

Jeff Smith

     40       Vice President

Fred Stoleru

     44       Vice President

William A. Ulrich

     32       Vice President of Corporate Development

Joel S. Heiser

     48       Associate General Counsel and Assistant Secretary

Biographical information on the officers and directors of our general partner is set forth below.

Edward E. Cohen, Chairman of the Board and Chief Executive Officer. Mr. Cohen has been the Chairman and Chief Executive Officer of our general partner since its inception in 2013. Mr. Cohen has been the Chief Executive Officer of ATLS since February 2015 and President from February 2015 to April 2015, and before that was Chairman and Chief Executive Officer since February 2012. Mr. Cohen has been the Executive Vice Chairman of ATLS and Executive Chairman of ARP since August 2015. Mr. Cohen was the Chairman of the Board of Atlas Energy’s general partner from its formation in January 2006 until February 2011, when he became its Chief Executive Officer and President until its sale to Targa Resources Corp. in February 2015, or the Atlas Energy merger. Mr. Cohen served as the Chief Executive Officer of Atlas Energy’s general partner from its formation in January 2006 until February 2009. Mr. Cohen served on the executive committee of Atlas Energy’s general partner from 2006 until the Atlas Energy merger. Mr. Cohen also was the Chairman of the Board and Chief Executive Officer of Atlas Energy, Inc. (formerly known as Atlas America, Inc.) from its organization in 2000 until the consummation of the its merger with Chevron in February 2011, or the Chevron merger, and also served as its President from September 2000 until October 2009. Mr. Cohen was the Executive Chair of the managing board of the general partner of APL from its formation in 1999 until February 2015. Mr. Cohen was the Chief Executive Officer of the general partner of APL from 1999 to January 2009. Mr. Cohen was the Chairman of the Board and Chief Executive Officer of Atlas Energy Resources, LLC and its manager, Atlas Energy Management, Inc., from their formation in June 2006 until the consummation of the Chevron merger. In addition, Mr. Cohen has been Chair of the Board of Directors of Resource America, Inc. (a publicly traded specialized asset management company) since 1990, and was its Chief Executive Officer from 1988 until 2004, and President from 2000 until 2003; Chair of the Board of Resource Capital Corp. (a publicly traded real estate investment trust) since its formation in September 2005 until November 2009 and currently serves on its board; and Chair of the Board of Brandywine Construction & Management, Inc. (a property management company) since 1994. Mr. Cohen is the father of Jonathan Z. Cohen.

Jonathan Z. Cohen, Executive Vice Chairman of the Board. Mr. Cohen has been Executive Vice Chairman of the board of directors of our general partner since its inception in 2013. Mr. Cohen has served as the Executive Chairman of the Board of ATLS since February 2015, and before that was Vice Chairman since February 2012.

 

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Mr. Cohen has served as Executive Vice Chairman of ARP since August 2015. Mr. Cohen served as Executive Chairman of the Board of Atlas Energy’s general partner from January 2012 until the Atlas Energy merger. Before that, he served as Chairman of the Board of Atlas Energy’s general partner from February 2011 until January 2012 and as Vice Chairman of the Board of its general partner from its formation in January 2006 until February 2011. Mr. Cohen served as chairman of the executive committee of Atlas Energy’s general partner from 2006 until the Atlas Energy merger. Mr. Cohen was the Vice Chairman of the Board of Atlas Energy, Inc. from its incorporation in September 2000 until the consummation of the Chevron merger. Mr. Cohen was the Executive Vice Chair of the managing board of the general partner of APL from its formation in 1999 until February 2015. Mr. Cohen was the Vice Chairman of the Board of Atlas Energy Resources, LLC and its manager, Atlas Energy Management, Inc., from their formation in June 2006 until the consummation of the Chevron Merger in February 2011. Mr. Cohen has been a senior officer of Resource America, Inc. (a publicly traded specialized asset management company) since 1998, serving as the Chief Executive Officer since 2004, President since 2003 and a director since 2002. Mr. Cohen has been Chief Executive Officer, President and a director of Resource Capital Corp. since its formation in 2005. Mr. Cohen is a son of Edward E. Cohen.

William R. Bagnell, Director. Mr. Bagnell has been a director of our general partner since its inception in 2013. Mr. Bagnell served as a director of Atlas Energy, Inc. from July 2009 through February 2011 and was a director of Atlas Energy, Inc. from February 2004 until July 2009. Mr. Bagnell has been Director of Sales – Northeast of Nordic Energy Services, LLC, an alternative electric and gas supplier, since October 2013. From October 2012 to October 2013, he was an Account Executive of Procurian Energy, an end-to-end energy management solutions company. Before that, he was Vice President of Energy for Planalytics, Inc., an energy industry risk management and software company, since March 2000. Before that, he served as Director of Business Development for Buckeye Pipeline Partners, L.P. (a refined petroleum products transportation company) from October 1992 until February 2000.

William G. Karis, Director. Mr. Karis served as a director of our general partner since its inception in 2013. Mr. Karis served as a director of ATLS’s general partner from January 2006 until April 2013. Mr. Karis has been the principal of Karis and Associates, LLC (a consulting company that provides financial and consulting services to the coal industry) since 1997. Prior to that, Mr. Karis served in various positions at CONSOL Inc. (now CONSOL Energy Company) from 1976 to 1997, culminating in his service as President and CEO from January 1995 to September 1997. Mr. Karis is a member of the board of directors and is chair of the audit and finance committees of Blue Danube Inc. and was a member of the board and chair of the audit and finance committees of Greenbrier Minerals, LLC from October 2004 to April 2013 when the company was sold.

Joel R. Mesznik, Director. Mr. Mesznik has been a director of our general partner since its inception in 2013. Mr. Mesznik has also been President of Mesco Ltd. since its inception in 1990. Mesco Ltd. has provided advisory services related to domestic and international transactions in a variety of industries. From 1999 to its sale to Microsoft in 2008, Mr. Mesznik served on the Board and in 2008, as Chairman of the Board, Greenfield Online, Inc. (a publicly traded company). From 1997 to 2006, he served as a trustee of RAIT Financial Trust (a publicly traded real estate investment trust). From 2000 to its sale in 2003, Mr. Mesznik served as director of Incentive Capital Group AG, a Swiss stock-exchange listed investment company. From 1998 to 2001, Mr. Mesznik served as a director of TRM Corporation (a publicly traded company). Since its inception in 1993, Mr. Mesznik has served as a director of Pharma/wHealth Management Company S.A., the Manager of the Luxembourg Stock Exchange listed open-end fund Pharma/wHealth. Mr. Mesznik has been a director of a number of privately owned companies and managing member of multiple limited liability companies invested in real estate. From 1976 to 1990, Mr. Mesznik was affiliated with Drexel Burnham Lambert, Inc., including from 1976 to 1988, serving as founder and head of its Public Finance Department. He started his career in finance at Citibank, NY.

Daniel C. Herz, President and Director. Mr. Herz has been the President and a director of our general partner since its inception in 2013. Mr. Herz has served as President of ATLS since April 2015 and Chief Executive Officer of ARP since August 2015. Mr. Herz served as Senior Vice President of Corporate Development and Strategy for ATLS and its predecessors since 2007, and was Vice President of Corporate Development from

 

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2004 through 2007. Mr. Herz served as Senior Vice President of Corporate Development of the general partner of APL from August 2007 until its sale to Targa Resources Partners LP in February 2015 as part of the Atlas Energy merger, and Vice President of Corporate Development from December 2004 until August 2007. Mr. Herz also served as Senior Vice President of Corporate Development of Atlas Energy, Inc. and Atlas Energy Resources, LLC from August 2007 until the Chevron merger, and Vice President of Corporate Development from December 2004 until August 2007.

Freddie M. Kotek, Executive Vice President and Director. Mr. Kotek has been the Executive Vice President and a director of our general partner since its inception in 2013. Mr. Kotek has also served as Senior Vice President of the Investment Partnership Division of ATLS since March 2012 and Senior Vice President of the Investment Partnership Division of ARP since August 2015. Mr. Kotek served as Senior Vice President of the Investment Partnership Division of Atlas Energy’s general partner from February 2011 until the Atlas Energy merger. Before that, Mr. Kotek served as an Executive Vice President of Atlas Energy, Inc. from February 2004 until February 2011 and served as a director from September 2001 until February 2004. He also served as Atlas Energy, Inc.’s Chief Financial Officer from February 2004 until March 2005, a Senior Vice President of Resource America, Inc. from 1995 until May 2004, and President of Resource Leasing, Inc. (a wholly owned subsidiary of Resource America, Inc.) from 1995 until May 2004.

Mark D. Schumacher, Executive Vice President of Operations. Mr. Schumacher has been Executive Vice President of our general partner since its inception in 2013. Mr. Schumacher has served as Senior Vice President of ATLS since April 2015 and President of ARP since August 2015. Mr. Schumacher previously served as Executive Vice President from July 2012 to October 2013 and Chief Operating Officer from October 2013 to February 2015, of the general partner of ARP prior to the Atlas Energy merger. From August 2008 to July 2012, Mr. Schumacher served as President of Titan Operating, LLC, which ARP acquired in July 2012. From November 2006 until August 2008, Mr. Schumacher served as President of Titan Resources, LLC, which built an acreage position in the Barnett Shale that it sold to XTO Energy in October 2008. From February 2005 to November 2006, Mr. Schumacher served as the Team Lead of EnCana Oil & Gas (USA) Inc. where he was responsible for Encana’s Barnett Shale development. Mr. Schumacher was an engineer with Union Pacific Resources from 1984 to 2000. Mr. Schumacher has over 29 years of experience in drilling, production and reservoir engineering management, operations and business development in East Texas, Austin Chalk, Barnett Shale, Mid-Continent, the Rockies, the Gulf of Mexico, Latin America and Canada.

Jeffrey M. Slotterback, Chief Financial Officer. Mr. Slotterback has been the Chief Accounting Officer of our general partner since its inception in 2013. Mr. Slotterback has also been the Chief Financial Officer of ATLS since September 2015 and its Chief Accounting Officer since March 2012. Mr. Slotterback has been the Chief Financial Officer and Chief Accounting Officer of ARP since September 2015. Mr. Slotterback served as Chief Accounting Officer of the general partner of Atlas Energy from March 2011 until February 2015 until the Atlas Energy merger. Mr. Slotterback was the Manager of Financial Reporting for Atlas Energy, Inc. from July 2009 until February 2011 and then served as the Manager of Financial Reporting of the general partner of Atlas Energy from February 2011 until March 2011. Mr. Slotterback was the Manager of Financial Reporting for both the general partner of Atlas Energy and the general partner of APL from May 2007 until July 2009. Mr. Slotterback was a Senior Auditor at Deloitte and Touche, LLP from 2004 until 2007, where he focused on energy and health care clients. Mr. Slotterback is a Certified Public Accountant.

Matthew Finkbeiner, Chief Accounting Officer. Mr. Finkbeiner has been the Chief Accounting Officer of our general partner since October 2015. Mr. Finkbeiner has also been the Chief Accounting Officer of ATLS and ARP since October 2015. Mr. Finkbeiner has held multiple positions with Deloitte & Touche LLP, including Audit Senior Manager from September 2010 until joining ATLS in October 2015, Audit Manager from September 2007 to September 2010 and Audit Senior/Staff from September 2002 until September 2007. While at Deloitte & Touche LLP, Mr. Finkbeiner managed audits for a diversified base of clients in the oil and gas industry, including MLPs. Mr. Finkbeiner is a Certified Public Accountant.

 

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John W. Crook, Vice President of Environment, Health and Safety. Mr. Crook has been Vice President of Environment, Health and Safety of our general partner since its inception in 2013. Mr. Crook has also served as Vice President of Environment, Health and Safety for ARP since March 2012. Mr. Crook previously as Operations & Compliance Chief of the Pennsylvania Department of Environmental Protection from March 2008 to March 2012 and Water Supply Supervisor from September 2001 to March 2008. During his time with the Pennsylvania Department of Environmental Protection, he assisted in developing new laws to deal with both public drinking water well design as well as oil and gas construction standards for pads, erosion and sedimentation, and mechanical integrity testing. He is a Licensed Professional Geologist in the State of

Pennsylvania. He also serves on the Board of Directors of the Pennsylvania Independent Oil & Gas Association and is an alternate member of the Board of Directors for the Marcellus Shale Coalition.

Brad O. Eubanks, Vice President of Land. Mr. Eubanks has been Vice President of Land of our general partner since its inception in 2013. Mr. Eubanks has also served as Senior Vice President of Land for ARP since October 2013 and before that served as Vice President of Land for ARP from March 2012 to October 2013. Mr. Eubanks served as Vice President of Land of Atlas Energy’s general partner from August 2011 until February 2015 until the Atlas Energy merger. Mr. Eubanks began his career with Shell Oil Company in 1970 as a Landman. From 1986 until 1998, he served as a District Land Manager for various regions of the country for Shell Oil. In 1998 he became Manager of Land and Acquisitions for Shell Louisiana Company. In 2001 he became Team Lead – Rockies for Shell Exploration & Production, Inc., and from December 2009 to July 2011, he served as Team Leader – Gulf of Mexico for Shell Offshore, Inc. Mr. Eubanks has served on the American Association of Professional Landmen’s board of directors from 2001 to 2011. Mr. Eubanks is a Certified Professional Landman.

Daniel J. Kortum, Vice President of Energy Marketing. Mr. Kortum has been Vice President of Energy Marketing of our general partner since its inception in 2013. Mr. Kortum has served as Vice President of Energy Marketing for ARP since March 2012. Before that, Mr. Kortum served as Director of Commercial/Marketing of EXCO Resources from December 2010 to March 2012 and as Vice President Midstream & Marketing for their Appalachian assets from September 2008 to November 2010. Prior to that, he was employed by Dominion Transmission, Inc. from April 2001 until September 2008. Throughout his career, Mr. Kortum worked for the U.S. Department of Energy and Damson Oil Corporation in Houston, TX; EQT in Pittsburgh, PA in various capacities including General Counsel for their interstate pipeline, Equitrans, Vice President Operations for Equitable Gas Company, and Director of Environment, Health & Safety for all Equitable Resources’ companies. While employed by Dominion, he was responsible for gathering and midstream activity in Pennsylvania and West Virginia.

Dave E. Leopold, Vice President of Operations. Mr. Leopold has been Vice President of Operations of our general partner since its inception in 2013. Mr. Leopold has served as Chief Operating Officer of ARP since August 2015. Mr. Leopold served as Senior Vice President of Operations of Atlas Energy from December 2013 until February 2015. Mr. Leopold served as Regional Vice President of Operations of Atlas Energy from March 2013 to December 2013. From March 2008 to February 2013, Mr. Leopold was the Operations Manager for Chesapeake Energy in Fort Worth, Texas where he led the Barnett Shale operations team to become the second largest producer in the play. From August 2000 to September 2006, Mr. Leopold held various management positions at Anadarko Petroleum Corporation, most recently serving as Production Engineering Manager over the Austin Chalk, Bossier Shale and what is now known as the Eagle Ford Shale. From 1991 to 2000, Mr. Leopold held various engineering and management roles with Union Pacific Resources in Fort Worth, Texas. From 1987 to 1991, he held drilling and reservoir engineering roles with Plains Petroleum Operating Company in Kansas and Colorado.

Lisa Washington, Chief Legal Officer and Secretary. Ms. Washington has served as Chief Legal Officer and Secretary of our general partner since its inception in 2013. Ms. Washington has served as Chief Legal Officer and Secretary for ATLS since February 2012 and Vice President since February 2015 and Vice President, Chief Legal Officer and Secretary of ARP since August 2015. Ms. Washington served as Chief Legal Officer and Secretary of the general partner of Atlas Energy from January 2006 until February 2015, and Vice President from

 

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February 2011 until February 2015. Ms. Washington also served as Chief Legal Officer and Secretary of Atlas Energy Resources, LLC from 2006 until February 2011, as Senior Vice President from July 2008 until February 2011, as Senior Vice President from July 2008 until February 2011 and as Vice President from 2006 until July 2008. Ms. Washington served as Chief Legal Officer and Secretary of Atlas Energy, Inc. from November 2005 until February 2011, as Senior Vice President from October 2008 until February 2011 and as Vice President from November 2005 until October 2008. Ms. Washington also served as Chief Legal Officer and Secretary of the general partner of Atlas Energy from January 2006 to October 2009, and as a Senior Vice President of the general partner of Atlas Energy from October 2008 to October 2009 and served as Vice President, Chief Legal Officer and Secretary from February 2011 until February 2015. Ms. Washington was Chief Legal Officer and Secretary of the general partner of APL from November 2005 to October 2009 and a Senior Vice President from October 2008 to October 2009, and Vice President from November 2005 until October 2008. From 1999 to November 2005, Ms. Washington was an attorney in the business department of the law firm of Blank Rome LLP.

Julie Wilson, Assistant General Counsel and Assistant Secretary. Ms. Wilson has been Assistant General Counsel and Assistant Secretary of our general partner since its inception in 2013. Ms. Wilson has served as Assistant General Counsel and Assistant Secretary for ATLS since February 2012 and as Associate General Counsel and Assistant Secretary for ARP since August 2015. Ms. Wilson has served as Assistant General Counsel and Assistant Secretary of the general partner of Atlas Energy from August 2009 until February 2015 and has served as the Assistant General Counsel and Assistant Secretary of the general partner of APL from August 2009 to February 2015. Ms. Wilson served as Assistant General Counsel and Assistant Secretary of Atlas Energy, Inc. from August 2009 until February 2011. From 2005 to 2009, Ms. Wilson was an attorney in the corporate and securities department of Ledgewood, P.C., and from 2001 to 2005, was an attorney in the corporate and securities department of Dechert LLP. From 2000 to 2001, Ms. Wilson served as a judicial law clerk to the Honorable Moody Tidwell, III of the U.S. Court of Federal Claims.

Justin T. Atkinson, Assistant Treasurer. Mr. Atkinson has been Assistant Treasurer of our general partner since its inception in 2013. Mr. Atkinson has also been Senior Vice President of Atlas Resources, LLC since May 2011, prior to that, he was Vice President from March 2009 until April 2011 and Director of Due Diligence from February 2003 until March 2009. Mr. Atkinson has also served as President of Anthem Securities since February 2004 and as Chief Compliance Officer since October 2002. Before his employment with Atlas Resources, LLC, Mr. Atkinson was a manager of investor and broker/dealer relations with Viking Resources Corporation from 1996 until November 2001.

Marci F. Bleichmar, Vice President. Ms. Bleichmar has been Vice President of our general partner since its inception in 2013. Ms. Bleichmar has also been Executive Vice President of Atlas Resources, LLC since May 2011, and before that was Senior Vice President of Marketing from May 2008 to April 2011, and Vice President of Marketing from February 2001 through May 2008. Ms. Bleichmar served as Senior Vice President of Marketing for Atlas Energy, Inc. from February 2001 until September 2009 and Senior Vice President of Marketing of Atlas Energy Resources, LLC from October 2009 until February 2011. Prior to joining Atlas, Ms. Bleichmar served as Director of Marketing for Jacob Asset Management (a mutual partnership manager) from March 2000 to February 2001. She was an account executive at Bloomberg Financial Services LP from March 1998 until March 2000. Ms. Bleichmar was an Associate on the Derivatives Trading Desk of JP Morgan from November 1994 until 1998. Ms. Bleichmar has been a registered representative of Anthem Securities since October 2001.

Jack L. Hollander, Vice President. Mr. Hollander has been Vice President of our general partner since its inception in 2013. Mr. Hollander has served as Executive Vice President of Atlas Resources, LLC since February 2011, and before that Senior Vice President – Direct Participation Programs from January 2002 until April 2011 and Vice President – Direct Participation Programs from January 2001 until December 2001. Mr. Hollander served as the Senior Vice President – Direct Participation Programs of Atlas Energy Resources, LLC from September 2009 until February 2011. Mr. Hollander also served as Senior Vice President – Direct Participation

 

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Programs of Atlas Energy, Inc. from January 2002 until September 2009. Mr. Hollander practiced law with Rattet, Hollander & Pasternak, concentrating in tax matters and real estate transactions, from 1990 to January 2001, and was employed with Integrated Resources, Inc. (a diversified financial services company) from 1982 to 1990. Mr. Hollander is a member of the New York State bar and he served as the Chairman of the Investment Program Association, which is an industry association, from March 2005 to November 2011. Mr. Hollander has been a registered representative of Anthem Securities since November 2004.

Jeff Smith, Vice President. Mr. Smith has been Vice President of our general partner since 2015. Mr. Smith joined Atlas Resources, LLC in 2013 and serves as Vice President – National Sales Manager. Before that, from September 2010 to June 2013, Mr. Smith served as the Sr. Regional Vice President of Sales for NorthStar Realty Securities. Prior to that, Mr. Smith was a Sr. Vice President of Sales for TNP Securities, LLC from April 2010 through September 2010. He was also Vice President of Sales for Wells Investment Securities, Inc. from May 2002 until December 2009. Mr. Smith has also served as a Registered Representative with Cambridge Investment Research, Inc. from August 2000 until April 2002 and a Registered Representative with Washington Square Securities, Inc. from December 1999 until August 2000. Mr. Smith maintains his Financial Industry Regulatory Authority Series 7, 24 and 66 securities licenses.

Fredrick M. Stoleru, Vice President. Mr. Stoleru has been Vice President of our general partner since its inception in 2013. Mr. Stoleru joined Atlas Resources, LLC in March 2012. Before that Mr. Stoleru was Managing Director of Resource Financial Institutions Group, Inc., responsible for business development. From 2005 to 2008, Mr. Stoleru was a Principal at Direct Invest with responsibility for broker-dealer relationships and raising capital for real estate programs. From 2002 to 2005, Mr. Stoleru was an Associate in the Capital Transactions group of the Shorenstein Company, a national private equity real estate investor. From 2000 to 2002, Mr. Stoleru was an Investment Banking Associate with JP Morgan Chase and from 1993 to 1998 with JP Morgan Investment Management. Mr. Stoleru holds FINRA Series 7 and 63 licenses.

William Ulrich, Vice President of Corporate Development. Mr. Ulrich has been Vice President of Corporate Development of our general partner since its inception in 2013. Mr. Ulrich has served as Vice President of Corporate Development of ATLS since March 2015 and as Senior Vice President of Corporate Development of ARP since August 2015. Mr. Ulrich served as the Vice President of Corporate Development and Strategy of the general partner of Atlas Energy from February 2011 to February 2015, and before that was Director of Corporate Development since July 2009. He has also been Director of Corporate Development of the general partner of APL from July 2009 to February 2015. Mr. Ulrich has also been Senior Vice President of Atlas Resources, LLC since May 2011, and before that was Director of Corporate Development since July 2009. Prior to joining Atlas, Mr. Ulrich was an investment banker in the Global Energy Group at UBS from 2005 to 2009.

Joel S. Heiser, Associate General Counsel and Assistant Secretary. Mr. Heiser has served as Associate General Counsel and Assistant Secretary of our general partner since April 30, 2015. Mr. Heiser has served as General Counsel and Assistant Secretary of ARP since March 2012. Mr. Heiser served as the Associate General Counsel of ATLS since March 2015 and of the general partner of Atlas Energy from September 2011 to February 2015. From June 2010 until joining the general partner of Atlas Energy, Mr. Heiser was the Vice President of Legal of EXCO Resources (PA), LLC, and was the Vice President, General Counsel and Assistant Secretary from December 2006 through May 2010 for EXCO Resources (PA), Inc. Mr. Heiser was Of Counsel at Bricker & Eckler LLP from January 2003 through December 2006, an Associate at Arter & Hadden LLP from July 1997 through December 2002 and an Associate at Climaco, Climaco, Seminatore, Lefkowitz & Garofoli LPA from January 1995 through July 1997.

Executive Compensation

Compensation Discussion and Analysis

We do not directly employ any of the persons responsible for managing our business. References to “our officers” and “our directors” refer to the officers and directors of our general partner. All of the executive officers

 

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that are responsible for managing our day-to-day affairs are also current officers of ATLS or its affiliates, and therefore will have responsibilities for both us and ATLS or such affiliate after this offering. The individuals that are considered to be “named executive officers” at ATLS or its affiliates and which provide management services to us are Edward E. Cohen, Jonathan Z. Cohen, Daniel C. Herz, Jeffrey M. Slotterback and Mark D. Schumacher.

The executive officers of our general partner are employed by ATLS or its affiliates and manage the day-to-day affairs of our business. These executive officers devote as much time to the management of our business as is necessary for the proper conduct of our business and affairs. The amount of time that each of our executive officers devotes to our business is subject to change depending on our activities, the activities of ATLS and its affiliates, and any acquisitions or dispositions made by us, ATLS or its affiliates. Because the executive officers of our general partner are employees of ATLS or its affiliates, compensation other than the long-term incentive plan benefits described below is determined and paid by ATLS or the appropriate affiliate, and reimbursed by us to the extent determined by our general partner. For a detailed description of the reimbursement arrangements among us and our general partner, relating to the executive officers and employees of our general partner who provide services to us, please read “Summary of the Partnership Agreement—The Partnership Agreement—Reimbursement of Expenses.” The executive officers of our general partner, as well as the employees of ATLS or its affiliates who provide services to us, may participate in employee benefit plans and arrangements sponsored by ATLS, including plans that may be established in the future. Aside from the long-term incentive plan described below, neither we nor our general partner have entered into any additional employment or benefit-related agreements with any of the individuals who provide executive officer services to us, and we do not anticipate entering into any such agreements in the near future.

Responsibility and authority for compensation-related decisions for executive officers and other personnel employed by our general partner, if any, resides with our general partner. All determinations with respect to awards to be made under our long-term incentive plan to executive officers and other employees of our general partner and of ATLS and its affiliates are made by the board of directors of our general partner, although our general partner’s board of directors may consult with ATLS or its affiliates when making such decisions.

Responsibility and authority for compensation-related decisions for executive officers and other personnel that are employed by ATLS or its affiliates reside with ATLS or the appropriate affiliate. ATLS has the ultimate decision-making authority with respect to the total compensation of its employees, including the individuals that serve as our executive officers, and with respect to the portion of that compensation that is allocated to us. Any such compensation decisions are not subject to any approval by the board of directors of our general partner. Although we bear an allocated portion of the costs of compensation and benefits provided to the ATLS and/or ATLS affiliate employees who serve as the executive officers of our general partner, we have no control over such costs. Each of these executive officers will continue to perform services for our general partner, as well as ATLS and its affiliates, after the closing of this offering. Other than awards that our general partner makes under our long-term incentive compensation plan, compensation paid by us in 2015 with respect to the executive officers of our general partner will reflect only the portion of compensation paid by ATLS that is allocated to us pursuant to ATLS’s allocation methodology.

Director Compensation

Any member of the board of directors of our general partner who is also an employee of our general partner, ATLS or their affiliates does not receive additional compensation for serving on the board of directors of our general partner. Each other director of our general partner receives an annual retainer of $100,000, for which we reimburse our general partner. In addition, we grant each director of our general partner who is not an employee of our general partner, ATLS or their affiliates on the anniversary date of their commencement of service on the board of directors of our general partner the right to receive an amount of common units equal to $100,000 divided by the “applicable offering price.” For these purposes, the “applicable offering price” means the price at which common units are then being offered to investors generally (excluding discounts that may be afforded to specified investors or underwriters), either in a public or an unregistered offering. If no offering is then being

 

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conducted, the “applicable offering price” will be the price at which common units were last sold in the most recent offering to investors. Under the terms of the grants, issuance of the common units is contingent upon the occurrence of a liquidity event. If there is a liquidity event, common units subject to these grants will be deemed to have been issued immediately prior to the occurrence of the liquidity event. The rights vest 25.00% per year, with unvested rights being forfeited when the grantee leaves our general partner’s board of directors; all unvested rights that have not been forfeited will be become vested upon the occurrence of a liquidity event. We anticipate that a liquidity event will occur within five years. However, our Pre-Listing Partnership Agreement does not require that a liquidity event will occur within a specified timeframe or at all.

Long-Term Incentive Plan

Our general partner has approved the Atlas Growth Partners, L.P. Long-Term Incentive Plan, or the LTIP. The LTIP is intended to promote the interests of the Partnership by providing to officers, employees and directors of our general partner and employees of its affiliates, consultants and joint venture partners who perform services for our general partner or us (including employees of ATLS) incentive awards for superior performance that are based on common units. The LTIP is intended to enhance the ability of our general partner and its affiliates to attract and retain the services of individuals who are essential for the growth and profitability of our general partner and us, and to encourage them to devote their best efforts to our business and that of our general partner.

The following is a brief description of the principal features of the LTIP. This summary is subject to, and qualified in its entirety by reference to, the LTIP, a copy of which is included as Exhibit F to this prospectus.

Grants made under the LTIP will be determined by the board of directors of our general partner or a committee of the board, or the board (or a committee of the board) of an affiliate of our general partner that is appointed by the board to administer the LTIP. The board of directors of our general partner, the board of directors of an affiliate, or any respective committee thereof that administers the LTIP shall collectively be referred to as the “Committee.”

Subject to the provisions of the LTIP, the Committee is authorized to administer and interpret the LTIP, to make factual determinations and to adopt or amend its rules, regulations, agreements and instruments for implementing the LTIP. The Committee will also have the full power and authority to determine the recipients of grants under the LTIP as well as the terms and provisions of restrictions relating to grants.

Subject to any applicable law, the Committee, in its sole discretion, may delegate any or all of its powers and duties under the LTIP, including the power to award grants under the LTIP, to the Chief Executive Officer of our general partner, subject to such limitations as the Committee may impose, if any. However, the Chief Executive Officer many not make awards to, or take any action with respect to any grant previously awarded to, himself or a person who is subject to Rule 16b-3 under the Exchange Act.

Persons eligible to receive grants under the LTIP are (i) officers and employees of our general partner, its affiliates, consultants or joint venture partners who perform services for us, our general partner or an affiliate or in furtherance of our general partner’s or our business (each such officer and employee, an “eligible employee”) and (ii) non-employee directors of our general partner within the meaning of Rule 16b-3 under the Exchange Act.

Prior to a listing event, no awards may be issued under the LTIP. Upon a listing event, the number of Post-Listing common units underlying awards issuable under the LTIP will be fixed at 10.00% of the then-outstanding Post-Listing common units (including such Post-Listing common units that may be issued in an offering contemporaneous with the listing event). This amount is subject to further adjustment for events such as distributions (in common units or other securities or property, including cash), unit splits (including reverse splits), recapitalizations, mergers, consolidations, reorganizations, reclassifications and other extraordinary events affecting the outstanding common units such that an adjustment is necessary in order to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under the LTIP. Common units issued under the LTIP may consist of common units newly issued by us, common units acquired in the open market or from any affiliate of our general partner or any other person. If any award granted under the LTIP is

 

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forfeited or otherwise terminates or is canceled or paid without the delivery of common units, then the common units covered by the award will (to the extent of the forfeiture, termination, or cancellation, as the case may be) again be available for grants of awards under the LTIP. Common units surrendered in payment of the exercise price of an option, and common units withheld or surrendered for payment of taxes, will not be available for re-issuance under the LTIP.

Awards granted under the LTIP may consist of options to purchase common units, phantom units and restricted units. All grants are subject to such terms and conditions as the Committee deems appropriate, including but not limited to vesting conditions.

An option is the right to purchase a common unit in the future at a predetermined price, or the exercise price. The exercise price of each option is determined by the Committee and may be equal to or greater than the fair market value of a common unit on the date the option is granted. The Committee will determine the vesting and exercise restrictions applicable to an award of options, if any, and the method or methods by which payment of the exercise price may be made, which may include, without limitation, cash, check acceptable to the board, a tender of common units having a fair market value equal to the exercise price, a “cashless” broker-assisted exercise, a recourse note in a form acceptable to the board of and that does not violate the Sarbanes-Oxley Act of 2002, a “net exercise” that permits us to withhold a number of common units that otherwise would be issued to the holder of the option pursuant to the exercise of the option having a fair market value equal to the exercise price or any combination of the methods described above.

Phantom units represent rights to receive a common unit, an amount of cash or other securities or property based on the value of a common unit, or a combination of common units and cash or other securities or property. Phantom units are subject to terms and conditions determined by the Committee, which may include vesting restrictions. In addition, the Committee may grant distribution equivalent rights in connection with a grant of phantom units. Distribution equivalent rights represent the right to receive an amount in cash, securities, or other property equal to, and at the same time as, the cash distributions or other distributions of securities or other property made by the Partnership with respect to a common unit during the period that the underlying phantom unit is outstanding. Distribution equivalents may (i) be paid currently by us or may be deferred and, if deferred, may accrue interest, (ii) accrue as a cash obligation or may convert into additional phantom units for the holder of the underlying phantom units, (iii) be payable based on the achievement of specific goals and (iv) be payable in cash or common units or in a combination of cash and common units, in each case as determined by the Committee.

Restricted units are actual common units issued to a participant that are subject to vesting restrictions and evidenced in such manner as the Committee may deem appropriate, including book-entry registration or issuance of one or more unit certificates. Prior to or upon the grant of an award of restricted units, the Committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both. A holder of restricted units will have certain rights of holders of common units in general, including the right to vote the restricted units. However, during the period during which the restricted units are subject to vesting restrictions, the holder will not be permitted to sell, assign, transfer, pledge or otherwise encumber the restricted units. As determined by the Committee, cash dividends on restricted units may be automatically deferred or reinvested in additional restricted units and held subject to the vesting of the underlying restricted units, and dividends payable in common units may be paid in the form of restricted units of the same class as the restricted units with respect to which the dividend is paid and may be subject to vesting of the underlying restricted units.

Upon a “change in control” (as defined in the LTIP), all unvested awards granted under the LTIP held by directors will immediately vest in full. In the case of awards granted under the LTIP held by eligible employees, upon the eligible employee’s termination of employment without “cause” (as defined in the LTIP) or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), in any case following a change in control, any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option.

 

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In connection with a change in control, the Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which our general partner (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason):

 

    cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity);

 

    accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to the common units that otherwise would have been unvested so that participants (as holders of awards granted under the LTIP) may participate in the transaction;

 

    provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards);

 

    terminate all or some awards upon the consummation of the change-in-control transaction, but only if the Committee provides for full vesting of awards immediately prior to the consummation of such transaction; and

 

    make such other modifications, adjustments or amendments to outstanding awards or the LTIP as the Committee deems necessary or appropriate.

Except as otherwise determined by the Committee, no award granted under the LTIP will be assignable or transferable except by will or the laws of descent and distribution. When a participant dies, the personal representative or other person entitled to succeed to the rights of the participant may exercise the participant’s rights under his or her awards.

All awards granted under the LTIP will be subject to applicable federal (including FICA), state, and local tax withholding requirements. If our general partner so permits, common units may be withheld to satisfy tax withholding obligations with respect to awards paid in common units, at the time such awards become subject to employment taxes and tax withholding, as applicable, up to an amount that does not exceed the minimum required withholding for federal (including FICA), state and local tax liabilities. Our general partner may require forfeiture of any award for which the participant does not timely pay the applicable withholding taxes.

Subject to the limitations described below, the Committee may amend, alter, suspend, discontinue or terminate the LTIP at any time without the consent of participants, except that the Committee may not amend the LTIP without approval of the unitholders if such approval is required in order to comply with applicable stock exchange requirements. No amendment or termination of the LTIP may materially impair any rights or obligations of participants under any previously granted awards, unless the participant has consented or such amendment or termination was reserved in the LTIP or the applicable award agreements. The Committee may not reprice options, nor may the LTIP be amended to permit option repricing, unless the unitholders approve such repricing or amendment.

The LTIP will continue until the earlier of (i) the date terminated by the board of directors of our general partner, in its sole discretion, (ii) the date common units are no longer available for the grant of awards under the LTIP, or (iii) 10 years after a listing event.

Ownership of Our General Partner

Our general partner is a limited liability company that is controlled by ATLS. ATLS has the right to appoint all of the members of our general partner’s board of directors. All decisions regarding the business of our general partner and our Partnership will be made by the board of directors of our general partner at meetings of the board of directors at which a quorum is present. The presence of a majority of the directors constitutes a quorum, and the vote of a majority of a quorum constitutes a decision by the board of directors.

 

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Dealer Manager

Anthem Securities, an affiliate of our general partner, is acting as dealer manager of this offering. Anthem Securities was formed for the purpose of serving as dealer manager of partnerships sponsored by ATLS and its affiliates. Anthem Securities became a member of FINRA in April 1997.

Remuneration of Officers and Directors

No officer or director of our general partner will receive any remuneration or other compensation from the Partnership. These persons will receive compensation solely from affiliated companies of our general partner.

Code of Business Conduct and Ethics

Because the Partnership does not employ any persons, the Partnership relies on the code of business conduct and ethics adopted by ATLS that applies to the executive officers, employees and other persons performing services for ATLS and its affiliates generally. You may obtain a copy of this code of business conduct and ethics without charge at www.atlasenergy.com.

Transactions with Management and Affiliates

The Partnership’s policies and procedures for reviewing, approving or ratifying related party transactions with our general partner are set forth in the Partnership Agreement, and the material terms of those policies and procedures are discussed in greater detail in “Conflicts of Interest and Fiduciary Duties.”

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

AND MANAGEMENT

The following table provides information with respect to the beneficial ownership of our common units as of October 19, 2015 by:

 

    our general partner;

 

    each of our general partner’s directors and named executive officers;

 

    each unitholder known to us to beneficially hold 5.00% or more of our common units; and

 

    all of our general partner’s directors and executive officers as a group.

We have determined beneficial ownership in accordance with the rules of the SEC. Except as indicated by the footnotes to the tables below, we believe, based on the information furnished to us, that the persons and entities named in the tables below have sole voting and investment power with respect to all common units that they beneficially own, subject to applicable community property laws. Unless otherwise noted, the business address of each beneficial owner listed on the tables below is Park Place Corporate Center One, 1000 Commerce Drive, Suite 410, Pittsburgh, PA 15278.

 

Name of Beneficial Owner

   Units     Percentage of
Common Units
Beneficially
Owned Prior to
Offering(1)
   Percentage of Common
Units Beneficially

Owned After
Offering(2)

Directors

        Minimum    Maximum

Edward E. Cohen

     30,000 (3)    *    *    *

Jonathan Z. Cohen

     30,000 (4)    *    *    *

William Bagnell

     —        *    *    *

William G. Karis

     —        *    *    *

Joel R. Mesznik

     —        *    *    *

Daniel C. Herz

     15,000 (5)    *    *    *

Freddie M. Kotek

     5,000 (6)    *    *    *

Non-Director Named Executive Officers

          

Mark D. Schumacher

     —   (7)    *    *    *

Lisa Washington

     —   (8)    *    *    *

Jeffrey M. Slotterback

     —        *    *    *

All directors and executive officers as a group (10 persons)

     80,000      *    *    *

 

* The percentage of common units beneficially owned by each director or executive officer does not exceed one percent of the common units outstanding; and the percentage of common units beneficially owned by all directors and executive officers of our general partner, as a group, does not exceed 1.00% of the common units outstanding.
(1)  Applicable beneficial ownership percentages prior to this offering are based on 23,300,410 common units outstanding as of October 19, 2015.
(2)  Applicable beneficial ownership percentages after this offering are based on 23,500,410 common units (if the minimum number of units is sold) or 123,300,410 common units (if the maximum number of common units is sold) outstanding, immediately after the closing of this offering.
(3)  Mr. E. Cohen also holds a 4.85% interest in Atlas Growth Partners GP, LLC, the general partner of Atlas Growth Partners, L.P.
(4)  Mr. J. Cohen also holds a 4.85% interest in Atlas Growth Partners GP, LLC, the general partner of Atlas Growth Partners, L.P.
(5)  Mr. Herz also holds a 2.17% interest in Atlas Growth Partners GP, LLC, the general partner of Atlas Growth Partners, L.P.

 

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(6)  Mr. Kotek also holds a 2.17% interest in Atlas Growth Partners GP, LLC, the general partner of Atlas Growth Partners, L.P.
(7)  Mr. Schumacher holds a 0.85% interest in Atlas Growth Partners GP, LLC, the general partner of Atlas Growth Partners, L.P.
(8)  Ms. Washington holds a 0.55% interest in Atlas Growth Partners GP, LLC, the general partner of Atlas Growth Partners, L.P.

The following table provides information with respect to the beneficial ownership of the common units of ATLS as of October 19, 2015 by each of our general partner’s directors and named executive officers and all of our general partner’s directors and executive officers as a group.

 

Name of Beneficial Owner

   Units      Percentage of
Common Units
Beneficially Owned(1)
 

Directors

     

Edward E. Cohen(2)

     737,804         2.84

Jonathan Z. Cohen(3)

     691,991         2.66

William Bagnell

     —           *   

William G. Karis

     6,128         *   

Joel R. Mesznik

     —           *   

Daniel C. Herz

     8,419         *   

Freddie M. Kotek(4)

     151,435         *   

Non-Director Named Executive Officers

     

Mark D. Schumacher

     7,375         *   

Lisa Washington

     4,377         *   

Jeffrey M. Slotterback

     1,101         *   

All directors and executive officers as a group (10 persons)

     1,608,630         6.18

 

* The percentage of common units beneficially owned by each director or executive officer does not exceed one percent of the common units outstanding
(1)  Applicable percentages are based on 26,010,766 common units outstanding as of October 19, 2015.
(2)  Includes (i) 13,125 units held in an individual retirement account of Mr. E. Cohen’s spouse; (ii) 570,163 units held by a charitable foundation of which Mr. E. Cohen, his spouse and their children are among the trustees; and (iii) 33,636 units owned by a trust for the benefit of Mr. E. Cohen’s spouse and/or children. Mr. E. Cohen disclaims beneficial ownership of the above referenced units. 603,799 of these units are also included in the common units referred to in footnote 3 below.
(3)  Includes (i) 33,636 units owned by a trust of which Mr. J. Cohen is a co-trustee and co-beneficiary and (ii) 570,163 units held by a charitable foundation of which Mr. J. Cohen, his parents and his sibling are among the trustees. These units are also included in the units referred to in footnote 2 above. Mr. J. Cohen disclaims beneficial ownership to the units described in (ii) above.
(4)  Includes (i) 43,325 units held by spouse; (ii) 58,240 units held by his children’s trust; (iii) 965 units held by his children; and (iv) 3,229 units held by his mother-in-law.

 

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CAPITAL CONTRIBUTIONS

The net capital contributions of unitholders per Class A common unit received in this offering, as applicable, will be $9.00, consisting of the $10.00 purchase price per unit less the $0.70 commission, the $0.30 dealer manager fee, in each case payable to our dealer manager and the participating broker-dealers selected by our dealer manager to participate in the offering of Units. The net capital contributions of unitholders per Class T common unit received in this offering will be $9.40, consisting of the $10.00 purchase price per Unit less the $0.30 commission, the $0.30 dealer manager fee, in each case payable to our dealer manager and the participating broker-dealers selected by our dealer manager to participate in the offering of Units. Prior to the date of this prospectus, our general partner paid a capital contribution of $1,000 for GP units representing its 2.00% general partner interest in the Partnership. In addition, prior to the date of this prospectus, ATLS has acquired $5,000,100 in common units for a total of 500,010 common units.

Our general partner intends that the capital contributions will be used as follows:

Distributions. Our general partner plans to follow a policy of making distributions of $0.70 per Unit on an annualized basis to unitholders, and the Partnership will deduct the distribution and unitholder servicing fee from cash distributions otherwise payable to the purchasers of Class T common units. All of the distributions you receive during our operations will be considered a return of capital until you receive 100.00% of your investment. This is because as proceeds are raised in the offering, it is not always possible immediately to invest them in oil and gas properties that generate our desired return on investment. There may be a delay between the raising of offering proceeds and the investment of those proceeds in oil and gas properties. Persons who acquire common units relatively early in this offering, as compared with later investors, may receive a greater return of offering proceeds as part of the earlier distributions. Although there is no limitation on the amount of distributions that can be funded from offering proceeds or financing proceeds, under the Partnership Agreement, we may not borrow funds for purposes of distributions, if the amount of those distributions would exceed our accrued and received revenues for the previous four quarters, less paid and accrued operating costs with respect to those revenues. The determination of such revenues and costs shall be made in accordance with generally accepted accounting principles, consistently applied.

Organization and Offering Costs. The Partnership will reimburse our general partner for certain expenses related to the offering of Units on an accountable basis. Commencing with the initial closing and with each subsequent closing, our general partner will determine the total organization and offering costs (exclusive of the sales commissions and dealer manager fees we will pay to the dealer manager as described in “Plan of Distribution”) incurred prior to each such closing that are not reimbursed by the Partnership. The Partnership will reimburse our general partner, up to a maximum expense cap that ranges from 1.5%–2% of the gross proceeds from our primary offering, depending on the gross proceeds from common units sold.

Because the organization and offering expenses are based on the aggregate offering proceeds, the total amount of organization and offering expenses cannot be determined until this offering is complete. Although the exact amount of organization and offering expenses cannot be determined at this time, our general partner may be reimbursed up to $20,000 for offering expenses if the minimum of 100,000 common units is sold in the offering and up to $15 million for offering expenses if the maximum of 100,000,000 common units is sold in the offering. The maximum reimbursements of organization and offering expenses (excluding sales commissions and dealer manager fees) that may be paid by us to our general partner are set forth in the following table.

 

Maximum Reimbursements for Offering Expenses

(Excluding Sales Commissions and Dealer Manager Fees)

Dollars in Thousands

 
     Minimum
Offering
     %      Maximum
Offering
     %  

Gross proceeds

   $ 1,000         100.00       $ 100,000         100.00   

Estimated reimbursement to general partner for fees and expenses related to organization and offering

   $ 20         2.00       $ 15,000         1.50   

 

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The Partnership will also pay an annual management fee to our general partner. Please read “Compensation.”

Oil and Gas Property Acquisition Costs. Our general partner intends to use the capital contributions and Partnership borrowings to pay the purchase price of oil and gas properties and related costs and expenses, such as broker fees, and legal, land, environmental review and reserve engineering fees.

Drilling and Other Property Development Costs. When we acquire a property, we will estimate the amount of costs to be incurred to conduct any additional development activities necessary to develop the property’s reserves. Our general partner will reserve an amount of capital contributions and, if we and the lenders agree to increase the borrowing base and the lenders’ commitments under our credit facility, borrowing capacity under our credit facility to pay such development costs. Our general partner may also use Partnership revenues to pay such costs.

 

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UNITS ELIGIBLE FOR FUTURE SALE

ATLS holds an aggregate of approximately 2.19% of our outstanding common units as of the date of this prospectus. The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

 

    1.00% of the total number of the securities outstanding; or

 

    the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A unitholder who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell his common units under Rule 144 without regard to the rule’s public information requirements, volume limitations, manner of sale provisions and notice requirements.

Our Partnership Agreement does not restrict our ability to issue any Partnership interests. Any issuance of additional common units or other equity interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, our common units then outstanding.

In the Post-Listing Partnership Agreement, we will agree to register for resale under the Securities Act and applicable state securities laws any common units or other partnership securities proposed to be sold by our general partner, ATLS or any of their respective affiliates if an exemption from the registration requirements is not otherwise available. There is no limit on the number of times that we may be required to file registration statements pursuant to this obligation. We will also agree to include any securities held by our general partner, ATLS or any of their respective affiliates in any registration statement that we file to offer securities for cash, other than an offering relating solely to an employee benefit plan. These registration rights continue for two years following any withdrawal or removal of our general partner. We must pay all expenses incidental to the registration, excluding underwriting discounts and commissions.

 

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MATERIAL FEDERAL INCOME TAX CONSEQUENCES

This section is a summary of the material federal income tax consequences that may be relevant to individual citizens or residents of the United States owning common units. This section is based upon current provisions of the Code, existing and proposed Treasury regulations promulgated under the Code, or the Treasury Regulations, and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “we,” “us” or the “Partnership” includes the Partnership and its operating subsidiaries.

The following discussion does not comment on all federal income tax matters affecting the Partnership or its unitholders and does not describe the application of the alternative minimum tax that may be applicable to certain unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, entities treated as partnerships for U.S. federal income tax purposes, trusts, nonresident aliens, U.S. expatriates and former citizens or long-term residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt institutions, foreign persons (including, without limitation, controlled foreign corporations, passive foreign investment companies and non-U.S. persons eligible for the benefits of an applicable income tax treaty with the United States), individual retirement accounts, or IRAs, real estate investment trusts, or REITs, or mutual funds, dealers in securities or currencies, traders in securities, U.S. persons whose “functional currency” is not the U.S. dollar, persons holding their Units as part of a “straddle,” “hedge,” “conversion transaction” or other risk reduction transaction, and persons deemed to sell their Units under the constructive sale provisions of the Code. In addition, the discussion only comments, to a limited extent, on state, local, and foreign tax consequences. Accordingly, the Partnership encourages each prospective unitholder to consult his own tax advisor in analyzing the state, local and foreign tax consequences particular to him of the ownership or disposition of common units and potential changes in applicable laws.

No ruling has been or will be requested from the IRS regarding any matter affecting the Partnership or the consequences of owning common units. Instead, the Partnership will rely on opinions of Paul Hastings LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the value of common units. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to unitholders and thus will be borne indirectly by unitholders. Furthermore, the tax treatment of the Partnership, or of an investment in the Partnership, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Paul Hastings LLP and are based on the accuracy of the representations made by the Partnership.

For the reasons described below, Paul Hastings LLP has not rendered an opinion with respect to the following specific federal income tax issues: (i) whether the Partnership’s monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Units—Allocations Between Transferors and Transferees”); (ii) whether percentage depletion will be available to a unitholder or the extent of the percentage depletion deduction available to any unitholder (please read “—Tax Treatment of Operations—Oil and Natural Gas Taxation—Depletion Deductions”); and (iii) whether the Partnership’s method for taking into account Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

 

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Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest.

If the Partnership is treated as a publicly traded partnership, it will generally be characterized as a corporation for federal income tax purposes. A partnership is treated as a publicly traded partnership if its interests are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Prior to the time the common units are listed on a national securities exchange or listed on an active market, the Partnership believes that it will not be treated as a publicly traded partnership.

Following a listing event, the Partnership will be treated as a publicly traded partnership, but the Partnership expects that at that time the Partnership will qualify for an exception, referred to as the “Qualifying Income Exception,” that exists with respect to publicly traded partnerships of which 90.00% or more of the gross income for every taxable year in which and after the Partnership becomes a publicly traded partnership consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, transportation and marketing of natural resources, including oil, gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. The Partnership currently estimates that all of its current gross income is qualifying income; however, this estimate could change from time to time.

The IRS has made no determination as to the Partnership’s status or the status of its operating subsidiaries for federal income tax purposes. Instead, the Partnership will rely on the opinion of Paul Hastings LLP on such matters. It is the opinion of Paul Hastings LLP that, based upon the Code, its regulations, published revenue rulings and court decisions and the representations described below that:

 

    The Partnership will be classified as a partnership for federal income tax purposes; and

 

    Each of the Partnership’s operating subsidiaries will be treated as a partnership or will be disregarded as an entity separate from it for federal income tax purposes.

In rendering its opinion, Paul Hastings LLP has relied on factual representations made by the Partnership. The representations made by the Partnership upon which Paul Hastings LLP has relied include that neither the Partnership nor any of its operating subsidiaries has elected or will elect to be treated, or is otherwise treated, as a corporation for federal income tax purposes.

If after a listing event, the Partnership fails to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require the Partnership to make adjustments with respect to its unitholders or pay other amounts), the Partnership will be treated as if it had transferred all of its assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which the Partnership fails to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in the Partnership. This deemed contribution and liquidation should be tax-free to unitholders and the Partnership so long as the Partnership, at that time, does not have liabilities in excess of the tax basis of its assets. Thereafter, the Partnership would be treated as a corporation for federal income tax purposes.

If the Partnership were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, its items of income, gain, loss and deduction would be reflected only on its tax return rather than being passed through to its unitholders, and the

 

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Partnership’s net income would be taxed to the Partnership at corporate rates. Any distribution made to a unitholder at a time the Partnership is treated as a corporation would be (i) a taxable dividend to the extent of the Partnership’s current and accumulated earnings and profits, then (ii) a nontaxable return of capital to the extent of the unitholder’s tax basis in his common units, and thereafter (iii) taxable capital gain. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the common units.

The discussion below is based on Paul Hastings LLP’s opinion that the Partnership will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders will be treated as partners of the Partnership for federal income tax purposes. Also, following a listing event, unitholders whose Post-Listing common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their Post-Listing common units will be treated as partners of the Partnership for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

Subject to the discussion below under “—Entity-Level Collections,” the Partnership will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of the Partnership’s income, gain, loss and deduction without regard to whether the Partnership makes cash distributions to him. Consequently, the Partnership may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of the Partnership’s income, gain, loss and deduction for its taxable year ending with or within his taxable year. The Partnership’s taxable year ends on December 31.

Treatment of Distributions

General. Distributions by the Partnership to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. The Partnership’s cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “—Disposition of Units.” Any reduction in a unitholder’s share of the Partnership’s liabilities for which no partner bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by the Partnership of cash to that unitholder. To the extent the Partnership’s distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “—Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in the Partnership because of its issuance of additional common units will decrease his share of the Partnership’s nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of the Partnership’s “unrealized receivables,” including depreciation, recapture and/or substantially appreciated “inventory items,” each as defined in the Code, and collectively, referred to as Section 751 Assets. To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with the Partnership in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder’s tax basis (often zero) for the share of Section 751 Assets deemed relinquished in the exchange.

 

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Distributions to Holders of Class T Common Units. A holder of Class T common units has an obligation to pay the distribution and unitholder servicing fee from his distributions otherwise owing to such holder. Please read “The Offering—Offering Price” and “Compensation—Compensation Related to the Organization of the Partnership and Offering of Units.” For federal income tax purposes, the amounts withheld from distributions to pay this fee will be treated as first having been distributed to the holder of the Class T common unit and then will be treated as having been paid by the holder of the Class T common unit to the dealer manager.

Distribution Reinvestment Plan. Unitholders who participate in the DRIP will be treated as receiving the cash distribution that they would have received if they had elected not to participate in the DRIP. As a result, your adjusted basis for tax purposes in your common units will be reduced by the full amount of the deemed cash distribution and then increased by the amount of the distributions reinvested in additional common units pursuant to the Plan. In addition, to the extent a unitholder purchases common units through our DRIP at a discount to their fair market value, the unitholder will be treated as receiving additional taxable income equal to the amount of the discount. Purchasing common units pursuant to the Plan will not affect the tax obligations associated with the common units you currently own and your allocable share of our net income allocable to such common units. However, participation in the Plan will reduce the amount of cash distributions available to you to satisfy any tax obligations associated with owning such common units. For a description of the tax treatment of our distributions, please read “—Treatment of Distributions.” common units received under the plan will have a holding period beginning on the day after purchase under the DRIP.

Basis of Units

We will allocate the purchase price paid by each purchaser between the common units and the warrants based upon their relative fair market value as determined by our general partner. A unitholder’s initial tax basis in his common units will be the portion of his purchase price allocable to such common units. A unitholder’s initial tax basis will be increased by his share of the Partnership’s income and by any increases in his share of the Partnership’s nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from the Partnership, by the unitholder’s share of the Partnership’s losses, by any decreases in his share of the Partnership’s nonrecourse liabilities and by his share of the Partnership’s expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have a share, generally based on his share of profits, of the Partnership’s nonrecourse liabilities. Please read “—Disposition of Units—Recognition of Gain or Loss.”

Limitations on Deductibility of Losses

The deduction by a unitholder of his share of the Partnership’s losses will be limited to the tax basis in his common units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50.00% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations), to the amount for which the unitholder is considered to be “at risk” with respect to the Partnership’s activities, if that is less than his tax basis. A unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such unitholder’s tax basis in his common units. Upon the taxable disposition of a common unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his common units, excluding any portion of that basis attributable to his share of the Partnership’s nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his common units, if the lender of those

 

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borrowed funds owns an interest in the Partnership, is related to the unitholder or can look only to the common units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s common units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of the Partnership’s nonrecourse liabilities.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, following a listing event, any passive losses the Partnership generates will only be available to offset its passive income generated in the future and will not be available to offset income from other passive activities or investments, including the Partnership’s investments or a unitholder’s investments in other publicly traded partnerships, or the unitholder’s salary, active business or other income. Passive losses that are not deductible because they exceed a unitholder’s share of income the Partnership generates may be deducted in full when he disposes of his entire investment in the Partnership in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

 

    interest on indebtedness properly allocable to property held for investment;

 

    the Partnership’s interest expense attributed to portfolio income; and

 

    the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a Unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. In addition, the unitholder’s share of the Partnership’s portfolio income will be treated as investment income.

Entity-Level Collections

If the Partnership is required or elects under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or any former unitholder, the Partnership is authorized to pay those taxes from its funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, the Partnership is authorized to treat the payment as a distribution to all current unitholders. Payments by the Partnership as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

If the Partnership has a net profit, its items of income, gain, loss and deduction will be allocated among its holders of common units in accordance with their percentage interests in the Partnership. If the Partnership has a net loss, its items of income, gain, loss and deduction will be allocated among all of its unitholders in accordance with their percentage interests in the Partnership to the extent of their positive capital accounts.

 

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Specified items of the Partnership’s income, gain, loss and deduction will be allocated to account for any difference between the tax basis and fair market value of any property contributed to the Partnership that exists at the time of such contribution, referred to in this discussion as the “Contributed Property.” The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from the Partnership in an offering will be essentially the same as if the tax bases of its assets were equal to their fair market values at the time of the offering.

In the event the Partnership issues additional common units (including common units issued pursuant to the DRIP) or engages in certain other transactions in the future, “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to all unitholders immediately prior to such issuance or other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by the Partnership at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, if negative capital accounts result from the allocation of operating losses, items of its income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of the Partnership’s items of income, gain, loss or deduction, other than an allocation required by the Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of his interest in the Partnership, which will be determined by taking into account all the facts and circumstances, including:

 

    his relative contributions to the Partnership;

 

    the interests of all the partners in profits and losses;

 

    the interest of all the partners in cash flow; and

 

    the rights of all the partners to distributions of capital upon liquidation.

Paul Hastings LLP is of the opinion that, with the exception of the issues described in “—Section 754 Election” and “—Disposition of Units—Allocations Between Transferors and Transferees,” allocations under the Partnership Agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Tax Rates

Currently, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.60% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 20.00%. Such rates are subject to change by new legislation at any time.

In addition, a 3.80% Medicare tax (NIIT) on certain net investment income earned by individuals, estates and trusts currently applies. For these purposes, net investment income generally includes a unitholder’s allocable share of the Partnership’s income and gain realized by a unitholder from a sale of common units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which

 

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the highest income tax bracket applicable to an estate or trust begins for such taxable year. The Department of the Treasury and the IRS have issued guidance in the form of proposed and final Treasury Regulations regarding the NIIT. Prospective unitholders are urged to consult with their tax advisors as to the impact of the NIIT on an investment in common units.

Section 754 Election

The Partnership may make the election permitted by Section 754 of the Code and, following a listing event, will make such election. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. The election will generally permit the Partnership to adjust a unitholder’s tax basis in its assets, or inside basis under Section 743(b) of the Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from the Partnership. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in the Partnership’s assets with respect to a unitholder will be considered to have two components: (i) his share of the Partnership’s tax basis in its assets, or common basis and (ii) his Section 743(b) adjustment to that basis.

Under the Partnership Agreement, our general partner is authorized to take a position to preserve the uniformity of common units even if that position is not consistent with applicable Treasury Regulations. The Partnership has adopted the remedial allocation method as to all of its properties. Where the remedial allocation method is adopted, a literal application of Treasury Regulations governing a Section 743(b) adjustment attributable to properties depreciable under Section 167 of the Internal Revenue Code may give rise to differences in the taxation of unitholders purchasing Units from the Partnership and unitholders purchasing from other unitholders. If the Partnership has any such properties, it intends to preserve the uniformity of common units, even if inconsistent with existing Treasury Regulations, and Paul Hastings LLP has not opined on the validity of this approach. Please read “—Uniformity of Units.”

The IRS may challenge the Partnership’s position with respect to depreciating or amortizing the Section 743(b) adjustment it takes to preserve the uniformity of the Units due to lack of controlling authority. Because a unitholder’s tax basis for its common units is reduced by its share of the Partnership’s items of deduction or loss, any position the Partnership takes that understates deductions will overstate a unitholder’s basis in its common units, and may cause the unitholder to understate gain or overstate loss on any sale of such common units. Please read “—Disposition of Units—Recognition of Gain or Loss.” If such a challenge were sustained, the gain from the sale of common units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee’s tax basis in his common units is higher than the common units’ share of the aggregate tax basis of the Partnership’s assets immediately prior to the transfer. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his common units is lower than those common units’ share of the aggregate tax basis of the Partnership’s assets immediately prior to the transfer. Thus, the fair market value of the common units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in the Partnership if it has a substantial built-in loss immediately after the transfer, or if it distributes property and has a substantial basis reduction. Generally, a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of the Partnership’s assets and other matters. For example, the allocation of the Section 743(b) adjustment among the Partnership’s assets must be made in accordance with the Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by the Partnership to its tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or may be amortizable over a longer period of time or under a less accelerated method than the Partnership’s tangible assets. The Partnership cannot assure you that the determinations it makes will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and

 

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should, in the Partnership’s opinion, the expense of compliance exceed the benefit of the election, the Partnership may seek permission from the IRS to revoke its Section 754 election. If permission is granted, a subsequent purchaser of common units may be allocated more income than he would have been allocated had the election not been revoked.

Taxation of Warrants

Warrants Issued in this Offering. We will allocate the purchase price paid by each purchaser between the common units and the warrants based upon their relative fair market value as determined by our general partner. A unitholder’s initial tax basis in his warrants will be the portion of his purchase price allocable to such warrants.

Distribution of Warrants to Existing Unitholders. While there is no direct controlling authority regarding the tax consequences to a unitholder arising from the pro rata distribution of warrants to our existing unitholders upon the effectiveness of the registration statement of which this prospectus is a part, the Partnership has been advised by its tax counsel that an existing unitholder should not recognize taxable income from the receipt of the new warrants distributed by the Partnership, but an existing unitholder should instead reallocate such unitholder’s aggregate tax basis in the common units and in the warrants currently held by such unitholder among his common units, the warrants that he currently holds and the new warrants to be distributed to such unitholder based upon the relative fair market value of those interests in the Partnership at the time of the distribution of the warrants.

Exercise of Warrants. In general, the exercise of a non-compensatory warrant will not be taxable. Instead, unitholders exercising warrants will be specially allocated book items of income or gain to the extent the value (generally the amount that would be received if the Partnership were liquidated) of the common units received upon exercise exceeds the amount paid or (deemed paid) to acquire and exercise the warrant. If there are insufficient book items, a unitholder exercising a warrant will be reallocated Partnership capital potentially causing the exercising unitholder to recognize taxable income as of the date of exercise.

Tax Treatment of Operations

Accounting Method and Taxable Year

The Partnership uses the year ending December 31 as its taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of the Partnership’s income, gain, loss and deduction for its taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his common units following the close of the Partnership’s taxable year but before the close of his taxable year must include his share of the Partnership’s income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of the Partnership’s income, gain, loss and deduction.

Please read “—Disposition of Units—Allocations Between Transferors and Transferees.”

Oil and Natural Gas Taxation

Depletion Deductions. Subject to the limitations on deductibility of losses discussed above (please read “—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses”), unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to the Partnership’s oil and natural gas interests. Although the Code requires each unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying property for depletion and other purposes, the Partnership intends to furnish each of its unitholders with information relating to this computation for federal income tax purposes. Each unitholder, however, remains responsible for calculating his own depletion allowance and maintaining records of his share of the adjusted tax basis of the underlying property for depletion and other purposes.

 

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Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative contracts or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15.00% (and, in the case of marginal production, potentially a higher percentage) of the unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100.00% of the taxable income of the unitholder from the property for each taxable year, computed without the depletion allowance. A unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the unitholder’s average net daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural gas production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65.00% of a unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65.00% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65.00% of the unitholder’s total taxable income for that year. The carryover period resulting from the 65.00% net income limitation is unlimited.

Unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (1) dividing the unitholder’s share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (2) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the unitholder’s share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a unitholder as a result of either the disposition by the Partnership of some or all of the Partnership’s oil and natural gas interests or the disposition by the unitholder of some or all of his common units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the tax basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the unitholders. Further, because depletion is required to be computed separately by each unitholder and not by the Partnership, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the unitholders for any taxable year. Moreover, the availability of percentage depletion may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “—Recent Legislative Developments.” the Partnership encourages each prospective unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

Deductions for Intangible Drilling and Development Costs. The Partnership elects to currently deduct intangible drilling and development costs, or IDCs. IDCs generally include its expenses for wages, fuel, repairs, hauling, supplies and other items that are incidental to, and necessary for, the drilling and preparation of wells for the production of oil, natural gas, or geothermal energy. The option to currently deduct IDCs applies only to those items that do not have a salvage value.

 

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Although the Partnership will elect to currently deduct IDCs, each unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a 60-month period, beginning with the taxable month in which the expenditure is made. If a unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount in respect of those IDCs will result for alternative minimum tax purposes.

IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the adjusted tax basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon the disposition by a unitholder of interests in the Partnership. Recapture is generally determined at the unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as allocable to the transferred undivided interest to the extent of any gain recognized. Please read “—Disposition of Units—Recognition of Gain or Loss.”

The election to currently deduct IDCs may be restricted or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “—Recent Legislative Developments.”

Lease Acquisition Costs. The cost of acquiring oil and natural gas lease or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. Please read “—Tax Treatment of Operations—Oil and Natural Gas Taxation—Depletion Deductions.”

Geophysical Costs. The cost of geophysical exploration incurred in connection with the exploration and development of oil and natural gas properties in the United States are deducted ratably over a 24-month period beginning on the date that such expense is paid or incurred.

Operating and Administrative Costs. Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs to the extent they constitute ordinary and necessary business expenses that are reasonable in amount.

Recent Legislative Developments. Following a listing event, the Partnership will be a publicly traded partnership. Please read “—Partnership Status.” The present federal income tax treatment of publicly traded partnerships may be modified by administrative, legislative or judicial interpretation at any time. For example, the Obama Administration’s budget proposal fiscal year 2016 recommends that publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of the U.S. Congress also propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships, including the elimination of the qualifying income exception upon which the Partnership will rely for its treatment as a partnership for U.S. federal income tax purposes after a listing event. Please read “—Partnership Status.” Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the Partnership is unable to predict whether any of these changes, or other proposals, will ultimately be enacted, any such changes could negatively impact the value of an investment in its common units.

In addition to the proposal regarding publicly traded partnerships described above, the Obama Administration’s budget proposal for fiscal year 2016 includes proposals that would, among other things, eliminate or reduce certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (1) the repeal of the percentage depletion allowance for oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs and certain environmental clean-up costs, and (3) an extension of the

 

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amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in its common units.

Tax Basis, Depreciation and Amortization

The tax bases of the Partnership’s assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of the Partnership’s assets and their tax bases immediately prior to an offering will be borne by unitholders holding interests in the Partnership prior to any such offering. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, the Partnership may elect to use the depreciation and cost recovery methods, including bonus depreciation, to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read “—Uniformity of Units.” Property it subsequently acquires or constructs may be depreciated using accelerated methods permitted by the Code.

If the Partnership disposes of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property the Partnership owns will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in the Partnership. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Units—Recognition of Gain or Loss.”

The costs the Partnership incurs in selling its common units, which are syndication expenses must be capitalized and cannot be deducted currently, ratably or upon its termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by the Partnership, and as syndication expenses, which may not be amortized by the Partnership. The underwriting discounts and commissions the Partnership incurs will be treated as syndication expenses.

Valuation and Tax Basis of the Partnership’s Properties

The federal income tax consequences of the ownership and disposition of common units will depend in part on the Partnership’s estimates of the relative fair market values, and the initial tax bases, of the Partnership’s assets. Although the Partnership may from time to time consult with professional appraisers regarding valuation matters, the Partnership will make many of the relative fair market value estimates itself. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of common units equal to the difference between the amount realized and the unitholder’s tax basis for the common units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of the

 

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Partnership’s nonrecourse liabilities. Because the amount realized includes a unitholder’s share of the Partnership’s nonrecourse liabilities, the gain recognized on the sale of common units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from the Partnership that in the aggregate were in excess of cumulative net taxable income for a Unit and, therefore, decreased a unitholder’s tax basis in that Unit will, in effect, become taxable income if the Unit is sold at a price greater than the unitholder’s tax basis in that Unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in common units, on the sale or exchange of a Unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of common units held for more than twelve months will generally be taxed at the U.S. federal income tax rate applicable to long-term capital gains. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to assets giving rise to depreciation recapture, depletion recapture or other “unrealized receivables” or to “inventory items” the Partnership owns. The term “unrealized receivables” includes potential recapture items, including depreciation and depletion recapture. Ordinary income attributable to unrealized receivables and inventory items and depreciation and depletion recapture may exceed net taxable gain realized upon the sale of a Unit and may be recognized even if there is a net taxable loss realized on the sale of a Unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of common units. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations. Both ordinary income and capital gain recognized on a sale of common units may be subject to the NIIT in certain circumstances. Please read “—Tax Consequences of Unit Ownership—Tax Rates.”

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership.

Allocations Between Transferors and Transferees

In general, the Partnership’s taxable income and losses will be determined annually, and, following a listing event, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of common units owned by each of them as of the opening of the applicable exchange on the first business day of the month. However, gain or loss realized on a sale or other disposition of the Partnership’s assets other than in the ordinary course of business will be allocated among the unitholders in the month in which that gain or loss is recognized. As a result, a unitholder transferring common units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. The Department of the Treasury and the IRS have issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, following a listing event, Paul Hastings LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, the Partnership’s taxable income or losses might be reallocated among the unitholders. The

 

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Partnership is authorized to revise its method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

Notification Requirements

A unitholder who sells any of his common units is generally required to notify the Partnership in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of common units who purchases common units from another unitholder is also generally required to notify the Partnership in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, the Partnership is required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify the Partnership of a purchase may, in some cases, lead to the imposition of penalties.

Uniformity of Units

The Partnership intends to maintain uniformity of the economic and tax characteristics of the common units to a purchaser of common units. In the absence of uniformity, the Partnership may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Following a listing event, any non-uniformity could have a negative impact on the value of the Post-Listing common units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.” The Partnership takes into account the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of the Partnership’s assets. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, the Partnership will apply the rules described in the Treasury Regulations and legislative history. If the Partnership determines that this position cannot reasonably be taken, it may adopt certain depreciation and amortization positions that may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. As stated above under “—Tax Consequences of Unit Ownership—Section 754 Election,” Paul Hastings LLP has not rendered an opinion with respect to these methods. Moreover, the IRS may challenge any method of depreciating the Section 743(b) adjustment under the methods adopted by the Partnership. If this challenge were sustained, the uniformity of Post-Listing common units might be affected, and the gain from the sale of Post-Listing common units might be increased without the benefit of additional deductions. Please read “—Disposition of Units—Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of common units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in common units. Employee benefit plans and most other organizations exempt from federal income tax, including IRAs and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of the Partnership’s income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

 

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Non-resident aliens and foreign corporations, trusts or estates that own common units will be considered to be engaged in business in the United States because of the ownership of common units. As a consequence, they will be required to file federal tax returns to report their share of the Partnership’s income, gain, loss or deduction and pay federal income tax at regular rates on their share of the Partnership’s net income or gain.

In addition, because a foreign corporation that owns common units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30.00%, in addition to regular federal income tax, on its share of the Partnership’s earnings and profits, as adjusted for changes in the foreign corporation’s “U.S. net equity,” that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A foreign unitholder who sells or otherwise disposes of a Unit will be subject to U.S.  federal income tax on gain realized from the sale or disposition of that Unit under the Foreign Investment in Real Property Tax Act.

Administrative Matters

Information Returns and Audit Procedures

The Partnership intends to furnish to each unitholder specific tax information, including a Schedule K-1, which describes such unitholder’s share of its income, gain, loss and deduction for the Partnership’s preceding taxable year. In preparing this information, which will not be reviewed by counsel, the Partnership will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. The Partnership cannot assure you that those positions will yield a result that conforms to the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS. Neither the Partnership nor Paul Hastings LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible.

The IRS may audit the Partnership’s federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to the Partnership’s returns as well as those related to the Partnership’s returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Code requires that one partner be designated as the “tax matters partner” for these purposes. The Partnership Agreement states that our general partner will be designated as its tax matters partner.

The tax matters partner has made and will make some elections on the Partnership’s behalf and on behalf of unitholders. In addition, the tax matters partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in the Partnership’s returns. The tax matters partner may bind a unitholder with less than a 1.00% profits interest in the Partnership to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the tax matters partner. The tax matters partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the tax matters partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1.00% interest in profits or by any group of unitholders having in the aggregate at least a 5.00% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on the Partnership’s return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

 

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State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which the Partnership does business or owns property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in the Partnership. The Partnership currently owns property or does business in Texas and Oklahoma. Oklahoma imposes a personal income tax on individuals; both of these states also impose an income or margin tax on corporations and other entities. The Partnership may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which the Partnership does business or owns property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require the Partnership, or the Partnership may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by the Partnership. Please read “—Tax Consequences of Unit Ownership—Entity-Level Collections.” Based on current law and the Partnership’s estimate of its future operations, the Partnership anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states, localities and foreign jurisdictions, of his investment in the Partnership. Accordingly, each prospective unitholder is urged to consult his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign returns, as well as U.S. federal tax returns, that may be required of him. Paul Hastings LLP has not rendered an opinion on the state, local, alternative minimum tax or foreign tax consequences of an investment in the Partnership.

 

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INVESTMENT BY TAX-EXEMPT ENTITIES AND ERISA CONSIDERATIONS

General

The following is a summary of certain additional considerations associated with an investment in the common units by tax-qualified pension, stock bonus or profit-sharing plans, employee benefit plans described in Section 3(3) and subject to Title I of ERISA, annuities described in Code Section 403(a) or (b), an individual retirement account or annuity described in Code Sections 408 or 408A, an Archer MSA described in Code Section 220(d), a health savings account described in Code Section 223(d), or a Coverdell education savings account described in Code Section 530, and any other plans, accounts, or related entities whose underlying assets are considered to include “plan assets” pursuant to ERISA, which are referred to in this section as Plans and IRAs, as applicable. This summary is based on provisions of ERISA and the Code, including amendments thereto through the date of this prospectus, and relevant regulations and opinions issued by the Department of Labor and the IRS through the date of this prospectus and is designed only to provide a general conceptual understanding of certain basic issues relevant to a Plan or IRA investor. We cannot assure you that adverse tax decisions or legislative, regulatory or administrative changes that would significantly modify the statements expressed herein will not occur. Any such changes may or may not apply to transactions entered into prior to the date of their enactment. Employee benefit plans that are governmental plans (as defined in Section 3(32) of ERISA), certain church plans (as defined in Section 3(33) of ERISA) and foreign plans (as described in Section 4(b)(4) of ERISA) are not subject to the requirements of ERISA or Section 4975 of the Code; however, such plans may be subject to non-US, federal, state or local laws or regulations that are substantially similar to Title I of ERISA or Section 4975 of the Code, or which otherwise affect their ability to invest in the notes. Any fiduciary of such a governmental, church or foreign plan considering an investment in the Notes should determine the need for compliance with, and, if necessary the availability of any exemptive relief under, such similar Laws and the regulations issued thereunder.

In considering an investment in the common units, those involved with making such an investment decision should consider applicable provisions of the Code and ERISA. While each of the ERISA and Code issues discussed below may not apply to all Plans and IRAs, individuals involved with making investment decisions with respect to Plans and IRAs should carefully review the rules and exceptions described below, and determine their applicability to their situation. This discussion should not be considered legal advice and prospective investors are required to consult their own legal advisors on these matters.

In general, individuals making investment decisions with respect to Plans and IRAs should, at a minimum, consider:

 

    whether the investment is in accordance with the documents and instruments governing the Plan or IRA;

 

    whether the investment satisfies the prudence and diversification and other fiduciary requirements of ERISA and the Code, if applicable;

 

    whether the investment will result in UBTI to the Plan or IRA (please read the section entitled “Material Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors” in this prospectus);

 

    whether there is sufficient liquidity for the Plan or IRA, considering the minimum and other distribution requirements under the Code and the liquidity needs of such Plan or IRA, after taking this investment into account;

 

    the need to value the assets of the Plan or IRA annually or more frequently;

 

    whether the investment would constitute or give rise to a non-exempt prohibited transaction under ERISA or the Code, if applicable; and

 

    the assets of an employee benefit plan subject to ERISA must generally be held in trust.

 

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Minimum and Other Distribution Requirements—Plan Liquidity

Potential Plan or IRA investors who intend to purchase common units should consider the limited liquidity of an investment in the common units as it relates to the minimum distribution requirements under the Code, if applicable, and as it relates to other distributions (such as, for example, cash out distributions) that may be required under the terms of the Plan or IRA from time to time. If the common units are held in an IRA or Plan and, before we sell our properties, mandatory or other distributions are required to be made to the participant or beneficiary of such IRA or Plan, pursuant to the Code, then this could require that a distribution of the common units be made in kind to such participant or beneficiary or that a rollover of such common units be made to an IRA or other plan, which may not be permissible under the terms and provisions of the IRA or Plan. Even if permissible, a distribution of common units in kind to a participant or beneficiary of an IRA or Plan must be included in the taxable income of the recipient for the year in which the Units are received at the then current fair market value of the common units, even though there would be no corresponding cash distribution with which to pay the income tax liability arising because of the distribution of common units. Please read the section entitled “Risk Factors—Federal Income Tax Risks.” The fair market value of any such distribution-in-kind can be only an estimated value per Unit because no public market for our common units exists or is likely to develop. Please read “—Annual or More Frequent Valuation Requirement” below. Further, there can be no assurance that such estimated value could actually be realized by a unitholder because estimates do not necessarily indicate the price at which our Units could be sold. Also, for distributions subject to mandatory income tax withholding under Section 3405 or other tax withholding provisions of the Code, the trustee of a Plan may have an obligation, even in situations involving in-kind distributions of common units, to liquidate a portion of the in-kind common units distributed in order to satisfy the withholding obligations, although there might be no market for the common units. There also may be similar state and/or local tax withholding or other tax obligations that should be considered.

Annual or More Frequent Valuation Requirement

Fiduciaries of Plans may be required to determine the fair market value of the assets of such Plans on at least an annual basis and, sometimes, as frequently as quarterly. If the fair market value of any particular asset is not readily available, the fiduciary is required to make a good faith determination of that asset’s value. Also, a trustee or custodian of an IRA must provide an IRA participant and the IRS with a statement of the value of the IRA each year. However, currently, neither the IRS nor the Department of Labor has promulgated regulations specifying how “fair market value” should be determined.

Unless and until our common units are listed on a national securities exchange, it is not expected that a public market for the common units will develop. To assist fiduciaries of Plans subject to the annual reporting requirements of ERISA and IRA trustees or custodians to prepare reports relating to an investment in our common units, we intend to provide reports of our quarterly and annual determinations of the current estimated common units value to those fiduciaries (including IRA trustees and custodians) who identify themselves to us and request the reports. We anticipate that we will provide annual reports of our determination of value (1) to IRA trustees and custodians not later than January 15 of each year, and (2) to other Plan fiduciaries within 75 days after the end of each calendar year. There can be no assurance, however, with respect to any estimate of value that we prepare, that:

 

    the estimated value per Unit would actually be realized by our unitholders on liquidation, because these estimates do not necessarily indicate the price at which common units can be sold;

 

    our unitholders would be able to realize estimated net asset values if they were to attempt to sell their common units, because no public market for our common units exists or is likely to develop; or

 

    that the value, or method used to establish value, would comply with ERISA or Code requirements described above.

Fiduciary Obligations—Prohibited Transactions

Any person identified as a “fiduciary” with respect to a Plan has duties and obligations under ERISA. For purposes of ERISA, any person who exercises any authority or control with respect to the management or

 

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disposition of the assets of a Plan is considered to be a fiduciary of such Plan. Further, many transactions between a Plan or an IRA and a “party-in-interest” or a “disqualified person” with respect to such Plan or IRA are prohibited by ERISA and/or the Code. ERISA also requires generally that the assets of Plans subject to ERISA be held in trust.

If our properties and other assets were deemed to be assets of a Plan or IRA for purposes of ERISA and/or Code Section 4975, referred to herein as “plan assets,” our general partner be deemed a fiduciary of any Plans or IRAs investing as unitholders. If this were to occur, certain contemplated transactions between us and our general partner could be deemed to be “prohibited transactions.”

Plan Assets—Definition

Section 3(42) of ERISA defines “plan assets” in accordance with Department of Labor regulations, referred to in this discussion as the Plan Asset Regulation, as modified or deemed to be modified by the express provisions included in the PPA. Under the Plan Asset Regulation, the assets of an entity in which a Plan or IRA makes an equity investment generally will be deemed to be assets of the Plan or IRA unless the entity satisfies one of the exceptions to this general rule. Generally, the exceptions require that the investment in the entity be one of the following:

 

    in “publicly offered securities,” defined generally as interests that are “freely transferable,” “widely held” and registered with the SEC; or

 

    in an entity in which equity participation by “benefit plan investors” is not “significant.”

Plan Assets—Publicly Offered Securities Exception

As noted above, if a Plan acquires “publicly offered securities,” the assets of the issuer of the securities will not be deemed to be “plan assets” under the Plan Asset Regulation. The definition of publicly offered securities requires that such securities be “widely held,” “freely transferable” and satisfy registration requirements under federal securities laws.

Under the Plan Asset Regulation, a class of securities will meet the registration requirements under federal securities laws if they are (i) part of a class of securities registered under section 12(b) or 12(g) of the Exchange Act, or (ii) part of an offering of securities to the public pursuant to an effective registration statement under the Securities Act and the class of securities of which such security is a part is registered under the Exchange Act within 120 days (or such later time as may be allowed by the SEC) after the end of the fiscal year of the issuer during which the offering of such securities to the public occurred. We anticipate that we will meet the registration requirements under the Plan Asset Regulation. Also under the Plan Asset Regulation, a class of securities will be “widely held” if it is held by 100 or more persons independent of the issuer. We anticipate that this requirement will be easily met.

Although our common units are intended to satisfy the registration requirements under this definition, and we expect that our securities will be “widely held,” the “freely transferable” requirement must also be satisfied in order for us to qualify for the “publicly offered securities” exception.

The Plan Asset Regulation provides that “whether a security is ‘freely transferable’ is a factual question to be determined on the basis of all relevant facts and circumstances.” Our common units are subject to certain transfer restrictions under the Partnership Agreement. The Plan Asset Regulation provides, however, that where the minimum investment in a public offering of securities is $10,000 or less, the presence of a restriction on transferability intended to prohibit transfers that would result in a termination or reclassification of the entity for U.S. federal or state tax purposes will not ordinarily affect a determination that the securities are “freely transferable.” The minimum investment in our common units is less than $10,000. Thus, the restrictions imposed on our common units under the Partnership Agreement should not prevent the common units from being deemed “freely transferable.” Therefore, we anticipate that we will meet the “publicly offered securities” exception, although there are no assurances that we will qualify for this exception.

 

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Plan Assets—Not Significant Investment Exception

If we are deemed not to qualify for the “publicly offered securities” exception, the Plan Asset Regulation also provides an exception with respect to equity participation in an entity by benefit plan investors is not “significant.” In this regard, the Plan Asset Regulation provides that equity participation in an entity by benefit plan investors is “significant” if at any time 25.00% or more of the value of any class of equity interests is held by benefit plan investors. As modified by the PPA, a “benefit plan investor” is defined to mean an employee benefit plan subject to Part 4 of Subtitle B of Title I of ERISA, any plan to which Code Section 4975 applies and any entity whose underlying assets include plan assets by reason of a plan’s investment in such entity. If we determine that we fail to meet the “publicly offered securities” exception, as a result of the transfer restrictions on the common units under the Partnership Agreement or otherwise, and we cannot ultimately establish that we are an operating company, we intend to restrict ownership of the common units held by benefit plan investors to an aggregate value of less than 25.00% of the total outstanding units (excluding common units purchased by our general partner) and thus qualify for the exception for investments in which equity participation by benefit plan investors is not significant.

Consequences of Holding Plan Assets

If our underlying assets were treated by the Department of Labor as “plan assets,” our general partner would be treated as a fiduciary with respect to each Plan or IRA unitholder, and an investment in our common units might expose the fiduciaries of the Plan or IRA to co-fiduciary liability under ERISA for any breach by our general partner of the fiduciary duties mandated under ERISA. Further, if our assets are deemed to be “plan assets,” an investment by a Plan or IRA in our common units might be deemed to result in an impermissible commingling of “plan assets” with other property.

If our general partner or affiliates were treated as fiduciaries with respect to Plan or IRA unitholders, the prohibited transaction restrictions of ERISA and/or the Code would apply to any transaction involving our assets. These restrictions could, for example, require that we avoid transactions with entities that are affiliated with our general partner or us or restructure our activities in order to obtain an administrative exemption from the prohibited transaction restrictions. Alternatively, we might have to provide Plan or IRA unitholders with the opportunity to sell their common units to us or we might dissolve or terminate.

Prohibited Transactions

Generally, both ERISA and the Code prohibit Plans and IRAs from engaging in certain transactions involving “plan assets” with specified parties, such as sales or exchanges or leasing of property, loans or other extensions of credit, furnishing goods or services, or transfers to, or use of, “plan assets.” The specified parties are referred to as “parties-in-interest” under ERISA and as “disqualified persons” under the Code. These definitions generally include “persons providing services” to the Plan or IRA, as well as employer sponsors of the Plan or IRA, fiduciaries and certain other individuals or entities affiliated with the foregoing.

A person generally is a fiduciary with respect to a Plan or IRA for these purposes if, among other things, the person has discretionary authority or control with respect to “plan assets” or provides investment advice for a fee with respect to “plan assets.” Under current Department of Labor regulations, a person will be deemed to be providing investment advice if that person renders advice as to the advisability of investing in our common units, and that person regularly provides investment advice to the Plan or IRA pursuant to a mutual agreement or understanding that such advice will serve as the primary basis for investment decisions, and that the advice will be individualized for the Plan or IRA based on its particular needs. Thus, if we are deemed to hold “plan assets,” our general partner could be characterized as a fiduciary with respect to our assets, and would be deemed to be a party-in-interest under ERISA and a disqualified person under the Code with respect to investing Plans and IRAs. Whether or not we are deemed to hold “plan assets,” if we or our affiliates are affiliated with a Plan or IRA investor, we might be a disqualified person or party-in-interest with respect to such Plan or IRA investor, potentially resulting in a prohibited transaction merely upon investment by the Plan or IRA in our common units.

 

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Prohibited Transactions—Consequences

ERISA forbids Plans from engaging in non-exempt prohibited transactions. Fiduciaries of a Plan that allow a non-exempt prohibited transaction to occur will breach their fiduciary responsibilities under ERISA, and may be liable for any damage sustained by the Plan, as well as civil (and criminal, if the violation was willful) penalties. If it is determined by the Department of Labor or the IRS that a non-exempt prohibited transaction has occurred, any disqualified person or party-in-interest involved with the prohibited transaction would be required to reverse or unwind the transaction and, for a Plan, compensate the Plan for any loss resulting therefrom. Additionally, the Code requires that a disqualified person involved with a non-exempt prohibited transaction must pay an excise tax equal to a percentage of the “amount involved” in the transaction for each year in which the transaction remains uncorrected. The percentage is generally 15.00%, but is increased to 100.00% if the non-exempt prohibited transaction is not corrected promptly. For IRAs, if an IRA engages in a non-exempt prohibited transaction, the tax-exempt status of the IRA may be lost.

ERISA Conclusion and Representation

Because of the foregoing, the common units should not be purchased or held by any person investing “plan assets” of any Plan, unless such purchase and holding will not constitute a prohibited transaction under ERISA, the Code or any applicable similar law(s). Further, by investment in a Unit, each purchaser and subsequent transferee will be deemed to have represented and agreed that either (i) no portion of the assets used by such purchaser or transferee to acquire and hold the notes (or any interest therein) constitutes assets of any Plan or (ii) the purchase, holding and disposition of notes (or any interest therein) by such purchaser or transferee will not constitute or result in a prohibited transaction under Section 406 of ERISA, Section 4975 of the Code or any other applicable similar laws.

 

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SUMMARY OF THE PARTNERSHIP AGREEMENT

Pursuant to the terms of our Partnership Agreement, simultaneously with the occurrence of a listing event, our Partnership Agreement will automatically be amended and restated in its entirety to be the Second Amended and Restated Agreement of Limited Partnership in the form attached to the Partnership Agreement as Annex A which we refer to as the Post-Listing Partnership Agreement. Each unitholder, by purchasing a Unit pursuant to the offering, is deemed to have consented to such amendment, and authorizes our general partner to execute the same on his, her or its behalf as attorney in fact.

The following table is a comparison of certain material aspects of our Partnership Agreement and the Post-Listing Partnership Agreement, but does not purport to be a complete description of either our Partnership Agreement or the Post-Listing Partnership Agreement and is qualified in its entirety by reference to our Partnership Agreement and the Post-Listing Partnership Agreement.

 

    

Partnership Agreement

  

Post-Listing Partnership Agreement

Authorized Equity Securities

  

The Partnership is authorized to issue an unlimited number of equity securities and options, rights, warrants and appreciations rights relating to our equity securities, all without the approval of holders of any class of equity securities outstanding. Prior to the issuance of a class or series of equity security, the board of directors of our general partner is permitted to fix the designations, preferences, rights, powers and duties (which may be senior or prior, pari passu or junior to the preferences, rights, powers and duties of any outstanding class or series of equity securities) relating to the class or series. Our Partnership Agreement specifically established the following classes of equity securities:

 

•        common units, which collectively represent an aggregate 98.00% membership interest in us,

 

•        GP units, which have certain class voting rights and collectively represent an aggregate 2.00% interest in us, and

 

•        Incentive distribution rights, or IDRs, which have no voting rights and entitle the holder to receive, after a

   No difference.

 

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listing event, increasing percentages, up to a maximum of 48.00% of any cash distributed in excess of $0.21875 per Unit, in any quarter after we have met certain tests set forth in our Partnership Agreement.

  

Distributions

  

Within 45 days after the end of each quarter, we are required to distribute all of our “available cash” to unitholders. “Available cash” is defined as all cash on hand at the end of the quarter plus cash on hand from working capital borrowings made after the end of the quarter less the amount of cash that the board of directors of our general partner in its discretion establishes to provide for the proper conduct of business (including reserves for future capital expenditures and credit needs), to comply with applicable law and any of our debt instruments and for other contracts, and certain other considerations, including reserving funds for future quarterly distributions.

 

It is the current intent of the board of directors of our general partner to reserve amounts of available cash above amounts necessary to distribute an amount equal to $0.175 per Unit and GP unit per fiscal quarter, or the target distribution, to expand our operations. The board of directors of our general partner may change this policy at any time without the approval of the holders of common units or the conflicts committee of the board of directors of our general partner.

   No difference.

 

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Right to Reset Incentive Distribution Levels

   No comparable provision.    The holder of the IDRs has the right to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the cash target distribution levels upon which the incentive distribution payments to our general partner would be set. The right to reset the target distribution levels upon which the IDRs are based may be exercised, without approval of the holders of the common units or the conflicts committee of the board of directors of our general partner, at any time when we have made cash distributions to the holders of the IDRs at the highest level of incentive distribution for the prior four consecutive fiscal quarters. We anticipate that the holder of the IDRs would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per Unit, taking into account the existing levels of incentive distribution payments being made to such holder.

Distributions upon Sale

  

Available cash with respect to a sale of substantially all of our assets will be distributed as follows:

 

•        First, 100.00% to the holders of the common units until they have received an amount equal to their capital contributions plus $0.175 per Unit for each quarter from the date of purchase through the sale, less all amounts previously distributed with respect to such interests.

 

•        Second, 100.00% to the holder of the GP units until they have received, including amounts previously received,

   Available cash will be distributed to unitholders in accordance with their capital accounts.

 

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an amount equal to 2.04% of the excess of (A) amounts distributed to the holders of the common units from operating surplus and clause first above, over (B) the product of $10.00 multiplied by the number of common units outstanding at the time of the sale.

 

•        Third, 100.00% to the holder of the incentive distribution rights, or IDRs, until it has received an amount equal to the sum of (A) the product of 25.00% multiplied by the sum of (x) the amount distributed to the common unit holders pursuant to clause first above plus (y) other amounts previously distributed with respect to the common units less (z) the product of $10.00 multiplied by the number of common units then outstanding, plus (B) the sum of all capital contributions with respect to our general partner interest, less (C) amounts previously distributed with respect to our IDRs (the amount of the distribution upon a sale that is distributed to the holder of the IDRs is referred to as the IDR Sales Distribution).

 

•        After that, 80.00% to the holders of the common units and 20.00% to the holder of the Incentive Distribution Rights.

  

Distributions in the Event of Merger

   Consideration to be received in the event of a merger shall be valued based on the price attributed thereto in the applicable merger agreement and distributed as described above in “—Distributions upon Sale.”    No comparable provision.

 

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Common Unit Issuance in lieu of IDRs to our General Partner at a Listing Event

   No comparable provision    Please read “Compensation—Operational Stage—Common unit issuance in lieu of IDRs to our general partner at a listing event.”

Common Unit Issuance in lieu of IDRs to our General Partner after a Listing Event

   No comparable provisions    Please read “Compensation—Operational Stage—Common unit issuance in lieu of IDRs to our general partner after a listing event.”

Amendments to Governing Documents and Approval of Extraordinary Transactions

     

Issuance of Additional Partnership Securities

   No approval right.    No difference.

Amendment of the Partnership Agreement

   Amendments may be proposed by our general partner or by limited partners whose common units equal 10.00% or more of the outstanding common units. Certain amendments (related to the admission of new partners, the issuance or authorization of new units, and amendments to cure ambiguities or correct inconsistent provisions) may be made by our general partner without the approval of the holders of the common units. In addition, upon the listing event, our Partnership Agreement will automatically be amended and restated in the form of the Post-Listing Partnership Agreement, without further approval by holders of the common units. Other amendments generally require the approval of a majority of the common units.    Amendments may be proposed only by our general partner. Our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners.

Merger or Sale

   Approval of a majority of the common units; consent of our general partner is not required.    Approval of a majority of the common units. Prior consent of our general partner is required.

Cancellation of Contract with our General Partner or its Affiliates that is Not Described in the Partnership Agreement

   Approval of a majority of the common units; consent of our general partner is not required.    No comparable provision.

Dissolution of the Partnership

   Approval of a majority of the common units; consent of our general partner is not required.    Approval of a majority of the common units. Prior consent of our general partner is required.

 

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Withdrawal of our General Partner

   Prior to June 30, 2025, under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner in a manner that would cause a dissolution of the Partnership.    No difference.

Removal of our General Partner

   Approval of a majority of the common units, excluding common units held by our general partner and its affiliates.    Not less than two-thirds of the outstanding common units, including common units held by our general partner and its affiliates.

Transfer of our General Partner Interest

   Our general partner may transfer without a vote of the holders of common units all, but not less than all, of its general partner interest in us to an affiliate or another person (other than an individual) in connection with its merger or consolidation with or into, or sale of all, or substantially all, of its assets, to such person. The approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of our general partner interest to a third party before June 30, 2025.    No difference.

Transfer of Ownership Interests in our General Partner

   No approval right.    No difference.

Calling Special Meetings of Unitholders

  

Special meetings of unitholders may be called by our general partner or by limited partners whose common units equal 10.00% or more of the outstanding common units.

 

Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding Units of the class or classes for which a meeting has been called represented in person or by proxy will constitute a

   Special meetings of the unitholders, for any purpose or purposes, may be called by our general partner or by limited partners owning 20.00% or more of the outstanding units of the class for which the meeting is proposed.

 

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quorum unless any action by the unitholders requires approval by holders of a greater percentage of the common units, in which case the quorum will be the greater percentage. Unitholders shall call a special meeting by delivering to our general partner one or more requests in writing stating that the signing unitholders wish to call a special meeting and indicating the general or specific purposes for which the special meeting is to be called. Within 15 days after receipt of such a call from unitholders or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, our general partner shall send a notice of the meeting in the United States mail to the unitholders either directly or indirectly through the transfer agent. A meeting shall be held at a reasonable time and place determined by our general partner on a date not less than 30 days nor more than 60 days after the mailing of notice of the meeting; provided, that the date for such meeting may be extended for a period of up to 60 days if, in the opinion of our general partner, such additional time is necessary to permit preparation of proxy or information statements or other documents required to be delivered in connection with such meeting by the SEC or other regulatory authorities.

 

Each record holder of a common unit has one vote per common unit. Common units held in nominee or street name account will be voted by the broker or

  

 

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other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

 

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our Partnership Agreement will be delivered to the record holder by us or by the transfer agent.

  

Conflicts of Interest

  

Other than provisions described in “Conflict of Interest and Fiduciary Duties,” any resolution or course of action by the board of directors of our general partner with respect to a conflict of interest will be permitted and deemed approved by all limited partners, and therefore will not constitute a breach of our Partnership Agreement, if the resolution is:

 

(i)     approved by a majority of the members of the conflicts committee;

 

(ii)    approved by a majority of the outstanding common units (excluding common units held by interested parties); or

 

(iii)  on terms no less favorable to us than those generally provided to or available from unrelated third parties.

 

If a proposed conflict of interest is material to our business and operations, only the resolution features in (i) and (ii) will be applicable.

 

Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee. If our general partner does not seek approval

   No difference, except that the standards of (iii) may be applied to all conflicts of interest, without limitation, and that a conflict may be resolved if the resolution is fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous.

 

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   from the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in (i), (ii) or, as applicable, (iii), then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any unitholder, the person bringing the proceeding will have the burden of overcoming the presumption.   

Fiduciary Duties of our General Partner

   Our Partnership Agreement restricts, eliminates or otherwise modifies the duties, including fiduciary duties, and liabilities of our general partner and its board of directors owed to us and our limited partners. It also restricts the remedies available to limited partners for actions taken that, without those limitations, might constitute breaches of fiduciary duties.    No difference

Indemnification

   For purposes of this section, “indemnitee” means (a) our general partner, (b) any departing general partner, (c) any person who is or was an affiliate of our general partner or any departing general partner, (d) any person who is or was a manager, managing member, officer, director, employee, agent, fiduciary or trustee of the Partnership or its subsidiaries, our general partner or any departing general partner or any affiliate of the Partnership or its subsidiaries, our general partner or any departing general partner, (e) any person who is or was serving at the request of our general partner or any departing general partner or any affiliate of our general partner   

We will indemnify the following persons, by reason of their status as such, to the fullest extent permitted by law, from and against all losses, claims or damages arising out of or incurred in connection with our business:

 

•       our general partner;

 

•       any departing general partner;

 

•        any person who is or was an affiliate of our general partner or any departing general partner;

 

•        any person who is or was a manager, managing member, officer, director, employee, agent, fiduciary or trustee of the Partnership, its

 

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or any departing general partner as a manager, managing member, officer, director, employee, agent, fiduciary or trustee of another person; provided that a person shall not be an indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services; and (f) any person that our general partner designates as an “indemnitee” for purposes of our Partnership Agreement.

 

The indemnitee shall not have any liability whatsoever to us, or to any unitholder for any loss suffered by us or the unitholders which arises out of any action or inaction of the indemnitee if:

 

•        the indemnitee determined in good faith that the course of conduct was in our best interest;

 

•        the indemnitee was acting on behalf of, or performing services for, us; and

 

•        the course of conduct did not constitute negligence or misconduct of the indemnitee.

 

The indemnitee shall be indemnified by us against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection with us, provided that:

 

•        the indemnitee determined in good faith that the course of conduct which caused the loss or liability was in our best interest;

 

•        the indemnitee was acting on behalf of, or performing services for, us; and

  

subsidiaries, our general partner, any departing general partner or any of our affiliates or our subsidiaries;

 

•        any person who is or was serving at the request of a general partner or any departing general partner or any affiliate of a general partner or any departing general partner as a manager, managing member officer, director, employee, agent, fiduciary or trustee of another person; and

 

•        any person whom our general partner designates as an indemnitee.

 

Our indemnification obligation arises only if the indemnified person did not act in bad faith or engage in fraud, willful misconduct or, in the case of a criminal matter, knowledge of the indemnified person’s unlawful conduct.

 

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•        the course of conduct was not the result of negligence or misconduct of the indemnitee.

 

Provided, however, payments arising from such indemnification or agreement to hold harmless are recoverable only out of the following:

 

•        the Partnership’s tangible net assets, which include its revenues; and

 

•        any insurance proceeds received by us.

 

Notwithstanding anything to the contrary contained in this section, the indemnitee and any person acting as a broker/dealer with respect to the offer or sale of the common units, shall not be indemnified for any losses, liabilities or expenses arising from or out of an alleged violation of federal or state securities laws by such party unless:

 

•        there has been a successful adjudication on the merits of each count involving alleged securities law violations as to the particular indemnitee;

 

•        the claims have been dismissed with prejudice on the merits by a court of competent jurisdiction as to the particular indemnitee; or

 

•        a court of competent jurisdiction approves a settlement of the claims against a particular indemnitee and finds that indemnification of the settlement and the related costs should be made, and the court considering the request for indemnification has been advised of the position of the SEC and any state securities regulatory authority in which plaintiffs claim they were offered or sold common units

  

 

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with respect to the issue of indemnification for violation of securities laws.

 

The advancement of Partnership funds to the indemnitee for legal expenses and other costs incurred as a result of any legal action for which indemnification is being sought from us is permissible only if we have adequate funds available and the following conditions are satisfied:

 

•        the legal action relates to acts or omissions with respect to the performance of duties or services on behalf of the Partnership;

 

•        the legal action is initiated by a third-party who is not a unitholder, or the legal action is initiated by a unitholder and a court of competent jurisdiction specifically approves the advancement; and

 

•        the indemnitee undertakes to repay the advanced funds to us, together with the applicable legal rate of interest thereon, in cases in which such party is found not to be entitled to indemnification.

 

The Partnership shall not bear the cost of that portion of insurance which insures the indemnitee for any liability for which they could not be indemnified pursuant to our Partnership Agreement.

  

Voting Rights; Anti-Takeover

   No comparable provision.    If any person or group (other than our general partner and its affiliates or persons who acquired their units directly from such persons) beneficially owns 20.00% or more of any class of units then outstanding, all units owned by such person or group cannot vote on any matter and are not considered outstanding.

 

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The Partnership Agreement

The following is a summary of our Partnership Agreement, a copy of which is attached as Exhibit A. While we believe this summary is materially complete, you should carefully read Exhibit A for all of the information regarding the Partnership that may be important to you. The Partnership Agreement attached as Exhibit A, not this summary, will govern your legal rights and obligations as a unitholder.

Organization and Duration

The Partnership was formed on February 11, 2013 as a Delaware limited partnership. Unless a listing event occurs before then, the Partnership will have a term of 10 years from June 30, 2015, or until June 30, 2025, subject to two one-year extensions in the sole discretion of our general partner.

Purpose

Our purpose under our Partnership Agreement is to (a) engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by our general partner, in its sole discretion, and that lawfully may be conducted by a limited partnership organized pursuant to Delaware Act; and (b) do anything necessary or appropriate to the foregoing; provided, that our general partner will not cause us to engage in any business activity that it determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for U.S.  federal income tax purposes.

Common Units

The common units are a class of limited partner interests in the Partnership. The holders of common units are entitled to participate in our distributions and exercise the rights or privileges available to holders of common units as outlined in our Partnership Agreement.

Restrictions on Transfer of Common Units

A limited partner’s ability to sell or otherwise transfer his common units is restricted by the securities laws, the tax laws and our Partnership Agreement, as described below. The sale or other transfer of common units may create negative tax consequences to a limited partner as described in “Material Federal Income Tax Consequences—Disposition of Units.”

“Transfer” is defined under our Partnership Agreement to include any sale, exchange, gift, assignment, pledge, mortgage, hypothecation, redemption or other form of transfer of a common unit, or any interest in a common unit, by a unitholder or by operation of law. Before a limited partner may transfer his common unit, our general partner, in its sole discretion, may require that the limited partner provide an opinion of counsel acceptable to our general partner that registration and qualification under any applicable federal or state securities laws are not required.

In addition, due to tax laws, unless the requirement for an opinion of counsel is waived by our general partner, our Partnership Agreement provides that a limited partner will not be able to transfer his common units if it would, in the opinion of our counsel, result in the following:

 

    the termination of the Partnership for tax purposes; or

 

    the Partnership being treated as a “publicly traded” partnership for tax purposes.

Finally, under our Partnership Agreement transfers of the common units are subject to the following additional limitations:

 

    except as provided by operation of law, we will recognize the transfer of only one or more whole common units unless the limited partner owns less than a whole unit, in which case the entire fractional interest must be transferred;

 

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    the costs and expenses associated with the transfer must be paid by the person transferring the common unit;

 

    the transfer documents must be in a form satisfactory to our general partner; and

 

    the terms of the transfer must not contravene those of our Partnership Agreement.

A transfer of a common unit will not:

 

    relieve the transferor of responsibility for any obligations related to his common units under our Partnership Agreement;

 

    grant rights under our Partnership Agreement, as among the transferees, to more than one party unanimously designated by the transferees to our general partner, and, if he has retained an interest in the transferred common unit, the transferor of the common unit; nor

 

    require an accounting of the Partnership.

If the assignee of the common unit does not become a substituted partner as described below in “—Conditions to Becoming a Substitute Partner,” the transfer will be effective as of midnight of the last day of the calendar month in which it is made or, at our general partner’s election, 7:00 A.M. of the following day.

Conditions to Becoming a Substitute Partner

An assignee of a common unit will not be entitled to any of the rights granted to a partner under our Partnership Agreement, other than the right to receive all or part of the share of the profits, losses, income, gains, deductions, credits and depletion allowances, or items thereof, and cash distributions or returns of capital to which his assignor would otherwise be entitled, unless the assignee becomes a substituted partner in accordance with the provisions set forth below. The conditions to become a substitute partner are as follows:

 

    the assignor gives the assignee the right;

 

    our general partner consents to the substitution in its sole discretion;

 

    the assignee pays to the Partnership all costs and expenses incurred by the Partnership in connection with the substitution; and

 

    the assignee executes and delivers, in a form acceptable to our general partner, the instruments necessary to establish that a legal transfer has taken place and to confirm his agreement to be bound by all of the terms and provisions of our Partnership Agreement.

A substitute partner is entitled to all of the rights of full ownership of the assigned common units, including the right to vote. We will amend our records at least once each calendar quarter to effect the substitution of substituted partners.

Capital Contributions; No Dilution of GP Units

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

The GP units are entitled to 2.00% of all distributions that the Partnership makes prior to its liquidation. The 2.00% sharing ratio of the GP units will not be reduced if we issue additional equity securities in the future. Because the 2.00% sharing ratio will not be reduced if we issue additional equity securities, and in order to ensure that each GP unit represents the same percentage economic interest in us as one common unit, if we issue additional common units, we will also issue to our general partner, for no additional consideration and without any requirement to make a capital contribution, an additional number of GP units so that the total number of outstanding GP units after such issuance equals 2.00% of the sum of the total number of common units and GP units after such issuance.

 

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Management Fee

Our general partner will receive an annual management fee equal to the product of 1.00% per annum multiplied by total capital contributions (other than those of our general partner and its affiliates), payable quarterly.

Cash Distribution Policy

The amount of distributions paid under our cash distribution policy and the decision to make any distribution will be determined by our general partner in its discretion, taking into account the terms of our Partnership Agreement. The amount of “available cash,” which is defined in our Partnership Agreement, will be determined by our general partner for each calendar quarter and will be based upon recommendations from our management.

Target Quarterly Distributions

We currently distribute to the holders of common units and GP units on a quarterly basis a target distribution of $0.175 per unit, or $0.70 per unit per year, to the extent we have sufficient available cash after establishing appropriate reserves and paying fees and expenses, including payments to our general partner in reimbursement of costs and expenses it incurs on our behalf. There is no guarantee that we will pay the target distribution, or any distribution, in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default or an existing event of default under any credit facility we may enter into.

Our general partner expects that we would raise the quarterly cash distribution only when our general partner believes that:

 

    we have sufficient reserves and liquidity for the proper conduct and expansion of our business; and

 

    we can maintain such an increased distribution level for a sustained period.

Quarterly Distributions of Available Cash

Our Partnership Agreement requires that we make distributions of all available cash within 45 days after the end of each quarter (beginning with the quarter following the quarter in which investors are first admitted to the Partnership as limited partners) to holders of record on the applicable record date.

For these purposes, “available cash” generally means, for any of our fiscal quarters:

 

    all cash on hand at the end of the quarter (including amounts available for working capital purposes under a credit facility, commercial paper facility or other similar financing arrangement),

 

    less the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter in order to:

 

    provide for the proper conduct of our business (including reserves for working capital, operating expenses, future capital expenditures and credit needs and potential acquisitions);

 

    comply with applicable law and any of our debt instruments or other agreements; or

 

    provide funds for distributions (1) to the unitholders for any one or more of the next four quarters or (2) with respect to the IDRs (provided that our general partner may not establish cash reserves for future distributions unless it determines that the establishment of such reserves will not prevent us from distributing the target distribution on all common units and GP units);

 

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    plus, if our general partner so determines, all or any portion of cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

Working capital borrowings are borrowings that are made under a credit facility or another arrangement and used solely for working capital purposes or to pay distributions to unitholders; provided that when such borrowings are incurred it is the intent of the borrower to repay such borrowings within 12 months from the date of such borrowings from sources other than additional working capital borrowings.

For purposes of determining available cash, reserves that are determined to be necessary by our general partner are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When our general partner determines available cash for any calendar quarter, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate distribution level. Our general partner intends to reserve cash in excess of amounts needed to provide for the Partnership’s operating and other costs and for the target distribution to limited partners, for use in acquiring and developing additional oil and gas properties. Distributions of available cash to limited partners are not cumulative. Consequently, if distributions on common units are not paid with respect to any calendar quarter, limited partners will not be entitled to receive such payments in the future.

Operating Surplus and Capital Surplus

General

All cash we distribute to unitholders will be characterized as either “operating surplus” or “capital surplus.” Our Partnership Agreement requires that it distribute available cash from operating surplus differently than available cash from capital surplus.

Definition of Operating Surplus

Operating surplus generally means:

 

    $60 million (as described below); plus

 

    all of our cash receipts, including working capital borrowings but excluding cash from (1) borrowings that are not working capital borrowings, (2) sales of equity and debt securities and (3) sales or other dispositions of assets outside the ordinary course of business; plus

 

    working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; plus

 

    cash distributions paid on equity securities that we may issue to finance all or a portion of the construction, acquisition, development, replacement or improvement of a capital asset (such as equipment or reserves) during the period beginning on the date that we enter into a binding obligation to commence the construction, acquisition, development or improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset begins producing in paying quantities, the date it is placed into service or the date that it is abandoned or disposed of; plus

 

    cash distributions paid (including incremental incentive distributions) on equity issued to pay the construction period interest on debt incurred (including periodic net payments under related interest rate swap arrangements), or to pay construction period distributions on equity issued, to finance the capital improvements or capital assets referred to above; less

 

    our operating expenditures (as defined below); less

 

    the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

 

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    all working capital borrowings not repaid within 12 months after having been incurred or repaid within such twelve-month period with the proceeds of additional working capital borrowings; less

 

    any cash loss realized on disposition of an investment capital expenditure.

If a working capital borrowing, which increases operating surplus, is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will not be treated as a reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

Operating expenditures is defined in our Partnership Agreement, and generally means all of the Partnership’s cash expenditures, including but not limited to:

 

    taxes;

 

    reimbursement of expenses to our general partner and its affiliates;

 

    payments made in the ordinary course of business on hedge contracts;

 

    officer compensation;

 

    repayment of working capital borrowings;

 

    debt service payments; and

 

    estimated maintenance capital expenditures.

Operating expenditures, however, do not include:

 

    repayment of working capital borrowings previously deducted from operating surplus pursuant to the penultimate bullet point of the definition of operating surplus when the repayment actually occurs;

 

    payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings;

 

    expansion capital expenditures;

 

    actual maintenance capital expenditures;

 

    investment capital expenditures;

 

    payment of transaction expenses relating to interim capital transactions;

 

    distributions to our unitholders and distributions with respect to its IDRs; or

 

    repurchases of equity interests except to fund obligations under employee benefit plans.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $60.0 million of cash that we receive in the future from non-operating sources, such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including in the definition of operating surplus certain cash distributions on equity securities would be to increase operating surplus by the amount of the cash distributions. As a result, we may also distribute as operating surplus up to the amount of the cash distributions it receives from non-operating sources.

None of actual maintenance capital expenditures, investment capital expenditures or expansion capital expenditures are subtracted from operating surplus. Because actual maintenance capital expenditures, investment capital expenditures and expansion capital expenditures include interest payments (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on IDRs) to finance all of the

 

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portion of the construction, acquisition, development, replacement or improvement of a capital asset (such as equipment or reserves) during the period from when we enter into a binding commitment to commence the construction, acquisition, development or improvement of a capital asset or replacement of a capital asset until the earlier to occur of the date any such capital asset is placed into service or the date that it is abandoned or disposed of, such interest payments and equity distributions are also not subtracted from operating surplus (except, in the case of maintenance capital expenditures, to the extent such interest payments and distributions are included in estimated maintenance capital expenditures).

Capital Expenditures

Estimated maintenance capital expenditures reduce operating surplus, but expansion capital expenditures, actual maintenance capital expenditures and investment capital expenditures do not.

Maintenance Capital Expenditures. Maintenance capital expenditures are those capital expenditures we expect to make on an ongoing basis to maintain our current production levels over the long term. We expect that a primary component of maintenance capital expenditures will be capital expenditures associated with the replacement of equipment and oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage and other similar assets), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property, including to offset expected production declines from producing properties if such expenditures are made to maintain the levels of oil and gas production of the Partnership for the long term. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on IDRs) to finance all or any portion of a replacement asset that is paid in respect of the period beginning on the date that we enter into a binding obligation to commence construction or development of the replacement asset and ending on the earlier to occur of the date the replacement asset is placed into service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

Because our maintenance capital expenditures can be irregular, the amount of actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to the unitholders if we subtracted actual maintenance capital expenditures from operating surplus. To address this issue, our Partnership Agreement will require that an estimate of the average quarterly maintenance capital expenditures (including estimated plugging and abandonment costs) necessary to maintain our asset base over the long term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year. We will make the estimate at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of future estimated maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. Any adjustment to this estimate will be prospective only.

The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:

 

    it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the target distribution to be paid on all the units for that quarter;

 

    it will increase our ability to distribute as operating surplus cash we receive from non-operating sources;

 

   

in quarters where estimated maintenance capital expenditures exceed actual maintenance capital expenditures, it will be more difficult for us to raise our distributions above the target distribution, because the amount of estimated maintenance capital expenditures will reduce the amount of cash available for distribution to unitholders, even in quarters where there are no corresponding actual

 

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capital expenditures; conversely, the use of estimated maintenance capital expenditures in calculating operating surplus will have the opposite effect for quarters in which actual maintenance capital expenditures exceed our estimated maintenance capital expenditures; and

 

    it will be more difficult for us to raise distributions above the target distribution (where our general partner would not otherwise reserve such amount to invest in projects) and pay IDRs.

Expansion Capital Expenditures

Expansion capital expenditures are those capital expenditures that we expect will increase the production of our oil and gas properties over the long term. Examples of expansion capital expenditures include the acquisition of reserves or equipment, the acquisition of new leasehold interests, or the development, exploitation and production of an existing leasehold interest, to the extent such expenditures are incurred to increase the production of our oil and gas properties over the long term. Expansion capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on IDRs) to finance all or any portion of a capital improvement that is paid in respect of the period beginning on the date that we enter into a binding obligation to commence construction or development of the capital improvement and ending on the earlier to occur of the date the capital improvement is placed into service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered expansion capital expenditures.

Investment Capital Expenditures

Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of our undeveloped properties in excess of the maintenance of our asset base, but which are not expected to expand our asset base for more than the short term.

Capital expenditures that are made in part for maintenance capital purposes and in part for investment capital or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditures by the board of directors of our general partner based upon its good faith determination.

Definition of Capital Surplus

Capital surplus is defined in our Partnership Agreement as any distribution of available cash in excess of the Partnership’s cumulative operating surplus (excluding cash generated by a merger or sale of substantially all of our assets in a liquidity event). Accordingly, capital surplus would generally be generated by:

 

    borrowings (including sales of debt securities) other than working capital borrowings;

 

    sales of debt and equity securities; and

 

    sales or other dispositions of assets for cash, other than inventory, accounts receivable and other assets disposed of in the ordinary course of business or as part of normal retirement or replacement of assets.

Characterization of Cash Distributions

We treat all available cash distributed as distributed from operating surplus until the sum of all available cash distributed since we began operations equals its total operating surplus from the date that it began operations

 

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until the end of the quarter that immediately preceded the distribution. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As described above, operating surplus includes up to $60.0 million, which does not reflect actual cash on hand that is available for distribution to unitholders. Rather, it is a provision that will enable us, if we so choose, to distribute as operating surplus up to this amount of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and borrowings that would otherwise be distributed as capital surplus. We do not currently anticipate that we will make any distributions from capital surplus.

Distributions of Available Cash from Operating Surplus

We will make distributions of available cash from operating surplus for any quarter in the following manner: 2.00% to holders of the GP units (which are held by our general partner) and 98.00% to the holders of common units, each pro rata.

Adjusted operating surplus for any period generally means operating surplus generated during that period, less:

 

    any net increase in working capital borrowings with respect to that period; and

 

    any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period,

and plus:

 

    any net decrease in working capital borrowings made with respect to that period;

 

    any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium; and

 

    any net decrease made in subsequent periods in cash reserves for operating expenditures initially established with respect to such period to the extent such decrease results in a reduction of adjusted operating surplus in subsequent periods pursuant to the second bullet point above.

Operating surplus generated during a period is equal to the difference between:

 

    the operating surplus determined at the end of that period; and

 

    the operating surplus determined at the beginning of that period.

Distributions from Capital Surplus

We distribute available cash from capital surplus, if any, in the following manner:

 

    first, 98.00% to the holders of common units and 2.00% to the holders of GP units, each pro rata, until distributions have been paid on each common unit from capital surplus in an aggregate amount equal to the initial unit price (as defined below); and

 

    after that, the Partnership will distribute all available cash from capital surplus, as if it were from operating surplus.

Our Partnership Agreement treats a distribution from capital surplus as the repayment of an investment in its units, which is referred to herein as the “unrecovered unit price.” The initial “unrecovered unit price” will be equal to the $10.00 per unit price in this offering. Any distributions from capital surplus will reduce the unrecovered unit price. In addition, any distribution of capital surplus will also reduce the target distribution levels. Each of the target distribution levels will be reduced in connection with a distribution of capital surplus to an amount equal to the then-applicable target distribution level multiplied by a fraction, the numerator of which is the unrecovered unit price immediately prior to such distribution of capital surplus, and the denominator of which is the unrecovered unit price immediately after such distribution of capital surplus.

 

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After the target distribution levels have been reduced to zero, we will treat all distributions of available cash from all sources as if they were from operating surplus. Because the target distribution levels will have been reduced to zero, our general partner will then be entitled to receive 50.00% of all distributions of available cash in its capacity as general partner and holder of the IDRs, in addition to any distributions to which it may be entitled as a holder of common units.

Distributions from capital surplus will not reduce the target distribution levels for the quarter in which they are distributed.

Adjustment of Target Distribution Levels

In addition to adjustments made upon a distribution of available cash from capital surplus, we will proportionately adjust the target distribution levels and any other amounts calculated on a per unit basis upward or downward, as appropriate, if any combination or subdivision of common units occurs. For example, if a two-for-one split of the common units occurs, the Partnership will reduce the target distribution levels by one-half.

We will not make any adjustment for the issuance of additional common units for cash or property.

We may also adjust the target distribution levels if legislation is enacted or if any current law is modified or interpreted in a manner that causes it to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes. In this event, we will reduce the target distribution and the target distribution levels for each quarter after that time to amounts equal to the product of:

 

    each of the target distribution levels, and

 

    one minus the sum of:

 

    the highest marginal federal income tax rate that could apply to a partnership that is taxed as a corporation; plus

 

    the effective overall state and local income tax rate that would have been applicable in the preceding calendar year as a result of the new imposition of the entity level tax, after taking into account the benefit of any deduction allowable for federal income tax purposes for the payment of state and local income taxes, but only to the extent of the increase in rates resulting from that legislation or interpretation.

For example, assuming we were not previously subject to state and local income tax, if it became taxable as a corporation for federal income tax purposes and subject to a maximum marginal federal, and effective state and local, income tax rate of 40.00%, then we would reduce the target distribution levels to 60.00% of the amount immediately before the adjustment.

Distributions Upon Sale

The Partnership will make distributions of available cash with respect to a sale of substantially all of its assets as follows:

 

    First, 100.00% to the holders of the common units until they have received an amount equal to their capital contributions plus $0.175 per Unit for each quarter from the date of purchase through the sale, less all amounts previously distributed with respect to such interests.

 

    Second, 100.00% to the holder of the GP units until they have received, including amounts previously received, an amount equal to 2.04% of the excess of (A) amounts distributed to the holders of the common units from operating surplus and clause first above, over (B) the product of $10.00 multiplied by the number of common units outstanding at the time of the sale.

 

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    Third, 100.00% to the holder of the incentive distribution rights, or IDRs, until it has received an amount equal to the sum of (A) the product of 25.00% multiplied by the sum of (x) the amount distributed to the common unit holders pursuant to clause first above plus (y) other amounts previously distributed with respect to the common units less (z) the product of $10.00 multiplied by the number of common units then outstanding, plus (B) the sum of all capital contributions with respect to our general partner interest, less (C) amounts previously distributed with respect to our IDRs (the amount of the distribution upon a sale that is distributed to the holder of the IDRs is referred to as the IDR Sales Distribution).

 

    After that, 80.00% to the holders of the common units and 20.00% to the holder of the IDRs.

Distributions Upon Merger

The Partnership will value consideration to be received in the event of a merger based on the price attributed thereto in the applicable transaction agreement and then distribute the consideration in accordance with the provisions described in “—Distributions Upon Sale.”

Common Unit Issuance in lieu of IDRs to our General Partner at a Listing Event

Upon the occurrence of a listing event, our general partner, as holder of the IDRs, will receive an aggregate number of common units equal to:

 

    the IDR Sales Distribution (as set forth in the third bullet point under “—Distributions Upon Sale” above) that would arise from a deemed sale of all of the Partnership’s assets, divided by

 

    the volume weighted average price of the common units for the initial five days after listing on the exchange on which they are traded, or the initial VWAP.

For purposes of determining the IDR Sales Distribution with respect to a listing event, the available cash from a deemed sale of the Partnership will be calculated as follows:

 

    the number of common units outstanding immediately prior to listing, multiplied by

 

    1.0204, multiplied by

 

    the initial VWAP.

The listing event distribution is designed to provide our general partner a 20% interest in the Partnership following the listing event, but only after the limited partners have received a return of their initial capital contribution together with a 7% non-compounded annual return.

Common Unit Issuance in lieu of IDRs to our General Partner after a Listing Event

After a listing event, if the Calculated IDR Amount exceeds the Actual IDR Amount (each as defined below) for any quarter following the listing event, then our general partner, as holder of the IDRs, will receive an aggregate number of common units equal to the excess of the Calculated IDR Amount over the Actual IDR Amount, divided by the volume weighted average price of the common units during the five trading days preceding the end of the quarter.

These provisions establish what would have been paid to the holder of the IDRs absent reserves established by our general partner for acquisition and drilling operations, utilizing a 1.1x coverage ratio. Please read “Cash Distribution Policy and Restrictions on Distributions.”

As used in this section:

“Actual IDR Amount” means the amount of distributions made pursuant to the IDRs in the fiscal quarter for which the calculation is being made.

 

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“Calculated IDR Amount” means the amount of distributions the holder of the IDRs would have received in the fiscal quarter for which the calculation is being made from the Partnership’s net cash absent the effect of reserves established by our general partner and other related adjustments.

Distributions of Cash Upon Liquidation

When the Partnership commences dissolution and liquidation, it will sell or otherwise dispose of its assets and adjust the partners’ capital account balances to reflect any resulting gain or loss. We will first apply the proceeds of liquidation to the payment of its creditors in the order of priority provided in our Partnership Agreement and by law. After that, we will distribute the proceeds to the unitholders and our general partner in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

We maintain capital accounts in order to ensure that our allocations of income, gain, loss and deduction are respected under the Code. The balance of a partner’s capital account also determines how much cash or other property the partner will receive on liquidation of the Partnership. A partner’s capital account is credited with (increased by) the following items:

 

    the amount of cash and fair market value of any property (net of liabilities) contributed by the partner to the Partnership, and

 

    the partner’s share of “book” income and gain (including income and gain exempt from tax).

A partner’s capital account is debited with (reduced by) the following items:

 

    the amount of cash and fair market value (net of liabilities) of property distributed to the partner, and

 

    the partner’s share of loss and deduction (including some items not deductible for tax purposes).

We have the authority under our Post-Listing Partnership Agreement to make allocations of items of income, gain, loss and deduction to cause each common unit to have an equal capital account.

Upon the liquidation of the Partnership, any gain, or unrealized gain attributable to assets distributed in kind, will be allocated to the partners in the following manner:

 

    First, to the partners to the extent of, and in proportion to, any negative balance in their capital accounts;

 

    Second, to the holders of the common units, pro rata, until the capital account of each common unit is equal to the sum of (1) the unreturned capital contributions of each common unit outstanding at the time of the liquidation and (2) the amount of the $0.175 per unit distribution to the holders of the common units for the quarter in which the liquidation occurs, and (3) any unpaid arrearages on our distribution to the holders of the common units of $0.175 per unit per quarter;

 

    Third, to the holder of the GP units, pro rata, until the capital account for each GP unit is equal to (1) the unreturned capital contributions attributable to the GP units, plus (2) 2.04% multiplied by the excess of: (A) the amount distributed to the holders of the common units, over (B) the product of $10.00 multiplied by the number of common units outstanding at the time of the liquidation, minus (3) the amount previously distributed to the holders of the GP units;

 

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    Fourth, to the holders of the incentive distribution rights, or IDRs, until the capital account for the holders of the IDRs is equal to the excess of (1) 25% multiplied by the excess of: (A) the amount distributed to the holders of the common units, over (B) the product of $10.00 multiplied by the number of common units outstanding at the time of the liquidation, over (2) the amount previously distributed to the holders of the IDRs; and

 

    Thereafter, 80% to the holders of the common units, pro rata, and 20% to the holders of the IDRs, pro rata.

Upon the liquidation of the Partnership, any loss will generally be allocated to our general partner and the unitholders in the following manner:

 

    first, 2.00% to the holders of GP units and 98.00% to the holders of common units, each pro rata, until the capital accounts of the holders of common units have been reduced to zero; and

 

    after that, 100.00% to our general partner.

In addition, we will make interim adjustments to the capital accounts at the time it issues additional equity interests or make distributions of property. We will also make interim adjustments upon a listing event to reflect the issuance to our general partner of common units in lieu of IDRs at a listing event (please read “—Common Unit Issuance in Lieu of IDRs to our General Partner at a Listing Event”), to reflect the revised sharing of our cash flow following a listing event (please read “The Post-Listing Partnership Agreement—Incentive Distribution Rights (IDRs)”), to reflect the issuance to our general partner of common units in lieu of IDRs following a listing event (please read “—Common Unit Issuance in Lieu of IDRs to our General Partner after a Listing Event”), to reflect the reset of the target distribution amount (please read “The Post-Listing Partnership Agreement—Right to Reset Incentive Distribution Levels”), and to reflect the issuance of common units pursuant to our DRIP (please read “Distribution Reinvestment Plan”). We will base these adjustments on the fair market value of the interests or the property distributed and we will allocate any gain or loss resulting from the adjustments to the unitholders and our general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive interim adjustments to the capital accounts, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional equity interests or distributions of Partnership property or upon the liquidation of the Partnership in a manner that results, to the extent possible, in the capital account balances of our unitholders equaling the amount that would have been our unitholders’ capital account balances if we had not made any earlier positive adjustments to the capital accounts.

Distributions In-Kind Upon Liquidation

Any in-kind property distributions to you from the Partnership must be made to a liquidating trust or similar entity, unless you affirmatively consent to receive an in-kind property distribution after being told the risks associated with the direct ownership of the property or unless there are alternative arrangements in place which assure that you will not be responsible for the operation or disposition of our properties. If our general partner has not received your written consent to a proposed in-kind property distribution within 30 days after it is mailed, then it will be presumed that you have not consented. Our general partner may then sell the asset at the best price reasonably obtainable from an independent third-party, or to itself or its affiliates at fair market value as determined by an independent expert selected by our general partner. Also, if the Partnership is liquidated, our general partner will be repaid any debts owed to it by us before there are any payments to you and the other unitholders.

Voting Rights

Other than as set forth below, you generally will not be entitled to vote on any Partnership matters at any Partnership meeting. At any time, however, unitholders whose common units equal 10.00% or more of the total common units in the Partnership may call a meeting to vote, or vote without a meeting, on the matters set forth below without the concurrence of our general partner or its affiliates. On the matters being voted on you are

 

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entitled to one vote per Unit or if you own a fractional Unit that fraction of one vote equal to the fractional interest in the Unit. Unitholders whose common units equal a majority of the outstanding total common units in the Partnership may vote to:

 

    dissolve the Partnership;

 

    remove our general partner and elect a new general partner;

 

    elect a new general partner if our general partner elects to withdraw from the Partnership;

 

    remove the operator and elect a new operator;

 

    approve or disapprove the sale of all or substantially all of the Partnership’s assets;

 

    cancel any contract for services with our general partner, the operator, or their affiliates, which is not otherwise described in this prospectus or our Partnership Agreement, without penalty on 60 days’ notice; and

 

    amend our Partnership Agreement; however, any amendment may not:

 

    without the approval of you or our general partner increase the duties or liabilities of you or our general partner, or increase or decrease the profits or losses or required capital contribution of you or our general partner; or

 

    without the unanimous approval of all unitholders in the Partnership, affect the classification of Partnership income and loss for federal income tax purposes.

Our general partner, its officers, directors, and affiliates may also subscribe for common units in us on a discounted basis, and they may vote on all matters, including the issues set forth above, other than canceling a contract described above and removing our general partner and operator. Any common units owned by our general partner and its affiliates will not be included in determining the requisite number of common units necessary to approve any Partnership matter on which our general partner and its affiliates may not vote or consent.

Applicable Law; Forum, Venue and Jurisdiction

Our Partnership Agreement is governed by Delaware law. Our Partnership Agreement does not require mandatory venue or mandatory arbitration of any claims by unitholders against our general partner.

Management

We have no officers, directors or employees. Instead, our Partnership Agreement confers broad, exclusive authority to our general partner to manage our affairs, which our general partner will exercise through its officers and directors and the officers, directors and employees of its affiliates. Under our Partnership Agreement, our general partner is required to devote only the amount of time and attention to our affairs as it, in its sole discretion but consistent with its fiduciary duties, deems necessary or appropriate.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and otherwise acts in conformity with the provisions of our Partnership Agreement, the limited partner’s liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to the Partnership for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:

 

    to remove or replace our general partner;

 

    to approve some amendments to our Partnership Agreement; or

 

    to take other action under our Partnership Agreement,

 

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constituted “participation in the control” of our business for purposes of the Delaware Act, then our limited partners could be held personally liable for the Partnership’s obligations under Delaware law to the same extent as our general partner. This liability would extend to persons who transact business with the Partnership and reasonably believe that the limited partner is a general partner. Neither our Partnership Agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership cannot make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. Moreover, under the Delaware Act, a limited partnership may also not make a distribution to a partner upon the winding up of the limited partnership before liabilities of the limited partnership to creditors have been satisfied by payment or the making of reasonable provision for payment thereof. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act will be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, an assignee who becomes a limited partner is liable for the obligations of his assignor to make contributions to the partnership, except such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from our Partnership Agreement.

Limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established in many jurisdictions. If it were determined that we were conducting business in any state without compliance with the applicable limited partnership statute, or that the right or exercise of the right by our limited partners as a group to remove or replace our general partner, to approve some amendments to our Partnership Agreement or to take other action under our Partnership Agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then our limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of our limited partners.

Issuance of Additional Securities

Our Partnership Agreement authorizes the Partnership to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units or other securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in distributions of our available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets. The holders of common units will not have preemptive rights to acquire additional common units or other Partnership securities.

In accordance with Delaware law and the provisions of our Partnership Agreement, we may also issue additional Partnership securities that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our Partnership Agreement does not prohibit the issuance by our subsidiaries of equity securities that may effectively rank senior to common units.

 

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We will issue additional GP units to our general partner if we issue additional equity securities as described in “—Capital Contributions; No Dilution of GP Units; One-to-One Ratio Between GP Units and Common Units.”

In addition to the right to receive additional GP units, our general partner will have a limited preemptive right in connection with any issuance by us of additional partnership securities. The right, which our general partner may assign in whole or in part to any of its affiliates, will entitle our general partner to purchase additional amounts of any securities being sold to third parties, on the same terms as such third parties, in an amount up to the amount necessary to maintain the aggregate ownership percentage of our general partner and its affiliates at the same level before and after such issuance.

Amendment of the Partnership Agreement

General. Amendments to our Partnership Agreement may be proposed by our general partner or by limited partners whose common units equal 10.00% or more of the outstanding common units. To adopt a proposed amendment, other than the amendments discussed under “—Amendment of the Partnership Agreement—No Unitholder Approval,” our general partner is required to seek written approval of the holders of the number of common units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment.

No Unitholder Approval. Our general partner may generally make amendments to our Partnership Agreement without the approval of any limited partner to reflect:

 

    a change in our name, the location of our principal place of business, our registered agent or registered office;

 

    the admission, substitution, withdrawal or removal of partners in accordance with our Partnership Agreement;

 

    a change that our general partner determines to be necessary or appropriate for us to qualify or continue qualification as a limited partnership or other entity in which our limited partners have limited liability under the laws of any state or to ensure that we will not be taxed as a corporation or otherwise taxed as an entity for U.S. federal income tax purposes;

 

    a change in our fiscal year or taxable year and related changes;

 

    an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner, or its directors, officers, agents or trustees, from in any manner being subject to the provisions of the Investment Company Act, the Investment Advisers Act or “plan asset” regulations adopted under ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

 

    an amendment that our general partner determines to be necessary or appropriate for the authorization or issuance of additional Partnership securities or options, warrants, rights or appreciation rights relating to any Partnership securities;

 

    an amendment expressly permitted in our Partnership Agreement to be made by our general partner acting alone;

 

    any amendment effected, necessitated or contemplated by a merger agreement or plan of conversion that has been approved under the terms of our Partnership Agreement;

 

    any amendment that our general partner determines to be necessary or appropriate for the formation by the use of, or its investment in, any corporation, partnership or other entity, as otherwise permitted by our Partnership Agreement;

 

   

any amendment necessary to require our limited partners to provide a statement, certification or other evidence to us regarding whether they are subject to U.S. federal income taxation on the income

 

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generated by us or regarding a limited partner’s nationality or citizenship and to provide for the ability of our general partner to redeem equity securities of the Partnership held by any limited partner who fails to provide such statement, certification or other evidence;

 

    conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; and

 

    any other amendment substantially similar to any of the matters described above.

In addition, our general partner may amend our Partnership Agreement, without the approval of the holders of common units, if our general partner determines that those amendments:

 

    do not adversely affect our limited partners in any material respect;

 

    are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

 

    are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange or interdealer quotation system on which the limited partner interests are or will be listed for trading;

 

    are necessary or appropriate for any action taken by our general partner relating to splits or combinations of common units or to implement the tax-related provisions of our Partnership Agreement; or

 

    are required to effect the intent expressed in our original offering documents or this registration statement of which this prospectus is a part or the intent of the provisions of our Partnership Agreement or that are otherwise contemplated by our Partnership Agreement.

Amendment Upon Listing Event. Pursuant to the terms of our Partnership Agreement, simultaneously with the listing event, our Partnership Agreement will automatically be amended and restated in its entirety to be the Post-Listing Partnership Agreement. Each limited partner, by his subscription agreement, shall be deemed to have consented to such amendment and authorizes our general partner to execute the same on its behalf as attorney in fact.

Merger, Consolidation, Conversion, Sale or Other Disposition of the Partnership’s Assets

A merger, consolidation or conversion of the Partnership requires the approval of a majority of common units; the consent of our general partner is not required.

In addition, our Partnership Agreement generally prohibits our general partner, without the prior approval by a majority of the common units, from causing the Partnership to sell, exchange or otherwise dispose of all or substantially all of the Partnership’s assets in a single transaction or a series of related transactions. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the Partnership’s assets without approval by the holders of the common units. Our general partner may also sell all or substantially all of the Partnership’s assets under a foreclosure or other realization upon those encumbrances without that approval.

The holders of common units will not be entitled to dissenters’ rights of appraisal under applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of the Partnership’s assets or any other similar transaction or event.

 

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Termination and Dissolution

The Partnership will continue as a limited partnership until dissolved under our Partnership Agreement. We will dissolve upon:

 

    the expiration of our fixed term;

 

    notice to the holders of the common units by our general partner of our election to terminate our affairs;

 

    notice by the holders of the common units to our general partner of their similar election through the affirmative vote of a majority of the common units;

 

    the Partnership’s termination under Section 708(b)(1)(A) of the Code or if it ceases to be a going concern; or

 

    any event that causes the dissolution of a limited partnership under the Delaware Act.

Other than the occurrence of an event described in the first four bullet points above, the Partnership or any successor limited partnership will not be wound up, but will be continued by the parties and their respective successors as a successor limited partnership under all of the terms of our Partnership Agreement. The successor limited partnership shall succeed to all of our assets.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless the Partnership is continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to June 30, 2025, without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after June 30, 2025, our general partner may withdraw as our general partner without first obtaining approval from the holders of the common units by giving 120 days’ written notice. In addition, our Partnership Agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the holders of the common units. Please read “—Transfer of General Partner Interest.”

If our general partner withdraws, other than as a result of a transfer of all or a part of its general partner interest, the holders of a majority of common units may elect a successor to the withdrawing general partner. If a successor is not elected prior to the effective date of the withdrawal, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved and liquidated, unless within a specified period of time after that withdrawal, the holders of a majority of the common units elect to continue the Partnership by appointing a successor general partner. Please read “—Termination and Dissolution.”

Our general partner may be removed at any time on 60 days’ advance written notice by the affirmative vote of the holders of a majority of the outstanding common units. If the limited partners vote to remove our general partner from the Partnership, then they must elect by an affirmative vote of a majority of the outstanding common units either to:

 

    dissolve, wind-up, and terminate the Partnership; or

 

    continue as a successor limited partnership under the terms of our Partnership Agreement.

 

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If the limited partners elect to continue as a successor limited partnership, then our general partner will not be removed until a substituted general partner has been selected by an affirmative vote of a majority of the outstanding common units and installed as such.

If our general partner is removed, then the value of its partnership interest will be determined by appraisal by a qualified independent expert. The independent expert will be selected by mutual agreement between the removed general partner and the incoming general partner. The appraisal will take into account an appropriate discount, to reflect the risk of recovering natural gas and oil reserves. The cost of the appraisal will be borne equally by the removed general partner and the Partnership. The incoming general partner will have the option to purchase 20.00% of the removed general partner’s partnership interest in the Partnership as general partner, but not as a limited partner, for the value determined by the independent expert.

The method of payment for the removed general partner’s interest must be fair and protect our solvency and liquidity. The method of payment will be as follows:

 

    when the termination is voluntary, the method of payment will be a non-interest bearing unsecured promissory note with principal payable, if at all, from distributions that our general partner otherwise would have received under our Partnership Agreement had it not been terminated; and

 

    when the termination is involuntary, the method of payment will be an interest bearing unsecured promissory note coming due in no less than five years with equal installments each year. The interest rate will be that charged on comparable loans.

Transfer of General Partner Interest

Except for the transfer by our general partner of all, but not less than all, of its GP units to:

 

    an affiliate of our general partner (other than an individual); or

 

    another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

our general partner may not transfer all or any part of its general partner interest to another person, prior to June 30, 2025, without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of the Post-Listing Partnership Agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Transfer of Ownership Interests in our General Partner

The members of our general partner may sell or transfer all or part of their interest in our general partner without the approval of the holders of the common units.

Transfer of Incentive Distribution Rights

Our general partner or any other holder of IDRs may transfer any or all of its IDRs without approval of the holders of the common units.

Return of Subscription Proceeds if Funds Are Not Invested in Twelve Months

Although our general partner anticipates that the Partnership will spend all of its subscription proceeds soon after the offering closes, we will have 12 months in which to use or commit our subscription proceeds to our activities. If within the 12-month period we have not used, or committed for use, all of our subscription proceeds, then our general partner will distribute the remaining subscription proceeds to you and the other unitholders in accordance with your respective subscription amounts as a return of capital.

 

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Meetings; Voting

Persons who are record holders of common units on a record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Our general partner does not anticipate that any meeting of holders of common units will be called in the foreseeable future.

Meetings of the holders of common units may be called by our general partner or by holders of at least 10.00% of the outstanding common units. Holders of common units may vote either in person or by proxy at meetings. Each record holder will have a vote in accordance with his percentage interest, although additional limited partner interests having different voting rights could be issued. Please read “—Issuance of Additional Securities.”

Non-Citizen Assignees; Redemption

If the Partnership is or becomes subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property in which we have an interest because of the nationality, citizenship or other related status of any limited partner, we may redeem the common units held by the limited partner at a reasonable price, as determined by our general partner in its sole discretion. The redemption prices are estimates of value and may not necessarily correspond to realizable value. For a discussion of the tax consequences of selling a Unit, please read “Material Federal Income Tax Consequences—Disposition of Units.”

Reimbursement of Expenses

Our Partnership Agreement requires the Partnership to reimburse our general partner on a monthly basis for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to it or otherwise incurred by our general partner in connection with operating our business, so long as such expenses are supportable as to the necessity thereof and the reasonableness of the amount charged and supported by appropriate invoices or other documentation. These expenses include directors’ fees paid to the independent directors on the board of directors of our general partner and salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf, as well as expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine the expenses that are allocable to us, and our Partnership Agreement does not place any aggregate limit on the amount of such reimbursements. However, our general partner shall bear a percentage of direct and administrative costs equal to its percentage of revenue participation in the Partnership. The amount of reimbursements paid to our general partner are subject to only narrow limits in certain circumstances: (1) the reimbursements of organization and offering costs to our general partner are limited to 2% of the aggregate proceeds of the primary offering if less than $500 million is raised or 1.5% if $500 million or more is raised, in each case excluding the DRIP; and (2) the reimbursements of administrative costs to our general partner are limited to those supportable as to the necessity of such reimbursement and the reasonableness of the amount charged and supported by appropriate invoices or other documentation and other considerations. Otherwise, our Partnership Agreement and the other agreements we have with our general partner do not place meaningful limits on the magnitude of potential reimbursements; specifically, our general partner will determine which costs incurred are reimbursable and there are no limits on the amount of reimbursements on administrative costs to be paid to our general partner.

The allocation of costs between us and our general partner will be audited annually by ATLS’s independent certified public accountants, who will be required to provide written attestation annually that the method used to make allocations was consistent with the method described herein and that the total amount of costs allocated did not materially exceed the amounts incurred by ATLS. If ATLS subsequently decides to allocate expenses in a manner different from that described herein, such change will be reported to the unitholders together with an explanation of why such change was made and the basis used for determining the reasonableness of the new allocation method.

 

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Books and Reports

Our general partner is required to keep appropriate books regarding the Partnership’s business at its principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For financial and tax reporting purposes, our fiscal year end is December 31.

We will provide the reports and information set forth below:

 

    Limited partners will be provided an annual report within 120 days after the close of the calendar year containing our audited financial statements and a report within 75 days after the end of the first six months of our calendar year containing our unaudited financial statements.

 

    Accompanying the annual report, we will provide the following:

 

    a description of each prospect in which we own an interest;

 

    a list of the wells drilled or abandoned during the period of the report;

 

    a description of all farmouts, farmins, and joint ventures, made during the period of the report;

 

    a summary of the computation of the Partnership’s total natural gas and oil proved reserves;

 

    a summary of the computation of the present worth of the reserves;

 

    a statement of each unitholder’s interest in the reserves;

 

    an estimate of the time required for the extraction of the reserves and a statement that, because of the time required to extract such reserves, the present value of revenues to be obtained in the future is less than if such reserves were immediately receivable; and

 

    a summary of the total fees and compensation paid by the Partnership to our general partner and its affiliates and a detailed statement of any transactions with our general partner or its affiliates. The independent certified public accountant will provide written attestation annually, which will be included in the annual report, that the method used to allocate administrative costs was consistent with the method described in “Compensation” and that the total amount of administrative costs allocated did not materially exceed the amounts described in “Compensation.” If our general partner subsequently decides to allocate expenses in a manner different from that described in “Compensation,” then the change must be reported to you and the other unitholders with an explanation of the reason for the change and the basis used for determining the reasonableness of the new allocation method.

The reserve computations will be based on engineering reports prepared by qualified independent petroleum consultants. If any event reduces our proved reserves by 10.00% or more, excluding a reduction of reserves as a result of normal production, sales of reserves, or natural gas or oil price changes, then a computation and estimate of the amount of the reduction in reserves will be sent to each unitholder within 90 days after our general partner determines that such a reduction in reserves has occurred.

By March 15 of each year limited partners will receive the information that is required for them to file their federal and state income tax returns.

Right to Inspect the Partnership’s Books and Records

Limited partners will have access to all of our records at any reasonable time on adequate notice. However, logs, well reports, and other drilling and operating data may be kept confidential for reasonable periods of time. Except with respect to documents pertaining to suitability determinations and to appraisals by independent experts that must be maintained during the term of Partnership and for six years thereafter, our general partner shall maintain and preserve during the term of the Partnership and for four years thereafter all accounts, books and other relevant Partnership documents. Also, the ability of limited partners to obtain the list of investors is subject to additional requirements set forth in our Partnership Agreement.

 

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The Post-Listing Partnership Agreement

The following summarizes those provisions of the Post-Listing Partnership Agreement that materially differ from our Partnership Agreement. While we believe this summary is materially complete, you should carefully read Exhibit B for all of the information regarding the Partnership that may be important to you following a listing event. The Post-Listing Partnership Agreement attached as Exhibit B, not this summary, will govern your legal rights and obligations as a unitholder following a listing event.

Duration

The Partnership will have a perpetual existence unless terminated pursuant to the terms of the Post-Listing Partnership Agreement.

Purpose

The Partnership’s purpose will be to engage in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided, that our general partner will not cause us to engage in any business activity that our general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the production of natural gas and oil, our general partner has no current plans to do so and may decline to do so free of any duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. Our general partner will be authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Transfer Agent and Registrar

Duties. Our general partner will appoint a registrar and transfer agent for the common units. The Partnership will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by holders of common units:

 

    surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

 

    special charges for services requested by a holder of common units; and

 

    other similar fees or charges.

There will be no charge to holders of common units for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional miscond uct of the indemnified person or entity.

Resignation or Removal. The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

Under the Post-Listing Partnership Agreement, each transferee of common units automatically will be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in the Partnership’s books and records. Each transferee:

 

    represents that the transferee has the capacity, power and authority to become bound by the Post-Listing Partnership Agreement;

 

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    automatically becomes bound by the terms and conditions of, and is deemed to have executed, the Post-Listing Partnership Agreement; and

 

    gives the consents and waivers contained in the Post-Listing Partnership Agreement.

We may, in our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfers of securities.

Until a common unit has been transferred on our books, we, along with the transfer agent, may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Applicable Law; Forum, Venue and Jurisdiction

The Post-Listing Partnership Agreement is governed by Delaware law. The Post-Listing Partnership Agreement requires that, unless the Partnership (through the approval of our general partner) consents in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware shall be the sole and exclusive forum for any claims, suits, actions or proceedings:

 

    arising out of or relating in any way to the Post-Listing Partnership Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the Post-Listing Partnership Agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, our limited partners or us);

 

    brought in a derivative manner on our behalf;

 

    asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of the Partnership or our general partner, or owed by our general partner, to us or our limited partners;

 

    asserting a claim arising pursuant to any provision of the Delaware Act; or

 

    asserting a claim governed by the internal affairs doctrine,

regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. However, if and only if the Court of Chancery of the State of Delaware dismisses any such claims, suits, actions or proceedings for lack of subject matter jurisdiction, such claims, suits, actions or proceedings may be brought in another state or federal court sitting in the State of Delaware. By acquiring or purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware in connection with any such claims, suits, actions or proceedings.

Cash Distribution Policy

The distribution provisions of the Post-Listing Partnership Agreement are identical to those of our Partnership Agreement except:

 

    a holder of common units who owns common units as of the record date of any distribution will be entitled to receive the full distribution for the quarter, without pro-ration;

 

    the provisions described above under “—The Partnership Agreement—Distributions Upon Sale” and “—Distributions Upon Merger” are eliminated; and

 

    our general partner is entitled to receive certain distributions upon the occurrence of a listing event.

 

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Incentive Distribution Rights (IDRs)

Although our general partner currently holds all of our IDRs, until a listing event, such IDRs do not entitle the holder thereof to any regular distributions.

From and after a listing event, the IDRs represent the right to receive increasing amounts of quarterly distributions of available cash from operating surplus after the Partnership has made payments in excess of the initial target distribution and the tests described below have been met. Our general partner currently holds all of the IDRs, but may transfer these rights separately from its general partner interest in us, without the consent of the holders of the common units.

We will make incentive distributions to our general partner for any quarter in which we have distributed available cash from operating surplus to our unitholders in an amount equal to the first target distribution, as follows:

 

    first, 2.00% to holders of GP units (which are held by our general partner) and 98.00% to the holders of common units, each pro rata, until each holder has received the initial target distribution;

 

    second, 2.00% to the holders of GP units and 85.00% to the holders of common units, each pro rata, and 13.00% to the holder of the IDRs, which will initially be our general partner, until each holder of GP units and holder of common units has received $0.20125 per outstanding unit, which is referred to as the “first target distribution”;

 

    third, 2.00% to the holders of GP units and 75.00% to the holders of common units, each pro rata, and 23.00% to the holder of the IDRs, until each holder of GP units and holder of common units has received $0.21875 per outstanding unit, which is referred to as the “second target distribution”; and

 

    after that, 2.00% to the holders of GP units and 50.00% to the holders of common units, each pro rata, and 48.00% to the holder of the IDRs.

provided, that, with respect to the first quarter for which each common unit is outstanding, all amounts shall be prorated based on the number of days in such quarter such common unit was outstanding.

The following table illustrates the percentage allocations of the available cash from operating surplus among the unitholders and the owner of the IDRs up to various distribution levels. The amounts set forth under “Marginal percentage interest in distributions” are the percentage interests of our common unitholders and the holders of the IDRs in any available cash from operating surplus that we distribute up to and including the corresponding amount in the column “Quarterly distribution level,” until available cash from operating surplus that we distribute reaches the next distribution level, if any.

 

     Quarterly
distribution
level
   Marginal percentage interest in
distributions
      Common units    GP units    IDRs

Initial Target Distribution per Common and GP unit

   up to $0.175    98.00%    2.00%    0.00%

Second Target Distribution per Common and GP unit

   above

$0.175 up to
$0.20125

   85.00%    2.00%    13.00%

Third Target Distribution per Common and GP unit

   above
$0.20125 up to

$0.21875

   75.00%    2.00%    23.00%

After that

   above
$0.21875
   50.00%    2.00%    48.00%

 

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Right to Reset Incentive Distribution Levels

The holder of the IDRs, which is currently our general partner, has the right under our Post-Listing Partnership Agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of the IDRs in the future, then the holder or holders of a majority of the IDRs will be entitled to exercise this right.

The right to reset the target distribution levels upon which the IDRs are based may be exercised, without approval of our unitholders or the conflicts committee of the board of directors of our general partner, at any time when we have made cash distributions to the holders of the IDRs at the highest level of incentive distribution for the prior four consecutive fiscal quarters. The reset target distribution levels are described below and will be higher than the target distribution levels prior to the reset. We anticipate that the holder of the IDRs would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per Unit, taking into account the existing levels of incentive distribution payments being made to such holder.

In connection with the resetting of target distribution levels and the corresponding relinquishment of incentive distribution payments based on the target cash distributions prior to the reset, the holder of the IDRs will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the IDRs received by such holder for the two quarters prior to the reset event, as compared to the average cash distributions per Unit during this period.

The number of common units that the holder of the IDRs would be entitled to receive in connection with a resetting of the target distribution levels then in effect would be equal to:

 

    the average amount of cash distributions received by the holder of the IDRs in respect of such rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election;

divided by

 

    the average of the amount of cash distributed per Unit during each of these two quarters.

Following a reset election, the initial target distribution amount will be reset to an amount equal to the average cash distribution amount per GP unit and common unit for the two fiscal quarters immediately preceding the reset election, which amount is referred herein as the reset distribution, and the other target distribution levels will be reset to be correspondingly higher such that the Partnership would distribute available cash from operating surplus for each quarter thereafter as follows:

 

    first, 2.00% to the holders of the GP units and 85.00% to the holders of common units, each pro rata, and 13.00% to the holder of the IDRs, until each holder of GP units and holder of common units receives an amount per unit equal to 115.00% of the reset distribution for the quarter;

 

    second, 2.00% to the holders of GP units and 75.00% to the holders of common units, each pro rata, and 23.00% to the holder of the IDRs, until each holder of GP units and holder of common units receives an amount per unit equal to 125.00% of the reset distribution for the quarter; and

 

    thereafter, 2.00% to the holders of GP units and 50.00% to the holders of common units, each pro rata, and 48.00% to the holder of the IDRs.

The holder of the IDRs will be entitled to cause the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our Partnership Agreement.

 

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Amendment of the Partnership Agreement

Amendments to the Post-Listing Partnership Agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners.

No amendment may be made that would:

 

    enlarge the obligations of any limited partner without his consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

 

    enlarge the obligations of, restrict in any way any action by or rights of or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.

The provision of the Post-Listing Partnership Agreement preventing amendments having the effects described in any of the clauses above can itself be amended only upon the approval of the holders of at least 90.00% of the outstanding common units voting together as a single class.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of the Partnership requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or any other standard imposed by the Post-Listing Partnership Agreement, the Delaware Act or applicable law.

Our general partner may consummate any merger, consolidation or conversion without the prior approval of the holders of the common units if the Partnership is the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction will not result in an amendment to the Post-Listing Partnership Agreement (other than an amendment that our general partner could adopt without the consent of other partners), each of the common units will be an identical unit of the Partnership following the transaction and the number of Partnership securities to be issued does not exceed 20.00% of our outstanding securities immediately prior to the transaction.

If the conditions specified in the Post-Listing Partnership Agreement are satisfied, our general partner may convert the Partnership or any of its subsidiaries into a new limited liability entity or merge the Partnership or any of its subsidiaries into, or convey all of our assets to, a newly formed entity if the purpose of that conversion, merger or conveyance is to effect a change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters and our general partner determines that the governing instruments of the new entity provide our limited partners and our general partner with substantially the same rights and obligations as contained in the Post-Listing Partnership Agreement.

The holders of common units will not be entitled to dissenters’ rights of appraisal under the Post-Listing Partnership Agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until dissolved under the Post-Listing Partnership Agreement. We will dissolve upon:

 

    the election of our general partner to dissolve us, if approved by holders of a majority of the common units;

 

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    the entry of a decree of judicial dissolution of the Partnership;

 

    there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law; or

 

    the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in us in accordance with the Post-Listing Partnership Agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under the last item above, the holders of a majority of the common units may also elect, within specific time limitations, to continue our business on the same terms and conditions described in the Post-Listing Partnership Agreement by appointing as a successor general partner an entity approved by the holders of a majority of the common units, subject to our receipt of an opinion of counsel to the effect that:

 

    the action would not result in the loss of limited liability under Delaware law of any limited partner; and

 

    neither us nor any of our subsidiaries would be taxed as a corporation or otherwise be taxable as an entity for U.S. federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Removal of Our General Partner

Our general partner may not be removed unless that removal is approved by the vote of the holders of at least 66 2/3% of the outstanding common units, including common units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, including units held by our general partner and its affiliates. The ownership of more than 33 1/3% of the outstanding common units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal.

In the event of removal of our general partner under circumstances where cause exists or a withdrawal of our general partner that violates the Post-Listing Partnership Agreement, a successor general partner will have the option to purchase the GP units and IDRs of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed, the departing general partner will have the option to require the successor general partner to purchase those interests for their fair market value. In each case, fair market value will be determined by agreement between the departing general partner and the successor general partner. If they cannot reach an agreement, an independent expert selected by the departing general partner and the successor general partner will determine the fair market value. If the departing general partner and the successor general partner cannot agree on an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the purchase option is not exercised by either the departing general partner or the successor general partner, the GP units and IDRs will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

 

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Meetings; Voting

Except as described below under “—Change of Management Provisions,” record holders of common units on a record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Our general partner does not anticipate that any meeting of holders of common units will be called in the foreseeable future.

Any action that is required or permitted to be taken by the holders of common units may be taken either at a meeting of the holders of common units or without a meeting if consents in writing describing the action so taken are signed by holders of the number of common units necessary to authorize or take that action at a meeting. Meetings of the holders of common units may be called by our general partner or by holders of at least 20.00% of the outstanding common units of the class for which a meeting is proposed. Holders of common units may vote either in person or by proxy at meetings. The holders of a majority of the outstanding common units, represented in person or by proxy, will constitute a quorum unless any action requires approval by holders of a greater percentage of the common units, in which case the quorum will be the greater percentage.

Except as described below under “—Change of Management Provisions,” each record holder will have a vote in accordance with his percentage interest, although additional limited partner interests having different voting rights could be issued. Please read “—Issuance of Additional Securities.” Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under the Post-Listing Partnership Agreement will be delivered to the record holder by us or by the transfer agent.

Change of Management Provisions

The Post-Listing Partnership Agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Atlas Growth Partners GP, LLC as our general partner or otherwise change the management of our general partner. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20.00% or more of common units, that person or group will lose voting rights on all of its common units and its common units will not be considered outstanding for the purposes of noticing meetings, determining the presence of a quorum, calculating required votes and other similar matters. This loss of voting rights does not apply to any person or group that acquires the common units from our general partner or its affiliates, any transferees of that person or group approved by our general partner or any person or group who acquires the common units directly from us if our general partner notifies such person or group in writing, in advance, that this limitation will not apply.

Limited Call Right

If at any time our general partner and its affiliates own more than two-thirds of the outstanding common units, our general partner will have the right, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons as of a record date selected by our general partner on at least 10 but not more than 60 days’ notice.

The purchase price will be the greater of:

 

    the highest cash price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

 

    the average of the daily closing prices of the limited partner interests of such class over the 20 trading days preceding the date three days before the date the notice is mailed.

 

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As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than the holder may anticipate the market price to be in the future. The U.S. federal income tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market.

Non-Citizen Assignees; Redemption

If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property in which we have an interest because of the nationality, citizenship or other related status of any limited partner, we may redeem the common units held by the limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require any limited partner or transferee to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish this information within 30 days after a request for the information, or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, then the limited partner may be treated as a non-citizen assignee. A non-citizen assignee does not have the right to direct the voting of his common units and may not receive distributions in kind upon liquidation.

In addition, in such circumstance, we will have the right to acquire all (but not less than all) of the common units held by such limited partner or non-citizen assignee. The purchase price for such common units will be the average of the daily closing prices per Unit for the 20 consecutive trading days immediately prior to the date set for such purchase, and such purchase price will be paid (in the sole discretion of our general partner) either in cash or by delivery of a promissory note. Any such promissory note will bear interest at the rate of 5.00% annually and will be payable in three equal annual installments of principal and accrued interest, commencing one year after the purchase date.

Non-Taxpaying Holders; Redemption

If our general partner, with the advice of counsel, determines that we are not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, or if a limited partner’s tax status (or lack of proof thereof) has, or is reasonably likely to have, a material adverse effect on the maximum applicable rate that can be charged to customers by our subsidiaries, then our general partner may adopt such amendments to the Post-Listing Partnership Agreement as it determines necessary or advisable to:

 

    obtain proof of the U.S. federal income tax status of our limited partners (and their owners, to the extent relevant); and

 

    permit us to redeem the common units, at their current market price, held by any person whose tax status has or is reasonably likely to have a material adverse effect on our ability to operate its assets or generate revenues from our assets or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status.

A non-taxpaying assignee does not have the right to direct the voting of his common units and may not receive distributions in-kind upon our liquidation.

Books and Reports

By March 30 of each year limited partners will receive the information that is required for them to file their federal and state income tax returns.

 

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We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent registered public accounting firm. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or makes the report available on a publicly available website that it maintains.

We will furnish each record holder of a common unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to the holders of common units will depend on the cooperation of those holders in supplying us with specific information. Every holder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect the Partnership’s Books and Records

The Post-Listing Partnership Agreement provides that a limited partner can, for a purpose reasonably related to its interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, obtain:

 

    a current list of the name and last known address of each partner;

 

    a copy of our tax returns;

 

    information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;

 

    copies of the Post-Listing Partnership Agreement, the certificate of limited partnership and related amendments and powers of attorney under which they have been executed; and

 

    information regarding the status of our business and financial condition.

Our general partner may, and intends to, keep confidential from our limited partners trade secrets or other information the disclosure of which our general partner believes is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

In the Post-Listing Partnership Agreement, we will agree to register for resale under the Securities Act and applicable state securities laws any common units or other partnership securities proposed to be sold by our general partner, ATLS or any of their respective affiliates if an exemption from the registration requirements is not otherwise available. There is no limit on the number of times that we may be required to file registration statements pursuant to this obligation. We will also agree to include any securities held by our general partner, ATLS or any of their respective affiliates in any registration statement that we file to offer securities for cash, other than an offering relating solely to an employee benefit plan. These registration rights continue for two years following any withdrawal or removal of our general partner. We must pay all expenses incidental to the registration, excluding underwriting discounts and commissions.

 

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DESCRIPTION OF THE COMMON UNITS

The following is a brief summary of the common units and is subject to, and qualified in its entirety by, the terms set forth in the Partnership Agreement, a copy of which is attached as Exhibit A. A summary of the terms and conditions of the Partnership Agreement, including the rights and obligations of a unitholder, can be found above in “Summary of the Partnership Agreement.”

The Common Units

The common units are a class of limited partner interests in the Partnership. The holders of common units are entitled to participate in our distributions and exercise the rights or privileges available to holders of common units as outlined in our Partnership Agreement. As of September 25, 2015, we had one GP Unit unitholder and 2,934 common unitholders and 23,300,410 common units outstanding.

Differences between the Class A Common Units and Class T Common Units

We are offering two classes of our common units in this offering: Class A common units and Class T common units. The differences between each class relate to the sales commissions payable in respect of each class and cash distributions. Specifically, purchasers of Class A common units will pay higher upfront sales commissions compared to purchasers of Class T common units. A purchaser of Class T common units, however, will pay an annual distribution and unitholder servicing fee. The distribution and unitholder servicing fee will be withheld from cash distributions otherwise payable to the purchasers of Class T common units at a rate of $0.025 per quarter per unit. Assuming our initial quarterly distribution is $0.175 per unit per quarter and we withhold $0.025 per unit per quarter, the holders of Class T common units will receive net quarterly distribution of $0.15 per unit until the deferred payment obligation is fulfilled or the Class T common units convert into Class A common units or are redeemed (for a maximum of up to 16 quarters). Please read “Plan of Distribution—Dealer Manager and Compensation We Will Pay for the Sale of Our Units—Distribution and Unitholder Servicing Fee (Class T Common Units Only)” for limitations on the payment of the distribution and unitholder servicing fee. Such distribution and unitholder servicing fee, together with all other underwriting compensation, may not exceed statutory limits of the underwriting compensation and we can cancel such distribution and unitholder servicing fee if a liquidity event occurs prior to the end of the period of year five of the purchaser’s investment. We anticipate that a liquidity event will occur within five years. However, our Pre-Listing Partnership Agreement does not require that a liquidity event will occur within a specified timeframe or at all.

Because the distribution and unitholder servicing fee is not charged on Class A common units, all things equal, per unit distributions on the Class T common units will be less than the per unit distributions on the Class A common units. We will reflect the sales commissions for Class A common units and Class T common units by recording such sales commissions as offering price less full organizational costs and offering costs (including sales commissions, dealer manager fees and issuer costs) on each unitholder’s account statements, whereas not recording the distribution and unitholder servicing fee on Class T common units’ account statements. To the extent we declare and pay distributions, we will pay distributions on all common units, including the Class T common units and the Class A common units, in the same per unit amount. There is no assurance we will pay distributions in any particular amount, if at all.

In addition, only purchasers of at least $500,000 of Class A common units may be entitled to volume discounts. We are offering an aggregate of up to 21,505,376 Class A common units pursuant to the DRIP, at a purchase price during this offering of 93.00% of the primary offering price of the Class A common units, or $9.30 per unit. Our DRIP offering will be made to both our existing common unit holders and to new investors purchasing common units in this offering.

Class A common units and Class T common units will be sold to the general public through broker dealers. You should consult with your financial advisor to determine your account type and eligibility to purchase each class of common units.

 

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Class A Common Units

We will pay our dealer manager sales commissions equal to 7.00% of the price per Class A common unit sold. Our dealer manager may reallow all or a portion of sales commissions to participating soliciting dealers as compensation for their services in soliciting and obtaining subscriptions. Please read “Plan of Distribution—Dealer Manager and Compensation We Will Pay For the Sale of Our Units” for additional information. In addition, we will also pay our dealer manager a fee equal to 3.00% of the price per Class A common unit sold. Certain purchasers of Class A common units may be eligible for volume discounts. Please read “Plan of Distribution—Volume Discounts for Class A Common Units” for additional information. There are no distribution and unitholder servicing fees charged with respect to the Class A common units.

Class T Common Units

We will pay our dealer manager sales commissions equal to 3.00% of the price per Class T common unit sold. Our dealer manager may reallow all or a portion of sales commissions to participating soliciting dealers as compensation for their services in soliciting and obtaining subscriptions. Please read “Plan of Distribution—Dealer Manager and Compensation We Will Pay For the Sale of Our Units” for additional information. In addition, we will also pay a dealer manager fee of 3.00% of the price per Class T common unit sold.

We will also pay a distribution and unitholder servicing fee in the aggregate amount of 4.00% of the gross proceeds from the sale of Class T common units, which distribution and unitholder servicing fee will be withheld from cash distributions otherwise payable to the purchasers of Class T common units at a rate of $0.025 per quarter per unit. Assuming our initial quarterly distribution is $0.175 per unit per quarter and we withhold $0.025 per unit per quarter, the holders of Class T common units will receive net quarterly distribution of $0.15 per unit until the deferred payment obligation is fulfilled or the Class T common units convert into Class A common units or are redeemed (for a maximum of up to 16 quarters). We will cease paying the distribution and unitholder servicing fee with respect to any particular Class T common unit and that Class T common unit will convert into Class A common units at the conversion rate described herein on the earliest of (i) a liquidity event and (ii) the end of the month in which the underwriting compensation paid in the primary offering plus the quarterly distribution and unitholder servicing fee paid with respect to that Class T common unit equals 10% of the gross offering price of that Class T common unit. We will further cease paying the quarterly distribution and unitholder servicing fee on any Class T common unit that is redeemed or repurchased, as well as upon our dissolution, liquidation or the winding up of our affairs, or a merger or other extraordinary transaction in which the Partnership is a party and in which the Class T common units as a class are exchanged for cash or other securities. The conversion rate will be equal to the quotient, the numerator of which is the estimated value per Class T common unit (taking into account any reduction for the unpaid portion of the distribution and unitholder servicing fee as described herein) and the denominator of which is the estimated value per Class A common unit. If the Class T common units are converted to Class A common units at a time when there are unpaid distribution and unitholder servicing fees, a Class T common unitholder will likely receive fewer than one Class A common unit in exchange for each Class T common unit. Such distribution and unitholder servicing, together with all other underwriting compensation, fee may not exceed statutory limits of the underwriting compensation and we can cancel such distribution and unitholder servicing fee if a liquidity event occurs prior to the end of the period of year five of the purchaser’s investment. We anticipate that a liquidity event will occur within five years. However, our Pre-Listing Partnership Agreement does not require that a liquidity event will occur within a specified timeframe or at all.

We will pay the distribution and unitholder servicing fee to our dealer manager, which may reallow the fees to the soliciting dealer, if any, who sold the Class T common units or, if applicable, to a subsequent broker-dealer of record of the Class T common units so long as the subsequent broker-dealer is party to a soliciting dealer agreement, or servicing agreement, with the dealer manager that provides for reallowance. The distribution and unitholder servicing fee is an ongoing fee that is not paid at the time of purchase. Please read “Plan of Distribution—Dealer Manager and Compensation We Will Pay for the Sale of Our Units—Distribution and Unitholder Servicing Fee (Class T Common Units Only).”

 

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Transfer Agent and Registrar

                    will serve as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units, except the following, which must be paid by unitholders:

 

    surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

 

    special charges for services requested by a holder of a common unit; and

 

    other similar fees or charges.

There is no charge to our unitholders for disbursements of our quarterly cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If a successor has not been appointed or has not accepted its appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Restrictions on Transfer of Common Units

A limited partner’s ability to sell or otherwise transfer his common units is restricted by the securities laws, the tax laws and our Partnership Agreement, as described below. The sale or other transfer of common units may create negative tax consequences to a limited partner as described in “Material Federal Income Tax Consequences—Disposition of Units.”

“Transfer” is defined under our Partnership Agreement to include any sale, exchange, gift, assignment, pledge, mortgage, hypothecation, redemption or other form of transfer of a common unit, or any interest in a common unit, by a unitholder or by operation of law. Before a limited partner may transfer his common unit, our general partner, in its sole discretion, may require that the limited partner provide an opinion of counsel acceptable to our general partner that registration and qualification under any applicable federal or state securities laws are not required.

In addition, due to tax laws, our Partnership Agreement provides that a limited partner will not be able to transfer his common units if it would, in the opinion of our counsel, result in the following:

 

    the termination of the Partnership for tax purposes; or

 

    the Partnership being treated as a “publicly traded” partnership for tax purposes.

Finally, under our Partnership Agreement transfers of the common units are subject to the following additional limitations:

 

    except as provided by operation of law, we will recognize the transfer of only one or more whole common units unless the limited partner owns less than a whole unit, in which case the entire fractional interest must be transferred;

 

    the costs and expenses associated with the transfer must be paid by the person transferring the common unit;

 

    the transfer documents must be in a form satisfactory to our general partner; and

 

    the terms of the transfer must not contravene those of our Partnership Agreement.

 

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A transfer of a common unit will not:

 

    relieve the transferor of responsibility for any obligations related to his common units under our Partnership Agreement;

 

    grant rights under our Partnership Agreement, as among the transferees, to more than one party unanimously designated by the transferees to our general partner; or

 

    require an accounting of the Partnership.

If the assignee of the common unit does not become a substituted partner as described in “Summary of the Partnership Agreement—The Partnership Agreement—Conditions to Becoming a Substitute Partner,” the transfer will be effective as of midnight of the last day of the calendar month in which it is made or, at our general partner’s election, 7:00 A.M. of the following day.

 

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DESCRIPTION OF THE WARRANTS

The following is a brief summary of the material terms of the warrants and is subject to, and qualified in its entirety by, the terms set forth in the warrant agreement, a copy of which is attached as Exhibit D.

Warrant Agreement

Investors that purchase common units in this offering (other than pursuant to the DRIP) will receive, for no additional consideration, warrants to purchase additional Post-Listing common units equal to 10.00% of such investor’s aggregate purchase of common units at the price of $10.00 per Unit. In addition, upon the effectiveness of the registration statement of which this prospectus is a part, we will distribute to each existing limited partner one warrant to purchase one additional Post-Listing common unit for every 10 common units held by such limited partner. Therefore, with respect to the warrants, we are registering the offer and sale of:

 

    to the holders of our existing 23,300,410 common units representing limited partner interests:

 

    warrants, and

 

    the 2,330,041 Post-Listing common units underlying such warrants; and

 

    to our new investors:

 

    warrants in connection with the issuance of the new common units being registered in this offering, and

 

    up to 10,000,000 Post-Listing common units underlying such warrants.

The warrants to be issued in this offering will be governed by a warrant agreement. The warrants will be issued in “book-entry only” form to the transfer agent, and evidenced by one or more global warrants. Those investors who own beneficial interests in a global warrant do so through the transfer agent, and the rights of these indirect owners will be governed solely by the applicable procedures of the transfer agent. The warrants may be exercised by notifying the transfer agent prior to the expiration of such warrants and providing payment of the exercise price for the common units for which such warrants are being exercised.

Exercise Price

The warrants have an exercise price equal to the price of a common unit in this offering. This allows the warrant holders to purchase additional Post-Listing common units in a number up to 10.00% of such investor’s aggregate initial purchase of Post-Listing common units at an exercise price of $10.00 per Unit. The exercise price and the number of Post-Listing common units underlying the warrants are both subject to adjustment in certain cases referred to below.

Exercisability

The warrants are exercisable upon the occurrence of a liquidity event. We anticipate that a liquidity event will occur within five years. However, our Pre-Listing Partnership Agreement does not require that a liquidity event will occur within a specified timeframe or at all. When the Partnership expects a liquidity event is likely to occur, the Partnership will notify each holder of a warrant in writing no less than 30 days prior to the liquidity event. Holders of warrants may exercise their warrants at any time during the period beginning with the date of the notice and ending one day prior to the date upon which the liquidity event occurs, except that if the liquidity event is a listing event, holders of warrants may exercise their warrants until the date that is 30 days following the listing event, provided that in each case if the expiration date does not fall on a business day, it shall be the next business day.

The warrants are exercisable, at the option of each holder, in whole or in part, by delivering to the Partnership a duly executed exercise notice accompanied by payment in full for the number of Post-Listing common units purchased upon such exercise. Each warrant is exercisable for one Post-Listing common unit (subject to adjustment, as discussed below).

 

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Transferability

Warrants may not be sold, exchanged, assigned or transferred unless the holder of such warrants provides to the Partnership such documents pertaining to the transfer, including opinions of counsel regarding compliance with securities or other laws, as the Partnership may require, in its sole discretion.

Exchange Listing

The Partnership does not plan on making an application to list the warrants on any national securities exchange or other nationally recognized trading system.

Rights as a Limited Partner

Except as otherwise provided in the warrants or by virtue of such holder’s ownership of common units, the holders of the warrants will not have the rights or privileges of holders of common units until they exercise their warrants.

No Fractional Units

No fractional Post-Listing common units will be issued upon the exercise of the warrants. As described in the warrant agreement, the Partnership will pay cash in lieu of fractional Post-Listing common units.

Adjustments

The exercise price and the number of Post-Listing common units issuable upon exercise of the warrants is subject to appropriate adjustment in relation to dividends payable in common units, splits, combinations or reclassifications affecting the common units.

Reservation of Common Units

The Partnership will at all times reserve and keep available such number of common units as will be issuable upon the exercise of all outstanding warrants and all additional warrants, if any, that may be issued. Such common units, when paid for and issued, will be duly and validly issued, fully paid, free of preemptive rights and free from all taxes, liens, charges and security interests with respect to the issuance thereof.

Amendment

From time to time, the Partnership, without the consent of the holders of the warrants, may amend or supplement the warrant agreement to cure defects or inconsistencies. The consent of each holder of the warrants affected will be required for any amendment pursuant to which the exercise price would be increased or the number of Post-Listing common units purchasable upon exercise of warrants would be decreased (other than pursuant to adjustments provided in the warrant agreement). Other amendments and supplements may be made with the consent of the Partnership and those holders of outstanding warrants, who, upon exercise in full would hold a majority of Post-Listing common units as a result of such exercise.

Liquidation, Dissolution or Winding Up of the Partnership

Holders of the warrants may not be entitled to share in the assets of the Partnership in the event of the liquidation, dissolution or winding up of the Partnership. In the event a bankruptcy or reorganization is commenced by or against the Partnership, a bankruptcy court may hold that unexercised warrants are executory contracts that may be subject to rejection by the Partnership with approval of the bankruptcy court, and the holders of the warrants may, even if sufficient Partnership assets are available, receive nothing or a lesser amount than that to which they would otherwise be entitled as a result of any such bankruptcy case if they had exercised their warrants prior to the commencement of any such case.

 

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DISTRIBUTION REINVESTMENT PLAN

We have adopted a distribution reinvestment plan. The following is a summary of our DRIP. A complete copy of our form of DRIP is included in this prospectus as Exhibit E.

Investment of Distributions

Pursuant to our DRIP, our unitholders may elect to purchase our Class A common units with our distributions. Our DRIP offering will be made to both our existing common unit holders and to new investors purchasing common units in this offering. Under our DRIP, distributions on common units reinvested pursuant to our DRIP will be used to purchase Class A common units. We have the discretion to extend the offering period for the units being offered pursuant to this prospectus under our DRIP beyond the termination of this offering of Class A and Class T common units until we have sold all of the units allocated to the plan through the reinvestment of distributions. We also may offer units under the DRIP pursuant to a new registration statement. We reserve the right to reallocate the number of common units we are offering between the primary offering and our DRIP. Any units issued pursuant to the DRIP are subject to registration and renewal in any state in which such units are offered and the offering of such units is not exempt under applicable laws and regulations. We will initially offer units under our DRIP at 93.00% of the primary offering price of the Class A common units. Based on a primary offering price of $10.00 per Class A common unit, we will initially offer units under our DRIP at $9.30 per unit. Under the DRIP, we have the right to adjust the purchase price to an amount that we determine is the fair market value of a Class A common unit. No dealer manager fees or sales commissions will be paid with respect to units purchased pursuant to the DRIP, therefore, we will retain all of the proceeds from the reinvestment of distributions.

Pursuant to the terms of our DRIP the reinvestment agent, which currently is us, will act on behalf of participants to reinvest the cash distributions they receive from us. Unitholders participating in the DRIP may purchase fractional units. If sufficient common units are not available for issuance under our DRIP, the reinvestment agent will remit excess cash distributions to the participants.

Election to Participate or Terminate Participation

A unitholder may become a participant in the DRIP by making a written election to participate on his or her subscription agreement at the time he or she subscribes for common units. Any unitholder who has not previously elected to participate in the DRIP may so elect at any time by delivering to the reinvestment agent a completed enrollment form or other written authorization required by the reinvestment agent. Participation in the DRIP will commence with the next distribution payable after receipt of the participant’s notice, provided it is received at least ten days prior to the last day of the fiscal quarter, month or other period to which the distribution relates.

Some brokers may determine not to offer their clients the opportunity to participate in the DRIP. Any prospective investor who wishes to participate in the DRIP should consult with his or her broker as to the broker’s position regarding participation in the DRIP.

We reserve the right to prohibit qualified retirement plans and other “benefit plan investors” (as defined in ERISA) from participating in the DRIP if such participation would cause our underlying assets to constitute “plan assets” of qualified retirement plans. Please read “Investment by Tax-Exempt Entities and ERISA Considerations.” A material change includes any anticipated or actual decrease in net worth or annual gross income or any other change in circumstances that would cause the unitholder to fail to meet the suitability standards set forth in this prospectus for the unitholder’s initial purchase of common units.

Each unitholder electing to participate in the DRIP must notify the reinvestment agent if any time during his or her participation in the DRIP, there is any material change in the unitholder’s financial condition or inaccuracy of any representation under the subscription agreement for such unitholder’s initial purchase of our common units.

 

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Subscribers should note that affirmative action in the form of written notice to the reinvestment agent must be taken to withdraw from participation in the DRIP. A withdrawal from participation in the DRIP will be effective with respect to distributions for a distribution period only if written notice of termination is received at least ten days prior to the end of such distribution period. In addition, a transfer of common units prior to the date our common units are listed for trading on a national securities exchange, which we have no intent to do at this time and which may never occur, will terminate participation in the DRIP with respect to such transferred common units as of the first day of the distribution period in which the transfer is effective, unless the transferee demonstrates to the reinvestment agent that the transferee meets the requirements for participation in the plan and affirmatively elects to participate in the DRIP by providing to the reinvestment agent an executed enrollment form or other written authorization required by the reinvestment agent.

To the extent it is economically feasible, money held for reinvestment must be placed in an income-producing account that provides an appropriate safety for the principal, and must be subject to withdrawal by the participant upon not less than 10 days’ notice. If the funds are not reinvested within 180 days of the date of distribution, the funds must be distributed, with such income, if any, to the participants. No sales commissions may be deducted directly or indirectly from the reinvested funds.

Offers and sales of common units pursuant to the DRIP must be registered in every state in which such offers and sales are made and the offering of such common units is not exempt under applicable laws and regulations. Generally, such registrations are for a period of one year. Thus, we may have to stop selling common units pursuant to the DRIP in any states in which our registration is not renewed or extended.

Reports to Participants

Within 90 days after the end of each calendar year, the reinvestment agent will mail to each participant a statement of account describing all material information regarding distributions to the participant and the effect of reinvesting such distributions, including the tax consequences thereof, and, as to such participant, the distributions received, the number of common units purchased, the purchase price for such common units and the total common units purchased on behalf of the participant during the prior year pursuant to our DRIP.

Excluded Distributions

Our general partner may designate that certain cash or other distributions attributable to net sales proceeds will be excluded from distributions that may be reinvested in common units under our DRIP, or excluded distributions.

Accordingly, if proceeds attributable to the potential sale transaction described above are distributed to unitholders as an Excluded Distribution, such amounts may not be reinvested in our common units pursuant to our DRIP. In its initial determination of whether to make a distribution and the amount of the distribution, our general partner will consider, among other factors, our cash position and our distribution requirements as a MLP. Once our general partner determines to make the distribution, it will then consider whether all or part of the distribution will be deemed an Excluded Distribution. Our general partner may determine, for instance, that it is not in our best interest to permit additional cash to be reinvested. In most instances, however, we expect that our general partner would not deem any of the distribution an Excluded Distribution. In that event, the amount distributed to participants in our DRIP will be reinvested in additional common units. If all or a portion of the distribution is deemed an excluded distribution, the distribution will be made to all unitholders, however, the excluded portion will not be reinvested. As a result, we would not be able to use any of the Excluded Distribution to assist in meeting future distributions and the unitholders would not be able to use the distribution to purchase additional common units through our DRIP. We currently do not have any planned Excluded Distributions, which will only be made, if at all, in addition to, not in lieu of, regular distributions.

 

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Material U.S. Federal Income Tax Considerations

Unitholders who participate in the DRIP will be treated as receiving the cash distribution that they would have received as if they had elected not to participate in the DRIP. As a result, your adjusted basis for tax purposes in your common units will be reduced by the full amount of the deemed cash distribution and then increased by the amount of the distributions reinvested in additional Units pursuant to the Plan. Purchasing common units pursuant to the Plan will not affect the tax obligations associated with the common units you currently own and your allocable share of our net income allocable to such common units. However, participation in the Plan will reduce the amount of cash distributions available to you to satisfy any tax obligations associated with owning such Units. Please read the sections entitled “Risk Factors—Federal Income Tax Risks” and “Material Federal Income Tax Consequences—Treatment of Distributions” in this prospectus. In addition, to the extent you purchase common units through our DRIP at a discount to their fair market value, you will be treated for U.S. federal income tax purposes as receiving additional taxable income equal to the amount of the discount.

The fair market value of our common units for U.S. federal income tax purposes is unclear. Initially, the per unit price for our common units pursuant to our DRIP will be 93.00% of the primary offering price of the $10.00 per Class A common unit or $9.30. It is unclear whether the fair market value of a unit of our Class A common unit for U.S. federal income tax purposes is equal to the $10.00 offering price or some lesser amount. In fact, it is possible that a participant in our DRIP who pays $9.30 per unit could be paying more than fair market value for a Class A common unit.

Tax information regarding each participant’s participation in the DRIP will be provided to each participant at least annually.

Amendment, Suspension and Termination

We reserve the right to amend any aspect of or suspend or terminate our DRIP at any time. The reinvestment agent also reserves the right to terminate a participant’s individual participation in the plan, and we reserve the right to terminate our DRIP itself in our sole discretion at any time. We will terminate the DRIP for all distributions paid after a listing event.

 

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REPORTS TO INVESTORS

Under the Partnership Agreement you and certain state securities commissions will be provided the reports and information set forth below, which the Partnership will pay as a direct cost:

 

    You will be provided an annual report containing audited financial statements of the Partnership within 120 days after the close of the calendar year and a report within 75 days after the end of the first six months of its calendar year, containing unaudited financial statements of the Partnership. Such financial information will be prepared on an accrual basis in accordance with general accepted accounting principles, with a reconciliation with respect to information furnished to you for income tax purposes.

 

    Accompanying the annual report, we will provide:

 

    A description of each prospect owned by the Partnership, including the cost, location, number of acres, and the interest.

 

    A list of the wells drilled or abandoned by the Partnership indicating:

 

    whether each of the wells has or has not been completed;

 

    a statement of the cost of each well completed or abandoned; and

 

    justification for wells abandoned after production begins.

 

    A description of all farmouts, farmins, and joint ventures, including justification for the arrangement and material terms.

 

    A summary of the computation of the Partnership’s total oil and natural gas proved reserves, based on engineering reports prepared by our general partner and reviewed by an independent expert.

 

    A summary of the computation of the present worth of the reserves.

 

    A statement of each unitholder’s interest in the reserves.

 

    An estimate of the time required for the extraction of the reserves and a statement that, because of the time required to extract such reserves, the present value of revenues to be obtained in the future is less than if immediately receivable.

 

    A summary of the total fees and compensation paid by the Partnership to our general partner and its affiliates and a detailed statement of any transactions with our general partner or its affiliates. The independent certified public accountant will provide written attestation annually, which will be included in the annual report, that the method used to allocate administrative costs was consistent with the method described in “Compensation” and that the total amount of administrative costs allocated did not materially exceed the amounts described in “Compensation.” If our general partner subsequently decides to allocate expenses in a manner different from that described in “Compensation,” then the change must be reported to you and the other unitholders with an explanation of the reason for the change and the basis used for determining the reasonableness of the new allocation method.

 

    On request, our general partner will provide you the information specified by Form 10-Q (if that report is required to be filed with the SEC) within 45 days after the close of each quarterly fiscal period. Also, this information will be available at the SEC’s website at www.sec.gov.

 

    By March 15 of each year, you will receive the information that is required for you to file your federal and state income tax returns.

 

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TRANSFERABILITY OF INTERESTS

Lack of Liquidity in Investment in Units

The common units will not be listed for trading or quotation on any securities exchange or other market, and you will likely have difficulty selling your common units. The common units are an illiquid investment, and purchasers must be able to hold their common units indefinitely. Please read “Risk Factors—The common units are not liquid and your ability to resell your common units will be limited by the absence of a public trading market and substantial transfer restrictions.”

Conditions to Becoming a Substitute Partner

An assignee of a Unit will not be entitled to any of the rights granted to a partner under the Partnership Agreement, other than the right to receive all or part of the share of the profits, losses, income, gain, credits and cash distributions or returns of capital to which his assignor would otherwise be entitled, unless the assignee becomes a substituted partner. In general, an assignee of a Unit will become a substitute partner upon acquisition of a Unit.

A substitute partner is entitled to all of the rights of full ownership of the assigned common units, including the right to vote.

Listing of Common Units on a National Securities Exchange

The common units are currently not listed on any exchange or over-the-counter market and we may not be able to effect such listing. The common units have not been approved for quotation or trading on a national securities exchange. Subject to the approval of the board of directors of our general partner, our Partnership Agreement gives our general partner the right to cause the common units to be listed on a national securities exchange if our general partner determines that the Partnership and the common units meet the listing requirements of a national securities exchange. No assurances can be made that the common units will be listed on a national securities exchange, and even if listed an active market for the common units may not develop.

 

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PLAN OF DISTRIBUTION

The Offering

We are offering a maximum of $1.0 billion of our common units, delineated as Class A common units and Class T common units, sold to the public through our dealer manager, a registered broker-dealer affiliated with our general partner, at a price of $10.00 per Unit, which includes the maximum allowed to be charged for commission and fees, subject to certain discounts on the Class A common units as described below. The minimum initial investment in our common units is generally $5,000, except that investors who already own our common units may make purchases for less than the minimum investment, so long as such purchases are in $1,000 increments. The minimum subsequent investment is $1,000 per transaction, provided that the minimum subsequent investment amount for all Unit classes does not apply to purchases made under our DRIP.

The offering period will terminate on the earliest of (i) the sale of 100,000,000 common units, (ii)                    , 2018 (the two-year anniversary following the effectiveness of the registration statement of which this prospectus is a part) unless extended by our general partner, but not past                     , 2018 (which is six months following the two-year anniversary of the effectiveness of the registration statement of which this prospectus is a part) or (iii) the failure to receive the minimum subscriptions on or before                    , 2018, which is two years from the effective date of the registration statement of which this prospectus is a part. If subscriptions for the minimum subscription are not received and accepted by our general partner prior to                    , 2018, each investor’s subscription will be promptly returned along with any interest earned. If we decide to continue this primary offering beyond two years from the effective date of the registration statement of which this prospectus is a part, we will provide that information in a prospectus supplement.

The common units are being offered on a “best efforts” basis, which means generally that the dealer manager is required to use only its best efforts to sell the common units and it has no firm commitment or obligation to purchase any of the common units.

We are also offering up to 21,505,376 Class A common units pursuant to our DRIP at 93% of the primary offering price of the Class A common units, or $9.30 per unit. Pursuant to our DRIP, you may elect to have the distributions you receive from us reinvested, in whole or in part, in units of our Class A common units. No sales commissions or dealer manager fees will be paid on common units sold under our DRIP.

If you participate in the DRIP, you will not receive the cash from your distributions, other than special distributions that are designated by our board of directors. As a result, you may have a tax liability with respect to your share of our taxable income, but you will not receive cash distributions to pay that liability. We may suspend or terminate the DRIP at our discretion at any time. We will sell common units under our DRIP beyond the termination of this offering.

We may reallocate the common units offered hereby in the primary offering between the Class A common units and the Class T common units and between our primary offering and the DRIP. Prior to the conclusion of this offering, if any of our common units initially allocated to the DRIP remain unsold after meeting anticipated obligations under the DRIP, we may decide to sell some or all of such units in the primary offering. Similarly, prior to the conclusion of this offering, if any of our common units initially allocated to the DRIP have been purchased and we anticipate additional demand for units under our DRIP, we may choose to reallocate some or all of the units allocated to be offered in the primary offering to the DRIP.

We reserve the right to increase the price per Unit following any material change to our business, assets or operations that increases the value of the Partnership, as determined by an independent expert in the valuation of oil and gas assets. If, following such a change, we determine to increase the price per Unit, which will include dealer manager fees and sales commissions, we will file a post-effective amendment to the registration statement of which this prospectus is a part that describes such independent expert’s valuation report that supports such increase in the value of the Partnership.

 

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We are offering to sell any combination of Class A common units and Class T common units with a dollar value up to the maximum offering amount. All investors must meet the suitability standards discussed in the section of this prospectus entitled “Suitability Standards.” The Unit classes have different sales commissions and ongoing fees. When deciding which class of common units to buy, you should consider, among other things:

 

    the amount of your investment;

 

    the length of time you intend to hold the common units;

 

    the sales commissions attributable to the common units; and

 

    whether you qualify for any sales commission discounts described below.

This offering must be registered in every state in which we offer or sell common units. Generally, these registrations are effective for a period of one year. Thus, we may have to stop selling common units in any state in which our registration is not renewed or otherwise extended. At the discretion of our general partner, we may elect to extend the termination date of our offering of common units reserved for issuance pursuant to the DRIP until we have sold all units allocated to the DRIP in which case participants in the DRIP will be notified. We reserve the right to terminate this offering at any time prior to the stated termination date.

No FINRA members shall execute any transaction in a discretionary account without prior approval of the transaction by the customer pursuant to FINRA Rule 2310(b)(2)(C).

Dealer Manager and Compensation We Will Pay for the Sale of Our Units

Our dealer manager was organized in Pennsylvania for the purpose of participating in and facilitating the distribution of securities in programs sponsored by Atlas Resources, LLC, its affiliates and its predecessors. For additional information about our dealer manager, including information relating to our dealer manager’s affiliation with us, please read “Risk Factors—Risks Related to Conflicts of Interest.”

Our general partner has arbitrarily determined the selling price of the common units, which is consistent with our prior unregistered offering and comparable non-traded oil and gas investment programs in the market, and such price was not based on a relationship to our book or asset values, or to any other established criteria for valuing issued or outstanding units. Because such initial offering price is not based upon any independent valuation, the offering price is not indicative of the proceeds that you would receive upon liquidation.

Except as provided below, our dealer manager will receive sales commissions, which must be paid in cash, of 7.00% or 3.00% of the gross proceeds from the primary offering of Class A common units and Class T common units, respectively. Our dealer manager will also receive a dealer manager fee, which must be paid in cash, in the amount of 3.00% of the gross proceeds from the primary offering of Class A common units and Class T common units as compensation for acting as the dealer manager. Our dealer manager may reallow up to 1.50% of the gross offering proceeds it receives as dealer manager fees to participating broker-dealers, which are FINRA members that enter into selling agreements with the dealer manager to distribute the Units, for marketing support. However, based on its past experience, our dealer manager does not expect to reallow more than 1.25% of the gross proceeds for such support. Our dealer manager may reallow all or a portion of sales commissions to participating broker-dealers. The total amount of all items of compensation from any source, payable to our dealer manager or the participating broker-dealers, including non-cash compensation and the distribution and unitholder servicing fee, will not exceed an amount that equals 10.00% of the gross proceeds of the offering excluding securities purchased through the DRIP imposed by FINRA Rule 2310(b)(4)(B)(ii), or FINRA’s 10.00% cap.

Pursuant to the dealer manager agreement with our dealer manager, sales commissions and dealer manager fees are payable only with respect to completed sales of our common units, which includes, among other things,

 

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the receipt by us or on our behalf of a properly completed and executed subscription agreement, together with payment of the full purchase price of each purchased unit (which includes the applicable sales commissions and dealer manager fees). The dealer manager is acting as an intermediary with respect to the sales commissions and fees payable to the selected dealers in connection with the sale of our common units. We will pay all such amounts to the dealer manager in accordance with the dealer manager agreement if a subscriber is accepted as a limited partner in connection with its purchase of our common units. All compensation of any kind or description paid by the Partnership, directly or indirectly to broker-dealers, must be taken into consideration in computing the allowable sales commission.

We will reimburse the dealer manager and certain participating broker-dealers for reasonable bona fide due diligence expenses incurred by the dealer manager or such participating broker-dealers which are supported by a detailed and itemized invoice. These due diligence reimbursements are considered an organization and offering expense under FINRA Rule 2310(b)(4)(C)(iii), and not considered a part of the 10.00% underwriting compensation under FINRA Rule 2310(b)(4)(B)(vii) so long as the expenses are included in a detailed and itemized invoice. The total of all items that are considered an issuer expense, including itemized expenses for conducting bona fide due diligence, may not, when aggregated with sales commissions, dealer manager fees, the distribution and unitholder servicing fee and all non-cash compensation or other items of value, exceed 15.00% of the offering proceeds.

The dealer manager does not intend to be a market maker and so will not execute trades for selling unitholders. Set forth below is a table indicating the estimated underwriting compensation and expenses that will be paid in connection with the offering. As set forth in the table below, the amount of proceeds payable to us as a result of the offering of the Class T common units also includes a distribution and unitholder servicing fee, in the amount of 4% of the gross proceeds, payable to Anthem Securities Inc. in equal installments over 16 quarters funded by withholding $0.025 per unit per quarter from distributions otherwise payable to the holders of Class T common units.

 

     Per Unit      Total Maximum  

Primary offering:

     

Class A Common Units:

     

Price to public

   $ 10.00       $ 700,000,000   

Less:

     

Sales commissions

     0.70       $ 49,000,000   

Dealer manager fees

     0.30       $ 21,000,000   

Proceeds to Atlas Growth Partners, L.P.

   $ 9.00       $ 630,000,000   

Class T Common Units(1):

     

Price to public

   $ 10.00       $ 300,000,000   

Less:

     

Sales commissions

     0.30       $ 9,000,000   

Dealer manager fees

     0.30       $ 9,000,000   

Proceeds to Atlas Growth Partners, L.P.

   $ 9.40       $ 282,000,000   

Distribution reinvestment plan:

     

Price to public

   $ 9.30       $ 199,999,997   

Distribution sales commissions

     —           —     

Dealer manager fees

     —           —     

Proceeds to Atlas Growth Partners, L.P.

   $ 9.30       $ 199,999,997   

 

(1)

The distribution and unitholder servicing fees are ongoing fees that are not paid at the time of purchase. We will cease paying the distribution and unitholder servicing fee with respect to any particular Class T common unit and that Class T common unit will convert into Class A common units at the conversion rate described herein on the earlier of (i) a liquidity event and (ii) the end of the month in which the underwriting

 

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  compensation paid in the primary offering plus the distribution and unitholder servicing fee paid with respect to that Class T common unit equals 10% of the gross offering price of that Class T common unit. We will further cease paying the distribution and unitholder servicing fee on any Class T common unit that is redeemed or repurchased, as well as upon our dissolution, liquidation or the winding up of our affairs, or a merger or other extraordinary transaction in which the Partnership is a party and in which the Class T common units as a class are exchanged for cash or other securities. The conversion rate will be equal to the quotient, the numerator of which is the estimated value per Class T common unit (including any reduction for the distribution and unitholder servicing fee as described herein) and the denominator of which is the estimated value per Class A common unit. If the Class T common units are converted to Class A common units at a time when there are unpaid distribution and unitholder servicing fees, a Class T common unitholder will likely receive fewer than one Class A common unit in exchange for each Class T common unit.

We, our dealer manager or our respective affiliates also may provide permissible forms of non-cash compensation pursuant to FINRA Rule 2310(c) to registered representatives of our dealer manager and the participating broker-dealers, such as:

 

    an occasional meal, a ticket to a sporting event or the theater, or comparable entertainment which is neither so frequent nor so extensive as to raise any question of propriety and is not preconditioned on achievement of a sales target;

 

    the national and regional sales conferences of our selected broker-dealers;

 

    training and education meetings for registered representatives of our selected broker-dealers; and

 

    gifts or tickets to a sporting event, the value of which shall not exceed an aggregate of $100 per annum per participating registered representative, or be pre-conditioned on achievement of a sales target.

The value of such items of non-cash compensation to participating broker-dealers will be considered underwriting compensation in connection with this offering and will be paid from the dealer manager fee or reduce the dealer manager fee if paid directly by us or our general partner.

We have agreed to indemnify the participating broker-dealers, including our dealer manager and selected registered investment advisors, against certain liabilities arising under the Securities Act. However, the SEC takes the position that indemnification against liabilities arising under the Securities Act is against public policy and is unenforceable.

Neither our dealer manager nor its affiliates will directly or indirectly compensate any person engaged as an investment advisor or a bank trust department by a potential investor as an inducement for such investment advisor or bank trust department to advise favorably for an investment in our units. However, nothing herein will prohibit a registered broker-dealer or other properly licensed person from earning a sales commission in connection with a sale of the common units.

Commencing with the annual report for the year ended December 31, 2016, we will provide, no less often than annually, a per-unit estimated value for each class of our units, an explanation of the method by which we developed the estimate and the date of the data we used to estimate the values.

In no event will the amount we pay to FINRA members exceed FINRA’s 10.00% cap. All amounts deemed to be “underwriting compensation” by FINRA will be subject to FINRA’s 10.00% cap. Also, our dealer manager will repay to us any excess amounts received over FINRA’s 10.00% cap if the offering is abruptly terminated after reaching the minimum amount, but before reaching the maximum amount, of offering proceeds.

Distribution and Unitholder Servicing Fee (Class T Common Units Only)

We will also pay a distribution and unitholder servicing fee in the aggregate amount of 4.00% of the gross proceeds from the sale of Class T common units, which distribution and unitholder servicing fee will be withheld

 

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from cash distributions otherwise payable to the purchasers of Class T common units at a rate of $0.025 per quarter until the obligation is fulfilled or the Class T common units convert or are redeemed as further described below. We will pay the distribution and unitholder servicing fee to our dealer manager, which may reallow the fees to the soliciting dealer, if any, who sold the Class T common units or, if applicable, to a subsequent broker-dealer of record of the Class T common units so long as the subsequent broker-dealer is a party to a selling agent agreement with the dealer manager that provides for reallowance.

The distribution and unitholder servicing fee is an ongoing fee that is not paid at the time of purchase. The distribution and unitholder servicing fee will be paid on each Class T common unit that is purchased in the primary offering. We will cease paying the distribution and unitholder servicing fee with respect to any particular Class T common unit and that Class T common unit will convert into Class A common units at the conversion rate described herein on the earlier of:

 

    a liquidity event; and

 

    the end of the month in which the underwriting compensation paid in the primary offering plus the distribution and unitholder servicing fee paid with respect to that Class T common unit equals 10.00% of the gross offering price of that Class T common unit.

We will further cease paying the distribution and unitholder servicing fee on any Class T common unit that is repurchased, as well as upon our dissolution, liquidation or the winding up of our affairs, or a merger or other extraordinary transaction in which the Partnership is a party and in which the Class T common units as a class are exchanged for cash or other securities. The conversion rate will be equal to the quotient, the numerator of which is the estimated value per Class T common unit (including any reduction for the distribution and unitholder servicing fee as described herein) and the denominator of which is the estimated value per Class A common unit. If the Class T common units are converted to Class A common units at a time when there are unpaid distribution and unitholder servicing fees, a Class T common unitholder will likely receive fewer than one Class A common unit in exchange for each Class T common unit.

If $1.0 billion in units (consisting of $700.0 million in Class A common units and $300.0 million in Class T common units) is sold in the offering, then the maximum amount of the distribution and unitholder servicing fee payable to the dealer manager is estimated to be up to $12,000,000. If we sell only Class T common units (assuming the maximum offering), then the maximum amount of the distribution and unitholder servicing fee payable to the dealer manager is estimated to be up to $40,000,000. These estimates will change if the actual allocation of Class A common units and Class T common units differs from our estimate. The aggregate amount of underwriting compensation for the Class A common units and Class T common units, including the distribution and unitholder servicing fee for the Class T common units, will not exceed FINRA’s 10.00% cap on underwriting compensation.

Discounts for Class A Common Units Purchased by Wrap Accounts, Clients of RIAs, Affiliates and Participating Broker-Dealers

Dealer manager fees will be paid, but no sales commissions will be paid in connection with the sale of common units to the following:

 

    investors whose contracts for investment advisory and related brokerage services with their broker-dealer include a fixed or “wrap” fee feature; and

 

    investors who have either engaged the services of a registered investment advisor or other financial advisor who will be paid compensation for investment advisory services or other financial or investment advice or is investing through a bank trust account with respect to which the investor has delegated the decision-making authority for investments made through the account to a bank trust department, or collectively, an RIA.

 

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If no other broker-dealer is involved in connection with an RIA sale, then our dealer manager will act as the broker-dealer of record and execute the sale presented to us by the RIA. Our dealer manager may be paid the dealer manager fees associated with the sale. However, the net proceeds to us will not be affected by reducing the commissions payable in connection with this type of transaction. Any reduction in the amount of the sales commissions for the sales described in this paragraph will be credited to the investor in the form of additional common units. Fractional common units will be issued.

Our general partner and its executive officers and directors, as well as officers and employees of our dealer manager and their family members (including spouses, parents, grandparents, children and siblings) or other affiliates and “Friends,” may purchase common units offered in this offering at a discount. “Friends” mean those individuals who have prior business and/or personal relationships with the executive officers or directors of our general partner, the dealer manager, or their respective affiliates, including, without limitation, any service provider. The purchase price for such common units will be $9.00 per unit, reflecting that no sales commissions or dealer manager fees will be paid in connection with those sales.

All Units purchased by our general partner and its respective affiliates and “Friends” will be applied to satisfying the minimum required subscription proceeds of $1 million. “Friends” mean those individuals who have prior business and/or personal relationships with the executive officers or directors of our general partner, the dealer manager, or their respective affiliates, including, without limitation, any service provider. The net offering proceeds we receive will not be affected by such sales of common units at a discount. Our general partner and its executive officers and directors and its other affiliates will be expected to hold their common units purchased for investment and not with a view towards resale. In addition, common units purchased by our general partner or its affiliates will not be entitled to vote on any matter presented to the unitholders for a vote relating to the removal of our general partner or any transaction between us and our general partner, or any of its respective affiliates. Any reduction in the sales commissions and dealer manager fees for these sales will be credited to the purchaser in the form of additional common units. Fractional common units will be issued.

Purchases by participating broker-dealers, including their registered representatives and their immediate family members as described above, will be less the sales commission, but the 3.00% dealer manager fee will be paid on these sales. Any reduction in the sales commissions for these sales will be credited to the participating broker-dealers, their registered representatives, and/or their immediate family members in the form of additional common units. Fractional common units will be issued.

Volume Discounts for Class A Common Units

We will offer a reduced common unit purchase price on Class A common units to “single purchasers” on orders of more than $500,000 and sales commissions paid to our dealer manager and participating broker-dealers will be reduced by the amount of the unit purchase price discount.

The per unit purchase price will apply to the specific range of each unit purchased in the total volume ranges set forth in the table below. The reduced purchase price will not affect the amount we receive for investment.

 

     Purchase Price Per Class
A Common Unit in
Volume Discount Range
   Sales Commission Per
Class A Common Unit in
Volume Discount Range

For a “Single Purchaser”

     

$1,000 – $500,000

   $10.00 (No Discount)    7.0%

$500,001 – $1,000,000

   $9.90    6.0%

$1,000,001 – $2,000,000

   $9.80    5.0%

$2,000,001 – $3,000,000

   $9.70    4.0%

$3,000,000 and above

   $9.60    3.0%
   (subject to reduction as
described below)
   (subject to reduction as
described below)

 

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Any reduction in the amount of the sales commissions in respect of volume discounts received will be credited to the investor in the form of additional Class A common units. Fractional Class A common units will be issued.

As an example, a single purchaser would receive 100,505.1 Class A common units rather than 100,000 Class A common units for an investment of $1,000,000 and the sales commission would be $65,303.10. The discount would be calculated as follows: the purchaser would acquire 50,000 Class A common units at a cost of $10.00 per Class A common unit and 50,505.1 Class A common units at a cost of $9.90 per Class A common unit and would pay commissions of $0.70 per Class A common unit for the 50,000 Class A common units and $0.60 per Class A common unit for the 50,505.1 Class A common units. The dealer manager fee of $0.30 per Class A common unit would still be payable out of the purchase price per Class A common unit. In no event will the proceeds to us be less than $9.00 per Class A common unit.

Orders for Class A common units may be combined for the purpose of determining the total commissions payable with respect to orders made by a “single purchaser,” so long as all the combined purchases are made through the same selling group participant. The amount of total commissions thus computed will be apportioned pro rata among the individual orders on the basis of the respective amounts of the orders being combined. As used in this offering, the term “single purchaser” will include:

 

    any person or entity, or persons or entities, acquiring common units as joint purchasers;

 

    all profit-sharing, pension and other retirement trusts maintained by a given corporation, partnership or other entity;

 

    all funds and foundations maintained by a given corporation, partnership or other entity;

 

    all profit-sharing, pension and other retirement trusts and all funds or foundations over which a designated bank or other trustee, person or entity exercises discretionary authority with respect to an investment in our Units; and

 

    any person or entity, or persons or entities, acquiring common units that are clients of and are advised by a single investment adviser registered under the Investment Advisers Act.

In the event a single purchaser described in the five categories above wishes to have its orders combined, that purchaser will be required to request the treatment in writing, which request must set forth the basis for the discount and identify the orders to be combined. Any request will be subject to our verification that all of the orders were made by a single purchaser.

Orders also may be combined for the purpose of determining the commissions payable in the case of orders by any purchaser described in any category above who, within 90 days of its initial purchase of Class A common units, orders additional Class A common units. In this event, the commission payable with respect to the subsequent purchase of Class A common units will equal the commission per Class A common units which would have been payable in accordance with the commission schedule set forth above if all purchases had been made simultaneously. Purchases subsequent to this 90 day period will not qualify to be combined for a volume discount as described herein.

Unless investors indicate that orders are to be combined and provide all other requested information, we will not be held responsible for failing to combine orders.

Purchases by entities not required to pay federal income tax may only be combined with purchases by other entities not required to pay federal income tax for purposes of computing amounts invested if the investment decisions are made by the same person. If the investment decisions are made by an independent investment advisor, that investment advisor may not have any direct or indirect beneficial interest in any of the entities not required to pay federal income tax whose purchases are sought to be combined. You must mark the “Additional Purchase” space on the subscription agreement signature page in order for purchases to be combined. We are not responsible for failing to combine purchases if you fail to mark the “Additional Purchase” space.

 

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If the subscription agreements for the purchases to be combined are submitted at the same time, then the additional Class A common units to be credited to you as a result of the combined purchases will be credited on a pro rata basis. If the subscription agreements for the purchases to be combined are not submitted at the same time, then any additional Class A common units to be credited as a result of the combined purchases will be credited to the last component purchase unless we are otherwise directed in writing at the time of the submission. However, the additional Class A common units to be credited to any entities not required to pay federal income tax whose purchases are combined for purposes of the volume discount will be credited only on a pro rata basis and the amounts of the investment of each entity not required to pay federal income tax on their combined purchases.

California residents should be aware that volume discounts will not be available in connection with the sale of common units to California residents to the extent the discounts do not comply with the provisions of Rule 260.140.51 adopted pursuant to the California Corporate Securities Law of 1968. Pursuant to this rule, volume discounts can be made available to California residents only in accordance with the following conditions:

 

    there can be no variance in the net proceeds to us from the sale of the common units to different purchasers of the same offering;

 

    all purchasers of the common units must be informed of the availability of quantity discounts;

 

    the same volume discounts must be allowed to all purchasers of common units which are part of the offering;

 

    the minimum amount of common units as to which volume discounts are allowed cannot be less than $10,000;

 

    the variance in the price of the common units must result solely from a different range of commissions, and all discounts must be based on a uniform scale of commissions; and

 

    no discounts are allowed to any group of purchasers.

Accordingly, volume discounts for California residents will be available in accordance with the foregoing table of uniform discount levels based on dollar volume of common units purchased, but no discounts are allowed to any group of purchasers, and no subscriptions may be aggregated as part of a combined order for purposes of determining the number of common units purchased.

Discount for Purchase of $5,000,000 or More

For purchases of $5,000,000 or more of either Class A common units or Class T common units, in our sole discretion, sales commissions may be reduced, and the dealer manager fee may be reduced from 3.00% of the purchase price but in no event will the proceeds to us be less than $9.00 per Unit. In the event of a sale of $5,000,000 or more with reduced sales commissions or a reduced dealer manager fee, we will supplement this prospectus to include: (a) the aggregate amount of the sale, (b) the price per Unit paid by the purchaser, and (c) a statement that other investors wishing to purchase at least the amount described in clause (a) above will pay no more per Unit than the purchaser described in clause (b) above.

Subscription Process

To purchase Units in this offering, you must complete and sign the subscription agreement in the form attached hereto as Exhibit C. You should pay for your common units by delivering a check for the full purchase price of the common units, payable to the applicable entity specified in the subscription agreement.

By executing the subscription agreement, you will attest, among other things, that you:

 

    have received the final prospectus;

 

    meet the minimum income and net worth requirements described in this prospectus;

 

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    are purchasing the common units for your own account; and

 

    acknowledge that there is no public market for our common units.

We include these representations in our subscription agreement in order to prevent persons who do not meet our suitability standards or other investment qualifications from subscribing to purchase our common units.

Subscriptions will be effective only upon our acceptance, and we reserve the right to reject any subscription in whole or in part. We may not accept a subscription for common units until at least five (5) business days after the date you receive the final prospectus. Subject to compliance with Rule 15c2-4 of the Exchange Act, our dealer manager and/or the participating broker-dealers will promptly submit a subscriber’s check on the business day following receipt of the subscriber’s subscription documents and check. In certain circumstances where the suitability review procedures are more lengthy than customary, a subscriber’s check will be promptly deposited in compliance with Exchange Act Rule 15c2-4. The proceeds from your subscription will be deposited in a segregated escrow account and will be held in trust for your benefit, pending our acceptance of your subscription.

A sale of the common units may not be completed until at least five (5) business days after the subscriber receives our final prospectus as filed with the SEC pursuant to Rule 424(b) of the Securities Act. Within 30 days of our receipt of each completed subscription agreement, we will accept or reject the subscription. If we accept the subscription, we will mail a confirmation within three days. If for any reason we reject the subscription, we will promptly return the check and the subscription agreement, without interest (unless we reject your subscription because we fail to achieve the minimum offering) or deduction, within ten business days after rejecting it.

Investments by IRAs and Certain Qualified Plans

We will appoint one or more IRA custodians for investors in our common units who desire to establish an IRA, simplified employee pension, or SEP or certain other tax-deferred accounts or transfer or rollover existing accounts. We will provide the name(s) of such IRA custodian(s) in a prospectus supplement. Our general partner may determine to pay the fees related to the establishment of investor accounts with such IRA custodian(s), and it also may pay the fees related to the maintenance of any such account for the first year following its establishment. Thereafter, we expect the IRA custodian(s) to provide this service to our unitholders with annual maintenance fees charged at a discounted rate. In the future, we may make similar arrangements for our investors with other custodians. Further information as to custodial services is available through your broker or may be requested from us.

Minimum Offering

Subscription proceeds will be placed in escrow until such time as subscriptions aggregating at least the minimum offering of $1.0 million of our common units have been received and accepted by us. Funds in escrow will be invested in short-term investments, which may include obligations of, or obligations guaranteed by, the U.S. government or bank money-market accounts or certificates of deposit of national or state banks that have deposits insured by the Federal Deposit Insurance Corporation (including certificates of deposit of any bank acting as a depository or custodian for any such funds) that can be readily sold, with appropriate safety of principal. Subscribers may not withdraw funds from the escrow account. Any Class A or Class T common units that are purchased by our sponsor, general partner, directors, officers or affiliates thereof will be included for purposes of determining whether we have satisfied this minimum investment amount.

If subscriptions for at least the minimum offering have not been received and accepted by                    , 2018, which is two years after the effective date of this offering, our escrow agent will promptly so notify us, this offering will be terminated and your funds and subscription agreement will be returned to you within ten (10) business days after the date of such termination. Interest will accrue on funds in the escrow account as applicable to the short-term investments in which such funds are invested. During any period in which

 

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subscription proceeds are held in escrow, interest earned thereon will be allocated among subscribers on the basis of the respective amounts of their subscriptions and the number of days that such amounts were on deposit. Such interest will be paid to subscribers upon the termination of the escrow period, subject to withholding for taxes pursuant to applicable Treasury Regulations. We will bear all expenses of the escrow and, as such, any interest to be paid to any subscriber will not be reduced for such expense.

ARP’s History in Connection with Liquidity Events

ARP, one of our affiliates, has over 30 years of experience in the oil and gas industry. The following discussion briefly summarizes whether ARP has offered prior programs in which ARP disclosed in the offering materials a date or time period at which the program might be liquidated, and whether the prior program in fact liquidated on or around that date or during that time period.

As disclosed in their respective offering documents, each prior partnership of ARP has a maximum term of 50 years before it is to be liquidated under its partnership agreement, except as set forth below:

 

Program

  

Maximum Term of Program

1. Atlas Energy Partners Limited (1986)

   December 31, 2025 (i.e., 39 years)

2. Atlas Energy Partners Limited 1987

   December 31, 2025 (i.e., 38 years)

3. Atlas Energy Partners Limited 1988

   December 31, 2028 (i.e., 40 years)

4. Atlas Energy Partners Limited 1989

   December 31, 2029 (i.e., 40 years)

5. Atlas Growth Partners, L.P. (Initial Offering)

   December 31, 2019 (i.e., 5 years)

No other date or time period at which any of ARP’s prior partnerships might be liquidated was disclosed in their respective offering documents.

Also, ARP sponsored each of its prior drilling partnerships with the intention to produce natural gas or oil from the partnership’s wells until such time as it became no longer economical for the partnership to continue to operate the wells, rather than selling the partnership’s productive wells during the term of the partnership. ARP anticipates that when each partnership’s wells become depleted, which means generally that the wells cannot produce enough natural gas and oil at the then current prices to economically justify the continued operation of the partnership and its wells, its wells will be sold, plugged and abandoned or otherwise disposed of, and the partnership will be liquidated.

 

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In this regard, ARP deemed the wells in the following partnerships to be uneconomical and it purchased all of the assets of each partnership on the dates shown in the table below and then liquidated the partnerships, which was before each partnership’s 50 year term was completed or, in the case of Atlas Energy Partners Limited 1989 and Atlas Energy Partners Limited 1988, before their respective maximum 40 year terms were completed, and Atlas Energy Partners Limited 1987, before its maximum 38 year term was completed.

 

Program

  

Program Termination Date

1. Atlas – Energy for the Nineties-1993 LTD.

   December 2, 2010

2. Atlas – Energy for the Nineties – Public #1 Ltd.

   December 2, 2013

3. Atlas – Energy for the Nineties – Public #2 Ltd.

   September 1, 2012

4. Atlas – Energy for the Nineties – Public #3 Ltd.

   December 2, 2013

5. Atlas – Energy for the Nineties – Public #4 Ltd.

   December 2, 2013

6. Atlas – Energy for the Nineties – Public #5 Ltd.

   December 2, 2013

7. Atlas – Energy for the Nineties – Public #7 Ltd.

   December 2, 2013

8. Atlas-Energy Partners 1991 L.P. (Series 11)

   October 1, 2012

9. Atlas – Energy for the Nineties – 1 L.P. (Series 12)

   October 1, 2012

10. Atlas – Energy For the Nineties – Series 14 Ltd.

   December 2, 2013

11. Atlas Energy Partners Limited 1989

   November 28, 2013

12. Atlas Energy Partners Limited 1993

   October 1, 2013

13. Atlas Energy Partners Limited 1995

   October 1, 2013

14. Atlas Energy Partners Limited 1999

   October 1, 2013

15. Atlas JV 92 Limited Partnership

   December 1, 2012

16. Atlas Energy Partners Limited 1988

   February 1, 2014

17. Atlas Energy Partners Limited 1987

   August 1, 2014

18. Atlas Energy Partners Limited 1992

   August 1, 2014

19. Atlas Energy Partners Limited 1998

   August 1, 2014

 

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HOW TO SUBSCRIBE

Investors who meet the suitability standards described in this prospectus may purchase common units. Please read “Suitability Standards” for the suitability standards. Investors who want to purchase common units should proceed as follows:

 

    Read the entire final prospectus and the current supplement(s), if any, accompanying the final prospectus.

 

    Complete the execution copy of the subscription agreement. A specimen copy of the subscription agreement, including instructions for completing it, is included as Exhibit C to this prospectus.

 

    Deliver a check to our dealer manager, or its designated agent, for the full purchase price of the common units being subscribed for, payable to “UMB Bank, N.A., escrow agent for Atlas Growth Partners, L.P.” along with the completed subscription agreement. The name of the participating broker-dealer must appear on the subscription agreement. Certain participating broker-dealers who have “net capital” as defined in the applicable federal securities regulations, of $250,000 or more may instruct their customers to make their checks payable directly to the participating broker-dealer. In such case, the participating broker-dealer will issue a check payable to us for the purchase price of your subscription.

 

    By executing the subscription agreement and paying the full purchase price for the common units subscribed for, each investor attests that he or she meets the minimum income and net worth standards as stated in “Suitability Standards” and accepts the terms of our Partnership Agreement.

A sale of the common units may not be completed until at least five business days after the subscriber receives our final prospectus as filed with the SEC pursuant to Rule 424(b) of the Securities Act. Within 30 days of our receipt of each completed subscription agreement, we will accept or reject the subscription. If we accept the subscription, we will mail a confirmation within three days. If for any reason we reject the subscription, we will promptly return the check and the subscription agreement, without interest (unless we reject your subscription because we fail to achieve the minimum offering) or deduction for any fees, within ten business days after rejecting it.

An approved trustee must process through and forward us subscriptions made through individual retirement accounts, Keogh plans and 401(k) plans. In the case of individual retirement accounts, Keogh plans and 401(k) plan stockholders, we will send the confirmation or, upon rejection, refund check to the trustee. If you want to purchase common units through an individual retirement account, Keogh plan or 401(k) plan, we intend to appoint one or more IRA custodians for such purpose, who we expect will provide this service to our unitholders with annual maintenance fees charged at a discounted rate.

You have the option of placing a transfer on death, or TOD, designation on your common units purchased in this offering. A TOD designation transfers the ownership of the common units to your designated beneficiary upon your death. This designation may only be made by individuals, not entities, who are the sole or joint owners with right to survivorship of the common units. This option, however, is not available to residents of Louisiana, Puerto Rico or Texas. If you would like to place a TOD designation on your common units, you must check the TOD box on the subscription agreement and you must complete and return the TOD form included as Exhibit G to this prospectus in order to effect the designation.

You may elect to have any registered investment advisory fees deducted from your account with us and paid directly to your registered investment advisor by completing and signing a letter of direction in the form attached as Exhibit H to this prospectus. The letter of direction will authorize us to deduct a specified dollar amount or percentage of distributions paid by us as business management and advisory fees payable to your registered investment advisor on a periodic basis. The letter of direction will be irrevocable and we will continue to pay business management and advisor fees payable from your account until such time as you provide us with a notice of revocation in the form of Exhibit I to this prospectus of your election to terminate deductions from your account for the purposes of such business management and advisor fees.

 

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SALES MATERIAL

In addition to this prospectus, we may use sales material in connection with the offering of the common units. In some jurisdictions, sales material may not be available. This material will include information relating to this offering, our general partner, ATLS and their respective affiliates, and may include brochures, articles, presentations for group meetings and publications about the oil and gas industry and oil and gas drilling partnerships.

All advertisements of, and oral or written invitations to seminars or other group meetings at which common units are to be described, offered or sold will clearly indicate that:

 

    the purpose of the meeting is to offer the common units for sale;

 

    the minimum purchase price of the common units;

 

    the suitability standards to be employed; and

 

    the name of the person selling the common units.

No cash, merchandise or other items of value shall be offered as an inducement to any prospective participants to attend any such meeting. All written or prepared audio-visual presentations, including scripts prepared in advance for oral presentations, to be made at such meetings must be filed with the appropriate regulatory agencies within the prescribed review period. The provisions of this paragraph shall not apply to meetings consisting only of representatives of broker-dealers.

The use of any sales materials is conditioned upon filing with, and if required, clearance by the appropriate regulatory agencies. Such clearance (if provided), however, does not indicate that the regulatory agency allowing the use of such materials has passed on the merits of the offering or the adequacy or accuracy of such materials. The offering of the common units, however, is made only by means of this prospectus and all sales material used must either be preceded by or accompanied with this prospectus. Although the information contained in the sales material does not conflict with any of the information contained in this prospectus, the material does not purport to be complete and should not be considered as a part of this prospectus or the registration statement of which the prospectus is a part, or as incorporated in this prospectus by reference or as forming the basis of this offering of the common units.

Statements made in sales material may not conflict with, or significantly modify, risk factors or other statements made in this prospectus. Sales materials must not be so excessive in size or amount as to detract from this prospectus, nor may any sales materials be used by broker-dealers unless the material has been approved by our general partner in writing and incorporates, if required, disclosure of the investor suitability standards.

 

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LEGAL OPINIONS

Paul Hastings LLP will opine on the validity of the issuance of the common units, Warrants to purchase additional common units and the common units issuable pursuant to the DRIP, and has provided us with an opinion on certain tax matters set forth under “Material Federal Income Tax Consequences.”

 

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EXPERTS

The audited consolidated financial statements of Atlas Growth Partners, L.P. included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

 

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ELECTRONIC DELIVERY OF DOCUMENTS

Subject to availability, you may authorize us to provide prospectuses, prospectus supplements, annual, quarterly and other reports, proxy statements, distribution notices and other information, or documents, electronically by so indicating on the subscription agreement, or by sending us instructions in writing in a form acceptable to us to receive such documents electronically. Unless otherwise provided in this prospectus or you elect in writing to receive documents electronically, all documents will be provided in paper form by mail. You must have internet access to use electronic delivery. While we impose no additional charge for this service, there may be potential costs associated with electronic delivery, such as on-line charges. Documents will be available on our website throughout the offering period. You may access and print all documents provided through this service. As documents become available, we will notify you of this by sending you an e-mail message that will include instructions on how to retrieve the document. If our e-mail notification is returned to us as “undeliverable,” we will contact you to obtain your updated e-mail address. If we are unable to obtain a valid e-mail address for you, we will resume sending a paper copy by regular U.S. mail to your address of record. You may revoke your consent for electronic delivery at any time and we will resume sending you a paper copy of all required documents. However, in order for us to be properly notified, your revocation must be given to us a reasonable time before electronic delivery has commenced. We will provide you with paper copies at any time on request. Such request will not constitute revocation of your consent to receive required documents electronically.

 

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WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules, and amendments to the registration statement) under the Securities Act, with respect to the common units and warrants offered by this prospectus. This prospectus does not contain all the information set forth in the registration statement. For further information with respect to us and our common units and warrants to be sold in this offering, we refer you to the registration statement. Statements contained in this prospectus as to the contents of any contract, agreement or other documents to which we make reference are not necessarily complete. In each instance, we refer you to the copy of such contract, agreement or other document filed as an exhibit to the registration statement.

Following this offering, we will be subject to the reporting and information requirements of the Securities Exchange Act of 1934, and, as a result, we file annual, quarterly and current reports, and other information with the SEC. You may read and copy this information at the Public Reference Room of the SEC located at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. Copies of all or any part of the registration statement may be obtained from the SEC’s offices upon payment of fees prescribed by the SEC. The SEC maintains an Internet site that contains periodic and current reports, information statements, and other information regarding issuers that file electronically with the SEC. The address of the SEC’s website is www.sec.gov.

We will provide a copy of our annual report to unitholders, including our audited financial statements, at no charge upon written request sent to Atlas Growth Partners, L.P., Park Place Corporate Center One, 1000 Commerce Drive, Suite 410, Pittsburgh, PA 15275. Our corporate website is located at www.atlasgrowthpartners.com. The information on, or that can be accessed through, our website is not incorporated by reference into this prospectus and should not be considered to be a part of this prospectus.

 

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GLOSSARY

/d—Per day.

Accumulated IDR Amount—An amount that the holder of the IDRs would have received had the Partnership, at the time of a listing event, instead sold its assets for cash in an amount equal to 1.0204 multiplied by the Initial Volume Weighted Average Price multiplied by the number of common units outstanding immediately prior to the listing event.

Actual IDR Amount—The amount of distributions made pursuant to the IDRs in the fiscal quarter for which the calculation is being made.

Additional Closing—A closing on the sale of common units in the offering following the initial closing pursuant to which investors are admitted as limited partners in the Partnership.

Anthem—Anthem Securities, Inc., the dealer manager for the offering.

APL—Atlas Pipeline Partners, L.P., an affiliate of Atlas Energy.

ARP—Atlas Resource Partners, L.P., an affiliate of Atlas Energy and our general partner.

Atlas Energy—Atlas Energy, L.P., the parent of our general partner before Atlas Energy’s merger with Targa Resources Corp.

Available Cash—Has the meaning set forth in “Summary of the Partnership Agreement—Quarterly Distributions of Available Cash.”

Basin—A large depression on the earth’s surface in which sediments accumulate.

Bbl—One barrel of crude oil, condensate or other liquid hydrocarbons equal to 42 United States gallons.

Bcf—One billion cubic feet of natural gas.

BOE—One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

Calculated IDR Amount—The amount of distributions the holder of the IDRs would have received in the fiscal quarter for which the calculation is being made from the Partnership’s net cash absent the effect of reserves established by our general partner and other related adjustments.

Capital Expenditures or Tangible Costs—Those costs associated with property acquisition and drilling and completing natural gas and oil wells that are generally accepted as capital expenditures under the Code. This includes all of the following: (a) costs of equipment, parts and items of hardware used in drilling and completing a well; (b) the costs (other than Intangible Drilling Costs and Lease acquisition costs) to re-enter and deepen an existing well, complete the well to deeper reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper reservoirs; and (c) those items necessary to deliver acceptable natural gas and oil production to purchasers to the extent installed downstream from the wellhead of any well and that are required to be capitalized under the Code and its regulations.

CERCLA—The Comprehensive Environmental Response, Compensation and Liability Act.

Code—The Internal Revenue Code of 1986, as amended.

 

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Completion—Completion of a well. The process by which a well is brought to its final classification—basically dry hole, producer, injector, or monitor well. A dry hole is normally plugged and abandoned. A well deemed to be producible of petroleum, or used as an injector, is completed by establishing a connection between the reservoir(s) and the surface so that fluids can be produced from, or injected into, the reservoir. Various methods are utilized to establish this connection, but they commonly involve the installation of some combination of borehole equipment, casing and tubing, and surface injection or production facilities.

CondensateCondensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Crude OilPetroleum that exists in the liquid phase in natural underground reservoirs and remains liquid at atmospheric conditions of pressure and temperature. Crude Oil may include small amounts of nonhydrocarbons produced with the liquids but does not include liquids obtained from the processing of natural gas.

Delaware Act—The Delaware Revised Uniform Limited Partnership Act.

Development Well—A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Developed AcreageThe number of acres which are allocated or assignable to producing wells or wells capable of production.

Dry hole or well—A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

EPA—United States Environmental Protection Agency.

ERISA—the Employee Retirement Income Security Act of 1974.

Exchange Act—The Securities Exchange Act of 1934, as amended.

Exploratory Well—An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.

Extension WellAn extension well is a well drilled to extend the limits of a known reservoir.

FarmoutAn agreement by the owner of the leasehold or Working Interest to assign his interest in certain acreage or well to the assignees, retaining some interest such as an Overriding Royalty Interest, an oil and gas payment, offset acreage or other type of interest, subject to the drilling of one or more specific wells or other performance as a condition of the assignment.

FERC—Federal Energy Regulatory Commission.

Field—An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

Formation—A sedimentary bed or series of beds sufficiently alike or distinctive to form an identifiable geological unit.

 

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GP unit—The units representing our general partner’s general partner interest in the Partnership, excluding Incentive Distribution Rights.

Infill Drilling—Wells drilled to fill in between established producing wells on a lease; a drilling program to reduce the spacing between wells in order to increase production from the lease.

Initial Volume Weighted Average Price—The volume weighted average price of the common units on the exchange on which they are traded for the five trading days following a listing event.

Investment Advisers Act—The Investment Advisers Act of 1940, as amended.

Investment Company Act—The Investment Company Act of 1940, as amended.

IRS—The United States Internal Revenue Service.

Lease—The instrument by which a leasehold or working interest is created in minerals.

Limited Partners—Investors who purchase common units and are admitted to the Partnership as limited partners.

Major Oil and Gas Company—An integrated oil and gas company that engages in exploration, production, transportation, refining and marketing; or one of the original “Seven Sisters” consisting originally of Exxon, British Petroleum, Chevron, Gulf, Mobil, Texaco and Royal Dutch Shell.

MBbl—One thousand barrels of crude oil, condensate or other liquid hydrocarbons.

Mcf—One thousand cubic feet of natural gas; the standard unit for measuring volumes of natural gas.

Mcfe—Mcf of natural gas equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMBbl—One million barrels of crude oil, condensate or other liquid hydrocarbons.

MMBOE—One million BOE.

MMcf—One million cubic feet of natural gas.

MMcfe—MMcf of natural gas equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Maximum Offering Amount—The maximum dollar amount to be raised in the offering, which is $1.0 billion.

Minimum Offering Amount—The minimum dollar amount to be raised in the offering, which is $1.0 million. If the minimum offering amount is not obtained before the offering terminates, investor funds held in escrow will be promptly returned to investors, with interest.

MLP—A master limited partnership.

Natural Gas—Natural Gas is the portion of petroleum that exists either in the gaseous phase or is in solution in crude oil in natural underground reservoirs, and which is gaseous at atmospheric conditions of pressure and temperature. Natural Gas may include some amount of nonhydrocarbons.

Natural Gas Liquids or NGLs—A mixture of light hydrocarbons that exist in the gaseous phase at reservoir conditions but are recovered as liquids in gas processing plants. NGL differs from condensate in two principal respects: (1) NGL is extracted and recovered in gas plants rather than lease separators or other lease facilities; and (2) NGL includes very light hydrocarbons (ethane, propane, butanes) as well as the pentanes-plus (the main constituent of condensates).

 

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NEPA—National Environmental Policy Act.

Net Profits Interest—An interest in an oil and natural gas property entitling the owner to a share of the gross revenues from oil and natural gas production less all operating, production, development, transportation, transmission and marketing expenses, as well as production, sales and ad valorem taxes attributable to such production. It does not include any rights to explore for, develop or produce oil and gas from the lands subject to the interest.

Non-operator—Subject to all cases of drilling, completing and operating a well, the working-interest owner or owners other than the one designated as operator of the property; a “silent” working-interest owner.

Non-Capital Expenditures or Intangible Drilling Costs—Means those expenditures associated with property acquisition and the drilling and completion of natural gas and oil wells that under present law are generally accepted as fully deductible currently for federal income tax purposes. This includes: all expenditures made for any well before production in commercial quantities for wages, fuel, repairs, hauling, supplies and other costs and expenses incident to and necessary for drilling the well and preparing the well for production of natural gas or oil, that are currently deductible pursuant to Section 263(c) of the Code and Treasury Reg. Section 1.612-4, and are generally termed “intangible drilling and development costs.”

NYMEX—New York Mercantile Exchange.

NYSE—New York Stock Exchange.

Offering—The offering of the common units and warrants pursuant to the registration statement.

Offset Well—(1) A well drilled on the next location to the original well, in which the distance from the first well to the offset well depends upon spacing regulations and whether the original well produces oil or gas; or (2) a well drilled on one tract of land to prevent the drainage of oil or gas to an adjoining tract where a well is being drilled or is already producing.

Oil—Crude oil and condensate.

Operator—The individual or company responsible for the exploration, development and production of an oil or gas well or lease.

Operating Costs—The cost of operating a producing well or a group of producing properties.

OSHA—The Occupational Safety and Health Act.

Partnership—Atlas Growth Partners, L.P.

Partnership Agreement—The First Amended and Restated Agreement of Limited Partnership of the Partnership annexed to the prospectus as Exhibit A and the Second Amended and Restated Agreement of Limited Partnership of the Partnership annexed as an exhibit thereto; provided, however, that with respect to a discussion herein comparing the respective agreements, “Partnership Agreement” shall refer to the First Amended and Restated Agreement of Limited Partnership.

Pipeline—A tubular system, usually made of steel pipe with welded connections, used to transport oil, gas and other fluids.

Post-Listing Partnership Agreement—the Second Amended and Restated Agreement of Limited Partnership of the Partnership that will become effective upon a listing event, a copy of which is included as Exhibit B.

 

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Producing (Productive) Well or Property—A well that is found to be capable of producing hydrocarbons in sufficient quantities such that the proceeds from the sale of such production exceed production expenses and taxes.

Production—(1) The removal of hydrocarbons from a subsurface reservoir by wells; (2) oil or natural gas produced from wells; or (3) the part of the petroleum industry that is concerned with bringing oil and natural gas to the surface and separating, gauging, storing and preparing it for transport. Production is the cumulative quantity of petroleum that has been actually recovered over a defined time period. While all recoverable resource estimates and production are reported in terms of the sales product specifications, raw production quantities (sales and nonsales, including nonhydrocarbons) are also measured to support engineering analyses requiring reservoir voidage calculations.

Project—Natural gas and oil properties and the wells drilled or to be drilled thereon. A project represents the link between the petroleum accumulation and the decision-making process, including budget allocation. A project may, for example, constitute the development of a single reservoir or field, or an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership. In general, an individual project will represent a specific maturity level at which a decision is made on whether or not to proceed (i.e., spend money), and there should be an associated range of estimated recoverable resources for that project.

Proved Developed Producing Reserves or PDP—Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved Reserves—Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

  (i) The area of the reservoir considered as proved includes:

 

  (a) The area identified by drilling and limited by fluid contacts, if any, and

 

  (b) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

  (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

  (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

  (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

 

  (a) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

 

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  (b) The project has been approved for development by all necessary parties and entities, including governmental entities.

 

  (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved Undeveloped Reserves or PUDs—Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Proved Undeveloped Location—A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

RCRA—The Resource Conservation and Recovery Act.

Recompletion—The completion for production of an existing well bore in another formation from that in which the well has been previously completed.

Reserves—Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir—A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Reservoir Engineering—The application of scientific and engineering principles to the production from a developed reservoir for maximum economic return. Reservoir engineering is the “art of development and production for high-economic recovery.”

Royalty Interest—An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

 

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Sarbanes-Oxley Act—The Sarbanes Oxley Act of 2002.

Securities Act—The Securities Act of 1933, as amended.

Seismic—The use of shock waves generated by controlled explosions of dynamite or other means to ascertain the nature and contour of underground geological structures.

Service WellA well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

Stratigraphic test wellA stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

Standardized Measure of Discounted Future Net Cash Flows—The estimated future net cash flows from proved oil and natural gas reserves computed using prices and costs, at the date indicated, after income taxes and discounted at 10.00%.

Undeveloped Acreage—Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains proved reserves.

Unproved ReservesUnproved Reserves are based on geoscience and/or engineering data similar to that used in estimates of Proved Reserves, but technical or other uncertainties preclude such reserves being classified as Proved. Unproved Reserves may be further categorized as Probable Reserves and Possible Reserves.

Warrant—A security allowing a holder to purchase one common unit upon the occurrence of a liquidity event.

Working Interest—An operating interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and the responsibility to pay royalties and a share of the costs of drilling and production operations under the applicable fiscal terms. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. For example, the owner of a 100.00% working interest in a lease burdened only by a landowner’s royalty of 12.50% would be required to pay 100.00% of the costs of a well but would be entitled to retain 87.50% of the production.

Workover—Operations on a producing well to restore or increase production. Tubing is pulled and the casing at the bottom of the well is pumped or washed free of sand that may have accumulated.

 

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INDEX TO FINANCIAL STATEMENTS

Audited Financial Statements for Periods ended December 31, 2014 and December 31, 2013

 

Report of Independent Registered Public Accounting Firm

     F-2   

Consolidated Balance Sheets

     F-3   

Consolidated Statements of Operations

     F-4   

Consolidated Statement of Partners’ Capital

     F-5   

Consolidated Statements of Cash Flows

     F-6   

Notes to Consolidated Financial Statements

     F-7   

Unaudited Financial Statements for Nine Months Ended September 30, 2015 and 2014

 

Consolidated Balance Sheets

    F-24   

Consolidated Statements of Operations for nine months ended September 30, 2015 and September  30, 2014

    F-25   

Consolidated Statement of Partners’ Capital

    F-26   

Consolidated Statements of Cash Flows for nine months ended September 30, 2015 and September  30, 2014

    F-27   

Notes to Consolidated Financial Statements

    F-28   

 

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Audited Financial Statements for Years ended December 31, 2014 and December 31, 2013

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Atlas Growth Partners, L.P.

We have audited the accompanying consolidated balance sheets of Atlas Growth Partners, L.P. (a Delaware limited partnership) and subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, changes in partners’ capital, and cash flows for the year ended December 31, 2014 and for the period February 11, 2013 (inception) to December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Atlas Growth Partners, L.P. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for the year ended December 31, 2014 and the period February 11, 2013 (inception) to December 31, 2013 in conformity with accounting principles generally accepted in the United States of America.

GRANT THORNTON LLP

/s/ GRANT THORNTON LLP

Cleveland, Ohio

October 20, 2015

 

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ATLAS GROWTH PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands)

 

     December 31,  
     2014     2013  

ASSETS

    

Current assets:

    

Cash and cash equivalents

   $ 33,405      $ 8,759   

Accounts receivable

     764        289   

Prepaid expenses

     437        —     
  

 

 

   

 

 

 

Total current assets

     34,606        9,048   

Property, plant and equipment, net

     155,469        3,913   

Other assets, net

     86        —     
  

 

 

   

 

 

 
   $ 190,161      $ 12,961   
  

 

 

   

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

    

Current liabilities:

    

Accounts payable

   $ 596      $ 754   

Deferred capital contributions

     11,749        —     

Advances from affiliates

     16,500        7,139   

Accrued well drilling and completion costs

     12,506        418   

Deferred acquisition purchase price

     80,789        —     

Accrued liabilities

     360        52   
  

 

 

   

 

 

 

Total current liabilities

     122,500        8,363   

Asset retirement obligations

     151        35   

Commitments and contingencies

    

Partners’ Capital:

    

General partner’s interest

     (446     (72

Common limited partners’ interests

     66,676        4,499   

Common limited partners’ warrants

     1,280        136   
  

 

 

   

 

 

 

Total partners’ capital

     67,510        4,563   
  

 

 

   

 

 

 
   $ 190,161      $ 12,961   
  

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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ATLAS GROWTH PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

 

    

Periods Ended

December 31,

 
     2014     2013
(Note 2)
 

Revenues:

    

Gas and oil production

   $ 5,707      $ 302   
  

 

 

   

 

 

 

Total revenues

     5,707        302   
  

 

 

   

 

 

 

Costs and expenses:

    

Gas and oil production

     2,070        80   

General and administrative

     627        211   

General and administrative – affiliate

     11,119        3,521   

Depreciation, depletion and amortization

     2,156        133   

Asset impairment

     6,880        —     
  

 

 

   

 

 

 

Total costs and expenses

     22,852        3,945   
  

 

 

   

 

 

 

Net loss

   $ (17,145   $ (3,643
  

 

 

   

 

 

 

Allocation of net loss attributable to common limited partners and the general partner:

    

Common limited partners’ interest

   $ (16,802   $ (3,570

General partner’s interest

     (343     (73
  

 

 

   

 

 

 

Net loss attributable to common limited partners and the general partner

   $ (17,145   $ (3,643
  

 

 

   

 

 

 

Net loss attributable to common limited partners per unit:

    

Basic and Diluted

   $ (3.85   $ (9.25
  

 

 

   

 

 

 

Weighted average common limited partner units outstanding:

    

Basic and Diluted

     4,364        386   
  

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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ATLAS GROWTH PARTNERS, L.P.

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in thousands, except unit data)

 

     General
Partner’s Interest
    Common Limited
Partners’ Interests
    Common Limited
Partners’ Warrants
     Total
Partners’
Capital
 
     Class A
Units
     Amount     Units      Amount     Warrants      Amount     

Balance at February 11, 2013 (inception)

     —         $ —          —         $ —          —         $ —         $ —     

Issuance of units, net of offering costs

     100         1        1,095,010         8,069        109,501         136         8,206   

Net loss

     —           (73     —           (3,570     —           —           (3,643
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Balance at December 31, 2013

     100       $ (72     1,095,010       $ 4,499        109,501       $ 136       $ 4,563   

Issuance of units, net of offering costs

     —           —          9,581,900         80,505        958,190         1,144         81,649   

Distributions paid

     —           (31     —           (1,526     —           —           (1,557

Net loss

     —           (343     —           (16,802     —           —           (17,145
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Balance at December 31, 2014

     100       $ (446     10,676,910       $ 66,676        1,067,691       $ 1,280       $ 67,510   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

See accompanying notes to consolidated financial statements.

 

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ATLAS GROWTH PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

 

     Periods Ended
December 31,
 
     2014     2013
(Note 2)
 

CASH FLOWS FROM OPERATING ACTIVITIES:

    

Net loss

   $ (17,145   $ (3,643

Adjustments to reconcile net loss to net cash provided by operating activities:

    

Depreciation, depletion and amortization

     2,156        133   

Asset impairment

     6,880        —     

Changes in operating assets and liabilities:

    

Accounts receivable, prepaid expenses and other

     (912     (289

Advances from affiliates

     9,361        7,139   

Accounts payable and accrued liabilities

     171        807   
  

 

 

   

 

 

 

Net cash provided by operating activities

     511        4,147   
  

 

 

   

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

    

Capital expenditures

     (12,873     (3,594

Net cash paid for acquisitions

     (54,746     —     
  

 

 

   

 

 

 

Net cash used in investing activities

     (67,619     (3,594
  

 

 

   

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

    

Net proceeds from issuance of common limited partner units and warrants

     81,649        8,206   

Deferred capital contributions

     11,749        —     

Distributions paid to unitholders

     (1,557     —     

Other

     (87     —     
  

 

 

   

 

 

 

Net cash provided by financing activities

     91,754        8,206   
  

 

 

   

 

 

 

Net change in cash and cash equivalents

     24,646        8,759   

Cash and cash equivalents, beginning of year

     8,759        —     
  

 

 

   

 

 

 

Cash and cash equivalents, end of year

   $ 33,405      $ 8,759   
  

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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ATLAS GROWTH PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014 and 2013

NOTE 1 – BASIS OF PRESENTATION

Atlas Growth Partners, L.P. (the “Partnership”) is a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”) with operations primarily focused in the Eagle Ford Shale in south Texas. At December 31, 2014, the Partnership’s general partner, Atlas Growth Partners GP, LLC (“AGP GP”) owned 100% of the general partner Class A units and all of the incentive distribution rights through which it manages and effectively controls the Partnership. At December 31, 2014, Atlas Energy, L.P. (“ATLS” or “Atlas Energy”), a publicly traded master limited partnership (NYSE: ATLS), owned a 1.9% limited partner interest in the Partnership and 80% of AGP GP’s general partner Class A units, which are entitled to receive 2% of the cash distributed without any obligation to make further capital contributions (see Note 11).

The Partnership was formed on February 11, 2013 to acquire undeveloped oil and gas properties and, subsequently, drill developmental wells on those properties. To date, the Partnership has funded its operations through the private placement of its common limited partner units at a purchase price of $10.00 per unit (the “Private Placement Offering”). Subscriptions, offered at a minimum investment of $25,000 and in $1,000 increments thereafter, are generally sold using wholesalers and through broker-dealers including Anthem Securities, Inc., an affiliated company, which receive a 3% dealer-manager fee, a 7% sales commission and a 2% direct issue cost, respectively.

Unless a listing event occurs before then, the Partnership will have a term of 10 years from June 30, 2015, or until June 30, 2025, subject to two one-year extensions in the sole discretion of its general partner.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The Partnership’s consolidated balance sheets at December 31, 2014 and 2013, and the consolidated statements of operations for the year ended December 31, 2014 and the period February 11, 2013 (inception) to December 31, 2013 include the accounts of the Partnership and its wholly-owned subsidiaries. Transactions between the Partnership and other ATLS operations have been identified in the consolidated financial statements as transactions between affiliates, where applicable. All material intercompany transactions have been eliminated.

Use of Estimates

The preparation of the Partnership’s consolidated financial statements in conformity with accounting principles generally accepted in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, and the probability of forecasted transactions. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the periods ended December 31, 2014 and 2013 represent actual results in all material respects (see “Revenue Recognition”).

 

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Cash Equivalents

The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.

Receivables

Accounts receivable on the consolidated balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the Partnership’s management performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of customers’ credit information. The Partnership extends credit on sales on an unsecured basis to many of its customers. At December 31, 2014 and 2013, the Partnership had recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements which generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Partnership’s results of operations.

The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and NGLs are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to six Mcf of natural gas. Mcf is defined as one thousand cubic feet.

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include the Partnership’s costs of property interests in proportionately consolidated joint venture wells, wells drilled solely by the Partnership for its interests, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Partnership’s consolidated statement of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its consolidated balance sheet. Upon the Partnership’s sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Partnership’s consolidated statement of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

 

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Impairment of Long-Lived Assets

The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. Reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate the Partnership will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. There were no impairments of unproved oil and gas properties for the years ended December 31, 2014 and 2013.

Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2014, the Partnership recognized $6.9 million of asset impairment related to oil and gas properties within the accompanying consolidated financial statements resulting from the decline in forward commodity prices during the fourth quarter of 2014 through the impairment testing date in January 2015. This impairment related to the carrying amounts of the gas and oil properties being in excess of the Partnership’s estimate of their fair values at December 31, 2014. There were no impairments of proved oil and gas properties for the period ended December 31, 2013.

Deferred Capital Contribution

The Partnership recognizes a current liability related to capital contributions received from limited partners prior to the issuance of the respective limited partner units. As prescribed by the Partnership Agreement, limited partner units are issued to investors on the first day of the month following the capital contribution.

Asset Retirement Obligations

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 5). The Partnership recognizes a liability for its future asset retirement obligations

 

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in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depreciation, depletion and amortization.

Environmental Matters

The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures. The Partnership had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2014 and 2013.

Concentration of Credit Risk

Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership places its temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At December 31, 2014 and 2013, the Partnership had $33.5 million and $8.8 million, respectively, in deposits at various banks, of which $33.2 million and $8.5 million, respectively, was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date. Cash on deposit at various banks may differ from the balance of cash and cash equivalents at period end due to certain reconciling items, including any outstanding checks as of period end.

The Partnership sells natural gas, crude oil and natural gas liquids under contracts to purchasers in the normal course of business. For each of the periods ended December 31, 2014 and 2013, the Partnership had two customers that accounted for all of its natural gas, oil and natural gas liquids consolidated revenues and related accounts receivable.

Revenue Recognition

The Partnership generally sells natural gas, crude oil and NGLs at prevailing market prices. Typically, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibilities of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” for further description). The Partnership had unbilled revenues of $0.8 million and $0.3 million at December 31, 2014 and 2013, respectively, which were included in accounts receivable within the Partnership’s consolidated balance sheets.

 

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Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of the general partner’s interest, by the weighted average number of common limited partner units outstanding during the period. The general partner’s interest in net income (loss) is calculated on a quarterly basis based upon its GP units and incentive distributions to be distributed for the quarter (see Note 10), with a priority allocation of net income to the general partner’s incentive distributions, if any, in accordance with the Partnership Agreement, and the remaining net income (loss) allocated with respect to the general partner’s and limited partners’ ownership interests.

The Partnership presents net income (loss) per unit under the two-class method for master limited partnerships, which considers whether the incentive distributions of a master limited partnership represent a participating security when considered in the calculation of earnings per unit under the two-class method. The two-class method considers whether the Partnership Agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the Partnership Agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, management of the Partnership believes the Partnership Agreement contractually limits cash distributions to available cash; therefore, undistributed earnings are not allocated to the incentive distribution rights.

The following is a reconciliation of net loss allocated to the common limited partners for purposes of calculating net loss attributable to common limited partners per unit (in thousands, except unit data):

 

     Periods Ended
December 31,
 
     2014      2013  

Net loss

   $ (17,145    $ (3,643

Less: General partner’s interest

     (343      (73
  

 

 

    

 

 

 

Net loss attributable to common limited partners(1)

   $ (16,802    $ (3,570
  

 

 

    

 

 

 

 

(1)  For the periods ended December 31, 2014 and 2013, approximately 1,067,000 and 110,000 common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of units issuable upon exercise of the warrants would have been anti-dilutive.

Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of common limited partner warrants, as calculated by the treasury stock method (see Note 9).

The following table sets forth the reconciliation of the Partnership’s weighted average number of common units used to compute basic net income (loss) attributable to common unit holders per unit with those used to compute diluted net income (loss) attributable to common unit holders per unit (in thousands):

 

     Periods Ended
December 31,
 
     2014      2013  

Weighted average number of common units – basic

     4,364         386   

Add effect of dilutive warrants(1)

     —           —     
  

 

 

    

 

 

 

Weighted average number of common units – diluted

     4,364         386   
  

 

 

    

 

 

 

 

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(1) For the periods ended December 31, 2014 and 2013, approximately 1,067,000 and 110,000 common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of units issuable upon exercise of the warrants would have been anti-dilutive.

Segment Reporting

The Partnership derives revenue from its gas and oil production. These facilities have been aggregated into one reportable segment because the facilities have similar long-term economic characteristics, products and types of customers.

Income Taxes

The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the accompanying consolidated financial statements. Accordingly, no federal or state current or deferred income tax has been provided for in the accompanying consolidated financial statements.

The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its consolidated financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Partnership has not recognized any potential interest or penalties in its consolidated financial statements for the periods ended December 31, 2014 and 2013.

The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. The Partnership is not subject to income tax examinations by major tax authorities for years prior to 2013, its year of formation. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2014.

Recently Issued Accounting Standards

In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (“Update 2015-06”). Under Topic 260, Earnings per Share, master limited partnerships (“MLPs”) apply the two-class method to calculate earnings per unit (“EPU”) because the general partner, limited partners, and incentive distribution rights holders each participate differently in the distribution of available cash. When a general partner transfers (or “drops down”) net assets to a master limited partnership and that transaction is accounted for as a transaction between entities under common control, the statements of operations of the master limited partnership are adjusted retrospectively to reflect the drop down transaction as if it occurred on the earliest date during which the entities were under common control. The amendments in Update 2015-06 specify that for purposes of calculating historical EPU under the two-class method, the earnings (losses) of a transferred business before the date of a drop down transaction should be allocated entirely to the general partner interest, and previously reported EPU of the limited partners would not change as a result of a drop down transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the drop down transaction occurs also are required. The amendments in Update 2015-06 are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted and amendments in Update 2015-06 should be applied retrospectively for all financial statements presented. The Partnership will adopt the requirements of Update 2015-06 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

 

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In March 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30) (“Update 2015-03”). The amendments in Update 2015-03 are intended to simplify presentation of debt issuance costs and require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs would not be affected by the amendments in Update 2015-03. The amendments in Update 2015-03 are effective for periods beginning after December 15, 2015, and interim periods within those periods. Early adoption is permitted, including adoption in an interim period, and an entity should apply the new guidance on a retrospective basis. The Partnership will adopt the requirements of Update 2015-03 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“Update 2015-02”). The amendments in Update 2015-02 are intended to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures. The amendments simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The amendments in Update 2015-02 are effective for periods beginning after December 31, 2015. Early adoption is permitted, including adoption in an interim period. The Partnership will adopt the requirements of Update 2015-02 upon its effective date of January 1, 2016, and is evaluating the impact of adoption on its financial position, results of operations or related disclosures.

In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. Eliminating the extraordinary classification simplifies income statement presentation by altogether removing the concept of extraordinary items from consideration. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The Partnership will adopt the requirements of Update 2015-01 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In June 2014, the FASB issued ASU 2014-12, Compensation – Stock Compensation (Topic 718) (“Update 2014-12”). The amendments in Update 2014-12 require that a performance target that affects vesting and that could be achieved after the requisite service period, be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be

 

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achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in Update 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. The Partnership will adopt the requirements of Update 2014-12 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is not permitted. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2018, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

NOTE 3 – ACQUISITION

On November 5, 2014, the Partnership and Atlas Resource Partners, L.P. (“ARP”), an entity related through common ownership and management by ATLS, completed an acquisition of oil and natural gas liquid interests in the Eagle Ford Shale in Atascosa County, Texas from Cima Resources, LLC and Cinco Resources, Inc. (together “Cinco”) for $343.0 million, net of purchase price adjustments (the “Eagle Ford Acquisition”). Approximately $183.1 million was paid in cash by ARP and $19.9 million was paid by the Partnership at closing, and approximately $140.0 million will be paid over the four quarters following closing. The deferred portion of the purchase price represents a non-cash transaction for statement of cash flow purposes during the year ended December 31, 2014. ARP will pay approximately $24.2 million of the deferred portion of the purchase price in three quarterly installments beginning March 31, 2015 (see Note 11). The Partnership paid $35.0 million of the deferred acquisition purchase price at December 31, 2014 and will pay the remaining deferred acquisition purchase price of $80.8 million in three quarterly installments in 2015. The Eagle Ford Acquisition had an effective date of July 1, 2014. The Partnership accounted for its acquisition of non-producing leasehold acreage as an acquisition of assets. At December 31, 2014, the fair value studies related to the assets acquired were not yet complete, therefore the assignment of cost to the proved and unproved assets acquired is subject to change in 2015.

 

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NOTE 4 – PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment at the date indicated (in thousands):

 

     December 31,  
     2014      2013  

Natural gas and oil properties:

     

Proved properties:

     

Leasehold interests

   $ 13,853       $ 1,758   

Pre-development costs

     155         —     

Wells and related equipment

     56,012         2,288   
  

 

 

    

 

 

 

Total proved properties

     70,020         4,046   

Unproved properties

     94,626         —     

Support equipment

     —           —     
  

 

 

    

 

 

 

Total natural gas and oil properties

     164,646         4,046   

Less – accumulated depreciation, depletion and amortization

     (9,177      (133
  

 

 

    

 

 

 
   $ 155,469       $ 3,913   
  

 

 

    

 

 

 

During the year ended December 31, 2014, the Partnership recognized $6.9 million of asset impairment related to oil and gas properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet resulting from the decline in forward commodity prices during the fourth quarter of 2014. This impairment related to the carrying amounts of the gas and oil properties being in excess of the Partnership’s estimate of their fair values at December 31, 2014. No asset impairment related to oil and gas properties was recognized for the year ended December 31, 2013.

NOTE 5 – ASSET RETIREMENT OBLIGATIONS

The Partnership recognized an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities. The Partnership also recognized a liability for its future asset retirement obligations where a reasonable estimate of the fair value of that liability could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability for asset retirement obligations was based on the Partnership’s historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its gas and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets.

 

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A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):

 

     Periods Ending
December 31,
 
     2014      2013  

Asset retirement obligations, beginning of year

   $ 35       $ —     

Liabilities incurred

     165         35   

Liabilities settled

     —           —     

Accretion expense

     12         —     

Revisions

     (61      —     
  

 

 

    

 

 

 

Asset retirement obligations, end of year

   $ 151       $ 35   
  

 

 

    

 

 

 

The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated statements of operations.

NOTE 6 – COMMITMENTS AND CONTINGENCIES

As of December 31, 2014, certain of the Partnership’s executives are parties to employment agreements with ATLS that provide compensation and certain other benefits. The agreements provided for severance payments under certain circumstances. On February 27, 2015, in connection with ATLS’s merger with Targa Resources Corp (see Note 11), the employment agreements were terminated.

As of December 31, 2014, the Partnership did not have any commitments for drilling and completion expenditures.

Legal Proceedings

The Partnership and its subsidiaries are parties to various routine legal proceedings arising out of the ordinary course of its business. Management of the Partnership and its subsidiaries believe that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.

NOTE 7 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

In the ordinary course of its business operations, the Partnership has ongoing relationships with several related entities:

Relationship with ATLS. The Partnership does not directly employ any persons to manage or operate its business. These functions are provided by employees of ATLS and/or its affiliates. AGP GP, the Partnership’s general partner, receives an annual management fee in connection with its management of the Partnership equivalent to 1% of capital contributions per annum. During the year ended December 31, 2014, the Partnership paid approximately $0.3 million related to this management fee. The Partnership did not pay a management fee for the period ended December 31, 2013. Other indirect costs, such as rent for offices, are allocated to the Partnership by ATLS based on the number of its employees who devoted substantially all of their time to activities on its behalf. The Partnership reimburses ATLS at cost for direct costs incurred on its behalf. The Partnership’s Partnership Agreement provides that its general partner will determine the costs and expenses that are allocable to the Partnership at its sole discretion, and does not set any aggregate limit on the amount of such reimbursements. The Partnership is required to pay AGP GP, the Partnership’s general partner, an amount equal to any actual, out-of-pocket expenses related to the Private Placement Offering and the formation and financing of the Partnership, including legal costs incurred by AGP GP, which payments are anticipated to be approximately 1% of the gross

 

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proceeds of the Private Placement Offering and in any event will not exceed 2% of the gross proceeds of the Private Placement Offering. All of the costs paid or payable to ATLS discussed above were included in general and administrative expenses – affiliate in the accompanying consolidated statement of operations for the year ended December 31, 2014.

Relationship with Anthem Securities, Inc. Anthem Securities, Inc. (“Anthem”), an affiliate of AGP GP, the Partnership’s general partner, is acting as dealer manager for the Private Placement Offering. For acting as the dealer manager, Anthem receives compensation from the Partnership equal to a maximum of 12% of the gross proceeds of the Private Placement Offering as selling commissions, marketing efforts, and other issuance costs. The Partnership includes these costs within common limited partners’ interests on the Partnership’s consolidated statement of partners’ capital for the periods ended December 31, 2014 and 2013, and such costs aggregated to $14.0 million and $1.9 million in each respective period.

Relationship with ARP. In connection with the Eagle Ford Acquisition (see Note 3), ARP, a publicly-traded Delaware master limited partnership (NYSE: ARP) managed by ATLS, guaranteed the timely payment of the deferred portion of the purchase price that is to be paid by the Partnership. Pursuant to the agreement between ARP and the Partnership, ARP will have the right to receive some or all of the assets acquired by the Partnership in the event of the Partnership’s failure to contribute its portion of any deferred payments (see Note 11).

NOTE 8 – FAIR VALUE OF FINANCIAL INSTRUMENTS

Management has established a hierarchy to measure the Partnership’s financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources, whereas, unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1 – Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Financial Instruments

The Partnership’s other current assets and liabilities on its consolidated balance sheet are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

Management estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates.

 

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Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the years ended December 31, 2014 and 2013 were as follows (in thousands):

 

     Periods Ended December 31,  
     2014      2013  
     Level 3      Total      Level 3      Total  

Asset retirement obligations

   $ 165       $ 165       $ 35       $ 35   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 165       $ 165       $ 35       $ 35   
  

 

 

    

 

 

    

 

 

    

 

 

 

Management estimates the fair value of the Partnership’s long-lived assets in connection with reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances. For the year ended December 31, 2014, the Partnership recognized $6.9 million of impairment of long-lived assets which were defined as Level 3 fair value measurements (see Note 2 – Impairment of Long-Lived Assets). No impairment of long-lived assets was recognized for the period ended December 31, 2013.

The fair value of the warrants associated with the issuance of common limited partner units (see Note 9) was measured using a Black-Scholes pricing model which is based on Level 3 inputs including a contractual exercise price of $10.00, discount rate of 0.3%, an expected term of 1 year, expected dividend yield of 7.0% and estimated volatility rate of 45%. The volatility rate used is consistent with that of ARP. The estimated fair value per warrant was $1.20, which includes a $0.21 liquidity adjustment.

NOTE 9 – ISSUANCES OF UNITS

Under the terms of the Partnership’s initial offering, the Partnership is offering in a private placement $500.0 million of its common limited partner units. The termination date of the Private Placement offering was December 31, 2014, subject to two 90 day extensions, the second of which expired on June 30, 2015. The Partnership agreed to exercise each of such extensions to the extent that it has not sold $500.0 million of common units at any extension date. Under the terms of the offering, an investor receives, for no additional consideration, warrants to purchase additional common units in an amount equal to 10% of the common units purchased by such investor. The warrants are exercisable at a price of $10.00 per common unit being purchased and may be exercised from and after the Warrant Date (generally, the date upon which the Partnership gives the holder notice of a Liquidity Event) until the Expiration Date (generally, the date that is one day prior to the Liquidity Event or, if the Liquidity Event is a listing on a national securities exchange, 30 days after the Liquidity Event occurs). Under the warrant, a Liquidity Event is defined as either (i) a listing of the common units on a national securities exchange, (ii) a business combination with or into an existing publicly-traded entity, or (iii) a sale of all or substantially all of the Partnership’s assets.

During the year ended December 31, 2014, the Partnership sold an aggregate of 9,581,900 of its common limited partner units at a gross offering price of $10.00 per unit. In connection with the issuance of common limited partner units, unitholders received 958,190 warrants to purchase the Partnership’s common limited partner units at an exercise price of $10.00 per unit.

During the period ended December 31, 2013, the Partnership sold an aggregate of 1,095,010 of its common limited partner units at a gross offering price of $10.00 per unit. In connection with the issuance of common limited partner units, unitholders received 109,501 warrants to purchase the Partnership’s common limited partner units at an exercise price of $10.00 per unit.

NOTE 10 – CASH DISTRIBUTIONS

The Partnership has a cash distribution policy under which it distributes to holders of common units and Class A units on a quarterly basis a target distribution of $0.175 per unit, or $0.70 per unit per year, to the extent

 

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the Partnership has sufficient available cash after establishing appropriate reserves and paying fees and expenses, including reimbursements of expenses to the general partner and its affiliates. Distributions are generally paid within 45 days of the end of the quarter to unitholders of record on the applicable record date. Unitholders are entitled to receive distributions beginning with the quarter following the quarter in which they are first admitted to the Partnership as limited partners. Distributions declared by the Partnership for the period from February 11, 2013 (inception) through December 31, 2014 were as follows (in thousands, except per unit amounts):

 

Date Cash Distribution Paid

   For the Quarter Ended    Cash
Distribution
per Common
Limited
Partner Unit
     Total Cash
Distribution
to Common
Limited
Partners
     Total Cash
Distribution
to the General
Partner’s Class A
Units
 

February 14, 2014(1)

   December 31, 2013    $ 0.1167       $ 120       $ 2   

May 15, 2014

   March 31, 2014    $ 0.1750       $ 223       $ 6   

August 14, 2014

   June 30, 2014    $ 0.1750       $ 342       $ 7   

November 14, 2014

   September 30, 2014    $ 0.1750       $ 841       $ 16   

 

(1)  Represents a pro-rated cash distribution of $0.1750 per common limited partner unit for the period from November 1, 2013, the date the Partnership commenced operations.

On February 5, 2015, the Partnership declared a quarterly distribution of $0.1750 per common unit for the quarter ended December 31, 2014. The $1.7 million distribution, including approximately $33,000 to the general partner, was paid on February 13, 2015 to holders of record as of December 31, 2014.

NOTE 11 – SUBSEQUENT EVENTS

The Partnership evaluated its December 31, 2014 financial statements for subsequent events through October 20, 2015, the date the financial statements were available to be issued. The Partnership is not aware of any subsequent events which would require disclosure in the financial statements, except as noted below.

Eagle Ford Shale Acquisition Installment Payment. On March 31, 2015, the Partnership paid $28.3 million to satisfy the second installment payment related to its Eagle Ford Shale Acquisition. Concurrently, ARP issued $20.0 million of its Class D preferred limited partner units to satisfy the second installment related to its Eagle Ford Shale Acquisition. In connection with the payments, the Partnership and ARP amended the purchase and sale agreement to alter the timing and amount of the quarterly installment payments beginning on June 30, 2015 and ending December 31, 2015. On June 30, 2015, the Partnership paid $16.0 million and ARP paid $0.6 million to satisfy the third installment related to the Eagle Ford Acquisition.

Atlas Energy Merger. On February 27, 2015, ATLS was acquired by Targa Resources Corp. (NYSE: TRGP) (“TRC”) through the merger of a subsidiary of TRC with and into ATLS (the “Atlas Energy Merger”). Immediately prior to the closing of the Atlas Energy Merger, Atlas Energy transferred its assets and liabilities, other than those related to its midstream segment, to Atlas Energy Group, LLC (“Atlas Energy Group”), ARP’s general partner, and distributed, to the ATLS unitholders of record as of February 25, 2015, approximately 26.0 million common units representing limited liability company interests in Atlas Energy Group. On March 2, 2015, Atlas Energy Group began trading on the NYSE under the symbol “ATLS.” As a result of the Atlas Energy Merger, AGP GP, the Partnership’s general partner, became a wholly-owned subsidiary of Atlas Energy Group.

Private Placement Offering. Through the conclusion of the Partnership’s private placement offering, the Partnership issued 23,300,410 of its common units. Of such amount, ATLS purchased $5.0 million, or 500,010 common units, during the offering.

Cash distributions. On July 29, 2015, the Partnership declared a quarterly distribution of $0.175 per common unit for the quarter ended June 30, 2015. The aggregate $2.7 million distribution, including $0.1 million to the general partner, was paid on August 14, 2015 to holders of record as of June 30, 2015.

 

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On April 21, 2015, the Partnership declared a quarterly distribution of $0.175 per common unit for the quarter ended March 31, 2015. The aggregate $2.2 million distribution, including approximately $45,000 to the general partner, was paid on May 15, 2015 to holders of record as of March 31, 2015.

On February 5, 2015, the Partnership declared a quarterly distribution of $0.1750 per common unit for the quarter ended December 31, 2014. The $1.7 million distribution, including approximately $33,000 to the general partner, was paid on February 13, 2015 to holders of record as of December 31, 2014.

Deferred Purchase Obligation. In September 2015, the Partnership agreed with ARP to transfer its remaining $36.3 million of deferred purchase obligation, along with the related undeveloped natural gas and oil properties, to ARP.

NOTE 12 – SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Gas Reserve Information. The preparation of the Partnership’s natural gas, oil and NGL reserve estimates was completed in accordance with its prescribed internal control procedures by its reserve engineers. The accompanying reserve information included below was derived from the reserve reports prepared for the Partnership for the years ended December 31, 2014 and 2013. The Partnership’s internal control procedures include a multi-functional management review. The preparation of reserve estimates was overseen by its Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 16 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by the Partnership’s senior engineering staff and management, with final approval by the Executive Vice President of Operations.

The reserve disclosures that follow reflect estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of royalty interests, of natural gas, crude oil and NGLs owned at year end and changes in proved reserves during the last year. Proved oil, gas and NGL reserves are those quantities of oil, gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved developed reserves are those reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for undeveloped reserves cannot be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. The proved reserves quantities and future net cash flows as of December 31, 2014 and 2013, was estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2014 and 2013, including adjustments related to regional price differentials and energy content.

 

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There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of oil, gas and NGL reserves included within the Partnership or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil, gas and NGL prices and in production and development costs and other factors, for their effects have not been proved.

Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows (unaudited):

 

     Gas (Mcf)      Oil (Bbls)      NGLs (Bbls)  

Balance, January 1, 2013

     —           —           —     

Extensions, discoveries and other additions

     —           —           —     

Sales of reserves in-place

     —           —           —     

Purchase of reserves in-place(1)

     249,183         72,734         37,942   

Revisions

     —           —           —     

Production

     (7,718      (2,587      (946
  

 

 

    

 

 

    

 

 

 

Balance, December 31, 2013

     241,465         70,147         36,996   

Extensions, discoveries and other additions(2)

     1,934,523         295,968         316,313   

Sales of reserves in-place

     —           —           —     

Purchase of reserves in-place(3)

     6,355,071         14,629,514         1,271,014   

Revisions(4)

     213,763         (21,676      30,198   

Production

     (252,191      (42,547      (32,225
  

 

 

    

 

 

    

 

 

 

Balance, December 31, 2014

     8,492,631         14,931,406         1,622,296   

Proved developed reserves at:

        

January 1, 2013

     —           —           —     

December 31, 2013

     241,465         70,147         36,996   

December 31, 2014

     1,254,513         612,486         205,044   

Proved undeveloped reserves at:

        

January 1, 2013

     —           —           —     

December 31, 2013

     —           —           —     

December 31, 2014

     7,238,118         14,318,919         1,417,252   

 

(1)  Represents purchase of proved reserves in Marble Falls.
(2) Includes increase of proved reserves primarily due to addition of Marble Falls and Mississippi Lime wells.
(3)  Represents purchase of proved reserves in Eagle Ford.
(4)  Represents a downward revision on oil primarily due to wells being shut-in. The upward revision on gas and NGL is primarily due to production outperforming previous forecast.

 

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Capitalized Costs Related to Oil and Gas Producing Activities The components of capitalized costs related to oil and gas producing activities of the Partnership during the periods indicated were as follows (in thousands):

 

     Years Ended
December 31,
 
     2014      2013  

Natural gas and oil properties:

     

Proved properties

   $ 70,020       $ 4,046   

Unproved properties

     94,626         —     

Support equipment

     —           —     
  

 

 

    

 

 

 
     164,646         4,046   

Accumulated depreciation, depletion and amortization

     (9,177      (133
  

 

 

    

 

 

 

Net capitalized costs

   $ 155,469       $ 3,913   
  

 

 

    

 

 

 

Results of Operations from Oil and Gas Producing Activities. The results of operations related to the Partnership’s oil and gas producing activities during the periods indicated were as follows (in thousands):

 

     Periods Ended
December 31,
 
     2014      2013  

Revenues

   $ 5,707       $ 302   

Production costs

     (2,070      (80

Depreciation, depletion and amortization

     (2,156      (133

Asset impairment(1)

     (6,880      —     
  

 

 

    

 

 

 
   $ (5,399    $ 89   
  

 

 

    

 

 

 

 

(1)  During the year ended December 31, 2014, the Partnership recognized $6.9 million of asset impairment related to oil and gas properties within property, plant, and equipment, net on the Partnership’s consolidated balance sheet resulting from the decline in forward commodity prices during the fourth quarter of 2014. No asset impairment was recognized for the period ended December 31, 2013.

Costs Incurred in Oil and Gas Producing Activities. The costs incurred by the Partnership in its oil and gas activities during the periods indicated are as follows (in thousands):

 

     Periods Ended
December 31,
 
     2014      2013  

Property acquisition costs:

     

Proved properties

   $ 17,659       $ 1,758   

Unproved properties

     38,174         —     

Exploration costs(1)

     —           —     

Development costs

     11,786         1,836   
  

 

 

    

 

 

 

Total costs incurred in oil & gas producing activities

   $ 67,619       $ 3,594   
  

 

 

    

 

 

 

 

(1)  There were no exploratory wells drilled during the years ended December 31, 2014 and 2013.

Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2014 and 2013, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and

 

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includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (in thousands):

 

     Periods Ended
December 31,
 
     2014      2013  

Future cash inflows

   $ 1,484,783       $ 8,460   

Future production costs

     (372,765      (4,183

Future development costs

     (465,914      (20
  

 

 

    

 

 

 

Future net cash flows

     646,104         4,257   

Less 10% annual discount for estimated timing of cash flows

     (355,688      (1,146
  

 

 

    

 

 

 

Standardized measure of discounted future net cash flows

   $ 290,416       $ 3,110   
  

 

 

    

 

 

 

Change in Standardized Discounted Cash Flows. The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil, gas and NGL reserves (in thousands), including amounts related to asset retirement obligations. Since the Partnership allocates taxable income to its owners, no recognition has been given to income taxes:

     Periods Ended
December 31,
 
     2014     2013  

Balance, beginning of year

   $ 3,110      $ —     

Increase (decrease) in discounted future net cash flows:

    

Sales and transfers of oil and gas produced, net of related costs(1)

     (2,828     (109

Net changes in prices and production costs

     58        —     

Revisions of previous quantity estimates

     355        —     

Extensions, discoveries, and improved recovery less related costs(2)

     8,604       —     

Purchases of reserves in-place(3)

     281,244        3,241   

Estimated settlement of asset retirement obligations

     (116     (35

Estimated proceeds on disposals of well equipment

     10        13   

Changes in production rates (timing) and other

     (21     —     
  

 

 

   

 

 

 

Outstanding, ending of year

   $ 290,416      $ 3,110   
  

 

 

   

 

 

 

 

(1) Includes the amount of sales and transfers of oil and gas previously included in proved reserves and sold during the period ended.
(2) Includes increase of proved reserves primarily due to the addition of the Marble Falls and Mississippi Lime wells.
(3) Represents the change in discounted value of the proved reserves primarily due to the purchase of proved reserves in Marble Falls for the period ended December 31, 2013 and primarily due to the purchase of proved reserves in Eagle Ford for the period ended December 31, 2014.

 

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Unaudited Financial Statements for Nine Months Ended September 30, 2015 and 2014

ATLAS GROWTH PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

 

     September 30,
2015
    December 31,
2014
 
ASSETS     

Current assets:

    

Cash and cash equivalents

   $ 38,225      $ 33,405   

Accounts receivable

     2,413        764   

Advances to affiliates

     5,003        —    

Current derivative assets

     399        —    

Prepaid expenses

     445        437   
  

 

 

   

 

 

 

Total current assets

     46,485        34,606   

Property, plant and equipment, net

     124,640        155,469   

Long-term derivative asset

     163        —    

Other assets, net

     234        86   
  

 

 

   

 

 

 
   $ 171,522      $ 190,161   
  

 

 

   

 

 

 
LIABILITIES AND PARTNERS’ CAPITAL     

Current liabilities:

    

Accounts payable

   $ 3,555      $ 596   

Deferred capital contributions

     —         11,749   

Advances from affiliates

     —         16,500   

Accrued well drilling and completion costs

     9,329        12,506   

Deferred acquisition purchase price

     —          80,789   

Accrued liabilities

     192        360   
  

 

 

   

 

 

 

Total current liabilities

     13,076        122,500   

Asset retirement obligations

     165        151   

Commitments and contingencies

    

Partners’ Capital:

    

General partner’s interest

     (885     (446

Common limited partners’ interests

     156,370        66,676   

Common limited partners’ warrants

     2,796        1,280   
  

 

 

   

 

 

 

Total partners’ capital

     158,281        67,510   
  

 

 

   

 

 

 
   $ 171,522      $ 190,161   
  

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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ATLAS GROWTH PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

 

     Nine Months Ended
September 30,
 
     2015     2014  

Revenues:

    

Gas and oil production

   $ 8,007      $ 4,563   

Gain on mark-to-market derivatives

     760        —    
  

 

 

   

 

 

 

Total revenues

     8,767        4,563   
  

 

 

   

 

 

 

Costs and expenses:

    

Gas and oil production

     1,684        1,552   

General and administrative

     529        251   

General and administrative – affiliate

     9,484        6,819   

Depreciation, depletion and amortization

     5,095        1,436   

Asset impairment

     7,291        —    
  

 

 

   

 

 

 

Total costs and expenses

     24,083        10,058   
  

 

 

   

 

 

 

Operating income (loss)

     (15,316     (5,495

Interest expense

     (14     —    
  

 

 

   

 

 

 

Net loss

   $ (15,330   $ (5,495
  

 

 

   

 

 

 

Allocation of net loss attributable to common limited partners and the general partner:

    

Common limited partners’ interest

   $ (15,024     (5,387

General partner’s interest

     (306     (108
  

 

 

   

 

 

 

Net loss attributable to common limited partners and the general partner

   $ (15,330   $ (5,495
  

 

 

   

 

 

 

Net loss attributable to common limited partners per unit:

    

Basic and Diluted

   $ (0.88   $ (2.01
  

 

 

   

 

 

 

Weighted average common limited partner units outstanding:

    

Basic and Diluted

     16,996        2,685   
  

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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ATLAS GROWTH PARTNERS, L.P.

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in thousands, except unit data)

(Unaudited)

 

     General
Partner’s Interest
    Common Limited
Partners’ Interests
    Common Limited
Partners’ Warrants
     Total
Partners’
Capital
 
     Class A
Units
     Amount     Units      Amount     Warrants      Amount     

Balance at December 31, 2014

     100       $ (446     10,676,910       $ 66,676        1,067,691       $ 1,280       $ 67,510   

Issuance of units, net of offering costs

     —          —         12,623,500         111,179        1,262,350         1,516         112,695   

Distributions paid

     —          (133     —          (6,461     —          —          (6,594

Net loss

     —          (306     —          (15,024     —          —          (15,330
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Balance at September 30, 2015

     100       $ (885     23,300,410       $ 156,370        2,330,041       $ 2,796       $ 158,281   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

See accompanying notes to consolidated financial statements.

 

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ATLAS GROWTH PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

 

     Nine Months Ended
September 30,
 
     2015     2014  

CASH FLOWS FROM OPERATING ACTIVITIES:

    

Net loss

   $ (15,330   $ (5,495

Adjustments to reconcile net loss to net cash used in operating activities:

    

Depreciation, depletion and amortization

     5,095        1,436   

Asset impairment

     7,291        —     

Gain on mark-to-market derivatives

     (563     —    

Amortization of deferred financing costs

     14       —    

Changes in operating assets and liabilities:

    

Accounts receivable, prepaid expenses and other

     (1,656     (711

Advances from (to) affiliates

     (20,646     4,191   

Accounts payable and accrued liabilities

     1,915        1,071   
  

 

 

   

 

 

 

Net cash (used in) provided by operating activities

     (23,880     492   
  

 

 

   

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

    

Capital expenditures

     (20,777     (12,147

Net cash paid for acquisitions

     (44,714     —     

Other

     (152     (62
  

 

 

   

 

 

 

Net cash used in investing activities

     (65,643     (12,209
  

 

 

   

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

    

Net proceeds from issuance of common limited partner units and warrants

     100,946        43,900   

Deferred capital contributions

     —         11,333   

Distributions paid to unitholders

     (6,594     (700

Other

     (9     —    
  

 

 

   

 

 

 

Net cash provided by financing activities

     94,343        54,533   
  

 

 

   

 

 

 

Net change in cash and cash equivalents

     4,820        42,816   

Cash and cash equivalents, beginning of period

     33,405        8,759   
  

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 38,225      $ 51,575   
  

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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ATLAS GROWTH PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2015

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION

Atlas Growth Partners, L.P. (the “Partnership”) is a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”) with operations primarily focused in the Eagle Ford Shale in south Texas. At September 30, 2015, the Partnership’s general partner, Atlas Growth Partners GP, LLC (“AGP GP”) owned 100% of the general partner Class A units and all of the incentive distribution rights through which it manages and effectively controls the Partnership. At September 30, 2015, Atlas Energy Group, LLC (“ATLS” or “Atlas Energy”), a publicly traded Delaware limited liability company (NYSE: ATLS), owned a 2.1% limited partner interest in the Partnership and 80% of AGP GP’s general partner Class A units, which are entitled to receive 2% of the cash distributed without any obligation to make further capital contributions (see Note 11). Current and former members of ATLS management own the remaining 20.0% membership interest in the general partner.

On February 27, 2015, Atlas Energy, L.P. was acquired by Targa Resources Corp. (NYSE: TRGP) (“TRC”) through the merger of a subsidiary of TRC with and into Atlas Energy, L.P. (the “Atlas Energy Merger”). Immediately prior to the closing of the Atlas Energy Merger, Atlas Energy L.P. transferred its assets and liabilities, other than those related to its midstream segment, to ATLS, Atlas Resource Partners, L.P.’s general partner, and distributed, to the Atlas Energy L.P. unitholders of record as of February 25, 2015, approximately 26.0 million common units representing limited liability company interests in ATLS. On March 2, 2015, ATLS began trading on the NYSE under the symbol “ATLS.” As a result of the Atlas Energy Merger, AGP GP, the Partnership’s general partner, became a subsidiary of ATLS.

The Partnership was formed on February 11, 2013 to acquire undeveloped oil and gas properties and, subsequently, drill developmental wells on those properties. The Partnership funds its operations through the private placement of its common limited partner units at a purchase price of $10.00 per unit (the “Private Placement Offering”). Subscriptions, offered at a minimum investment of $25,000 and in $1,000 increments thereafter, were generally sold using wholesalers and through broker-dealers including Anthem Securities, Inc., an affiliated company, which receive a 3% dealer-manager fee, a 7% sales commission and a 2% direct issue cost, respectively.

Unless a listing event occurs before then, the Partnership will have a term of 10 years from June 30, 2015, or until June 30, 2025, subject to two one-year extensions in the sole discretion of its general partner.

The accompanying consolidated financial statements, which are unaudited, are presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. The results of operations for the nine months ended September 30, 2015 may not necessarily be indicative of the results of operations for the full year ending December 31, 2015.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The Partnership’s consolidated balance sheet at September 30, 2015 and the consolidated statements of operations for the nine months ended September 30, 2015 and 2014 include the accounts of the Partnership and its wholly-owned subsidiaries. Transactions between the Partnership and other ATLS operations have been identified in the consolidated financial statements as transactions between affiliates, where applicable. All material intercompany transactions have been eliminated.

 

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Use of Estimates

The preparation of the Partnership’s consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion and depreciation and amortization. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the nine months ended September 30, 2015 and 2014 represent actual results in all material respects (see “Revenue Recognition”).

Cash Equivalents

The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.

Receivables

Accounts receivable on the consolidated balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the Partnership’s management performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of customers’ credit information. The Partnership extends credit on sales on an unsecured basis to many of its customers. At September 30, 2015 and December 31, 2014, the Partnership had recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements which generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Partnership’s results of operations.

The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and NGLs are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to six Mcf of natural gas. Mcf is defined as one thousand cubic feet.

 

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The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include the Partnership’s costs of property interests in proportionately consolidated joint venture wells, wells drilled solely by the Partnership for its interests, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Partnership’s consolidated statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its consolidated balance sheet. Upon the Partnership’s sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Partnership’s consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Impairment of Long-Lived Assets

The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. Reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods.

Deferred Capital Contribution

The Partnership recognizes a current liability related to capital contributions received from limited partners prior to the issuance of the respective limited partner units. As prescribed by the Partnership Agreement, limited partner units are issued to investors on the first day of the month following the month in which the capital contribution is received.

 

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Derivative Instruments

The Partnership enters into certain financial contracts to manage its exposure to movement in commodity prices (see Note 6). The derivative instruments recorded in the consolidated balance sheets are measured as either an asset or liability at fair value. Changes in the fair value of derivative instruments are recognized currently within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated statements of operations.

Asset Retirement Obligations

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 5). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depreciation, depletion and amortization.

Revenue Recognition

The Partnership generally sells natural gas, crude oil and NGLs at prevailing market prices. Typically, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibilities of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” for further description). The Partnership had unbilled revenues of $2.2 million and $0.8 million at September 30, 2015 and December 31, 2014, respectively, which were included in accounts receivable within the Partnership’s consolidated balance sheets.

Segment Reporting

The Partnership derives revenue from its gas and oil production. These production facilities have been aggregated into one reportable segment because the facilities have similar long-term economic characteristics, products and types of customers.

Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of the general partner’s interest, by the weighted average number of common limited partner units outstanding during the period. The general partner’s interest in net income (loss) is calculated on a quarterly basis based upon its Class A units and incentive distributions to be distributed for the quarter (see Note 10), with a priority allocation of net income to the general partner’s incentive distributions, if any, in accordance with the partnership agreement, and the remaining net income (loss) allocated with respect to the general partner’s and limited partners’ ownership interests.

 

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The Partnership presents net income (loss) per unit under the two-class method, which considers whether the incentive distributions represent a participating security when considered in the calculation of earnings per unit under the two-class method. The two-class method considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, management of the Partnership believes the partnership agreement contractually limits cash distributions to available cash; therefore, undistributed earnings are not allocated to the incentive distribution rights.

The following is a reconciliation of net loss allocated to the common limited partners for purposes of calculating net loss attributable to common limited partners per unit (in thousands, except unit data):

 

     Nine Months Ended
September 30,
 
     2015      2014  

Net loss

   $ (15,330    $ (5,495

Less: General partner’s interest

     (306      (108
  

 

 

    

 

 

 

Net loss attributable to common limited partners(1)

   $ (15,024    $ (5,387
  

 

 

    

 

 

 

 

(1)  For the nine months ended September 30, 2015 and 2014, approximately 2,330,000 and 641,000 common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of units issuable upon the exercise of the warrants would have been anti-dilutive.

Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of common limited partner warrants, as calculated by the treasury stock method (see Note 10).

The following table sets forth the reconciliation of the Partnership’s weighted average number of common units used to compute basic net income (loss) attributable to common unit holders per unit with those used to compute diluted net income (loss) attributable to common unit holders per unit (in thousands):

 

     Nine Months Ended
September 30,
 
     2015      2014  

Weighted average number of common unit holders per unit – basic

     16,996         2,685   

Add effect of dilutive warrants(1)

     —          —    
  

 

 

    

 

 

 

Weighted average number of common unit holders per unit – diluted

     16,996         2,685   
  

 

 

    

 

 

 

 

(1)  For the nine months ended September 30, 2015 and 2014, approximately 2,330,000 and 641,000 common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of units issuable upon the exercise of the warrants would have been anti-dilutive.

 

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Income Taxes

The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the accompanying consolidated financial statements. Accordingly, no federal or state current or deferred income tax has been provided for in the accompanying consolidated financial statements.

The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its consolidated financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Partnership has not recognized any potential interest or penalties in its consolidated financial statements for the nine months ended September 30, 2015 and 2014.

The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. The Partnership is not subject to income tax examinations by major tax authorities for years prior to 2013, its year of formation. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of September 30, 2015.

Recently Issued Accounting Standards

In September 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-16, Business Combinations (Subtopic 805) (“Update 2015-16”) which eliminates the need to retrospectively adjust previously issued financial statements for changes in provisional amounts recognized at the date on which a business was acquired and later revised based on new information about facts and circumstances that existed at the acquisition date. Subsequent to the effective date of this accounting standard, such adjustments will be applied prospectively and the nature of, and reason for, the change in accounting principle will be disclosed. The Partnership will adopt the requirements of Update 2015-16 upon its effective date of January 1, 2016, and the Partnership does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In April 2015, FASB issued ASU 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (“Update 2015-06”). Under Topic 260, Earnings per Share, master limited partnerships (“MLPs”) apply the two-class method to calculate earnings per unit (“EPU”) because the general partner, limited partners, and incentive distribution rights holders each participate differently in the distribution of available cash. When a general partner transfers (or “drops down”) net assets to a master limited partnership and that transaction is accounted for as a transaction between entities under common control, the statements of operations of the master limited partnership are adjusted retrospectively to reflect the drop down transaction as if it occurred on the earliest date during which the entities were under common control. The amendments in Update 2015-06 specify that for purposes of calculating historical EPU under the two-class method, the earnings (losses) of a transferred business before the date of a drop down transaction should be allocated entirely to the general partner interest, and previously reported EPU of the limited partners would not change as a result of a drop down transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the drop down transaction occurs also are required. The amendments in Update 2015-06 are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted and amendments in Update 2015-06 should be applied retrospectively for all financial statements presented. The Partnership will adopt the requirements of Update 2015-06 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

 

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In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“Update 2015-02”). The amendments in Update 2015-02 are intended to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures. The amendments simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The amendments in Update 2015-02 are effective for periods beginning after December 31, 2015. Early adoption is permitted, including adoption in an interim period. The Partnership will adopt the requirements of Update 2015-02 upon its effective date of January 1, 2016, and is evaluating the impact of adoption on its financial position, results of operations or related disclosures.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is not permitted. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2018, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

NOTE 3 – ACQUISITION

On November 5, 2014, the Partnership and Atlas Resource Partners, L.P. (“ARP”), an entity related through common ownership and management, completed an acquisition of oil and natural gas liquid interests in the Eagle Ford Shale in Atascosa County, Texas from Cima Resources, LLC and Cinco Resources, Inc. (together “Cinco”) for $342.0 million, net of purchase price adjustments (the “Eagle Ford Acquisition”). Approximately $183.1 million was paid in cash by ARP and $19.9 million was paid by the Partnership at closing, and approximately $139.0 million was to be paid in four quarterly installments beginning December 31, 2014. On December 31, 2014, the Partnership made its first installment payment of $35.0 million related to the Eagle Ford Acquisition. Prior to the March 31, 2015 installment, the Partnership, ARP and Cinco amended the purchase and sale agreement to alter the timing and amount of the quarterly payments beginning with the March 31, 2015 payment and ending December 31, 2015, with no change to the overall purchase price. On March 31, 2015, the Partnership paid $28.3 million and ARP issued $20.0 million of its 8.625% Class D Preferred Units to satisfy the second installment related to the Eagle Ford Acquisition. On June 30, 2015, the Partnership paid $16.0 million and ARP paid $0.6 million to satisfy the third installment related to the Eagle Ford Acquisition. On July 8, 2015, the Partnership sold to ARP, for a purchase price of $1.4 million, the Partnership’s interest in a portion of the acreage the Partnership acquired in the Eagle Ford Acquisition. On September 21, 2015, the Partnership and ARP, in accordance with the terms of the Eagle Ford shared acquisition and operating agreement, agreed that ARP will fund the remaining two deferred purchase price installments of $16.2 million and $20.1 million to be

 

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paid on September 30, 2015 and December 31, 2015, respectively. In conjunction with this agreement, the Partnership assigned ARP a portion of its non-operating Eagle Ford assets that have an allocated value (as such value was agreed upon by the sellers and the buyers in connection with the Eagle Ford Acquisition) equal to both installments to be paid by ARP. The transaction was approved by the Partnership’s and ARP’s respective conflicts committees. The Eagle Ford Acquisition had an effective date of July 1, 2014. The Partnership accounted for its acquisition of non-producing leasehold acreage as an acquisition of assets.

NOTE 4 – PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment at the date indicated (in thousands):

 

     September 30,
2015
     December 31,
2014
 

Natural gas and oil properties:

     

Proved properties:

     

Leasehold interests

   $ 13,503       $ 13,853   

Pre-development costs

     497         155   

Wells and related equipment

     77,155         56,012   
  

 

 

    

 

 

 

Total proved properties

     91,155         70,020   

Unproved properties

     52,080         94,626   

Support equipment

     14         —    
  

 

 

    

 

 

 

Total natural gas and oil properties

     143,249         164,646   

Pipelines, processing and compression facilities

     2,968         —    
  

 

 

    

 

 

 
     146,217         164,646   

Less – accumulated depreciation, depletion and amortization

     (21,577      (9,177
  

 

 

    

 

 

 
   $ 124,640       $ 155,469   
  

 

 

    

 

 

 

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate the Partnership will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. There were no impairments of unproved gas and oil properties recorded by the Partnership for the nine months ended September 30, 2015 and 2014.

Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. For the nine months ended September 30, 2015, the Partnership recognized $7.3 million of asset impairment related to oil and gas properties in the Marble Falls and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices. There were no impairments of proved gas and oil properties for the nine months ended September 30, 2014.

During the nine months ended September 30, 2015 and 2014, the Partnership recognized $2.1 million and $0.1 million, respectively, of non-cash property, plant and equipment additions, which were included within the changes in accounts payable and accrued liabilities on the Partnership’s consolidated statements of cash flows. During the nine months ended September 30, 2015, the Partnership also assigned a portion of its non-operating Eagle Ford assets to ARP in exchange for ARP funding the Partnership’s remaining $36.3 million of deferred Eagle Ford Acquisition purchase price (see Note 3), which represented a non-cash transaction within the Partnership’s consolidated statement of cash flow.

 

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NOTE 5 – ASSET RETIREMENT OBLIGATIONS

The Partnership recognized an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities. The Partnership also recognized a liability for its future asset retirement obligations where a reasonable estimate of the fair value of that liability could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability for asset retirement obligations was based on the Partnership’s historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its gas and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets.

A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):

 

     Nine Months Ended
September 30,
 
     2015      2014  

Asset retirement obligations, beginning of period

   $ 151       $ 35   

Liabilities incurred

     4         105   

Liabilities settled

     —          —    

Accretion expense

     10         6   
  

 

 

    

 

 

 

Asset retirement obligations, end of period

   $ 165       $ 146   
  

 

 

    

 

 

 

The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated statements of operations.

NOTE 6 – DERIVATIVE INSTRUMENTS

The Partnership uses swaps in connection with its commodity price risk management activities. The Partnership enters into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period.

The Partnership has elected not to utilize hedge accounting for its derivative instruments. Changes in fair value of derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated statements of operations.

The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s consolidated balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. The Partnership enters into commodity future option contracts to achieve more predictable

 

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cash flows by hedging their exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while other natural gas liquids contracts are based on an OPIS Mt. Belvieu index.

Derivatives are recorded on the Partnership’s consolidated balance sheets as assets or liabilities at fair value. The Partnership reflected net derivative assets on its consolidated balance sheet of approximately $0.6 million at September 30, 2015. The Partnership did not have any derivatives at December 31, 2014.

The following table summarizes the commodity derivative activity for the nine months ended September 30, 2015 (in thousands):

 

     Nine Months Ended
September 30,
 
     2015      2014  

Changes in fair value prior to settlement

   $ 563       $ —    

Cash settlements of derivative contracts

     197         —    
  

 

 

    

 

 

 

Gain on mark-to-market derivatives

   $ 760       $ —    
  

 

 

    

 

 

 

At May 1, 2015, the Partnership entered into a secured credit facility agreement with a syndicate of banks. As of the date hereof, the lenders under the credit facility have no commitment to lend to the Partnership under the credit facility, but the Partnership and its subsidiaries have the ability to enter into derivative contracts to manage their exposure to commodity price movements which will benefit from the collateral securing the credit facility. The credit facility may be amended in the future if the Partnership and the lenders agree to increase the borrowing base and the lenders’ commitments thereunder. The secured credit facility agreement contains covenants that limit the ability of the Partnership and its subsidiaries to incur indebtedness, grant liens, make loans or investments, make distributions, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions, including a sale of all or substantially all of its assets. The Partnership was in compliance with these covenants as of September 30, 2015. In addition, the Partnership’s credit facility includes customary events of default, including failure to timely pay, breach of covenants, bankruptcy, cross-default with other material indebtedness (including obligations under swap agreements in excess of any agreed upon threshold amount), and change of control provisions.

 

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The following table summarizes the gross fair values of the Partnership’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s combined consolidated balance sheets as of the date indicated (in thousands):

 

     Gross
Amounts of
Recognized
Assets
     Gross
Amounts
Offset in the
Consolidated
Balance Sheets
     Net Amount of
Assets Presented
in the
Consolidated
Balance Sheets
 

Offsetting Derivative Assets

        

As of September 30, 2015

        

Current portion of derivative assets

   $ 399       $ —         $ 399   

Long-term portion of derivative assets

     163         —           163   
  

 

 

    

 

 

    

 

 

 

Total derivative assets

   $ 562       $ —         $ 562   
  

 

 

    

 

 

    

 

 

 

As of December 31, 2014

        

Current portion of derivative assets

   $ —         $ —         $ —     

Long-term portion of derivative assets

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Total derivative assets

   $ —         $ —         $ —     
  

 

 

    

 

 

    

 

 

 

 

     Gross
Amounts of
Recognized
Liabilities
     Gross
Amounts
Offset in the
Consolidated
Balance Sheets
     Net Amount of
Liabilities Presented
in the
Consolidated
Balance Sheets
 

Offsetting Derivative Liabilities

        

As of September 30, 2015

        

Current portion of derivative liabilities

   $ —         $ —         $ —     

Long-term portion of derivative liabilities

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Total derivative liabilities

   $ —         $ —         $ —     
  

 

 

    

 

 

    

 

 

 

As of December 31, 2014

        

Current portion of derivative liabilities

   $ —         $ —         $ —     

Long-term portion of derivative liabilities

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Total derivative liabilities

   $ —         $ —         $ —     
  

 

 

    

 

 

    

 

 

 

As of September 30, 2015, the Partnership had the following commodity derivatives:

Crude Oil – Fixed Price Swaps

 

ProductionPeriod EndingDecember 31,

   Volumes      Average
Fixed Price
     Fair Value
Asset
 
     (Bbl)(1)      (per Bbl)(1)      (in thousands)(2)  

2015

     13,500       $ 61.000       $ 205   

2016

     18,000       $ 63.150         249   

2017

     9,000       $ 65.000         108   
        

 

 

 
     Total commodity derivatives       $ 562   
        

 

 

 

 

(1)  “Bbl” represents barrels.
(2)  Fair value based on forward WTI crude oil prices, as applicable.

 

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NOTE 7 – COMMITMENTS AND CONTINGENCIES

As of September 30, 2015, certain of the Partnership’s executives are parties to employment agreements with ATLS that provide compensation and certain other benefits. The agreements provided for severance payments under certain circumstances.

As of September 30, 2015, the Partnership did not have any commitments for drilling and completion expenditures.

Legal Proceedings

The Partnership and its subsidiaries are parties to various routine legal proceedings arising out of the ordinary course of its business. Management of the Partnership and its subsidiaries believe that none of these actions, individually or in the aggregate, will not have a material adverse effect on the Partnership’s financial condition or results of operations.

NOTE 8 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

In the ordinary course of its business operations, the Partnership has ongoing relationships with several related entities:

Relationship with ATLS. The Partnership does not directly employ any persons to manage or operate its business. These functions are provided by employees of ATLS and/or its affiliates. AGP GP, the Partnership’s general partner, receives an annual management fee in connection with its management of the Partnership equivalent to 1% of capital contributions per annum. During the nine months ended September 30, 2015 and 2014, the Partnership paid approximately $1.2 million and $0.1 million related to this management fee. Other indirect costs, such as rent for offices, are allocated to the Partnership by ATLS based on the number of its employees who devoted substantially all of their time to activities on its behalf. The Partnership reimburses ATLS at cost for direct costs incurred on its behalf. The Partnership will reimburse all necessary and reasonable costs allocated by the general partner. The Partnership was required to pay AGP GP, the Partnership’s general partner, an amount equal to any actual, out-of-pocket expenses related to the Private Placement Offering and the formation and financing of the Partnership, including legal costs incurred by AGP GP, which payments were approximately 2% of the gross proceeds of the Private Placement Offering. All of the costs paid or payable to ATLS discussed above were included in general and administrative expenses – affiliate in the consolidated statement of operations for the nine months ended September 30, 2015.

Relationship with Anthem Securities, Inc. Anthem Securities, Inc. (“Anthem”), an affiliate of AGP GP, the Partnership’s general partner, is acting as dealer manager for the Private Placement Offering. For acting as the dealer manager, Anthem receives compensation from the Partnership equal to a maximum of 12% of the gross proceeds of the Private Placement Offering as selling commissions, marketing efforts, and other issuance costs. The Partnership includes these costs within common limited partners’ interests on the Partnership’s consolidated statement of partners’ capital for the nine months ended September 30, 2015, and such costs were $12.7 million and $9.1 million during the nine month periods ended September 30, 2015 and 2014, respectively.

Relationship with ARP. In connection with the Eagle Ford Acquisition (see Note 3), ARP, a publicly-traded Delaware master limited partnership (NYSE: ARP) managed by ATLS, guaranteed the timely payment of the deferred portion of the purchase price that is to be paid by the Partnership. On September 21, 2015, the Partnership and ARP, in accordance with the terms of the Eagle Ford shared acquisition and operating agreement, agreed that ARP will fund the remaining two deferred purchase price installments (see Note 3). In conjunction with this agreement, the Partnership assigned ARP a portion of its non-operating Eagle Ford assets

 

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that have an allocated value (as such value was agreed upon by the sellers and the buyers in connection with the Eagle Ford Acquisition) equal to both installments to be paid by ARP. As of September 30, 2015, the Partnership had a $5.0 million receivable from ARP related to the timing of funding cash accounts, which is recorded in advances to affiliates in the consolidated balance sheet.

NOTE 9 – FAIR VALUE OF FINANCIAL INSTRUMENTS

Management has established a hierarchy to measure the Partnership’s financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources, whereas, unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1 –Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 –Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3 –Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 6). The Partnership manages and reports derivative assets and liabilities on the basis of its exposure to market risks and credit risks by counterparty. Commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.

No derivatives were held at December 31, 2014. Information for the Partnership’s assets and liabilities measured at fair value at September 30, 2015 was as follows (in thousands):

 

     Level 1      Level 2      Level 3      Total  

As of September 30, 2015

           

Assets, gross

           

Commodity swaps

   $ —        $ 562       $ —        $ 562   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total derivative assets, gross

     —          562         —          562   
  

 

 

    

 

 

    

 

 

    

 

 

 

Liabilities, gross

           

Commodity swaps

     —          —           —          —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total derivative liabilities, gross

     —          —           —          —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total assets, fair value, net

   $ —        $ 562       $ —        $ 562   
  

 

 

    

 

 

    

 

 

    

 

 

 

Other Financial Instruments

The estimated fair values of the Partnership’s other financial instruments have been determined based upon assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Partnership could realize upon the sale or refinancing of such financial instruments.

 

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The Partnership’s other current assets and liabilities on its consolidated balance sheet are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

Management estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates.

Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the nine months ended September 30, 2015 and 2014 were as follows (in thousands):

 

     Nine Months Ended September 30, 2015  
                 2015                              2014              
     Level 3      Total      Level 3      Total  

Asset retirement obligations

   $ 4       $ 4       $ 105       $ 105   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 4       $ 4       $ 105       $ 105   
  

 

 

    

 

 

    

 

 

    

 

 

 

Management estimates the fair value of the Partnership’s long-lived assets in connection with reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances. For the nine months ended September 30, 2015, the Partnership recognized $7.3 million of asset impairment related to oil and gas properties in the Marble Falls and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices. For the nine months ended September 30, 2014, the Partnership recognized no impairment of long-lived assets. The determinations of fair values used in the impairment assessments represent Level 3 fair value measurements (see Note 4).

The fair value of the warrants associated with the issuance of common limited partner units (see Note 10) was measured using a Black-Scholes pricing model which is based on Level 3 inputs including an exercise price of $10.00, discount rate of 0.3%, an expected term of 1 year, expected dividend yield of 7.0% and estimated volatility rate of 45%. The volatility rate used is consistent with that of ARP. The estimated fair value per warrant was $1.20, which includes a $0.21 liquidity adjustment.

NOTE 10 – ISSUANCES OF UNITS

Under the terms of the Partnership’s initial offering, the Partnership offered in a private placement $500.0 million of its common limited partner units. The termination date of the Private Placement offering was December 31, 2014, subject to two 90 day extensions to the extent that it had not sold $500.0 million of common units at any extension date. The Partnership exercised each of such extensions. Under the terms of the offering, an investor received, for no additional consideration, warrants to purchase additional common units in an amount equal to 10% of the common units purchased by such investor. The warrants are exercisable at a price of $10.00 per common unit being purchased and may be exercised from and after the Warrant Date (generally, the date upon which the Partnership gives the holder notice of a Liquidity Event) until the Expiration Date (generally, the date that is one day prior to the Liquidity Event or, if the Liquidity Event is a listing on a national securities exchange, 30 days after the Liquidity Event occurs). Under the warrant, a Liquidity Event is defined as either (i) a listing of the common units on a national securities exchange, (ii) a business combination with or into an existing publicly-traded entity, or (iii) a sale of all or substantially all of the Partnership’s assets.

 

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Through the conclusion of our private placement offering on June 30, 2015, we issued 23,300,410 of our common limited partner units in exchange for proceeds to us, net of dealer manager fees and commissions and expenses, of $203.4 million. Of the aggregate amount, ATLS purchased 500,010 common limited partner units for $5.0 million during the offering.

During the nine months ended September 30, 2015, the Partnership sold an aggregate of 12,623,500 of its common limited partner units at a gross offering price of $10.00 per unit. In connection with the issuance of common limited partner units, unitholders received 1,262,350 warrants to purchase the Partnership’s common limited partner units at an exercise price of $10.00 per unit.

NOTE 11 – CASH DISTRIBUTIONS

The Partnership has a cash distribution policy under which it distributes to holders of common units and Class A units on a quarterly basis a target distribution of $0.175 per unit, or $0.70 per unit per year, to the extent the Partnership has sufficient available cash after establishing appropriate reserves and paying fees and expenses, including reimbursements of expenses to the general partner and its affiliates. Distributions are generally paid within 45 days of the end of the quarter to unitholders of record on the applicable record date. Unitholders are entitled to receive distributions beginning with the quarter following the quarter in which they are first admitted to the Partnership as limited partners. Distributions declared by the Partnership for the period from February 11, 2013 (inception) through September 30, 2015 were as follows (in thousands, except per unit amounts):

 

Date Cash Distribution Paid

   For the Quarter Ended    Cash
Distribution
per Common
Limited
Partner Unit
     Total Cash
Distribution
to Common
Limited
Partners
     Total Cash
Distribution
to the General
Partner’s Class A
Units
 

February 14, 2014(1)

   December 31, 2013    $ 0.1167       $ 120.00       $ 2.00   

May 15, 2014

   March 31, 2014    $ 0.1750       $ 223.00       $ 6.00   

August 14, 2014

   June 30, 2014    $ 0.1750       $ 342.00       $ 7.00   

November 14, 2014

   September 30, 2014    $ 0.1750       $ 841.00       $ 16.00   

February 13, 2015

   December 31, 2014    $ 0.1750       $ 1,636.00       $ 33.00   

May 15, 2015

   March 31, 2015    $ 0.1750       $ 2,180.00       $ 45.00   

August 14, 2015

   June 30, 2015    $ 0.1750       $ 2,646.00       $ 54.00   

 

(1)  Represents a pro-rated cash distribution of $0.1750 per common limited partner unit for the period from November 1, 2013, the date the Partnership commenced operations.

NOTE 12 – SUBSEQUENT EVENTS

The Partnership evaluated its September 30, 2015 financial statements for subsequent events through December 9, 2015, the date the financial statements were available to be issued. The Partnership is not aware of any subsequent events which would require disclosure in the financial statements, except as noted below.

Cash distributions. On November 5, 2015, the Partnership declared a quarterly distribution of $0.1750 per common unit for the quarter ended September 30, 2015. The aggregate $4.2 million distribution, including $0.1 million to the general partner, was paid on November 13, 2015 to holders of record as of September 30, 2015.

 

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Appendix A to Prospectus

CALCULATION OF DISTRIBUTION UPON A SALE OR MERGER

The following examples show how distributions with respect to a sale or merger would be calculated under varying assumptions. These examples are for illustrative purposes only and are not, and do not purport to be, a representation or prediction of future results.

General Structure

At event of sale:

First, 100% of sale proceeds to limited partner until it has received $135 including any distributions received from operations;

Second, 100% of the remaining proceeds until the general partner (or holder of GP units) has received 2.04% of the difference between total cash distributions made to limited partner and initial contribution;

Third, 100% of remaining sale proceeds to general partner until it has received $8.75 less any distributions earned for its GP units;

Fourth, any remaining sale proceeds 80% to limited partners and 20% to the general partner

Example 1: Preferred return not met

Assumptions

Limited partner contributes $100

Limited partner has received $1.75 quarterly (7% annualized) for 5 years ($35 in aggregate)

General partner has received $0.1429 per year in GP unit distributions ($0.714 in aggregate)

Sale occurs in fifth year for $50

Cash Distribution at Sale

 

1) Limited partner receives $50

 

2) General partner receives $0

Summary for 5 year period

Limited partner total cash distributions are $85 ($35 + $50)

General partner total cash distributions are $0.714

Example 2: Preferred return met but does not fully satisfy general partner catch-up provision

Assumptions

Limited partner contributes $100

Limited partner has received $1.75 quarterly (7% annualized) for 5 years ($35 in aggregate)

 

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General partner has received $0.1429 per year in GP unit distributions ($0.714 in aggregate)

Sale occurs in fifth year for $105

Cash Distribution at Sale

 

1) Limited partner receives $100

 

2) General partner received $0.714 (2.04% x $35)

 

3) General partner receives $4.286 (general partner entitled to up to ($35/80%) x 20% or $8.75 less any GP unit distributions received)

Summary for 5 year period

Limited partner total cash distributions are $135 ($35 + $100)

General partner total cash distributions are $5.714 ($0.714+$0.714 + $4.286)

Example 3: Preferred return met and exceeds general partner catch-up provision

Assumptions

Limited partner contributes $100

Limited partner has received $1.75 quarterly (7% annualized) for 5 years ($35 in aggregate)

General partner has received $0.1429 per year in GP unit distributions ($0.714 in aggregate)

Sale occurs in fifth year for $150

Cash Distribution at Sale

 

1) Limited partner receives $100

 

2) General partner received $0.714 (2.04% x $35)

 

3) General partner receives $7.322 (general partner entitled up to ($35/80%) x 20% or $8.75 less any GP unit distributions received)

 

4) 80%/20% split between limited partner and general partner

 

  a) 80% x ($150 - $100 - $0.714 - $7.322) = $33.57

 

  b) 20% x ($150 - $100 - $0.714 - $7.322) = $8.39

Summary for 5 year period

Limited partner total cash distributions are $168.57 ($35 + $100 + $33.57)

General partner total cash distributions are $17.14 ($0.715 + $8.035 + $8.39)

 

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Exhibit A to Prospectus

PRE-LISTING PARTNERSHIP AGREEMENT

 

EXA-1


Table of Contents

FIRST AMENDED AND RESTATED PARTNERSHIP AGREEMENT OF

ATLAS GROWTH PARTNERS, L.P.

 

EXA-2


Table of Contents

TABLE OF CONTENTS

 

ARTICLE I FORMATION

     EXA-4   

1.01.

  Formation.      EXA-4   

1.02.

  Name, Principal Office and Residence.      EXA-4   

1.03.

  Purpose.      EXA-4   

ARTICLE II DEFINITION OF TERMS

     EXA-5   

2.01.

  Definitions.      EXA-5   

ARTICLE III UNITS, SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS

     EXA-25   

3.01.

  Designation of General Partner and Participants.      EXA-25   

3.02.

  Limited Partner at Formation.      EXA-25   

3.03.

  Classes of Common Units.      EXA-25   

3.04.

  Subscriptions to the Second Offering.      EXA-26   

3.05.

  No Additional Capital Contributions of the General Partner or Dilution.      EXA-27   

3.06.

  Payment of Subscriptions      EXA-28   

3.07.

  Partnership Funds.      EXA-28   

ARTICLE IV CONDUCT OF OPERATIONS

     EXA-29   

4.01

  Acquisition of Leases.      EXA-29   

4.02.

  Conduct of Operations.      EXA-30   

4.03.

  General Rights and Obligations of the Participants and Restricted and Prohibited Transactions.      EXA-35   

4.04.

  Designation, Compensation and Removal of General Partner.      EXA-45   

4.05.

  Indemnification and Exoneration.      EXA-47   

4.06.

  Other Activities.      EXA-49   

4.07.

  Issuances of Additional Partnership Interests.      EXA-49   

4.08.

  Splits and Combinations.      EXA-50   

ARTICLE V CAPITAL ACCOUNTS, ALLOCATIONS, ELECTIONS AND DISTRIBUTIONS

     EXA-50   

5.01.

  Capital Accounts.      EXA-50   

5.02.

  Allocations for Capital Account Purposes.      EXA-53   

5.03.

  Allocations for Tax Purposes.      EXA-58   

5.04.

  Requirement and Characterization of Distributions; Distributions to Record Holders.      EXA-61   

5.05.

  Distributions of Available Cash from Operating Surplus.      EXA-61   

5.06.

  Distributions of Available Cash from Capital Surplus.      EXA-61   

5.07.

  Special Provisions Relating to the Holders of Incentive Distribution Rights.      EXA-62   

5.08.

  Distributions of Available Cash from Sale of All or Substantially All Assets.      EXA-62   

5.09.

  Distributions in the Event of Merger.      EXA-62   

5.10.

  Distribution Reinvestment Plans.      EXA-62   

ARTICLE VI TRANSFER OF UNITS

     EXA-63   

6.01.

  Transferability of Common Units.      EXA-63   

6.02.

  Special Restrictions on Transfers of Units by Participants.      EXA-63   

6.03.

  Redemption of Common Units from Non-Citizens.      EXA-64   

ARTICLE VII DURATION, DISSOLUTION, AND WINDING UP

     EXA-65   

7.01.

  Duration.      EXA-65   

7.02.

  Dissolution and Winding Up.      EXA-65   

8.01.

  Notices.      EXA-66   

8.02.

  Time.      EXA-67   

8.03.

  Applicable Law.      EXA-67   

8.04.

  Agreement in Counterparts.      EXA-67   

8.05.

  Amendment.      EXA-67   

8.06.

  Legal Effect.      EXA-68   

 

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Table of Contents

THIS FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP is made and entered into as of the date set forth below, by and among Atlas Growth Partners GP, LLC, referred to as “Atlas” or the “General Partner,” the limited partner, and the remaining parties from time to time signing a Subscription Agreement for Limited Partner Interests, these parties, sometimes referred to as “Limited Partners.”

ARTICLE I FORMATION

1.01. Formation.

The parties have formed a limited partnership under the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) on the terms and conditions set forth in this Agreement. The General Partner and organizational limited partner executed an Agreement of Limited Partnership, dated as of February 11, 2013 (the “Original Agreement”). In connection with a public offering and pursuant to § 8.05(b)(iv) and § 8.05(b)(vii) of the Original Agreement, the General Partner hereby amends and restates the Original Agreement in its entirety to provide for the conduct of the business and affairs of the Partnership and certain relations between the Limited Partners in accordance with the terms and conditions of this agreement, as it may be amended from time to time.

1.02. Name, Principal Office and Residence.

1.02(a). Name. The name of the Partnership is Atlas Growth Partners, L.P.

1.02(b). Residence. The residence of the General Partner is its principal place of business at Park Place Corporate Center One, 1000 Commerce Drive, Suite 410, Pittsburgh, Pennsylvania 15275, which shall also serve as the principal place of business of the Partnership. The residence of each Participant shall be as set forth on the Subscription Agreement executed by the Participant. All addresses shall be subject to change on notice to the parties.

1.02(c). Agent for Service of Process. The name and address of the agent for service of process shall be The Corporation Service Company at 1209 Orange Street, Wilmington, Delaware 19801.

1.03. Purpose.

The purpose and nature of the business to be conducted by the Partnership shall be to (a) engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner, in its sole discretion, and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act; and (b) do anything necessary or appropriate to the foregoing; provided, however, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve, and may, in its sole discretion, decline to propose or approve, the conduct by the Partnership of any business, free of any duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to so propose or approve, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

 

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Table of Contents

ARTICLE II DEFINITION OF TERMS

2.01. Definitions.

As used in this Agreement, the following terms shall have the meanings set forth below:

“Acquisition” means any transaction in which any Group Member acquires (through an asset acquisition, merger, stock acquisition or other form of investment) control over all or a portion of the assets, properties or business of another Person for the purpose of increasing the asset base of the Partnership from the asset base of the Partnership existing immediately prior to such transaction.

“Additional Book Basis” means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events. For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:

 

  (a) Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Down Event or a Book-Up Event.

 

  (b) If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided that the amount treated as Additional Book Basis as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceeds the remaining Additional Book Basis attributable to all of the Partnership’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (b) to such Book-Down Event).

“Additional Book Basis Derivative Items” means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Partnership’s Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the “Excess Additional Book Basis”), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period. With respect to a Disposed of Adjusted Property, the Additional Book Basis Derivative Items shall be the amount of Additional Book Basis taken into account in computing gain or loss from the disposition of such Disposed of Adjusted Property; provided that the provisions of the immediately preceding sentence shall apply to the determination of the Additional Book Basis Derivative Items attributable to a Disposed of Adjusted Property.

“Adjusted Capital Account” means the Capital Account maintained for each Partner as of the end of each taxable year of the Partnership, (a) increased by any amounts that such Partner is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all adjustments that, as of the end of such taxable year, reasonably are expected to be made to such Partner’s Capital Account under Treasury Regulation Section 1.704-1(b)(2)(iv)(k) for depletion allowances with respect to oil and gas properties of the Partnership, (ii) the amount of all losses and deductions that, as of the end of such taxable year, reasonably are expected to be allocated to such Partner in subsequent years pursuant to Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (iii) the amount of all distributions that, as of the end of such taxable year, reasonably are expected to be made to such Partner in subsequent years in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Partner’s Capital Account that are reasonably expected to occur during (or prior to)

 

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the year in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to § 5.02(d)(i) or (d)(ii)). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Partner in respect of a GP Unit, a

Common Unit or an Incentive Distribution Right or any other Partnership Interest shall be the amount that such Adjusted Capital Account would be if such GP Unit, Common Unit, Incentive Distribution Right or other Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such GP Unit, Common Unit, Incentive Distribution Right or other Partnership Interest was first issued.

“Adjusted Operating Surplus” means, with respect to any period, (a) Operating Surplus generated with respect to such period (b) less (i) the amount of any net increase in Working Capital Borrowings with respect to such period and (ii) the amount of any net decrease in cash reserves for Operating Expenditures with respect to such period not relating to an Operating Expenditure made with respect to such period (it being understood that, in calculating the amount of Adjusted Operating Surplus in respect of any Subsidiary of the Partnership that is not directly or indirectly wholly owned by the Partnership, such cash reserves for Operating Expenditures by such Subsidiary shall be multiplied by a fraction, the numerator of which is the percentage of equity in such Subsidiary held directly or indirectly by the Partnership and the denominator of which is 100), and (c) plus (i) the amount of any net decrease in Working Capital Borrowings with respect to such period, (ii) the amount of any net increase in cash reserves for Operating Expenditures with respect to such period required by any debt instrument for the repayment of principal, interest or premium (it being understood that, in calculating the amount of Adjusted Operating Surplus in respect of any Subsidiary of the Partnership that is not directly or indirectly wholly owned by the Partnership, such cash reserves for Operating Expenditures by such Subsidiary shall be multiplied by a fraction, the numerator of which is the percentage of equity in such Subsidiary held directly or indirectly by the Partnership and the denominator of which is 100) and (iii) the amount of any net decrease made in subsequent periods in cash reserves for Operating Expenditures initially established with respect to such period to the extent such decrease results in a reduction in Adjusted Operating Surplus in subsequent periods pursuant to clause (b)(ii) above. Adjusted Operating Surplus does not include that portion of Operating Surplus included in clause (a)(i) of the definition of Operating Surplus.

“Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to §5.01(d)(1) or (d)(2).

“Administrative Costs” means all customary and routine expenses incurred by the Sponsor for the conduct of Partnership administration, including: in-house legal, finance, in-house accounting, secretarial, travel, office rent, telephone, data processing and other items of a similar nature. Administrative Costs shall be limited as follows:

 

  (i) no Administrative Costs charged shall be duplicated under any other category of expense or cost; and

 

  (ii) no portion of the salaries, benefits, compensation or remuneration of controlling persons of the General Partner shall be reimbursed by the Partnership as Administrative Costs. Controlling persons include directors, executive officers and those holding a 5% or more equity interest in the General Partner or a person having power to direct or cause the direction of the General Partner, whether through the ownership of voting securities, by contract, or otherwise.

“Administrator” means the official or agency administering the securities laws of a state.

“Affiliate” means with respect to a specific person:

 

  (i) any person directly or indirectly owning, controlling, or holding with power to vote 10% or more of the outstanding voting securities of the specified person;

 

  (ii) any person 10% or more of whose outstanding voting securities are directly or indirectly owned, controlled, or held with power to vote, by the specified person;

 

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  (iii) any person directly or indirectly controlling, controlled by, or under common control with the specified person;

 

  (iv) any officer, director, trustee or partner of the specified person; and

 

  (v) if the specified person is an officer, director, trustee or partner, any person for which the person acts in any such capacity.

“Aggregate Remaining Net Positive Adjustments” means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all the Partners.

“Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of § 5.02, including a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).

“Agreed Value” of any Contributed Property means the fair market value of such property or other consideration at the time of contribution and in the case of an Adjusted Property, the fair market value of such Adjusted Property on the date of the revaluation event as described in § 5.01(d), in both cases as determined by the General Partner. The General Partner shall use such method as it determines to be appropriate to allocate the aggregate Agreed Value of Contributed Properties contributed to the Partnership in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each Contributed Property.

“Agreement” means this First Amended and Restated Agreement of Limited Partnership, as it may be amended, supplemented or restated.

“Anthem Securities” means Anthem Securities, Inc., whose principal executive offices are located at Park Place Corporate Center One, 1000 Commerce Drive, Suite 410, Pittsburgh, Pennsylvania 15275.

“Assessments” means additional amounts of capital which may be mandatorily required of or paid voluntarily by a Participant beyond his subscription commitment.

“Asset Sale” has the meaning set forth in § 5.08.

“Atlas” means Atlas Growth Partners GP, LLC, a Delaware limited liability company, whose principal executive offices are located at Park Place Corporate Center One, 1000 Commerce Drive, Suite 410, Pittsburgh, Pennsylvania 15275, and any successor entity to Atlas Growth Partners GP, LLC, whether by merger or any other form of reorganization, or the acquisition of all, or substantially all, of Atlas Growth Partners GP, LLC’s assets.

“Available Cash” means, with respect to any Quarter ending prior to the date of Final Terminating Event,

 

  (a) the sum of:

 

  (i) all cash and cash equivalents (including amounts available for working capital purposes under a credit facility, commercial paper facility or other similar financing arrangement) of the Partnership on hand at the end of such Quarter (it being understood that, in calculating the amount of Available Cash in respect of a Subsidiary of the Partnership that is not directly or indirectly wholly owned by the Partnership, such cash and cash equivalents of such Subsidiary shall be multiplied by a fraction, the numerator of which is the percentage of equity in such Subsidiary held directly or indirectly by the Partnership and the denominator of which is 100); and

 

  (ii)

if the General Partner so determines in its sole discretion, all or any portion of additional cash and cash equivalents of the Partnership on hand on the date of determination of Available Cash with

 

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  respect to such Quarter resulting from borrowings (including Working Capital Borrowings) made subsequent to the end of such Quarter (it being understood that, in calculating the amount of Available Cash in respect of a Subsidiary of the Partnership that is not directly or indirectly wholly owned by the Partnership, such additional cash and cash equivalents of such Subsidiary shall be multiplied by a fraction, the numerator of which is the percentage of equity in such Subsidiary held directly or indirectly by the Partnership and the denominator of which is 100);

 

  (b) less the amount of any cash reserves established by the General Partner for the Partnership (it being understood that, in calculating the amount of Available Cash in respect of a Subsidiary of the Partnership that is not directly or indirectly wholly owned by the Partnership, such cash reserves established for such Subsidiary shall be multiplied by a fraction, the numerator of which is the percentage of equity in such Subsidiary held directly or indirectly by the Partnership and the denominator of which is 100) on the date of determination of Available Cash with respect to such Quarter, to:

 

  (i) provide for the proper conduct of the business of the Partnership (including reserves for working capital, operating expenses, future capital expenditures, potential acquisitions and for anticipated future credit needs of the Partnership);

 

  (ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which the Partnership is a party or by which it is bound or its assets are subject; or

 

  (iii) provide funds for distributions pursuant to §§ 5.05 or 5.06 with respect to any one or more of the next four Quarters;

provided, however, that the General Partner may not establish cash reserves pursuant to subclause (iii) above if the effect of such reserves would be that the Partnership is unable to distribute the Target Distribution on all Common Units and GP Units with respect to such Quarter; and provided further, that disbursements made by the Partnership or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Quarter if the General Partner so determines. Notwithstanding the foregoing, “Available Cash” with respect to the Quarter in which the Final Termination Event occurs and any subsequent Quarter shall equal zero.

“Board of Directors” means (i) if the General Partner is a corporation or a limited liability company, the General Partner’s board of directors or board of managers, as applicable, and (ii) if the General Partner is a limited partnership, the board of directors or board of managers, as applicable, of the general partner of the General Partner.

“Book Basis Derivative Items” means any item of income, deduction, gain or loss included in the determination of Net Income or Net Loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, depletion, or gain or loss with respect to an Adjusted Property).

“Book-Down Event” means an event that triggers a negative adjustment to the Capital Accounts of the Partners pursuant to § 5.01(d).

“Book-Tax Disparity” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for U.S. federal income tax purposes as of such date. A Partner’s share of the Partnership’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner’s Capital Account balance as maintained pursuant to § 5.01 and the hypothetical balance of such Partner’s Capital Account computed as if it had been maintained strictly in accordance with U.S. federal income tax accounting principles.

 

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“Book-Up Event” means an event that triggers a positive adjustment to the Capital Accounts of the Partners pursuant to § 5.01(d).

“Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the Commonwealth of Pennsylvania shall not be regarded as a Business Day.

“Capital Account” or “account” means the account established for each party, maintained as provided in § 5.01.

“Capital Contribution” means the amount agreed to be contributed to the Partnership by a Partner.

“Capital Expenditures” means those costs associated with property acquisition and the drilling and completion of oil and gas wells which are generally accepted as capital expenditures pursuant to the provisions of the Internal Revenue Code.

“Capital Improvement” means any (a) addition or improvement to the capital assets owned by any Group Member, (b) acquisition (through an asset acquisition, merger, stock acquisition or other form of investment) of existing, or construction of new or improvement or replacement of existing, capital assets (including undeveloped leasehold acreage, properties containing estimated proved reserves (whether or not producing) and other similar assets) or (c) capital contribution by a Group Member to a Person that is not a Subsidiary in which a Group Member has an equity interest, or after such capital contribution will have an equity interest, to fund such Group Member’s pro rata share of the cost of the addition or improvement to, the acquisition of existing, the construction of new or the improvement or replacement of existing capital assets by such Person, in each case if such addition, improvement, replacement, acquisition or construction is made to increase the asset base of the Partnership, in the case of clauses (a) and (b), or such Person, in the case of clause (c), from the asset base of the Partnership or such Person, as the case may be, existing immediately prior to such addition, improvement, replacement, acquisition or construction.

“Capital Surplus” has the meaning set forth in § 5.04(a).

“Carried Interest” means an equity interest in the Partnership issued to a Person without consideration, in the form of cash or tangible property, in an amount proportionately equivalent to that received from the Participants.

“Carrying Value” means (a) with respect to a Contributed Property or Adjusted Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, Simulated Depletion, amortization and cost recovery deductions charged to the Partners’ Capital Accounts in respect of such property, and (b) with respect to any other Partnership property, the adjusted basis of such property for U.S. federal income tax purposes, all as of the time of determination. The Carrying Value of any property shall be adjusted from time to time in accordance with § 5.01(d)(i) and (d)(ii) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

“Class A Common Unit” means a Common Unit having the rights and obligations specified with respect to Class A Common Units in this Agreement.

“Class T Common Unit” means a Common Unit having the rights and obligations specified with respect to Class T Common Units in this Agreement.

“Code” means the Internal Revenue Code of 1986, as amended.

 

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“Commences Commercial Service” and “Commencement of Commercial Service” shall mean the date on which a Capital Improvement or replacement asset begins producing in paying quantities or is first put into commercial service following completion of construction, acquisition, development and testing, as applicable.

“Common Unit” means a Partnership Interest representing a fractional part of the Partnership Interests held by all Limited Partners and by the General Partner (exclusive of the General Partner’s interest as a holder of the General Partner Interest, GP Units and Incentive Distribution Rights), which Partnership Interest may, but shall not be required to be, designated as a Class A Common Unit or a Class T Common Unit.

“Conflicts Committee” means a committee of the Board of Directors composed of one or more directors, each of whom (a) is not an officer or employee of the General Partner, (b) is not an officer, director or employee of any Affiliate of the General Partner, (c) is not a holder of any ownership interest in the General Partner or the Partnership, other than Common Units or other awards granted to such director under the Partnership’s equity compensation plans, and (d) meets the independence standards required of directors who serve on an audit committee of a board of directors established by the Securities Exchange Act and the rules and regulations of the SEC thereunder.

“Contributed Property” means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership (or deemed contributed to a new partnership on termination of the Partnership pursuant to Section 708 of the Code). Once the Carrying Value of a Contributed Property is adjusted pursuant to § 5.01(d), such property shall no longer constitute a Contributed Property but shall be deemed an Adjusted Property.

“Cost,” when used with respect to the sale or transfer of property to the Partnership from the Sponsor or an Affiliate, means:

 

  (i) the sum of the prices paid by the seller or transferor to an unaffiliated Person for the property, including bonuses;

 

  (ii) title insurance or examination costs, brokers’ commissions, filing fees, recording costs, transfer taxes, if any, and like charges in connection with the acquisition of the property;

 

  (iii) a pro rata portion of the seller’s or transferor’s actual necessary and reasonable expenses for seismic and geophysical services; and

 

  (iv) rentals and ad valorem taxes paid by the seller or transferor for the property to the date of its transfer to the buyer, interest and points actually incurred on funds used to acquire or maintain the property, and the portion of the seller’s or transferor’s reasonable, necessary and actual expenses for geological, geophysical, engineering, drafting, accounting, legal and other like services allocated to the property cost in conformity with generally accepted accounting principles and industry standards, except for expenses in connection with the past drilling of wells which are not producers of sufficient quantities of oil or gas to make commercially reasonable their continued operations, and provided that the expenses enumerated in this subsection (iv) shall have been incurred not more than 36 months before the sale or transfer to the Partnership.

“Cost,” when used with respect to services, means the reasonable, necessary and actual expense incurred by the provider on behalf of the Partnership in providing the services, determined in accordance with generally accepted accounting principles. As used elsewhere, “Cost” means the price paid by the seller in an arm’s-length transaction.

“Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of § 5.01(d)(x).

“Dealer-Manager” means Anthem Securities, Inc., an Affiliate of the General Partner, the broker/dealer which will manage the offering and sale of the Units.

 

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“Delaware Act” has the meaning set forth in § 1.01.

“Developed Reserves” means oil and gas reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

“Development Well” means a well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic Horizon known to be productive.

“Direct Costs” means all actual and necessary costs directly incurred for the benefit of the Partnership and generally attributable to the goods and services provided to the Partnership by parties other than the Sponsor or its Affiliates. Direct Costs may not include any cost otherwise classified as Organization and Offering Costs, Administrative Costs, Intangible Drilling Costs, Tangible Costs, Operating Costs, or costs related to the Leases, but may include the cost of services provided by the Sponsor or its Affiliates if the services are provided pursuant to written contracts and in compliance with § 4.03(d)(6) or pursuant to the General Partner’s role as Tax Matters Partner. Direct Costs shall be billed directly to and paid by the Partnership to the extent practicable.

“Disposed of Adjusted Property” has the meaning set forth in § 5.02(d)(xi)(B).

“Distribution and Unitholder Servicing Fee” has the meaning set forth in §3.03(b).

“Distribution Interest” means an undivided interest in the Partnership’s assets after payments to the Partnership’s creditors or the creation of a reasonable reserve therefor, in the ratio the positive balance of a party’s Capital Account bears to the aggregate positive balance of the Capital Accounts of all of the parties determined after taking into account all Capital Account adjustments for the taxable year during which liquidation occurs (other than those made pursuant to liquidating distributions or restoration of deficit Capital Account balances). Provided, however, after the Capital Accounts of all of the parties have been reduced to zero, the interest in the remaining Partnership assets shall equal a party’s interest in the related Partnership revenues as set forth in §5.01 and its subsections.

“Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752-2(a).

“Estimated Maintenance Capital Expenditures” means an estimate made in good faith by the Board of Directors of the average quarterly Maintenance Capital Expenditures that the Partnership will need to incur over the long term to maintain the levels of oil and natural gas production of the Partnership existing at the time the estimate is made. The Board of Directors will be permitted to make such estimate in any manner it determines reasonable. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of future Estimated Maintenance Capital Expenditures. The Partnership shall disclose to its Partners any change in the amount of Estimated Maintenance Capital Expenditures in its reports made in accordance with § 4.03(b) to the extent not previously disclosed. Any adjustments to Estimated Maintenance Capital Expenditures shall be prospective only.

“Expansion Capital Expenditures” means cash expenditures for Acquisitions or Capital Improvements. Expansion Capital Expenditures shall include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance the construction of a Capital Improvement and paid in respect of the period beginning on the date that a Group Member enters into a binding obligation to commence construction or development of a Capital Improvement and ending on the earlier to occur of the date that such Capital Improvement Commences Commercial Service or the date that such Capital Improvement is abandoned or disposed of. Debt incurred to fund such construction period interest payments or to fund distributions in respect of equity issued (including incremental Incentive Distributions related thereto) to fund the construction of a Capital Improvement as described in clause (a)(iv) of the definition of Operating Surplus shall also be deemed to be debt incurred to finance the construction of a Capital Improvement. Where capital expenditures are made in part for Expansion Capital Expenditures and in part for other purposes, the General Partner shall determine the allocation between the amounts paid for each.

 

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“Exploratory Well” means a well drilled to find and produce oil or gas in an unproved area, find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir. Generally, an exploratory well is any well that is not a developmental well, a service well, or a stratigraphic test well as those items are defined by the SEC.

“Farmout” means an agreement by the owner of the leasehold or Working Interest to assign his interest in certain acreage or well to the assignees, retaining some interest such as an Overriding Royalty Interest, an oil and gas payment, offset acreage or other type of interest, subject to the drilling of one or more specific wells or other performance as a condition of the assignment.

“Final Terminating Event” means any one of the following:

 

  (i) the expiration of the Partnership’s term;

 

  (ii) notice to the Participants by the General Partner of its election to terminate the Partnership’s affairs;

 

  (iii) notice by the Participants to the General Partner of their similar election through the affirmative vote of Participants whose Units equal a majority of the total Units; or

 

  (iv) the termination of the Partnership under Section 708(b)(1)(A) of the Code or the Partnership ceases to be a going concern.

“General Partner” means:

 

  (i) Atlas; or

 

  (ii) any Person admitted to the Partnership as a general partner who is designated to exclusively supervise and manage the operations of the Partnership.

“General Partner Interest” means the ownership interest of the General Partner in the Partnership (in its capacity as a general partner without reference to any Limited Partner Interest, including Incentive Distribution Rights or Common Units, held by it), which ownership interest is evidenced by Class A Units, and includes any and all benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement.

“GP Unit” means a fractional part of the General Partner Interest having the rights and obligations specified with respect to the General Partner Interest. A GP Unit is not a Unit.

“Gross Liability Value” means, with respect to any Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i), the amount of cash that a willing assignor would pay to a willing assignee to assume such Liability in an arm’s length transaction.

“Group Member” means each of the Partnership and its subsidiaries.

“Horizon” means a zone of a particular formation; that part of a formation of sufficient porosity and permeability to form a petroleum reservoir.

“Incentive Distribution Right” means a non-voting Limited Partner Interest issued to the General Partner pursuant to § 3.01, which Limited Partner Interest will confer upon the holder thereof only the rights and obligations specifically provided in this Agreement, as may be amended from time to time, with respect to Incentive Distribution Rights (and no other rights otherwise available to or other obligations of a holder of a Partnership Interest). Notwithstanding anything in this Agreement to the contrary, the holder of an Incentive Distribution Right shall not be entitled to vote such Incentive Distribution Right on any Partnership matter except as may otherwise be required by law.

 

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“Incentive Distributions” means any amount of cash distributed to the holder(s) of the Incentive Distribution Rights.

“Indemnitee” means (a) the General Partner, (b) any departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any departing General Partner, (d) any Person who is or was a manager, managing member, officer, director, employee, agent, fiduciary or trustee of any Group Member, the General Partner or any departing General Partner or any Affiliate of any Group Member, the General Partner or any departing General Partner, (e) any Person who is or was serving at the request of the General Partner or any departing General Partner or any Affiliate of the General Partner or any departing General Partner as a manager, managing member, officer, director, employee, agent, fiduciary or trustee of another Person; provided that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services; and (f) any Person that the General Partner designates as an “Indemnitee” for purposes of this Agreement.

“Independent Expert” means a person with no material relationship to the Sponsor or its Affiliates who is qualified and in the business of rendering opinions regarding the value of natural gas and oil properties based on the evaluation of all pertinent economic, financial, geologic and engineering information available to the Sponsor or its Affiliates.

“Initial Offering” means the initial offering of the Common Units, which was completed on the Initial Offering Termination Date.

“Initial Offering Initial Closing Date” means October 31, 2013.

“Initial Offering Termination Date” means June 30, 2015.

“Initial Unit Price” means (a) with respect to the Common Units sold in the Initial Offering, $10.00 per Common Unit, (b) with respect to the Common Units sold in the Second Offering, $10.00 per Common Unit or such other amount determined in accordance with § 3.04(d), and (c) for any other class or series of Partnership Interests, the price per Partnership Interest at which such class or series of Partnership Interest is initially sold by the Partnership, as determined by the General Partner, in each case adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of Partnership Interests.

“Intangible Drilling Costs” means those expenditures associated with property acquisition and the drilling and completion of natural gas and oil wells that under present law are generally accepted as fully deductible currently for federal income tax purposes. This includes:

 

  (i) all expenditures made for any well before production in commercial quantities for wages, fuel, repairs, hauling, supplies and other costs and expenses incident to and necessary for drilling the well and preparing the well for production of natural gas or oil, that are currently deductible pursuant to Section 263(c) of the Code and Treasury Regulations Section 1.612-4, and are generally termed “intangible drilling and development costs”;

 

  (ii) the expense of plugging and abandoning any well before a completion attempt; and

 

  (iii) the costs (other than Tangible Costs and Lease acquisition costs) to re-enter and deepen an existing well, complete the well to deeper reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper reservoirs.

“Interim Capital Transactions” means the following transactions if they occur prior to the date of a Final Terminating Event: (a) borrowings, refinancings or refundings of indebtedness (other than Working Capital Borrowings and other than for items purchased on open account in the ordinary course of business) by any Group Member and sales of debt securities of any Group Member; (b) issuances of equity interests of any Group

 

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Member; and (c) sales or other voluntary or involuntary dispositions of any assets of any Group Member other than (i) sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and (ii) sales or other dispositions of assets as part of normal retirements or replacements.

“Interim Closing Date” means those date(s) after the Initial Offering Initial Closing Date that the General Partner, in its sole discretion, admits Participants whose Subscription Agreements are accepted by the General Partner as Limited Partners.

“Investment Capital Expenditures” means capital expenditures other than Maintenance Capital Expenditures and Expansion Capital Expenditures.

“IRS” means the U.S. Internal Revenue Service.

“Landowner’s Royalty Interest” means an interest in production, or its proceeds, to be received free and clear of all costs of development, operation, or maintenance, reserved by a landowner on the creation of a Lease.

“Leases” means full or partial interests in natural gas and oil leases, oil and natural gas mineral rights, fee rights, licenses, concessions, drilling rights or other rights under which the holder, directly or indirectly, is entitled to explore for and produce oil and/or natural gas, and includes any contractual rights to acquire any such interest.

“Liability” means any liability or obligation of any nature, whether accrued, contingent or otherwise.

“Limited Partner Interest” means the ownership interest of a Limited Partner in the Partnership, which may be evidenced by Common Units, Incentive Distribution Rights or other Partnership Interests or a combination thereof or interest therein, and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner to comply with the terms and provisions of this Agreement; provided, however, that when the term “Limited Partner Interest” is used herein in the context of any vote or other approval, such term shall not, solely for such purpose, include any holder of an Incentive Distribution Right (solely with respect to its Incentive Distribution Rights and not with respect to any other Limited Partner Interest held by such Person), and that when the term “Limited Partner Interest” is used herein, such term shall not include any holder of a GP Unit or General Partner Interest (solely with respect to its GP Units and General Partner Interest), except as may otherwise be required by law.

“Limited Partners” means:

 

  (i) the Organizational Limited Partner;

 

  (ii) the Persons signing the Subscription Agreement as Limited Partners; and

 

  (iii) any other Persons who are admitted to the Partnership as additional or substituted Limited Partners.

All Limited Partners shall be of the same class and have the same rights.

“Listing Event” means the Partnership’s first listing of the Common Units on a National Securities Exchange.

“Maintenance Capital Expenditures” means cash expenditures, including expenditures for the addition or improvement to or replacement of the capital assets owned by any Group Member, or for the acquisition of existing, or the construction or development of new, capital assets, including replacement of equipment and oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage, properties containing estimated proved reserves and other similar assets), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property, including to offset expected production declines from producing properties, if such expenditures are made to maintain the levels of oil and natural gas production of the Partnership for the long term. Maintenance Capital

 

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Expenditures shall not include Expansion Capital Expenditures. Maintenance Capital Expenditures shall include interest (and related fees) on debt incurred and distributions on equity issued, in each case, to finance the construction or development of a replacement asset and paid in respect of the period beginning on the date that a Group Member enters into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date that such replacement asset Commences Commercial Service and the date that such replacement asset is abandoned or disposed of. Debt incurred to pay or equity issued to fund construction or development period interest payments, or such construction or development period distributions on equity, shall also be deemed to be debt or equity, as the case may be, incurred to finance the construction or development of a replacement asset.

“Merger” means the merger or consolidation of the Partnership with or into one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general or limited (including a limited liability partnership)) or conversion into any such entity.

“National Securities Exchange” means an exchange registered with the SEC under Section 6(a) of the Securities Exchange Act (or any successor to such Section) and any other securities exchange (whether or not registered with the SEC under Section 6(a) (or successor to such Section) of the Securities Exchange Act) that the General Partner shall designate as a National Securities Exchange for purposes of this Agreement.

“Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any Liabilities either assumed by the Partnership upon such contribution or to which such property is subject when contributed, and (b) in the case of any property distributed to a Partner by the Partnership, the Partnership’s Carrying Value of such property (as adjusted pursuant to § 5.01(d)(ii)) at the time such property is distributed, reduced by any Liability either assumed by such Partner upon such distribution or to which such property is subject at the time of distribution, in either case, as determined and required by the Treasury Regulations promulgated under Section 704(b) of the Code.

“Net Income” means, for any taxable period, the excess, if any, of the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Income shall be determined in accordance with § 5.01(b) and shall include Simulated Gain but shall not include any items specially allocated under §§ 5.02(d) or (e); provided that the determination of the items that have been specially allocated under § 5.02(d) shall be made as if § 5.02(d)(xii) were not in this Agreement.

“Net Loss” means, for any taxable period, the excess, if any, of the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Loss shall be determined in accordance with § 5.01(b) and shall include Simulated Gain but shall not include any items specially allocated under §§ 5.02(d) or (e); provided that the determination of the items that have been specially allocated under § 5.02(d) shall be made as if § 5.02(d)(xii) were not in this Agreement.

“Net Positive Adjustments” means, with respect to any Partner, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Partner pursuant to Book-Up Events and Book-Down Events.

“Net Termination Gain” means, for any taxable period, the sum, if positive, of all items of income, gain, loss or deduction recognized by the Partnership after the date of Final Terminating Event. The items included in

 

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the determination of Net Termination Gain shall be determined in accordance with § 5.01(b) and shall include Simulated Gain, but shall not include any items of income, gain or loss specially allocated under §§ 5.02(d) or (e).

“Net Termination Loss” means, for any taxable period, the sum, if negative, of all items of income, gain, loss or deduction recognized by the Partnership after the date of Final Terminating Event. The items included in the determination of Net Termination Loss shall be determined in accordance with § 5.01(b) and shall include Simulated Gain, but shall not include any items of income, gain or loss specially allocated under §§ 5.02(d) or (e).

“Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to §§ 5.03(c)(iii), (d)(i)(A), (d)(ii)(A) and (d)(iii) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

“Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(b)(1) and 1.704-2(c), are attributable to a Nonrecourse Liability.

“Nonrecourse Liability” has the meaning set forth in Treasury Regulation Section 1.704-2(b)(3).

“Operating Costs” means expenditures made and costs incurred in producing and marketing natural gas or oil from completed wells. These costs include, but are not limited to:

 

  (i) labor, fuel, repairs, hauling, materials, supplies, utility charges and other costs incident to or related to producing and marketing natural gas and oil;

 

  (ii) ad valorem and severance taxes;

 

  (iii) insurance and casualty loss expense; and

 

  (iv) compensation to well operators or others for services rendered in conducting these operations.

Operating Costs also include disposal and injection wells, transporting and treating water and other waste from the Partnership’s wells by pipeline, truck or barge, reworking, workover, subsequent equipping, and similar expenses relating to any well, gathering fees and the payment or reimbursement of the General Partner as set forth in § 4.03(d)(6).

“Operating Expenditures” means all cash expenditures of the Partnership (it being understood that, in calculating the amount of Operating Expenditures in respect of any Subsidiary of the Partnership that is not directly or indirectly wholly owned by the Partnership, such cash expenditures by such Subsidiary shall be multiplied by a fraction, the numerator of which is the percentage of equity in such Subsidiary held directly or indirectly by the Partnership and the denominator of which is 100), including taxes, reimbursements of expenses of the General Partner and its Affiliates, payments made in the ordinary course of business under hedge contracts, officer compensation, repayment of Working Capital Borrowings, debt service payments and Estimated Maintenance Capital Expenditures, subject to the following:

 

  (a) repayment of Working Capital Borrowings deducted from Operating Surplus pursuant to clause (b)(iii) of the definition of Operating Surplus shall not constitute Operating Expenditures when actually repaid;

 

  (b) payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than Working Capital Borrowings shall not constitute Operating Expenditures;

 

  (c)

Operating Expenditures shall not include (i) Expansion Capital Expenditures, (ii) actual Maintenance Capital Expenditures, (iii) Investment Capital Expenditures, (iv) payment of transaction expenses

 

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  (including taxes) relating to Interim Capital Transactions, (v) distributions to Partners (including distributions in respect of any Incentive Distributions Rights) or (vi) repurchases of Partnership Interests, other than repurchases of Partnership Interests to satisfy obligations under employee benefit plans, or reimbursements of expenses of the General Partner for such purchases.

“Operating Surplus” means, with respect to any period ending prior to the date of a Final Terminating Event, on a cumulative basis and without duplication,

 

  (a) the sum of (i) $60.0 million, (ii) all cash receipts of the Partnership (it being understood that, in calculating the amount of Operating Surplus in respect of any Subsidiary of the Partnership that is not directly or indirectly wholly owned by the Partnership, such cash receipts of such Subsidiary shall be multiplied by a fraction, the numerator of which is the percentage of equity in such Subsidiary held directly or indirectly by the Partnership and the denominator of which is 100) for the period beginning on the day following the Initial Offering Initial Closing Date and ending on the last day of such period, including Working Capital Borrowings but excluding cash receipts from Interim Capital Transactions, (iii) all cash receipts of the Partnership (it being understood that, in calculating the amount of Operating Surplus in respect of any Subsidiary of the Partnership that is not directly or indirectly wholly owned by the Partnership, such cash receipts of such Subsidiary shall be multiplied by a fraction, the numerator of which is the percentage of equity in such Subsidiary held directly or indirectly by the Partnership and the denominator of which is 100) after the end of such period but on or before the date of determination of Operating Surplus with respect to such period resulting from Working Capital Borrowings and (iv) the amount of cash distributions paid on equity issued (including incremental incentive distributions) to finance all or a portion of the construction, acquisition, development or improvement of a Capital Improvement or replacement of a capital asset (such as equipment or reserves) and paid in respect of the period beginning on the date that the Group Member enters into a binding obligation to commence the construction, acquisition, development, replacement or improvement of a Capital Improvement or replacement of a capital asset and ending on the earlier to occur of the date the Capital Improvement or capital asset Commences Commercial Service or the date that it is abandoned or disposed of (equity issued to fund construction period interest payments on debt incurred (including periodic net payments under related interest rate swap agreements), or construction period distributions on equity issued, including incremental incentive distributions, to finance the construction, acquisition, development or improvement of a Capital Improvement or replacement of a capital asset shall also be deemed to be equity issued to finance the construction, acquisition, development, replacement or improvement of a Capital Improvement or replacement of a capital asset for purposes of this clause (iv)); less

 

  (b) the sum of (i) Operating Expenditures for the period beginning on the day following the Initial Offering Initial Closing Date and ending on the last day of such period, (ii) the amount of cash reserves established by the General Partner for the Partnership (it being understood that, in calculating the amount of Operating Surplus in respect of any Subsidiary of the Partnership that is not directly or indirectly wholly owned by the Partnership, such cash reserves for such Subsidiary shall be multiplied by a fraction, the numerator of which is the percentage of equity in such Subsidiary held directly or indirectly by the Partnership and the denominator of which is 100) to provide funds for future Operating Expenditures, (iii) all Working Capital Borrowings not repaid within twelve months after having been incurred or repaid within such 12-month period with the proceeds of additional Working Capital Borrowings and (iv) any cash loss realized on the disposition of an Investment Capital Expenditure;

provided, however, that disbursements made (including contributions to a Group Member or disbursements on behalf of a Group Member) or cash reserves established, increased or reduced after the end of such period but on or before the date of determination of Available Cash with respect to such period shall be deemed to have been made, established, increased or reduced, for purposes of determining Operating Surplus, within such period if the

 

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General Partner so determines. Notwithstanding the foregoing, “Operating Surplus” with respect to the Quarter in which the Final Termination Event occurs and any subsequent Quarter shall equal zero.

“Organization and Offering Costs” means all costs of organizing and selling the Common Units in the Second Offering including, but not limited to:

 

  (i) total underwriting and brokerage discounts and commissions, including fees of the underwriters’ attorneys, the Dealer-Manager fee, sales commissions and reimbursement for bona fide due diligence expenses;

 

  (ii) expenses for printing, engraving, mailing, salaries of employees while engaged in sales activities, charges of transfer agents, registrars, trustees, escrow holders, depositaries, engineers and other experts;

 

  (iii) expenses of qualification of the sale of the securities under federal and state law, including taxes and fees, accountants’ and attorneys’ fees; and

 

  (iv) other front-end fees.

“Organization Costs” means all costs of organizing the offering including, but not limited to:

 

  (i) expenses for printing, engraving, mailing, salaries of employees while engaged in sales activities, charges of transfer agents, registrars, trustees, escrow holders, depositaries, engineers and other experts;

 

  (ii) expenses of qualification of the sale of the securities under federal and state law, including taxes and fees, accountants’ and attorneys’ fees; and

 

  (iii) other front-end fees.
 

“Organizational Limited Partner” means Atlas Energy, LP, predecessor to Atlas Energy Group, LLC, in its capacity as the organizational limited partner of the Partnership.

“Overriding Royalty Interest” means an interest in the natural gas and oil produced under a Lease, or the proceeds from the sale thereof, carved out of the Working Interest, to be received free and clear of all costs of development, operation, or maintenance.

“Participant List” has the meaning set forth in § 4.03(b)(6)(i).

“Participants” means the Limited Partners.

“Partner Nonrecourse Debt” has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).

“Partner Nonrecourse Debt Minimum Gain” has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).

“Partner Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(i)(1) and 1.704-2(i)(2), are attributable to a Partner Nonrecourse Debt.

“Partners” means the General Partner and the Limited Partners.

“Partnership” means Atlas Growth Partners, L.P. and, when appropriate, its Subsidiaries, treated as a consolidated entity.

 

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“Partnership Interest” means any equity interest in the Partnership, which shall include any General Partner Interest and Limited Partner Interests but shall exclude options, warrants, rights and appreciation rights relating to an equity interest in the Partnership.

“Partnership Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulation Section 1.704-2(b)(2) and 1.704-2(d).

“Partnership Representative” has the meaning set forth in Section 6223 of the Code, as amended by the Bipartisan Budget Act of 2015 (the “2015 Act”).

“Partnership Well” means a well, some portion of the revenues from which is received by the Partnership.

“Per Unit Capital Amount” means, as of any date of determination, the Capital Account, stated on a per Unit basis, underlying any Partnership Interest held by a Person other than the General Partner or any Affiliate of the General Partner who holds Partnership Interests.

“Percentage Interest” means as of any date of determination, (a) as to any holder of GP Units, the Percentage Interest attributable to such GP Units shall equal the product obtained by multiplying (i) 100% less the percentage applicable to clause (c) below by (ii) the quotient obtained by dividing (x) the number of GP Units held by such holder by (y) the sum of the total number of all outstanding Common Units and the total number of outstanding GP Units; (b) as to any holder of Common Units, the Percentage Interest attributable to such Common Units shall equal the product obtained by multiplying (i) 100% less the percentage applicable to clause (c) below by (ii) the quotient obtained by dividing (x) the number of Common Units held by such holder by (y) the sum of the total number of all outstanding Common Units and the total number of outstanding GP Units; and (c) as to the holders of additional Partnership Interests issued by the Partnership in accordance with § 4.07, the percentage established as a part of such issuance. Unless the context otherwise requires, references to the Percentage Interest of any holder of more than one class or series of Partnership Interests shall mean the aggregate Percentage Interest attributable to all such Partnership Interests. The Percentage Interest with respect to an Incentive Distribution Right shall at all times be zero.

“Person” means a natural person, partnership, corporation, association, trust or other legal entity.

“Production Purchase” or “Income Program” means any program whose investment objective is to directly acquire, hold, operate, and/or dispose of producing oil and gas properties. Such a program may acquire any type of ownership interest in a producing property, including, but not limited to, working interests, royalties, or production payments. A program which spends at least 90% of capital contributions and funds borrowed (excluding offering and organizational expenses) in the above described activities is presumed to be a production purchase or income program.

“Program” means one or more limited or general partnerships or other investment vehicles formed, or to be formed, for the primary purpose of:

 

  (i) exploring for natural gas, oil and other hydrocarbon substances; or

 

  (ii) investing in or holding any property interests which permit the exploration for or production of hydrocarbons or the receipt of such production or its proceeds.

“Pro Rata” means (a) when used with respect to Partnership Interests or any class or classes thereof, apportioned equally among all designated Partnership Interests in accordance with their relative Percentage Interests, (b) when used with respect to Partners or Record Holders, apportioned among all Partners or Record Holders in accordance with their relative Percentage Interests and (c) when used with respect to holders of Incentive Distribution Rights, apportioned equally among all holders of Incentive Distribution Rights in accordance with the relative number or percentage of Incentive Distribution Rights held by each such holder.

 

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“Prospect” means an area covering lands which are believed by the General Partner to contain subsurface structural or stratigraphic conditions making it susceptible to the accumulations of hydrocarbons in commercially productive quantities at one or more Horizons. The area, which may be different for different Horizons, shall be:

 

  (i) designated by the General Partner in writing before the conduct of Partnership operations thereon; and

 

  (ii) enlarged or contracted from time to time on the basis of subsequently acquired information to define the anticipated limits of the associated hydrocarbon reserves and to include all acreage encompassed therein.

Subject to the above, “Prospect” will be deemed the following in the following areas:

 

  (i) in the Eagle Ford Shale primary area in southern, Texas, the wellbore plus 125 feet on either side of the center line of a lateral in the well extending from the beginning of the first perforation to the end of the last perforation and from the base of the Austin Chalk to the top of the Buda Formation;

 

  (ii) in the Marble Falls primary area in north-central Texas, approximately 40 acres for vertical oil wells and approximately 160 acres for vertical natural gas wells, and will further be limited to the deepest depth penetrated at the cessation of drilling activities and as adjusted to take into account lease boundaries; and

 

  (iii) for horizontal wells in the Mississippi Lime primary area in northern Oklahoma, the wellbore plus 125 feet on either side of the center line of a lateral in the well, extending from the beginning of the first perforation to the end of the last perforation and from the bottom of the Mississippi Unconformity to the top of the Kinderhook formation, subject to any limited under Oklahoma law and as adjusted to take into account lease boundaries.

If the well to be drilled by the Partnership is to a Horizon containing Proved Reserves, then a “Prospect” for a particular Horizon may be limited to the minimum area permitted by state law or local practice, whichever is applicable, to protect against drainage from adjacent wells. Notwithstanding, a horizontal well may be drilled on the well pad on a Prospect on which another Partnership Well is drilled.

“Prospectus” means the Prospectus included in the Registration Statement for the Partnership on Form S-1 relating to the offer and sale of the Units which has been filed with the SEC under the Securities Act of 1933. As used in this Agreement, the terms “Prospectus” and “Registration Statement” refer solely to the Prospectus and Registration Statement, as amended, described above, except that:

 

  (i) from and after the date on which any post-effective amendment to the Registration Statement is declared effective by the SEC, the term “Registration Statement” shall refer to the Registration Statement as amended by that post-effective amendment, and the term “Prospectus” shall refer to the Prospectus then forming a part of the Registration Statement; and

 

  (ii) if the Prospectus filed pursuant to Rule 424(b) or (c) promulgated by the SEC under the Securities Act of 1933 differs from the Prospectus on file with the SEC at the time the Registration Statement or any post-effective amendment thereto shall have become effective, the term “Prospectus” shall refer to the Prospectus filed pursuant thereto from and after the date on which it was filed.

“Proved Reserves” means those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

  (i) The area of the reservoir considered as proved includes:

 

  (a) the area identified by drilling and limited by fluid contacts, if any; and

 

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  (b) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

  (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

  (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

  (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification

when:

 

  (a) successful testing by a pilot project, in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

 

  (b) the project has been approved for development by all necessary parties and entities, including governmental entities.

 

  (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“Proved Undeveloped Reserves” means reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

“Quarter” means, unless the context requires otherwise, a fiscal quarter of the Partnership.

“Recapture Income” means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

“Record Date” means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

 

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“Record Holder” means (a) with respect to Partnership Interests of any class for which a Transfer Agent has been appointed, the Person in whose name a Partnership Interest of such class is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day or (b) with respect to other classes of Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the opening of business on such Business Day.

“Reinvestment Plan” has the meaning set forth in § 5.10.

“Remaining Net Positive Adjustments” means as of the end of any taxable period, (i) with respect to the Unitholders, the excess of (a) the Net Positive Adjustments of the Unitholders as of the end of such period over (b) the sum of those Partners’ Share of Additional Book Basis Derivative Items for each prior taxable period, (ii) with respect to the General Partner (as holder of the GP Units), the excess of (a) the Net Positive Adjustments of the General Partner as of the end of such period over (b) the sum of the General Partner’s Share of Additional Book Basis Derivative Items with respect to the GP Units for each prior taxable period, and (iii) with respect to the holders of Incentive Distribution Rights, the excess of (a) the Net Positive Adjustments of the holders of Incentive Distribution Rights as of the end of such period over (b) the sum of the Share of Additional Book Basis Derivative Items of the holders of the Incentive Distribution Rights for each prior taxable period.

“Required Allocations” means any allocation of an item of income, gain, loss, deduction, Simulated Depletion or Simulated Loss pursuant to §§5.02(d)(i), (d)(ii), (d)(iv), (d)(v), (d)(vi), (d)(vii), or (d)(ix).

“Reserves” means estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Residual Gain” or “Residual Loss” means any item of gain or loss, or Simulated Gain or Simulated Loss, as the case may be, of the Partnership recognized for U.S. federal income tax purposes resulting from a sale, exchange or other disposition of a Contributed Property or Adjusted Property, to the extent such item of gain or loss or Simulated Gain or Simulated Loss is not allocated pursuant to §§ 5.03(d)(i)(A) or (d)(ii)(A), respectively, to eliminate Book-Tax Disparities.

“Roll-Up” means a transaction involving the acquisition, merger, conversion or consolidation, either directly or indirectly, of the Partnership and the issuance of securities of a Roll-Up Entity. The term does not include:

 

  (i) a transaction involving securities of the Partnership that have been listed for at least 12 months on a National Securities Exchange; or

 

  (ii) a transaction involving the conversion to corporate, trust or association form of only the Partnership if, as a consequence of the transaction, there will be no significant adverse change in any of the following:

 

  (a) voting rights;

 

  (b) the Partnership’s term of existence;

 

  (c) the General Partner’s compensation; and

 

  (d) the Partnership’s investment objectives; or

 

  (iii) a transaction involving the issuance of securities of any entity where securities of the same class have been listed for at least 12 months on a National Securities Exchange.

“Roll-Up Entity” means a partnership, trust, corporation or other entity that would be created or survive after the successful completion of a proposed roll-up transaction.

 

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“Sales Commissions” means all cash underwriting and brokerage discounts and commissions incurred in the sale of Units payable to registered broker/dealers, but excluding the following:

 

  (i) the 3% Dealer-Manager fee, which must be paid in cash; and

 

  (ii) the reimbursement for bona fide due diligence expenses.

“Second Offering” means the Partnership’s first public offering of the Common Units.

“SEC” means the U.S. Securities and Exchange Commission.

“Selling Agents” means the broker/dealers which are selected by the Dealer-Manager to participate in the offer and sale of the Common Units.

“Share of Additional Book Basis Derivative Items” means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (i) with respect to the Unitholders, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such taxable period bears to the Aggregate Remaining Net Positive Adjustments as of that time, (ii) with respect to the General Partner (as holder of the GP Units), the amount that bears the same ratio to such Additional Book Basis Derivative Items as the General Partner’s Remaining Net Positive Adjustments as of the end of such taxable period bears to the Aggregate Remaining Net Positive Adjustment as of that time, and (iii) with respect to the Partners holding Incentive Distribution Rights, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Remaining Net Positive Adjustments of the Partners holding the Incentive Distribution Rights as of the end of such taxable period bears to the Aggregate Remaining Net Positive Adjustments as of that time.

“Simulated Basis” means the Carrying Value of any oil and gas property (as defined in Section 614 of the Code).

“Simulated Depletion” means, with respect to an oil and gas property (as defined in Section 614 of the Code), a depletion allowance computed in accordance with U.S. federal income tax principles (as if the Simulated Basis of the property was its adjusted tax basis) and in the manner specified in Treasury Regulation Section 1.704-1(b)(2)(iv)(k)(2). For purposes of computing Simulated Depletion with respect to any property, the Simulated Basis of such property shall be deemed to be the Carrying Value of such property, and in no event shall such allowance for Simulated Depletion, in the aggregate, exceed such Simulated Basis.

“Simulated Gain” means the excess, if any, of the amount realized from the sale or other disposition of an oil or gas property over the Carrying Value of such property.

“Simulated Loss” means the excess, if any, of the Carrying Value of an oil or gas property over the amount realized from the sale or other disposition of such property.

“Special Approval” means approval by a majority of the members of the Conflicts Committee.

“Sponsor” means any person directly or indirectly instrumental in organizing, wholly or in part, a Program or any Person who will manage or is entitled to manage or participate in the management or control of a Program. The definition includes the managing and controlling general partner(s) and any other Person who actually controls or selects the Person who controls 25% or more of the exploratory, developmental or producing activities of the Program, or any segment thereof, even if that Person has not entered into a contract at the time of formation of the Program. “Sponsor” does not include wholly independent third-parties such as attorneys, accountants, and underwriters whose only compensation is for professional services rendered in connection with the offering of Units. Whenever the context of this agreement so requires, the term “Sponsor” shall be deemed to include its affiliates.

“Subscription Agreement” means an execution and subscription instrument in the form attached as Exhibit (I-B) to this Agreement, which is incorporated in this Agreement by reference.

 

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“Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation or partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

“Tangible Costs” means those costs associated with property acquisition and drilling and completing natural gas and oil wells which are generally accepted as capital expenditures under the Code. This includes all of the following:

 

  (i) costs of equipment, parts and items of hardware used in drilling and completing a well;

 

  (ii) the costs (other than Intangible Drilling Costs and Lease acquisition costs) to re-enter and deepen an existing well, complete the well to deeper reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper reservoirs; and

 

  (iii) those items necessary to deliver acceptable natural gas and oil production to purchasers to the extent installed downstream from the wellhead of any well and which are required to be capitalized under the Code and its regulations.

“Target Distribution” means an amount equal to $0.175 per Common Unit and GP Unit per Quarter (or with respect to periods of less than a full fiscal quarter, it means the product of $0.175 multiplied by a fraction, the numerator of which is the number of days in such period and the denominator of which is the total number of days in such fiscal quarter), subject to adjustment in accordance with this Agreement.

“Tax Matters Partner” means the General Partner.

“Treasury Regulations” means the regulations promulgated by the U.S. Treasury Department interpreting the Code.

“Undeveloped Reserves” means reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion, provided that:

 

  (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

  (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

 

  (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

“Unit” means a Partnership Interest that is designated as a “Unit” and shall include Common Units but shall not include (a) GP Units (or the General Partner Interest represented thereby) or (b) Incentive Distribution Rights.

 

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“Unitholders” means the holders of Partnership Interests.

“Unrealized Gain” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under § 5.01(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to § 5.01(d) as of such date).

“Unrealized Loss” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to § 5.01(d) as of such date) over (b) the fair market value of such property as of such date (as determined under § 5.01(d)).

“Working Capital Borrowings” means borrowings of the Partnership (it being understood that, in calculating the amount of Working Capital Borrowings in respect of any Subsidiary of the Partnership that is not directly or indirectly wholly owned by the Partnership, such borrowings by such Subsidiary shall be multiplied by a fraction, the numerator of which is the percentage of equity in such Subsidiary held directly or indirectly by the Partnership and the denominator of which is 100) made pursuant to a credit facility, commercial paper facility or other similar financing arrangement that are used solely for working capital purposes or to pay distributions to the Partners; provided that when such borrowings are incurred it is the intent of the borrower to repay such borrowings within 12 months from the date of such borrowings from sources other than additional Working Capital Borrowings.

“Working Interest” means an interest in a Lease which is subject to some portion of the cost of development, operation, or maintenance of the Lease.

ARTICLE III UNITS, SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS

3.01. Designation of General Partner and Participants.

In connection with the formation of the Partnership under the Delaware Act, the General Partner made an initial Capital Contribution to the Partnership in the amount of $1,000 in exchange for a General Partner Interest consisting of GP Units representing a General Partner Interest with a Percentage Interest of 2%, subject to all of the rights, privileges and duties of the General Partner under this Agreement, and the Incentive Distribution Rights, and was admitted as the General Partner of the Partnership.

In order to create an identity of interest with the participants, Atlas Energy Group, LLC, the parent company of the General Partner, purchased $5,000,000 of the Partnership’s Common Units in the Initial Offering at the public offering price of $10.00 per Common Unit.

3.02. Limited Partner at Formation.

Atlas Energy, LP, predecessor to Atlas Energy Group, LLC, as Organizational Limited Partner, has acquired ten Common Units and has made a Capital Contribution of $100.

3.03. Classes of Common Units.

The Common Units issuable in the Second Offering shall be of two classes: (i) Class A Common Units and (ii) Class T Common Units, and such classes of Common Units shall have the commissions and fees set forth in this § 3.03. Other than with respect to such commissions and fees, each of the Class A Common Units and Class T Common Units shall have the rights and obligations with respect to a Common Unit hereunder.

3.03(a). Class A Common Units. Each Class A Common Unit issued in the Second Offering shall be subject to a 3% Dealer-Manager fee and the 7% Sales Commission, which compensation is subject to change in subsequent offerings. No Dealer-Manager fee or Sales Commissions shall be paid with respect to any Class A Common Unit issued pursuant to the Reinvestment Plan.

 

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3.03(b). Class T Common Units. Each Class T Common Unit issued in the Second Offering shall be subject to a 3% Dealer-Manager fee and a 3% Sales Commission, which compensation is subject to change in subsequent offerings. In addition, with respect to Class T Common Units, the Partnership shall pay to the Dealer-Manager a distribution and unitholder servicing fee, which amount will be withheld from cash distributions otherwise payable to the purchasers of Class T Common Units at a rate of $0.025 per quarter per Class T Common Unit (the “Distribution and Unitholder Servicing Fee”). The Partnership will cease paying the Distribution and Unitholder Servicing Fee with respect to any particular Class T Common Unit and that Class T Common Unit will convert into a Class A Common Unit by multiplying each Class T Common Unit to be converted by the conversion rate described herein on the earlier of (i) a Listing Event; (ii) a Merger or Asset Sale and (iii) the end of the month in which the underwriting compensation paid in the primary offering plus the Distribution and Unitholder Servicing Fee paid with respect to that Class T Common Unit equals 10% of the gross offering price of that Class T Common Unit. The Partnership will also cease paying the Distribution and Unitholder Servicing Fee on any Class T Common Unit that is redeemed or repurchased, as well as upon our dissolution, liquidation or the winding up of our affairs, or a merger or other extraordinary transaction in which the Partnership is a party and in which the Class T common units as a class are exchanged for cash or other securities. The conversion rate will be equal to the quotient, the numerator of which is the estimated value per Class T Common Unit (including any reduction for the distribution and unitholder servicing fee as described herein) and the denominator of which is the estimated value per Class A Common Unit. Such Distribution and Unitholder Servicing Fee, together with all other underwriting compensation, may not exceed statutory limits of underwriting compensation and the Partnership can cancel such Distribution and Unitholder Servicing Fee upon the occurrence of a Merger, Asset Sale or Listing Event.

3.04. Subscriptions to the Second Offering.

3.04(a). Subscriptions by Participants.

3.04(a)(1). Subscription Price and Minimum Subscription. The subscription price of a Common Unit in the Second Offering shall be the Initial Unit Price, except as set forth below, and shall be payable as set forth in § 3.06. The minimum subscription per Participant with respect to the Second Offering shall be 500 Common Units ($5,000). Subscriptions greater than $5,000 will be accepted in $1,000 increments. All subscribers’ funds shall be held in an interest bearing account or accounts by an independent escrow holder and shall not be released to the Partnership until the receipt and acceptance of the minimum amount of subscription proceeds set forth in §3.04(b). Thereafter, subscriptions may be paid directly to a Partnership account. Notwithstanding the foregoing, the subscription price for (i) the General Partner, its officers, directors, and Affiliates will be reduced by an amount not to exceed the 3% Dealer-Manager fee and the 7% Sales Commission, which shall not be paid with respect to those sales; (ii) Participants who buy Common Units through the officers and directors of the General Partner will be reduced by an amount not to exceed the 3% Dealer-Manager fee and the 7% Sales Commission, which shall not be paid with respect to those sales; (iii) registered investment advisors and their clients will be reduced by an amount not to exceed the 7% Sales Commission, which shall not be paid with respect to those sales; and (iv) selling agents and their registered representatives and principals will be reduced by an amount not to exceed the 7% Sales Commission, which shall not be paid with respect to those sales.

3.04(a)(2). Effect of Subscription. Execution of a Subscription Agreement shall serve as an agreement by the Participant to be bound by each and every term of this Agreement.

3.04(b). Minimum Number of Common Units. The minimum number of Common Units available in the Second Offering shall equal at least 100,000 Common Units, but in any event not less than the number of Common Units that provides the Partnership with cash subscription proceeds of $1,000,000, including common units purchased by the General Partner and its Affiliates. If subscriptions for the minimum number of Common Units have not been received and accepted on or before the date that is two years from the effective date of the prospectus for the Second Offering (as the same may be extended by the General Partner, in its discretion, for a maximum aggregate additional 180 days), then all monies deposited by subscribers shall be promptly returned to

 

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them. They shall receive interest earned on their subscription proceeds from the date the monies were deposited in escrow through the date of refund, without deduction for any fees. The Partnership may break escrow, in the General Partner’s sole discretion, on receipt and acceptance of the minimum subscription proceeds.

3.04(c). Acceptance of Subscriptions to the Second Offering.

3.04(c)(1). Discretion by the General Partner. Acceptance of subscriptions is discretionary with the General Partner. The General Partner may reject any subscription for any reason it deems appropriate.

3.04(c)(2). Time Period in Which to Accept Subscriptions. Subscriptions shall be accepted or rejected by the General Partner within 30 days of their receipt. If a subscription is rejected, then all of the subscriber’s funds shall be returned to the subscriber promptly, with interest earned and without deduction for any fees.

3.04(c)(3). Admission to the Partnership. The Participants shall be admitted to the Partnership as follows:

 

  (i) not later than 15 days after the release from the escrow account of Participants’ subscription proceeds to the Partnership; or

 

  (ii) if a Participant’s subscription proceeds are received by the Partnership after the close of the escrow account, then not later than the last day of the calendar month in which his Subscription Agreement was accepted by the General Partner.

3.04(d). Increase in Initial Unit Price for Second Offering. The General Partner shall be permitted, but not required, to increase the Initial Unit Price per Common Unit for the Second Offering following any material change to the Partnership’s business, assets or operations that increases the value of the Partnership, as determined by an independent expert in the valuation of oil and gas assets.

3.05. No Additional Capital Contributions of the General Partner or Dilution.

3.05(a). The Percentage Interest represented by all of the outstanding GP Units shall at all times be equal to 2%, regardless of any issuance of any Limited Partner Interests or Units by the Partnership, and the General Partner shall not be obligated to make any capital contribution to the Partnership in order for such GP Units to represent such Percentage Interest.

3.05(b). The parties intend that each GP Unit shall represent the same Percentage Interest as one Unit. Accordingly, upon issuance of any Limited Partner Interests or Units by the Partnership, the Partnership will automatically issue to the General Partner, without further consideration or any requirement of capital contribution by the General Partner, a number of GP Units so that the total number of outstanding GP Units after such issuance equals 2% of the sum of (i) the total number of outstanding Units after such issuance and (ii) the total number of outstanding GP Units after such issuance.

3.05(c). General Partner’s Right to Assign Its Partnership Interest. Prior to the tenth anniversary of the Initial Offering Initial Closing Date, the General Partner shall not transfer all or any part of its General Partner Interest (represented by GP Units) to a Person unless such transfer (i) has been approved by the prior written consent or vote of the holders of at least a majority of the outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) or (ii) is of all, but not less than all, of its General Partner Interest to (A) an Affiliate of the General Partner (other than an individual) or (B) another Person (other than an individual) in connection with the merger or consolidation of the General Partner with or into another Person or the transfer by the General Partner of all or substantially all of its assets to another Person. On or after the tenth anniversary of the Initial Offering Initial Closing Date, the General Partner may transfer all or any part of its General Partner Interest (represented by GP Units) to any Person without Unitholder approval. Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest (represented by GP Units) to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this

 

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Agreement, (ii) the Partnership receives an opinion of counsel that such transfer would not result in the loss of limited liability of any Limited Partner under the Delaware Act or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or membership interest of the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to and in compliance with this § 3.05(c), the transferee or successor (as the case may be) shall be admitted to the Partnership as the General Partner effective immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution. No transfer of the General Partner’s interest in the Partnership to its Affiliates under this § 3.05(c) shall require an accounting by the General Partner or the Partnership to the Participants.

3.06. Payment of Subscriptions

A Participant shall pay the subscription amount designated on his Subscription Agreement 100% in cash at the time of subscribing.

3.07. Partnership Funds.

3.07(a). Fiduciary Duty. The General Partner has a fiduciary responsibility for the safekeeping and use of all funds and assets of the Partnership, whether or not in the General Partner’s possession or control. The General Partner shall not employ, or permit another to employ, the funds and assets of the Partnership in any manner except for the exclusive benefit of the Partnership.

The fiduciary duty owed by the General Partner to Limited Partners will not be contractually limited, except for:

 

  (i) indemnification of the General Partner and affiliates as described in §4.05;

 

  (ii) devotion of the General Partner’s time to the Partnership as described in §4.06(a);

 

  (iii) the General Partner conducting business with the Partnership other than as General Partner as described in §4.06(a);

 

  (iv) the General Partner’s pursuit of business opportunities as described in §4.06(a); and

 

  (v) the General Partner’s management of multiple programs simultaneously as described in §4.06(b).

3.07(b). Special Account After the Receipt of the Minimum Partnership Subscriptions. Following the receipt of the minimum amount of subscriptions and breaking escrow, the funds of the Partnership shall be held in a separate interest- bearing account maintained for the Partnership and shall not be commingled with funds of any other entity.

3.07(c). Advance Payments. Advance payments to the General Partner or its Affiliates are prohibited, except where necessary to secure tax benefits of prepaid drilling costs. These payments, if any, shall not include nonrefundable payments for completion costs prior to the time that a decision is made that the well or wells warrant a completion attempt.

3.07(d). Return of Capital. Any proceeds of any offering of Units of the Partnership not used, or committed for use, as evidenced by a written agreement, in the Partnership’s operations within one year of the termination date of such offering, except for necessary operating capital, must be distributed to the Unitholders Pro Rata as a return of capital, and the General Partner shall reimburse the Unitholders for selling, management fees and offering expenses allocable to the return of capital.

 

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ARTICLE IV CONDUCT OF OPERATIONS

4.01 Acquisition of Leases.

4.01(a)(1). In General. The General Partner shall select, acquire and assign or cause to have assigned to the Partnership full or partial interests in Leases by any method customary in the natural gas and oil industry, subject to the terms and conditions set forth below. The Partnership may acquire and develop interests in Leases covering one or more of the same Prospects, in the General Partner’s discretion.

4.01(a)(2). Federal and State Leases. The Partnership is authorized to acquire Leases on federal and state lands.

4.01(a)(3). General Partner’s Discretion as to Terms and Burdens of Acquisition. Subject to the provisions of § 4.03(d), the acquisitions of Leases or other property may be made under any terms and obligations, including any limitations as to the Horizons to be assigned to the Partnership and subject to any burdens as the General Partner deems necessary in its sole discretion. Subject to § 4.03(d), wellbore assignments from the General Partner or its Affiliates to the Partnership in the case of Prospects on which horizontal wells will be drilled are expressly authorized in the General Partner’s discretion.

4.01(a)(4). Cost of Leases. Subject to § 4.02(b)(3), all Leases sold to the Partnership by the General Partner or its Affiliates, including those from the General Partner’s or an affiliate’s existing inventory, if any, shall be sold on terms that are fair and reasonable to the Unitholders. All Leases sold to the Partnership by the General Partner or its Affiliates shall be sold at the Cost of the Lease, unless the General Partner has cause to believe that Cost is materially more than the fair market value of the Lease, in which case the Lease must be sold to the Partnership at a price not in excess of the fair market value. However, if the transfer is from an affiliated Partnership that has held the Lease for more than two years, then the transfer may be made at fair market value if the General Partner’s interest is substantially similar to, or less than, its interest in the Partnership. Also, the General Partner may average the cost of the Leases by area or type of drilling to arrive at an average Cost of the Leases per Prospect for each area which the General Partner believes is less than fair market value. A determination of fair market value must be supported by an appraisal from an Independent Expert.

4.01(a)(5). The General Partner’s or Affiliates’ Rights in the Remainder Interests. Subject to the provisions of § 4.03(d), to the extent the Partnership does not acquire a full interest in a Lease from the General Partner or its Affiliates, the remainder of the interest in the Lease may be held by the General Partner or its Affiliates. They may either:

 

  (i) retain and exploit the remaining interest for their own account; or

 

  (ii) sell or otherwise dispose of all or a part of the remaining interest.

Profits from the exploitation and/or disposition of their retained interests in the Leases shall be for the benefit of the General Partner or its Affiliates to the exclusion of the Partnership and the Participants.

4.01(a)(6). No Breach of Duty. Subject to the provisions of § 4.03(d), the acquisition of Leases from the General Partner or its Affiliates shall not be considered a breach of any obligation owed by them to the Partnership or the Participants.

4.01(b). No Overriding Royalty Interests. Neither the General Partner nor any Affiliate shall retain any Overriding Royalty Interest on the Leases acquired by the Partnership.

4.01(c). Title and Nominee Arrangements.

4.01(c)(1). Legal Title. Legal title to all Leases acquired by the Partnership shall be held on a permanent basis in the name of the Partnership or a Group Member. However, Partnership properties may be held temporarily in the name of:

 

  (i) the General Partner;

 

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  (ii) its Affiliates; or

 

  (iii) any other nominee designated by the General Partner;

to facilitate the acquisition of the properties.

4.01(c)(2). General Partner’s Discretion. The General Partner shall take the steps which are necessary in its best judgment to render title to the Leases to be acquired by the Partnership acceptable for the purposes of the Partnership. The General Partner shall be free, however, to use its own best judgment in waiving title requirements. The General Partner shall not be liable to the Partnership the Participants or any other parties for any mistakes of judgment; nor shall the General Partner be deemed to be making any warranties or representations, express or implied, as to the validity or merchantability of the title to the Leases assigned to the Partnership or the extent of the interest covered thereby.

4.01(c)(3). Commencement of Operations. The Partnership shall not begin operations on its Leases unless the General Partner is satisfied that necessary title requirements have been satisfied.

4.02. Conduct of Operations.

4.02(a). Management. Subject to any restrictions contained in this Agreement, the General Partner shall exercise full control over all operations of the Partnership.

4.02(b). General Powers of the General Partner.

4.02(b)(1)(a). In General. Subject to the provisions of § 4.03, the General Partner shall have full authority to do all things deemed necessary or desirable by it in the conduct of the business of the Partnership. Without limiting the generality of the foregoing, the General Partner is expressly authorized to engage in:

 

  (i) the making of all determinations of which Leases, wells and operations will be participated in by the Partnership, which includes:

 

  (a) which Leases are developed;

 

  (b) which Leases are abandoned; or

 

  (c) which Leases are sold or assigned to other parties, including other investor ventures organized by the General Partner or any of its Affiliates;

 

  (ii) the negotiation and execution on any terms deemed desirable in its sole discretion of any contracts, conveyances, or other instruments, considered useful to the conduct of the operations or the implementation of the powers granted it under this Agreement;

 

  (iii) the exercise, on behalf of the Partnership or the parties, as the General Partner in its sole judgment deems best, of all rights, elections and options granted or imposed by any agreement, statute, rule, regulation, or order;

 

  (iv) the making of all decisions concerning the desirability of payment, and the payment or supervision of the payment, of all delay rentals and shut-in and minimum or advance royalty payments;

 

  (v) the selection of full or part-time employees and outside consultants and contractors and the determination of their compensation and other terms of employment or hiring, and the allocation of expenses to the Partnership pursuant to § 4.03(d)(6)(a);

 

  (vi) the maintenance of insurance for the benefit of the Partnership, the Partners and the indemnitees;

 

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  (vii) the use of the funds and revenues of the Partnership, and the borrowing on behalf of, and the loan of money to, the Partnership, on any terms it sees fit, for any purpose, including without limitation:

 

  (a) the conduct or financing, in whole or in part, of, or reinvestment in, the drilling and other activities of the Partnership;

 

  (b) the conduct of additional operations; and

 

  (c) the repayment of any borrowings or loans used initially to finance these operations or activities;

 

  (viii) the disposition, hypothecation, sale, exchange, release, surrender, reassignment or abandonment of any or all assets of the Partnership, including without limitation, the Leases, wells, equipment and production therefrom, provided that an Asset Sale shall only be made as provided in § 4.03(c)(2);

 

  (ix) the formation of any further limited or general partnership, tax partnership, joint venture, or other relationship which it deems desirable with any parties who it, in its sole discretion, selects, including any of its Affiliates;

 

  (x) the control of any matters affecting the rights and obligations of the Partnership, including:

 

  (a) the employment of attorneys to advise and otherwise represent the Partnership;

 

  (b) the conduct of litigation and incurring other legal expenses; and

 

  (c) the settlement of claims and litigation;

 

  (xi) the operation of producing wells drilled on the Leases or on a Prospect which includes any part of the Leases;

 

  (xii) the exercise of the rights granted to it under the power of attorney created under this Agreement;

 

  (xiii) the determination of whether, when and how the Listing Event shall occur; and

 

  (xiv) the incurring of all costs and the making of all expenditures in any way related to any of the foregoing.

4.02(b)(1)(b). Except as expressly set forth in this Agreement or the Delaware Act, neither the General Partner nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Partnership, any Group Member or any Limited Partner, and the Partners agree that the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the General Partner or any other Indemnitee otherwise existing at law or in equity, replace such other duties and liabilities of the General Partner or such other Indemnitee. The Limited Partners and any other Person who acquires an interest in a Partnership Interest or any other Person who is bound by this Agreement shall be deemed to have expressly approved this § 4.02(b)(1)(b).

4.02(b)(2). Delegation of Authority.

4.02(b)(2)(a). The General Partner may subcontract and delegate all or any part of its duties under this Agreement to any entity chosen by it, including an entity Affiliated with it, which party shall have the same powers in the conduct of the duties as would the General Partner. The delegation, however, shall not relieve the General Partner of its responsibilities under this Agreement.

4.02(b)(2)(b). The General Partner may rely upon, and shall be protected in acting or refraining from acting upon, any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

4.02(b)(2)(c). The General Partner may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the advice or opinion (including an opinion of counsel) of such Persons as to matters that the General Partner reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such advice or opinion.

 

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4.02(b)(2)(d). The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its duly authorized officers, a duly appointed attorney or attorneys-in-fact or the duly authorized officers of the Partnership or any Group Member.

4.02(b)(3). Conflicts of Interest.

4.02(b)(3)(a). Whenever a potential conflict of interest exists or arises between the General Partner or any of its Affiliates (other than the Partnership, any Group Member or any Partner), on the one hand, and the Partnership, any Group Member or any Partner, on the other, any resolution or course of action by the General Partner or its Affiliates in respect of such conflict of interest shall conclusively be permitted and deemed approved by all Partners, and shall not constitute a breach of this Agreement, or of any agreement contemplated herein, or of any duty stated hereunder or implied by law or equity or otherwise, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of a majority of the outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates), or (iii) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties; provided, however, that clause (iii) hereof shall not be applicable to any proposed conflict of interest which is material to the business and operations of the Partnership. The General Partner shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval or Unitholder approval of such resolution, and the General Partner may also adopt a resolution or course of action that has not received Special Approval or Unitholder approval. If Special Approval is sought, then it shall be presumed that, in making its decision, the Conflicts Committee acted in good faith in the best interest of the Partnership, and if neither Special Approval nor Unitholder approval is sought and the Board of Directors determines that the resolution or course of action taken with respect to a conflict of interest satisfies the standard set forth in clause (iii) above, then it shall be presumed that, in making its decision, the Board of Directors acted in good faith in the best interest of the Partnership, and in either case, in any proceeding brought by any Limited Partner or by or on behalf of such Limited Partner or any other Limited Partner or the Partnership challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the existence of the conflicts of interest described in the Prospectus filed in connection with the Second Offering and any actions of the General Partner taken in connection therewith are hereby approved by all Partners and shall not constitute a breach of this Agreement or of any duty hereunder or existing at law, in equity or otherwise.

4.02 (b)(3)(b). Whenever the General Partner, the Board of Directors or any committee of the Board of Directors (including the Conflicts Committee), makes a determination or takes or declines to take any other action, or any Affiliate of the General Partner causes the General Partner to do so, in its capacity as the general partner of the Partnership as opposed to in its individual capacity, whether under this Agreement or any other agreement contemplated hereby or otherwise, then, unless another express standard is provided for in this Agreement, the General Partner, the Board of Directors or such committee causing the General Partner, in its capacity as the general partner of the Partnership as opposed to in its individual capacity, to do so, shall make such determination or take or decline to take such other action in good faith in the best interest of the Partnership and shall not be subject to any other or different standards imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity (including fiduciary standards). A determination, other action or failure to act by the General Partner, the Board of Directors, any committee of the Board of Directors (including the Conflicts Committee), or such Affiliate causing the General Partner to do so, will be deemed to be in good faith in the best interest of the Partnership unless the applicable party believed such determination, other action or failure to act was adverse to the interests of the Partnership. In any proceeding brought by the Partnership, any Limited Partner, any Person who acquires an interest in a Partnership Interest or any other Person who is bound by this Agreement challenging such action, determination or failure to act, the Person bringing or prosecuting such proceeding shall have the burden of proving that such determination, action or failure to act was not in good faith in the best interest of the Partnership.

 

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4.02(b)(3)(c). Whenever the General Partner or any of its Affiliates or any other Indemnitee makes a determination or takes or declines to take any other action, or any Affiliate of the General Partner causes the General Partner to do so, in the General Partner’s individual capacity as opposed to in its capacity as the general partner of the Partnership, whether under this Agreement or any other agreement contemplated hereby or otherwise, then the General Partner, such Affiliates and such Indemnitee are entitled, to the fullest extent permitted by law, to make such determination or to take or decline to take such other action free of any duty existing at law, in equity or otherwise or obligation whatsoever to the Partnership, any Partner, any other Person who acquires an interest in a Partnership Interest or any other Person bound by this Agreement, and the General Partner, such Affiliates and such Indemnitee shall not, to the fullest extent permitted by law, be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. By way of illustration and not of limitation, whenever the phrases, “at the option of the General Partner,” “in its discretion” or some variation of those phrases, are used in this Agreement, it indicates that the General Partner is acting in its individual capacity. For the avoidance of doubt, whenever the General Partner, any of its Affiliates or any Indemnitee votes or transfers its Partnership Interests or refrains from voting or transferring its Partnership Interests, it shall be acting in its individual capacity. The General Partner’s organizational documents may provide that determinations to take or decline to take any action in its individual, rather than representative, capacity may or shall be determined by its members, if the General Partner is a limited liability company, stockholders, if the General Partner is a corporation, or the members or stockholders of the General Partner’s general partner, if the General Partner is a partnership.

4.02(b)(3)(d). Notwithstanding anything to the contrary in this Agreement, none of the General Partner, any Affiliate of the General Partner or any Indemnitee shall have any duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of or equity interest in the Partnership or (ii) permit any Group Member to use any facilities or assets of the General Partner, its Affiliates or any Indemnitee, except as may be provided in any definitive agreement entered into from time to time specifically dealing with such use. Any determination by the General Partner, any of its Affiliates or Indemnitee to enter into such contracts shall be in its sole discretion.

4.02(b)(3)(e). The Limited Partners, each Person who acquires an interest in a Partnership Interest and each other Person who is bound by this Agreement hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this § 4.02(b)(3)(e). Nothing in this § 4.02(b)(3)(e) shall be deemed to expand any duties or liabilities of the General Partner, its Affiliates or any other Indemnitee to the Partnership, any Group Member, any Partner, any Person who acquires an interest in a Partnership Interest or other person who is bound by this Agreement for breach of this Agreement, to the extent that those duties or liabilities shall have been limited pursuant to §§ 4.02(b)(1)(b), this 4.02(b)(3) or 4.06.

4.02(c). Power of Attorney.

4.02(c)(1). In General. Each Participant appoints the General Partner his true and lawful attorney-in-fact for him and in his name, place, and stead and for his use and benefit, from time to time:

 

  (i) to create, prepare, complete, execute, file, swear to, deliver, endorse, and record any and all documents, certificates, government reports, or other instruments as may be required by law, or are necessary to amend this Agreement as authorized under the terms of this Agreement, or to qualify the Partnership as a limited partnership or partnership in commendam and to conduct business under the laws of any jurisdiction in which the General Partner elects to qualify the Partnership or conduct business; and

 

  (ii) to create, prepare, complete, execute, file, swear to, deliver, endorse and record any and all instruments, assignments, security agreements, financing statements, certificates, and other documents as may be necessary from time to time to implement the borrowing powers granted under this Agreement and any agreements entered into by the Partnership to hedge its natural gas and oil reserves and pledge up to 100% of its assets and natural gas and oil reserves in connection therewith.

 

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4.02(c)(2). Further Action. Each Participant authorizes the attorney-in-fact to take any further action which the attorney-in-fact considers necessary or advisable in connection with any of the foregoing powers and rights granted the General Partner under this section. Each party acknowledges that the power of attorney granted hereunder:

 

  (i) is a special power of attorney coupled with an interest and is irrevocable; and

 

  (ii) shall survive the assignment by the Participant of the whole or a portion of his Common Units; except when the assignment is of all of the Participant’s Common Units and the purchaser, transferee, or assignee of the Common Units is admitted as a successor Participant, the power of attorney of the assigning Participant shall survive the delivery of the assignment for the sole purpose of enabling the attorney-in-fact to execute, acknowledge, and file any agreement, certificate, instrument or document necessary to effect the substitution.

4.02(d). Borrowings and Use of Partnership Revenues.

4.02(d)(1). In General. If additional funds over the Participants’ Capital Contributions are needed for Partnership operations, then the General Partner may:

 

  (i) use Partnership revenues for such purposes;

 

  (ii) together with its Affiliates, advance the necessary funds to the Partnership, although they are not obligated to advance any funds to the Partnership; or

 

  (iii) borrow funds, subject to § 4.02(d)(2).

4.02(d)(2). Limitations on Loans to the Partnership. Partnership borrowings, other than credit transactions on open account customary in the industry to obtain goods and services, shall be subject to the following limitations:

 

  (i) the borrowings must be without recourse to the Limited Partners;

 

  (ii) the amount that may be borrowed at any one time may not exceed an amount equal to 100% of the Capital Contributions; and

 

  (iii) neither the General Partner nor any Affiliate shall loan money to the Partnership if the interest to be charged exceeds either:

 

  (a) the General Partner’s or the Affiliate’s interest cost; or

 

  (b) that which would be charged to the Partnership, without reference to the General Partner’s or the Affiliate’s financial abilities or guarantees, by unrelated lenders, on comparable loans for the same purpose.

Neither the General Partner nor any Affiliate shall receive points or other financing charges or fees, regardless of the amount, although the actual amount of any such charges incurred by them from third-party lenders may be reimbursed to the General Partner or the Affiliate. Notwithstanding the foregoing, the above limitations shall not limit or otherwise affect the Partnership’s ability to enter into agreements and financial instruments relating to hedging the Partnership’s natural gas and oil and the pledge of up to 100% of the Partnership’s assets and reserves in connection therewith.

4.02(e). Tax Matters Partner.

4.02(e)(1). Designation of Tax Matters Partner. The General Partner is hereby designated the Tax Matters Partner and the Partnership Representative of the Partnership under Section 6231(a)(7) of the Code. The General Partner is authorized to act in this capacity on behalf of the Partnership and the Participants and to take any action, including settlement or litigation, which it in its sole discretion deems to be in the best interest of the Partnership.

4.02(e)(2). Costs Incurred by Tax Matters Partner. Costs incurred by the Tax Matters Partner shall be considered a Direct Cost of the Partnership.

 

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4.02(e)(3). Notice to Participants of IRS Proceedings. The Tax Matters Partner and the Partnership Representative shall notify all of the Participants of any material administrative or other legal proceedings involving the Partnership and the IRS or any other taxing authority, and thereafter shall furnish all of the Participants reports at least annually on the status of the proceedings.

4.02(e)(4). Participant Restrictions. Each Participant agrees as follows:

 

  (i) he will not file the statement described in Section 6224(c)(3)(B) of the Code prohibiting the General Partner as the Tax Matters Partner for the Partnership from entering into a settlement on his behalf with respect to Partnership items, as that term is defined in Section 6231(a)(3) of Code, of the Partnership;

 

  (ii) he will not form or become and exercise any rights as a member of a group of Partners having a 5% or greater interest in the profits of the Partnership under Section 6223(b)(2) of the Code; and

 

  (iii) the General Partner is authorized to file a copy of this Agreement, or pertinent portions of this Agreement, with the IRS under Section 6224(b) of the Code if necessary to perfect the waiver of rights under this subsection.

4.02(f). Bipartisan Budget Act of 2015. For taxable years beginning after December 31, 2017 (or any earlier year, if the General Partner so elects) (i) the General Partner will be designated, and will be specifically authorized to act as, the Partnership Representative, and (ii) the Partnership Representative will apply the provisions of subchapter C of Chapter 63 of the Code, as amended by the 2015 Act (or any successor rules thereto) with respect to any audit, imputed underpayment, other adjustment, or any such decision or action by the Internal Revenue Service with respect to the Partnership or the Partners for such taxable years, in the manner determined by the Partnership Representative. For the avoidance of doubt, the Partnership Representative may (A) elect to apply the rules in subchapter C of Chapter 63 of the Code, as amended by the 2015 Act, for taxable years prior to January 1, 2018, or (B) elect to apply Section 6221(b) (if applicable) or Section 6226 of the Code or elect to file an administrative adjustment pursuant to Section 6227 of the Code, in each case as amended by the 2015 Act and in the manner determined by the Partnership Representative. Each Partner does hereby agree to indemnify and hold harmless the Partnership from and against any liability with respect to its share of any tax deficiency paid or payable by the Partnership that is allocable to the Partner (as reasonably determined by the General Partner) with respect to an audited or reviewed taxable year for which such Partner was a Partner in the Partnership (for the avoidance of doubt, including any applicable interest and penalties). The obligations set forth in this Section 4.02(f) will survive such Partner’s ceasing to be a Partner in the Partnership and/or the termination, dissolution, liquidation and winding up of the Partnership.

4.02(g) Cooperation. Each Partner will provide such cooperation and assistance, including executing and filing forms or other statements and providing information about the Partner, as is reasonably requested by the Tax Matters Partner or Partnership Representative, as applicable, to enable the Partnership to satisfy any applicable tax reporting or compliance requirements, to make any tax election or to qualify for an exception from or reduced rate of tax or other tax benefit or be relieved of liability for any tax regardless of whether such requirement, tax benefit or tax liability existed on the date such Partner was admitted to the Partnership. If a Partner fails to provide any such forms, statements, or other information requested by the Tax Matters Partner or Partnership Representative, as applicable, such Partner will be required to indemnify the Partnership for the share of any tax deficiency paid or payable by the Partnership that is due to such failure (as reasonably determined by the General Partner). The obligations set forth in this Section 4.02(g) will survive such Partner’s ceasing to be a Partner in the Partnership and/or the termination, dissolution, liquidation and winding up of the Partnership.

4.03. General Rights and Obligations of the Participants and Restricted and Prohibited Transactions.

4.03(a)(1). Limited Liability of Limited Partners. Limited Partners shall not be bound by the obligations of the Partnership other than as provided under the Delaware Act. Limited Partners shall not be personally liable for any debts of the Partnership or any of the obligations or losses of the Partnership beyond their Capital Contributions unless, in the case of the General Partner, it purchases Common Units.

 

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4.03(a)(2). No Management Authority of Participants. Participants, other than the General Partner if it buys Common Units, shall have no power over the conduct of the affairs of the Partnership. No Participant, other than the General Partner if it buys Common Units, shall take part in the management of the business of the Partnership, or have the power to sign for or to bind the Partnership.

4.03(b). Reports and Disclosures.

4.03(b)(1). Annual Reports and Financial Statements. Beginning with the 2016 calendar year, the Partnership shall provide each Participant an annual report within 120 days after the close of the calendar year containing audited financial statements of the Partnership and, beginning with the 2016 calendar year, a report within 75 days after the end of the first six months of its calendar year containing unaudited financial statements of the Partnership. Audited financial statements of the Partnership, including a balance sheet and statements of income, cash flow, and Partners’ equity shall be prepared on an accrual basis in accordance with generally accepted accounting principles and accompanied by an auditor’s report containing an opinion of an independent public accountant selected by the General Partner stating that its audit was made in accordance with generally accepted auditing standards and that in its opinion the financial statements present fairly the financial position, results of operations, Partners’ equity, and cash flows in accordance with generally accepted accounting principles. Accompanying the annual report, the Partnership shall provide to each Participant the following:

 

  (i) A description of each Prospect in which the Partnership owns an interest, including:

 

  (a) the cost, location, and number of acres under Lease; and

 

  (b) the Working Interest owned in the Prospect by the Partnership.

 

  Succeeding reports, however, must only contain material changes, if any, regarding the Prospects.

 

  (ii) A list of the wells drilled or abandoned by the Partnership during the period of the report, indicating:

 

  (a) whether each of the wells has or has not been completed;

 

  (b) a statement of the cost of each well completed or abandoned; and

 

  (c) justification for wells abandoned after production has begun.

 

  (iii) A description of all Farmouts, farmins, and joint ventures, made during the period of the report, including:

 

  (a) the General Partner’s justification for the arrangement; and

 

  (b) a description of the material terms.

 

  (iv) A summary of the computation of the Partnership’s total natural gas and oil proved reserves.

 

  (v) A summary of the computation of the present worth of the reserves.

 

  (vi) A statement of each unitholder’s interest in the reserves.

 

  (vii) An estimate of the time required for the extraction of the reserves and a statement that, because of the time required to extract such reserves, the present value of revenues to be obtained in the future is less than if immediately receivable.

 

  (viii)

A summary of the total fees and compensation paid by the Partnership to the General Partner and its Affiliates and a detailed statement of any transactions with the General Partner or its Affiliates. The independent certified public accountant will provide written attestation annually, which will be included in the annual report, that the method used to allocate administrative costs was consistent with the method described in the prospectus for the Second Offering and that the total amount of administrative costs allocated did not materially exceed the amounts described in the prospectus for the Second Offering. If the General Partner subsequently decides to allocate expenses in a manner different

 

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  from that described in the prospectus for the Second Offering, then the change must be reported to the Participants with an explanation of the reason for the change and the basis used for determining the reasonableness of the new allocation method.

The reserve computations shall be based on engineering reports prepared by qualified independent petroleum consultants. If any event reduces the Partnership’s proved reserves by 10% or more, excluding a reduction of reserves as a result of normal production, sales of reserves, or natural gas or oil price changes, then a computation and estimate of the amount of the reduction in reserves will be sent to each Participant within 90 days after the General Partner determines that such a reduction in reserves has occurred.

4.03(b)(2). Tax Information. The Partnership shall, by March 15 of each year, prepare, or supervise the preparation of, and transmit to each Participant the information needed for the Participant to file the following:

 

  (i) his federal income tax return;

 

  (ii) any required state income tax return; and

 

  (iii) any other reporting or filing requirements imposed by any governmental agency or authority.

4.03(b)(3). Reserve Report. Accompanying the annual report, the Partnership shall provide to each Participant the following:

 

  (i) a summary of the computation of the Partnership’s total natural gas and oil Proved Reserves;

 

  (ii) a summary of the computation of the present worth of the reserves determined using:

 

  (a) a discount rate of 10%;

 

  (b) a constant price for the oil; and

 

  (c) basing the price of natural gas on the existing natural gas contracts, if any, or prices;

 

  (iii) a statement of each Participant’s interest in the reserves; and

 

  (iv) an estimate of the time required for the extraction of the reserves with a statement that because of the time period required to extract the reserves the present value of revenues to be obtained in the future is less than if immediately receivable.

The reserve computations shall be based on engineering reports prepared by the General Partner and reviewed by an Independent Expert. If any event reduces the Partnership’s Proved Reserves by 10% or more, excluding a reduction of reserves as a result of normal production, sales of reserves, or natural gas or oil price changes, then a computation and estimate of the amount of the reduction in reserves must be sent to each Participant within 90 days after the General Partner determines that such a reduction in reserves has occurred.

4.03(b)(4). Participant Access to Records. The Participants and/or their representatives shall be permitted access to all Partnership records, provided that access to the list of Participants shall be subject to § 4.03(b)(6). Subject to the foregoing, a Participant may inspect and copy any of the Partnership’s records after giving adequate notice to the General Partner at any reasonable time. Notwithstanding the foregoing, the General Partner may keep logs, well reports, and other drilling and operating data confidential for reasonable periods of time. The General Partner may release information concerning the operations of the Partnership to Persons that are customary in the industry or required by rule, regulation, or order of any regulatory body.

4.03(b)(5). Required Length of Time to Hold Records. Unless otherwise required by any other provision of this Agreement, the General Partner must maintain and preserve during the term of the Partnership and for four years thereafter all accounts, books and other relevant documents which include any appraisal, along with associated supporting information, of the fair market value of the Leases sold to the Partnership by the General

 

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Partner or its Affiliates required by § 4.01(a)(4) or of any producing property for which an appraisal is required by any other provision of this Agreement. Notwithstanding the foregoing, the General Partner must maintain and preserve during the term of the Partnership and for six years thereafter all documents forming a record that a Participant meets the suitability standards established in connection with an investment in the Partnership.

4.03(b)(6). Participant Lists. The following provisions apply regarding access to the list of Participants:

 

  (i) an alphabetical list of the names, addresses, and business telephone numbers of the Participants along with the number of Common Units held by each of them (the “Participant List”) must be maintained as a part of the Partnership’s books and records and be available for inspection by any Participant or his designated agent at the home office of the Partnership on the Participant’s request;

 

  (ii) the Participant List must be updated at least quarterly to reflect changes in the information contained in the Participant List;

 

  (iii) except as provided below, a copy of the Participant List must be mailed to any Participant requesting the Participant List within 10 days of the written request, printed in alphabetical order on white paper, and in a readily readable type size in no event smaller than 10-point type; a reasonable charge for copy work will be charged by the Partnership;

 

  (iv) the purposes for which a Participant may request a copy of the Participant List include, without limitation, matters relating to Participant’s voting rights under this Agreement and the exercise of Participant’s rights under the federal proxy laws; and

 

  (v) the General Partner may refuse to exhibit, produce, or mail a copy of the Participant List as requested if the General Partner believes that the actual purpose and reason for the request for inspection or for a copy of the Participant List is to secure the list of Participants or other information for the purpose of selling the list or information or copies of the list, or of using the same for a commercial purpose other than relating to the interest of the applicant, as a Participant, in the affairs of the Partnership. The General Partner will require the Participant requesting the Participant List to represent in writing that the list was not requested for a commercial purpose unrelated to the Participant’s interest in the Partnership.

4.03(b)(7). State Filings. Concurrently with their transmittal to Participants, and as required, the General Partner shall file a copy of each report provided for in this § 4.03(b) with the securities commissions of states which request the report.

4.03(c). Meetings of Participants.

4.03(c)(1). Procedure for a Participant Meeting.

4.03(c)(1)(a). Meetings May Be Called by General Partner or Participants. Meetings of all of the Participants may be called as follows:

 

  (i) by the General Partner; or

 

  (ii) by Participants whose Common Units equal 10% or more of the outstanding Common Units for any matters on which Participants may vote.

The call for a meeting by the Participants as described above shall be deemed to have been made on receipt by the General Partner of a written request from holders of the requisite percentage of Common Units stating the purpose(s) of the meeting.

4.03(c)(1)(b). Notice Requirement. The General Partner shall deposit in the United States mail, within 15 days after the receipt of the request, written notice to all Participants of the meeting and the purpose of the meeting.

 

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The meeting shall be held on a date not less than 30 days nor more than 60 days after the date of the mailing of the notice, at a reasonable time and place. Notwithstanding the foregoing, the date for notice of the meeting may be extended for a period of up to 60 days if, in the opinion of the General Partner, the additional time is necessary to permit preparation of proxy or information statements or other documents required to be delivered in connection with the meeting by the SEC or other regulatory authorities.

4.03(c)(1)(c). May Vote by Proxy. Participants shall have the right to vote at any meeting either:

 

  (i) in person; or

 

  (ii) by proxy.

4.03(c)(2). Special Voting Rights. At the request of Participants whose Common Units equal 10% or more of the outstanding Common Units, the General Partner shall call for a vote by Participants. Each Common Unit is entitled to one vote on all matters. Participants whose Common Units equal a majority of the outstanding Common Units may, without the concurrence of the General Partner or its Affiliates, vote to:

 

  (i) dissolve the Partnership;

 

  (ii) remove the General Partner and elect a new General Partner;

 

  (iii) elect a new General Partner if the General Partner elects to withdraw from the Partnership;

 

  (iv) approve or disapprove an Asset Sale or Merger;

 

  (v) cancel any contract for services with the General Partner or its Affiliates that is not described in this Agreement without penalty on 60 days’ notice; and

 

  (vi) except as provided in § 8.05(b) and (c), amend this Agreement; provided however:

 

  (a) any amendment may not increase the duties or liabilities of any Participant or the General Partner or increase or decrease the profit or loss sharing or required Capital Contribution of any Participant or the General Partner without the approval of the Participant or the General Partner, respectively; and

 

  (b) any amendment may not affect the classification of Partnership income and loss for federal income tax purposes without the unanimous approval of all Participants.

4.03(c)(3). Restrictions on General Partner’s Voting Rights. With respect to Common Units owned by the General Partner or its Affiliates, the General Partner and its Affiliates may vote or consent on all matters other than the matters set forth in § 4.03(c)(2)(ii) and (v) above and matters regarding any transaction between the General Partner and the Partnership. In determining the requisite percentage in interest of Common Units necessary to approve any Partnership matter on which the General Partner and its Affiliates may not vote or consent, any Common Units owned by the General Partner and its Affiliates shall not be included or deemed to be outstanding.

4.03(c)(4). Restrictions on Limited Partner Voting Rights. The exercise by the Limited Partners of the rights granted Participants under § 4.03(c), except for the special voting rights granted Participants under § 4.03(c)(2), shall be subject to the prior legal determination that the grant or exercise of the powers will not adversely affect the limited liability of Limited Partners. Notwithstanding the foregoing, if in the opinion of counsel to the Partnership the legal determination is not necessary under Delaware law to maintain the limited liability of the Limited Partners, then it shall not be required. A legal determination under this paragraph may be made either pursuant to:

 

  (i) an opinion of counsel, the counsel being independent of the Partnership and selected on the vote of Limited Partners whose Common Units equal a majority of the total Common Units held by Limited Partners; or

 

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  (ii) a declaratory judgment issued by a court of competent jurisdiction.

4.03(d). Transactions with the General Partner.

4.03(d)(1). General Partner May Waive Lease Encroachments by Affiliated Programs and May Waive Lease Encroachments by the Partnership, If Any. It is possible that a horizontal well drilled by the Partnership may encroach on Lease interests covering a well that was previously drilled by another entity sponsored by or Affiliated with the General Partner or its Affiliates. In that event, the encroachment will be waived and allowed by the other entity without restriction or charge to the Partnership unless the General Partner determines, in its discretion, that the encroachment by the Partnership’s well results in drainage from the other entity’s well. In that event, the Partnership shall compensate the other entity for the drainage, either by a cash payment or the assignment of an overriding royalty interest or a portion of the working interest in the Partnership Well that encroaches on the other entity’s well, as determined by the General Partner in its discretion, consistent with its or its Affiliates’ duties to the Partnership and the other entities. On the other hand, these provisions shall also apply to the Partnership if there is encroachment on a previously drilled Partnership Well as a result of horizontal drilling conducted by an entity sponsored by or Affiliated with the General Partner or its Affiliates, including drilling partnerships sponsored by the General Partner in the future.

4.03(d)(2). Transfer of Less than the General Partner’s and its Affiliates’ Entire Interest. Subject to § 4.02(b)(3), a sale, transfer or a conveyance to the Partnership of less than all of the ownership of the General Partner or an Affiliate (excluding another Program in which the interest of the General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) in any Prospect shall not be made unless:

 

  (i) the interest retained by the General Partner or the Affiliate is a proportionate Working Interest;

 

  (ii) the respective obligations of the General Partner or its Affiliates and the Partnership are substantially the same after the sale of the interest by the General Partner or its Affiliates; and

 

  (iii) the General Partner’s interest in revenues does not exceed the amount proportionate to its retained Working Interest.

This section does not prevent the General Partner or its Affiliates from subsequently dealing with their retained interest as they may choose with unaffiliated parties or Affiliated entities.

4.03(d)(3). Limitations on Sale of Undeveloped and Developed Leases to the General Partner. Subject to § 4.02(b)(3), other than as set forth in § 4.03(d)(5), the General Partner and its Affiliates shall not purchase any undeveloped Leases from the Partnership other than at the higher of Cost or fair market value. However, when a well is plugged and abandoned the Partnership’s Lease rights may be assigned by the Partnership to the General Partner in return for a cash payment, Farmout, Overriding Royalty Interest or other interest in the Prospect as determined by the General Partner, in its sole discretion, consistent with its duties to the Partnership. Farmouts to the General Partner and its Affiliates may be made as set forth in § 4.03(d)(8). Subject to the foregoing, the General Partner and its Affiliates, other than an Income Program sponsored by an Affiliate of the General Partner, shall not purchase any producing natural gas or oil property from the Partnership unless the sale is in connection with the liquidation of the Partnership and the sale is at fair market value as supported by an appraisal of an Independent Expert.

4.03(d)(4). Transfer of Equal Proportionate Interest. Subject to § 4.02(b)(3), when the General Partner (excluding another Program in which the interest of the General Partner is substantially similar to or less than its interest in the Partnership) sells, transfers or conveys any natural gas, oil or other mineral interests or property to the Partnership, it must, at the same time, sell, transfer or convey to the Partnership an equal proportionate interest in all its other property in the same Prospect. Notwithstanding, a horizontal well may be drilled on the same Prospect on which a vertical well is drilled. If the area constituting a Partnership Prospect is subsequently enlarged to encompass any area in which the General Partner (excluding another Program in which the interest of

 

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the General Partner is substantially similar to or less than its interest in the Partnership) owns a separate property interest and the activities of the Partnership were material in establishing the existence of Proved Undeveloped Reserves that are attributable to the separate property interest, then the separate property interest or a portion thereof must be sold, transferred, or conveyed to the Partnership as set forth in this section and §§4.01(a)(4) and 4.03(d)(2). Notwithstanding the foregoing, Prospects drilled to the Mississippi Lime formation, the Marble Falls reservoirs, the Eagle Ford shale or any other formation or reservoir shall not be enlarged or contracted except in the General Partner’s discretion if the Prospect was limited because the well was being drilled to prove Reserves and to protect against drainage.

4.03(d)(5). Transfer of Leases Between Affiliated Limited Partnerships. Subject to § 4.02(b)(3), the transfer of an undeveloped Lease from the Partnership to another entity sponsored or managed by, or Affiliated with, the General Partner or its Affiliates must be made at fair market value as supported by an appraisal from an independent expert if the undeveloped Lease has been held by the Partnership for more than two years. Any such appraisal of the property must be maintained in the Partnership’s records for at least six years. Otherwise, if the General Partner deems it to be in the best interest of the Partnership, the transfer may be made at Cost. An Income Program sponsored by an Affiliate of the General Partner may purchase a producing natural gas and oil property from the Partnership at any time at:

 

  (i) fair market value as supported by an appraisal from an Independent Expert if the property has been held by the Partnership for more than six months or the Partnership has made significant expenditures in connection with the property. Any such appraisal of the property must be maintained in the Partnership’s records for at least six years; or

 

  (ii) Cost, as adjusted for intervening operations, if the General Partner deems it to be in the best interest of the Partnership.

However, these prohibitions shall not apply to joint ventures or Farmouts among Affiliated entities, provided that:

 

  (i) the respective obligations and revenue sharing of all parties to the transaction are substantially the same; and

 

  (ii) the compensation arrangement or any other interest or right of either the General Partner or its Affiliates is the same in each Affiliated entity, or, if different, the aggregate compensation of the General Partner or the Affiliate is reduced to reflect the lower compensation arrangement.

4.03(d)(6). Services. Except as provided in this § 4.03(d)(6) and elsewhere in this Agreement, the General Partner shall not be compensated for its services as a General Partner or managing member of any Group Member.

4.03(d)(6)(a). Reimbursement of the General Partner.

4.03(d)(6)(a)(1). The General Partner shall be reimbursed from the Partnership on a monthly basis, or such other basis as the General Partner may determine, for all Administrative Costs, so long as they are supportable as to the necessity thereof and the reasonableness of the amount charged and supported by appropriate invoices or other documentation and, in addition (and notwithstanding clause (ii) of the definition of such term), (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership (including salary, bonus, incentive compensation, employee benefits and other amounts paid to any Person, including Affiliates of the General Partner, to perform services for the Partnership or for the General Partner in the discharge of its duties to the Partnership), (ii) compensation to, and expenses of, the directors of the General Partner incurred in connection with the performance of services for the Partnership, and (iii) all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with managing and operating the Partnership’s business and affairs (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the Partnership. Reimbursements pursuant to this subsection may be

 

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paid out of capital contributions and out of Partnership revenues and shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to § 4.05.

The General Partner shall bear a percentage of direct costs and administrative costs equal to its percentage of revenue participation.

4.03(d)(6)(a)(2). The General Partner, without the approval of the Limited Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership benefit plans, programs and practices (including plans, programs and practices involving the issuance of Partnership Interests or options to purchase or rights, warrants or appreciation rights or phantom or tracking interests relating to Partnership Interests), or cause the Partnership to issue Partnership Interests in connection with, or pursuant to, any benefit plan, program or practice maintained or sponsored by the General Partner or any of its Affiliates, in each case for the benefit of employees and directors of the General Partner or any of its Affiliates, in respect of services performed, directly or indirectly, for the benefit of the Partnership. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Interests that the General Partner or such Affiliate is obligated to provide to any employees and directors pursuant to any such benefit plans, programs or practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliate of Partnership Interests purchased by the General Partner or such Affiliate from the Partnership or otherwise, to fulfill options or awards under such plans, programs and practices) shall be reimbursed in accordance with § 4.03(d)(6)(a)(1). Any and all obligations of the General Partner under any benefit plans, programs or practices adopted by the General Partner as permitted by this subsection shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to § 4.04(a)(3) or the transferee of or successor to all of the General Partner’s General Partner Interest (represented by GP Units).

4.03(d)(6)(a)(3). Competitive Rates. The General Partner and any Affiliate shall not render to the Partnership any oil field, equipage, drilling or other services nor sell or lease to the Partnership any equipment or related supplies unless:

 

  (i) except as provided below, the Person is engaged, independently of the Partnership and as an ordinary and ongoing business, in the business of rendering the services or selling or leasing the equipment and supplies to a substantial extent to other Persons in the natural gas and oil industry in addition to the entities in which the General Partner or any of its Affiliates has an interest; and

 

  (ii) the compensation, price, or rental therefor is competitive with the compensation, price, or rental of other Persons in the area engaged in the business of rendering comparable services or selling or leasing comparable equipment and supplies which could reasonably be made available to the Partnership.

If the Person is not engaged in such a business, then the compensation, price or rental shall be the Cost of the services, equipment or supplies to the person or the competitive rate which could be obtained in the area, whichever is less.

The General Partner or its Affiliates, as operator or drilling contractor, may not receive a rate that is not competitive with the rates charged by unaffiliated operators or contractors in the same geographic region, enter into a turnkey drilling contract with the Partnership, profit by drilling in contravention of its fiduciary obligations to the Partnership, or benefit by interpositioning itself between the Partnership and the actual provider of operation or drilling contractor services.

4.03(d)(6)(b). If Not Disclosed in this Agreement, Then Services by the General Partner Must be Described in a Separate Contract and Cancelable. Any services for which the General Partner or an Affiliate is to receive compensation, other than those described in this Agreement, shall be set forth in a written contract which precisely describes the services to be rendered and all compensation to be paid. These contracts shall be cancelable without penalty on 60 days written notice by Participants whose Common Units equal a majority of the outstanding Common Units.

 

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4.03(d)(7). No Loans from the Partnership. No loans or advances shall be made by the Partnership to the General Partner or its Affiliates.

4.03(d)(8). Farmouts. The General Partner shall not enter into a Farmout to avoid its paying its share of costs, if any, related to drilling a well on an undeveloped Lease. The Partnership shall not Farmout an undeveloped Lease or well activity to the General Partner or its Affiliates, except that this restriction shall not apply to Farmouts between the Partnership and another entity managed by the General Partner or its Affiliates, either separately or jointly, provided that the respective obligations and revenue sharing of all parties to the transactions are substantially the same and the compensation arrangement or any other interest or right of the General Partner or its Affiliates is the same in each entity, or, if different, the aggregate compensation of the General Partner and its Affiliates is reduced to reflect the lower compensation agreement. The Partnership may Farmout an undeveloped lease or well activity only if the General Partner, exercising the standard of a prudent operator, determines that:

 

  (i) the Partnership lacks the funds to complete the oil and gas operations on the Lease or well and cannot obtain suitable financing;

 

  (ii) drilling on the Lease or the intended well activity would concentrate excessive funds in one location, creating undue risks to the Partnership;

 

  (iii) the Leases or well activity have been downgraded by events occurring after assignment to the Partnership so that development of the Leases or well activity would not be desirable; or

 

  (iv) the Farmout is in the best interests of the Partnership.

If the Partnership Farmouts a Lease or well activity, the General Partner must retain on behalf of the Partnership the economic interests and concessions as a reasonably prudent oil and gas operator would or could retain under the circumstances prevailing at the time, consistent with industry practices. If the Partnership acquires an undeveloped Lease pursuant to a Farmout or joint venture from an entity Affiliated with the General Partner or its Affiliates, the General Partner’s and its Affiliates’ aggregate compensation associated with the property and any direct and indirect ownership interest in the property may not exceed the lower of the compensation and ownership interest in the General Partner and/or its Affiliates could receive if the property were separately owned or retained by either the Partnership or the Affiliated entity.

4.03(d)(9). No Compensating Balances. Neither the General Partner nor any Affiliate shall use the Partnership’s funds as compensating balances for its own benefit.

4.03(d)(10). Future Production. Neither the General Partner nor any Affiliate shall commit the future production of a well developed by the Partnership exclusively for its own benefit.

4.03(d)(11). Marketing Arrangements. Subject to § 4.06, all benefits from marketing arrangements or other relationships affecting the property of the General Partner or its Affiliates, including its Affiliated partnerships and the Partnership, shall be fairly and equitably apportioned according to the respective interests of each in the property.

4.03(d)(12). Participation in Other Partnerships. If the Partnership participates in other partnerships or joint ventures (multi-tier arrangements), then the terms of any of these arrangements shall not result in the circumvention of any of the requirements or prohibitions contained in this Agreement, including the following:

 

  (i) there shall be no duplication or increase in Organization and Offering Costs, the General Partner’s compensation, Partnership expenses or other fees and costs;

 

  (ii) there shall be no substantive alteration in the fiduciary and contractual relationship between the General Partner and the Participants; and

 

  (iii) there shall be no diminishment in the voting rights of the Participants.

 

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4.03(d)(13). Organization and Offering Expenses. All Organization and Offering Costs incurred in order to sell program units shall be reasonable. Additionally, the total reimbursements of Organization and Offering Costs that may be charged to the Partnership shall not exceed 15% of the gross proceeds received by the Partnership in the Second Offering.

4.03(d)(14). Acquisition from Unaffiliated Person. During a period of five years from the date of formation of the Partnership, if the General Partner or any of its Affiliates proposes to acquire an interest from an unaffiliated person in a Prospect in which the Partnership possesses an interest or in a Prospect in which the Partnership’s interest has been terminated without compensation within one year preceding such proposed acquisition, and (i) none of the General Partner or its Affiliates owns property in the Prospect separately from the Partnership, then none of the General Partner or its Affiliates shall be permitted to purchase an interest in the Prospect; and (ii) if the General Partner or its Affiliates currently own a proportionate interest in the Prospect separately from the Partnership, then the interest to be acquired shall be divided between the Partnership and the General Partner or its Affiliates, as applicable, in the same proportion as is the other property in the Prospect; provided, however, if cash or financing is not available to the Partnership to enable it to consummate a purchase of the additional interest to which it is entitled, then none of the General Partner or its Affiliates shall be permitted to purchase any additional interest in the Prospect.

4.03(d)(15). Roll-Up Limitations.

4.03(d)(15)(a). Requirement for Appraisal and Its Assumptions. In connection with a proposed Roll-Up, an appraisal of all Partnership assets shall be obtained from a competent Independent Expert. If the appraisal will be included in a prospectus used to offer securities of a Roll-Up Entity, then the appraisal shall be filed with the SEC and the Administrator as an exhibit to the registration statement for the offering. If the appraisal is filed with the SEC and the Administrators, the Partnership shall be subject to liability for violation of Section 11 of the Securities Act of 1933 and comparable provisions under state law for any material misrepresentations or material omissions in the appraisal. Partnership assets shall be appraised on a consistent basis. The appraisal shall be based on all relevant information, including current reserve estimates prepared as set forth in § 4.03(b)(3), and shall indicate the value of the Partnership’s assets as of a date immediately before the announcement of the proposed Roll-Up transaction. The appraisal shall assume an orderly liquidation of the Partnership’s assets over a 12-month period. The terms of the engagement of the Independent Expert shall clearly state that the engagement is for the benefit of the Partnership and the Participants. A summary of the independent appraisal, indicating all material assumptions underlying the appraisal, shall be included in a report to the Participants in connection with a proposed Roll-Up.

4.03(d)(15)(b). Rights of Participants Who Vote Against Proposal. In connection with a proposed Roll-Up, Participants who vote “no” on the proposal shall be offered the choice of:

 

  (i) accepting the securities of the Roll-Up Entity offered in the proposed Roll-Up; or

 

  (ii) one of the following:

 

  (a) remaining as Participants in the Partnership and preserving their Common Units in the Partnership on the same terms and conditions as existed previously; or

 

  (b) receiving cash in an amount equal to the Participants’ pro rata share of the appraised value of the net assets of the Partnership based on their respective number of Common Units.

4.03(d)(15)(c). No Roll-Up If Diminishment of Voting Rights. The Partnership shall not participate in any proposed Roll-Up which, if approved, would result in the diminishment of any Participant’s voting rights under the Roll-Up Entity’s chartering agreement. In no event shall the democracy rights of Participants in the Roll-Up Entity be less than those provided for under §§ 4.03(c)(1) and 4.03(c)(2). If the Roll-Up Entity is a corporation, then the democracy rights of Participants shall correspond to the democracy rights provided for in this Agreement to the greatest extent possible.

 

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4.03(d)(15)(d). No Roll-Up If Accumulation of Shares Would be Impeded. The Partnership shall not participate in any proposed Roll-Up transaction which includes provisions that would operate to materially impede or frustrate the accumulation of shares by any purchaser of the securities of the Roll-Up Entity, except to the minimum extent necessary to preserve the tax status of the Roll-Up Entity. The Partnership shall not participate in any proposed Roll-Up transaction which would limit the ability of a Participant to exercise the voting rights of its securities of the Roll-Up Entity on the basis of the number of Common Units held by that Participant.

4.03(d)(15)(e). No Roll-Up If Access to Records Would Be Limited. The Partnership shall not participate in a Roll-Up in which Participants’ rights of access to the records of the Roll-Up Entity would be less than those provided for under §§ 4.03(b)(4), 4.03(b)(5), and 4.03(b)(6).

4.03(d)(15)(f). Cost of Roll-Up. The Partnership shall not participate in any proposed Roll-Up transaction in which any of the costs of the transaction would be borne by the Partnership if Participants whose Common Units equal a majority of the total Common Units do not vote to approve the proposed Roll-Up.

4.03(d)(15)(g). Roll-Up Approval. The Partnership shall not participate in a Roll-Up transaction unless the Roll-Up transaction is approved by Participants whose Common Units equal a majority of the total Common Units.

4.03(d)(16). Rebates. The General Partner and its Affiliates may not accept any rebates or give-ups or participate in any reciprocal business arrangements which would circumvent the provisions of this Agreement.

4.03(d)(17). Disclosure of Binding Agreements. Any agreement or arrangement that binds the Partnership must be disclosed in the prospectus for the Second Offering.

4.03(d)(18). Sales Commissions. All compensation of any kind or description paid by the Partnership, directly or indirectly, to broker dealers must be taken into consideration in computing the allowable sales commissions.

4.04. Designation, Compensation and Removal of General Partner.

4.04(a). General Partner.

4.04(a)(1). Term of Service. Except as otherwise provided in this Agreement, Atlas shall serve as the General Partner of the Partnership until either it:

 

  (i) is removed pursuant to § 4.04(a)(3); or

 

  (ii) withdraws pursuant to § 4.04(a)(3)(f).

4.04(a)(2)(a). Charges Must Be Necessary and Reasonable. Charges by the General Partner for goods and services must be fully supportable as to:

 

  (i) the necessity of the goods and services; and

 

  (ii) the reasonableness of the amount charged.

All actual and necessary expenses incurred by the Partnership may be paid out of the Partnership’s subscription proceeds and revenues.

4.04(a)(2)(b). Management Fee. The General Partner shall receive a management fee equal to the product of one percent (1%) per annum multiplied by gross Capital Contributions, payable quarterly.

4.04(a)(3). Removal of General Partner.

4.04(a)(3)(a). Majority Vote Required to Remove the General Partner. The General Partner may be removed at any time on 60 days’ advance written notice to the outgoing General Partner by the affirmative vote of Participants whose Common Units equal a majority of the outstanding Common Units.

 

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If the Participants vote to remove the General Partner from the Partnership, then Participants must elect by an affirmative vote of Participants whose Common Units equal a majority of the outstanding Common Units either to:

 

  (i) dissolve, wind-up, and terminate the Partnership; or

 

  (ii) continue as a successor limited partnership under all the terms of this Partnership Agreement as provided in § 7.01(c).

If the Participants elect to continue as a successor limited partnership, then the General Partner shall not be removed until a substituted General Partner has been selected by an affirmative vote of Participants whose Common Units equal a majority of the outstanding Common Units and installed as such.

4.04(a)(3)(b). Valuation of General Partner’s Interest in the Partnership. If the General Partner is removed, then the value of its General Partner Interest (represented by the GP Units) shall be determined by appraisal by a qualified Independent Expert. The Independent Expert shall be selected by mutual agreement between the removed General Partner and the incoming General Partner. The appraisal shall take into account an appropriate discount, to reflect the risk of recovering natural gas and oil reserves. The cost of the appraisal shall be borne equally by the removed General Partner and the Partnership.

4.04(a)(3)(c). Incoming General Partner’s Option to Purchase. The incoming General Partner shall have the option to purchase 20% of the removed General Partner’s General Partner Interest (represented by the GP Units) for the value determined by the Independent Expert.

4.04(a)(3)(d). Method of Payment. The method of payment by the Partnership for the removed General Partner’s General Partner Interest (represented by the GP Units) if not purchased pursuant to § 4.04(a)(3)(c) must be fair and protect the solvency and liquidity of the Partnership. The method of payment shall be as follows:

 

  (i) when the termination is voluntary, the method of payment shall be a non-interest bearing unsecured promissory note with principal payable, if at all, from distributions which the General Partner otherwise would have received under this Agreement with respect to its General Partner Interest (represented by the GP Units) had the General Partner not been terminated; and

 

  (ii) when the termination is involuntary, the method of payment shall be an interest bearing unsecured promissory note coming due in no less than five years with equal installments each year. The interest rate shall be that charged on comparable loans.

4.04(a)(3)(e). Termination of Contracts. At the time of its removal, the removed General Partner shall cause, to the extent it is legally possible to do so, its successor to be transferred or assigned all of its rights, obligations and interests as General Partner of the Partnership in contracts entered into by it on behalf of the Partnership. In any event, the removed General Partner shall cause all of its rights, obligations and interests as General Partner of the Partnership in any such contract to terminate at the time of its removal.

4.04(a)(3)(f). The General Partner’s Right to Voluntarily Withdraw. At any time beginning 10 years after the Initial Offering Initial Closing Date, the General Partner may voluntarily withdraw as General Partner on giving 120 days’ written notice of withdrawal to the Participants. If the General Partner withdraws, then the following conditions shall apply:

 

  (i) the General Partner’s interest in the Partnership shall be determined as described in § 4.04(a)(3)(b) above with respect to removal; and

 

  (ii) the interest shall be distributed to the General Partner as described in § 4.04(a)(3)(d)(i) above.

Any successor General Partner shall have the option to purchase 20% of the withdrawing General Partner’s General Partner Interest (represented by the GP Units) at the value determined as described above with respect to removal.

 

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4.04(a)(3)(g). Right of General Partner to Hypothecate Its Interests. The General Partner shall have the authority without the consent of the Participants and without affecting the allocation of costs and revenues incurred or received under this Agreement, to hypothecate, pledge, or otherwise encumber, on any terms it chooses for its own general purposes, its Partnership Interest. All repayments of these borrowings and costs, interest or other charges related to the borrowings shall be borne and paid separately by the General Partner. In no event shall the repayments, costs, interest, or other charges related to the borrowing be charged to the account of the Participants.

 

4.05. Indemnification and Exoneration.

4.05(a)(1). Standards for the General Partner Not Incurring Liability to the Partnership or Participants. The Indemnitee shall not have any liability whatsoever to the Partnership, or to any Participant for any loss suffered by the Partnership or the Participants which arises out of any action or inaction of the Indemnitee if:

 

  (i) the Indemnitee determined in good faith that the course of conduct was in the best interest of the Partnership;

 

  (ii) the Indemnitee was acting on behalf of, or performing services for, the Partnership; and

 

  (iii) the course of conduct did not constitute negligence or misconduct of the Indemnitee.

4.05(a)(2). Standards for General Partner Indemnification. The Indemnitee shall be indemnified by the Partnership against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection with the Partnership, provided that:

 

  (i) the Indemnitee determined in good faith that the course of conduct which caused the loss or liability was in the best interest of the Partnership;

 

  (ii) the Indemnitee was acting on behalf of, or performing services for, the Partnership; and

 

  (iii) the course of conduct was not the result of negligence or misconduct of the Indemnitee. .

Provided, however, payments arising from such indemnification or agreement to hold harmless are recoverable only out of the following:

 

  (i) the Partnership’s tangible net assets, which include its revenues; and

 

  (ii) any insurance proceeds received by the partnership.

4.05(a)(3). Standards for Securities Law Indemnification. Notwithstanding anything to the contrary contained in this section, the Indemnitee and any person acting as a broker/dealer with respect to the offer or sale of the Units, shall not be indemnified for any losses, liabilities or expenses arising from or out of an alleged violation of federal or state securities laws by such party unless:

 

  (i) there has been a successful adjudication on the merits of each count involving alleged securities law violations as to the particular indemnitee;

 

  (ii) the claims have been dismissed with prejudice on the merits by a court of competent jurisdiction as to the particular indemnitee; or

 

  (iii) a court of competent jurisdiction approves a settlement of the claims against a particular indemnitee and finds that indemnification of the settlement and the related costs should be made, and the court considering the request for indemnification has been advised of the position of the SEC and any state securities regulatory authority in which plaintiffs claim they were offered or sold Units with respect to the issue of indemnification for violation of securities laws.

4.05(a)(4). Standards for Advancement of Funds to the General Partner and Insurance. The advancement of Partnership funds to the Indemnitee for legal expenses and other costs incurred as a result of any legal action

 

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for which indemnification is being sought from the Partnership is permissible only if the Partnership has adequate funds available and the following conditions are satisfied:

 

  (i) the legal action relates to acts or omissions with respect to the performance of duties or services on behalf of the Partnership;

 

  (ii) the legal action is initiated by a third-party who is not a Participant, or the legal action is initiated by a Participant and a court of competent jurisdiction specifically approves the advancement; and

 

  (iii) the Indemnitee undertakes to repay the advanced funds to the Partnership, together with the applicable legal rate of interest thereon, in cases in which such party is found not to be entitled to indemnification.

The Partnership shall not bear the cost of that portion of insurance which insures the Indemnitee for any liability for which they could not be indemnified pursuant to §§4.05(a)(1) and 4.05(a)(2).

4.05(a)(5). Reserved.

4.05(a)(6). In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

4.05(a)(7). An Indemnitee shall not be denied indemnification in whole or in part under this § 4.05(a) because the Indemnitee had an interest in the transaction with respect to which the indemnification applies.

4.05(a)(8). The provisions of this § 4.05(a) are for the benefit of the Indemnitees and their heirs, successors, assigns, executors and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

4.05(a)(9). No amendment, modification or repeal of this § 4.05(a) or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this § 4.05(a) as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

4.05(b). Liability of Indemnitees.

4.05(b)(1). Subject to its obligations and duties as General Partner set forth herein, the General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner in good faith.

4.05(b)(2). To the extent that, at law or in equity, an Indemnitee has duties and liabilities relating thereto to the Partnership, the Partners, any Person who acquires an interest in a Partnership Interest or any other Person who is bound by this Agreement, any Indemnitee acting in connection with the Partnership’s business or affairs shall not be liable, to the fullest extent permitted by law, to the Partnership, to any Partner, to any other Person who acquires an interest in a Partnership Interest or to any other Person who is bound by this Agreement for its reliance on the provisions of this Agreement.

4.05(b)(3). Any amendment, modification or repeal of this § 4.05(b) or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this § 4.05(b) as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

 

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4.05(c). Authorized Transactions Are Deemed Not to Be a Breach. No transaction entered into or action taken by the Partnership, or by the General Partner or its Affiliates, which is authorized by this Agreement shall be deemed a breach of any obligation owed by the General Partner or its Affiliates to the Partnership or the Participants.

4.06. Other Activities.

4.06(a). The General Partner and its Affiliates May Pursue Other Natural Gas and Oil Activities for Its Own Account. The General Partner and its Affiliates are now engaged, and will engage in the future, for their own account and for the account of others, including other investors, in all aspects of the natural gas and oil business. This includes without limitation, the evaluation, acquisition, and sale of producing and nonproducing Leases, and the exploration for and production of natural gas, natural gas liquids, oil and other minerals. The General Partner is required to devote only so much of its time to the Partnership as it determines in its sole discretion, but consistent with its duties, is necessary to manage the affairs of the Partnership. Except as expressly provided to the contrary in this Agreement, the General Partner and its Affiliates may do the following:

 

  (i) continue their activities, or initiate further such activities, individually, jointly with others, or as a part of any other limited or general partnership, tax partnership, joint venture, or other entity or activity to which they are or may become a party, in any locale and in the same fields, areas of operation or prospects in which the Partnership may likewise be active;

 

  (ii) reserve partial interests in Leases being assigned to the Partnership or any other interests not expressly prohibited by this Agreement;

 

  (iii) deal with the Partnership as an independent party or through any other entity in which they may be interested;

 

  (iv) conduct business with the Partnership as set forth in this Agreement; and

 

  (v) participate in such other investor operations, as investors or otherwise.

4.06(b). General Partner May Manage Multiple Partnerships. The General Partner or its Affiliates may manage multiple Programs simultaneously.

4.07. Issuances of Additional Partnership Interests.

4.07(a). The Partnership may issue additional Partnership Interests and options, rights, warrants and appreciation rights relating to the Partnership Interests for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Limited Partners.

4.07(b). Each additional Partnership Interest authorized to be issued by the Partnership pursuant to § 4.07(a) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of Partnership Interests), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may or shall be required to redeem the Partnership Interest (including sinking fund provisions) (v) whether such Partnership Interest is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Interest will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Interest; and (viii) the right, if any, of each such Partnership Interest to vote on Partnership matters, including matters relating to the relative designations, preferences, rights, powers and duties of such Partnership Interest.

 

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4.07(c). The General Partner is hereby authorized and directed to take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Interests and options, rights, warrants and appreciation rights relating to Partnership Interests pursuant to this § 4.07, (ii) the admission of additional Limited Partners and (iii) all additional issuances of Partnership Interests. The General Partner shall determine the relative rights, powers and duties of the holders of the Units or other Partnership Interests being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Interests pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Interests are listed or admitted for trading.

4.07(d). No fractional Units shall be issued by the Partnership. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units (but for this § 4.07(d)), then each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

4.08. Splits and Combinations.

4.08(a). Subject to § 4.07(d) (dealing with adjustments of distribution levels), the Partnership may make a pro rata distribution of Partnership Interests to all Record Holders or may effect a subdivision or combination of Partnership Interests so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per Partnership Interest basis or stated as a number of Partnership Interests are proportionately adjusted.

4.08(b). Whenever such a distribution, subdivision or combination of Partnership Interests is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Interests to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

4.08(c). Promptly following any such distribution, subdivision or combination, the Partnership may issue certificated or uncertificated Partnership Interests to the Record Holders of Partnership Interests as of the applicable Record Date representing the new number of Partnership Interests held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Interests outstanding, and a Partnership Interest is represented by a certificate, the Partnership shall require, as a condition to the delivery to a Record Holder of such new certificate, the surrender of any certificate held by such Record Holder immediately prior to such Record Date.

ARTICLE V CAPITAL ACCOUNTS, ALLOCATIONS, ELECTIONS AND DISTRIBUTIONS

5.01. Capital Accounts.

5.01(a). The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest and (ii) all items of Partnership income and gain (including Simulated Gain and income and gain exempt from tax)

 

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computed in accordance with § 5.01(b) and allocated with respect to such Partnership Interest pursuant to § 5.02, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest and (y) all items of Partnership deduction and loss (including Simulated Depletion and Simulated Loss) computed in accordance with § 5.01(b) and allocated with respect to such Partnership Interest pursuant to § 5.02.

5.01(b). For purposes of computing the amount of any item of income, gain, loss, deduction, Simulated Depletion, Simulated Gain or Simulated Loss to be allocated pursuant to this Article V and to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for U.S. federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose); provided that:

 

  (i) Solely for purposes of this § 5.01, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable governing, organizational or similar documents) of all property owned by (x) any other Group Member that is classified as a partnership for U.S. federal income tax purposes and (y) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership for U.S. federal income tax purposes of which a Group Member is, directly or indirectly, a partner, member or other equity holder.

 

  (ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to § 5.02.

 

  (iii) Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss shall be made without regard to any election under Section 754 of the Code that may be made by the Partnership and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for

U.S. federal income tax purposes. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

 

  (iv) Any income, gain, loss, Simulated Gain, Simulated Loss or deduction attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Partnership’s Carrying Value with respect to such property as of such date.

 

  (v) Any item of income of the Partnership that is described in Section 705(a)(1)(B) of the Code (with respect to items of income that are exempt from tax) shall be treated as an item of income for the purpose of this § 5.01(b), and any item of expense of the Partnership that is described in Section 705(a)(2)(B) of the Code (with respect to expenditures that are not deductible and not chargeable to capital accounts) shall be treated as an item of deduction for the purpose of this § 5.01(b), in each case without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for U.S. federal income tax purposes.

 

  (vi)

In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery, amortization or Simulated Depletion attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Partnership were equal to the Agreed Value of such property. Upon an adjustment pursuant to § 5.01(d) to the Carrying Value of any Partnership property subject to depreciation, cost recovery, amortization, or Simulated Depletion, any further deductions for such depreciation, cost recovery, amortization or Simulated

 

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  Depletion attributable to such property shall be determined (A) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment and (B) using a rate of depreciation, cost recovery or amortization derived from the same method and useful life (or, if applicable, the remaining useful life) as is applied for U.S. federal income tax purposes; provided, however, that, if the asset has a zero adjusted basis for U.S. federal income tax purposes, depreciation, cost recovery or amortization deductions shall be determined using any method that the General Partner may adopt.

 

  (vii) The Gross Liability Value of each Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i) shall be adjusted at such times as provided in this Agreement for an adjustment to Carrying Values. The amount of any such adjustment shall be treated for purposes hereof as an item of loss (if the adjustment increases the Carrying Value of such Liability of the Partnership) or an item of gain (if the adjustment decreases the Carrying Value of such Liability of the Partnership).

 

  (viii) If the Partnership’s adjusted basis in a depreciable or cost recovery property is reduced for U.S. federal income tax purposes pursuant to Section 50(c)(1) or (3) of the Code, the amount of such reduction shall, solely for purposes hereof, be deemed to be an additional depreciation or cost recovery deduction in the year such property is placed in service and shall be allocated among the Partners pursuant to § 5.02. Any restoration of such basis pursuant to Section 50(c)(2) of the Code shall, to the extent possible, be allocated in the same manner to the Partners to whom such deemed deduction was allocated.

5.01(c). A transferee of a Partnership Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.

5.01(d)(1). In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Partnership Interests for cash (other than issuances of Common Units at the Initial Unit Price, in which case no adjustment shall be required to be made under this subsection) or Contributed Property or the issuance of Partnership Interests as consideration for the provision of services, the Capital Account of all Partners and the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property for an amount equal to its fair market value immediately prior to such issuance and had been allocated among the Partners at such time pursuant to § 5.02 in the same manner as any item of gain or loss actually recognized during such period would have been allocated; provided, however, that in the event of an issuance of Partnership Interests for a de minimis amount of cash or Contributed Property, or in the event of an issuance of a de minimis amount of Partnership Interests as consideration for the provision of services, the General Partner may determine that such adjustments are unnecessary for the proper administration of the Partnership. If upon the occurrence of an event described in this § 5.01(d)(1), a warrant of the Partnership is outstanding, the Partnership shall adjust the Carrying Value of each Partnership property in accordance with Treasury Regulation Sections 1.704-1(b)(2)(iv)(f)(1) and 1.704-1(b)(2)(iv)(h)(2). In determining such Unrealized Gain or Unrealized Loss, the aggregate fair market value of all Partnership property (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests (or, in the case of an issuance of a warrant, immediately after such issuance if required pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(s)(1)) shall be determined by the General Partner using such method of valuation as it may adopt. In determining such Unrealized Gain or Unrealized Loss for purposes of maintaining Capital Accounts, the aggregate fair market value of all Partnership property (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such method of valuation as it may adopt; provided, however, that the General Partner, in arriving at such valuation, may determine that it is appropriate to first determine an aggregate value for the Partnership, derived from taking fully into account the fair market value of the Partnership Interests of all Partners at such time. The General Partner shall allocate such aggregate value among the assets of the Partnership (in such manner as it determines) to arrive at a fair market value for individual properties.

 

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5.01(d)(2). In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Capital Accounts of all Partners and the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized in a sale of such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated among the Partners, at such time, pursuant to § 5.02 in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized during such period would have been allocated; provided, however, that in the event of a distribution of a de minimis amount of Partnership property, the General Partner may determine that such adjustments are unnecessary for the proper administration of the Partnership. In determining such Unrealized Gain or Unrealized Loss for purposes of maintaining Capital Accounts, the aggregate fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to § 5.08 or in the case of a deemed distribution, be determined in the same manner as that provided in § 5.01(d)(1), or (B) in the case of a liquidating distribution pursuant to § 5.08, be determined and allocated by the Liquidator using such method of valuation as it may adopt.

5.02. Allocations for Capital Account Purposes.

For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss (computed in accordance with § 5.01(b)) shall be allocated among the Partners in each taxable year (or portion thereof) as provided herein below.

5.02(a). Net Income. After giving effect to the special allocations set forth in § 5.02(d), and any allocations to other Partnership Interests, Net Income for each taxable year and all items of income, gain, loss, deduction and Simulated Gain taken into account in computing Net Income for such taxable year shall be allocated to the Partners as follows:

 

  (i) First, 100% to the General Partner in an amount equal to the aggregate Net Losses allocated to the General Partner pursuant to § 5.02(b)(iii) for all previous taxable years until the aggregate Net Income allocated to the General Partner pursuant to this § 5.02(a)(i) for the current taxable year and all previous taxable years is equal to the aggregate Net Losses allocated to the General Partner pursuant to § 5.02(b)(iii) for all previous taxable years;

 

  (ii) Second, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests, until the aggregate Net Income allocated to such Partners pursuant to this § 5.02(a)(ii) for the current taxable year and all previous taxable years is equal to the aggregate Net Losses allocated to such Partners pursuant to § 5.02(b)(ii) for all previous taxable years; and

 

  (iii) Third, the balance, if any, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests.

5.02(b). Net Losses. After giving effect to the special allocations set forth in § 5.02(d), and any allocations to other Partnership Interests, Net Losses for each taxable period and all items of income, gain, loss, deduction and Simulated Gain taken into account in computing Net Losses for such taxable period shall be allocated to the Partners as follows:

 

  (i) First, 100% to the General Partner, until the aggregate Net Losses allocated pursuant to this § 5.02(b)(i) for the current taxable year and all previous taxable years is equal to the aggregate Net Income allocated to such Partners pursuant to § 5.02(a)(iii) for all previous taxable years, provided that the Net Losses shall not be allocated pursuant to this § 5.02(b)(i) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account);

 

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  (ii) Second, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests; provided, that Net Losses shall not be allocated pursuant to this § 5.02(b)(ii) to the extent that such allocation would cause the General Partner or any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account); and

 

  (iii) Third, the balance, if any, 100% to the General Partner.

5.02(c). Net Termination Gains and Losses. After giving effect to the special allocations set forth in § 5.02(d), all items of income, gain, loss, deduction and Simulated Gain taken into account in computing Net Termination Gain or Net Termination Loss for such taxable period shall be allocated in the same manner as such Net Termination Gain or Net Termination Loss is allocated hereunder. All allocations under this § 5.02(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this § 5.02 and after all distributions of Available Cash provided under §§ 5.05 and 5.06 have been made; provided, however, that solely for purposes of this § 5.02(c), Capital Accounts shall not be adjusted for distributions made pursuant to § 5.08.

 

  (i) If a Net Termination Gain is recognized (or deemed recognized pursuant to § 5.01(d)), such Net Termination Gain shall be allocated among the Partners in the following manner (and the Capital Accounts of the Partners shall be increased by the amount so allocated in each of the following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):

 

  (A) First, to each Partner having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Partners, until each such Partner has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account;

 

  (B) Second, to the holders of the Common Units, Pro Rata, until the Capital Account of each Common Unit is equal to the sum of (1) the unreturned Capital Contributions of each Common Unit outstanding at the time of the liquidation and (2) the amount of the $0.175 per Common Unit distribution to the holders of the Common Units for the Quarter in which the liquidation occurs, and (3) any unpaid arrearages owing to the holders of the Common Units assuming that the holders of the Common Units were entitled to the Target Distribution taking into account distributions to the holders of the Common Units pursuant to § 5.05 and § 5.06;

 

  (C) Third, to the holder of the GP Units, Pro Rata, until the Capital Account for each GP Unit is equal to (1) the unreturned Capital Contributions attributable to the GP Units, plus (2) 2.04% multiplied by the excess of (A) the amount distributed to the holders of the Common Units, over (B) the product of $10.00 multiplied by the number of Common Units outstanding at the time of the liquidation, minus (3) the amount previously distributed to the holders of the GP Units (provided that the Capital Account shall not be reduced below zero);

 

  (D) Fourth, to the holders of the Incentive Distribution Rights, Pro Rata, until the Capital Accounts, Pro Rata, for the holders of the Incentive Distribution Rights is equal to the excess of (1) 25% multiplied by the excess of (A) the amount distributed to the holders of the Common Units, over (B) the product of $10.00 multiplied by the number of Common Units outstanding at the time of the liquidation, over (2) the amount previously distributed to the holders of the Incentive Distribution Rights; and

 

  (E) Thereafter, 80% to the holders of the Common Units, Pro Rata, and 20% to the holders of the Incentive Distribution Rights, Pro Rata.

Notwithstanding the foregoing provisions in this Section 5.02(c)(i), the General Partner may adjust the amount of any Net Termination Gain arising in connection with an event described in Section 5.01(d) that is allocated to the holders of Incentive Distribution Rights in a manner that will result (i) in the Capital Account for each Common Unit that is outstanding prior to such event described in Section 5.01(d) being equal to the fair

 

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market value of the Partnership Interests and (ii) to the greatest extent possible, the Capital Account with respect to the Incentive Distribution Rights that are outstanding prior to such event described in Section 5.01(d) being equal to the amount of Net Termination Gain that would be allocated to the holders of the Incentive Distribution Rights pursuant to this Section 5.02(c)(i) if the Capital Accounts with respect to all Partnership Interests that were outstanding immediately prior to such event described in Section 5.01(d) and the Carrying Value of each Partnership property were equal to zero.

 

  (ii) If a Net Termination Loss is recognized (or deemed recognized pursuant to § 5.01(d)), such Net Termination Loss shall be allocated among the Partners in the following manner:

 

  (A) First, 2% to the holders of GP Units, Pro Rata, and 98% to the holders of Common Units, Pro Rata, until the Capital Account in respect of each Common Unit then outstanding has been reduced to zero; and

 

  (B) Second, the balance, if any, 100% to the General Partner.

5.02(d). Special Allocations. Notwithstanding any other provision of this § 5.02, the following special allocations shall be made for such taxable period:

 

  (i) Partnership Minimum Gain Chargeback. Notwithstanding any other provision of this § 5.02, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704- 2(j)(2)(i), or any successor provision. For purposes of this § 5.02(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain or Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this § 5.02(d) with respect to such taxable period (other than an allocation pursuant to §§ 5.02(d)(vi) and 5.02(d)(vii)). This § 5.02(d)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

 

  (ii) Chargeback of Partner Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this § 5.02 (other than § 5.02(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this § 5.02(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain or Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this § 5.02(d), other than § 5.02(d)(i) and other than an allocation pursuant to §§ 5.02(d)(vi) and 5.02(d)(vii), with respect to such taxable period. This § 5.02(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

 

  (iii) Priority Allocations.

 

  (A)

If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed pursuant to § 5.08) to any Unitholder with respect to its Units or GP Units, as the case may be for a taxable year is greater (on a per Unit basis or per GP Unit basis, as the case may be) than the amount of cash or the Net Agreed Value of property distributed to the other Unitholders with respect to their Units or GP Units, as the case may be (on a per Unit basis or a per GP Unit basis, as the case may be), then each Unitholder receiving such greater cash or property distribution shall be allocated gross income in an amount equal to the product of (1) the amount by which the distribution (on a per Unit basis or per GP Unit basis, as the case may be) to such

 

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  Unitholder exceeds the distribution (on a per Unit basis or per GP Unit basis, as the case may be) to the Unitholders receiving the smallest distribution and (2) the number of Units or GP Units, as the case may be, owned by the Unitholder receiving the greater distribution.

 

  (B) After the application of § 5.02(d)(iii)(A), all or any portion of the remaining items of Partnership gross income or gain for the taxable period, if any, shall be allocated 100% to the holders of Incentive Distribution Rights, Pro Rata, until the aggregate amount of such items allocated to the holders of Incentive Distribution Rights pursuant to this § 5.02(d)(iii)(B) for the current taxable year and all previous taxable years is equal to the cumulative amount of all Incentive Distributions made to the holders of Incentive Distribution Rights from the Initial Offering Initial Closing Date to a date 45 days after the end of the current taxable year.

 

  (iv) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Section 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5) or 1.704-1(b)(2)(ii)(d)(6), items of Partnership income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible unless such deficit balance is otherwise eliminated pursuant to § 5.02(d)(i) or (ii).

 

  (v) Gross Income Allocations. In the event any Partner has a deficit balance in its Capital Account at the end of any Partnership taxable period in excess of the sum of (A) the amount such Partner is obligated to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership gross income, gain and Simulated Gain in the amount of such excess as quickly as possible; provided that an allocation pursuant to this § 5.02(d)(v) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this § 5.02 have been tentatively made as if this § 5.02(d)(v) were not in this Agreement.

 

  (vi) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Partners in accordance with their respective Percentage Interests. If the General Partner determines that the Partnership’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

 

  (vii) Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i)(1). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss.

 

  (viii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners in accordance with their respective Percentage Interests.

 

  (ix)

Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain or Simulated Gain (if the adjustment increases the basis of the asset) or loss or Simulated Loss (if the adjustment decreases such basis), and such item of gain or loss, Simulated Gain or Simulated Loss shall be

 

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  specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

 

  (x) Curative Allocation.

 

  (A) Notwithstanding any other provision of this § 5.02, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this § 5.02. Notwithstanding the preceding sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partnership Minimum Gain and (2) Partner Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partner Nonrecourse Debt Minimum Gain. Allocations pursuant to this § 5.02(d)(x)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners. Further, allocations pursuant to this § 5.02(d)(x)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the General Partner determines that such allocations are likely to be offset by subsequent Required Allocations.

 

  (B) The General Partner shall, with respect to each taxable period, (1) apply the provisions of § 5.02(d)(x)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to § 5.02(d)(x)(A) among the Partners in a manner that is likely to minimize such economic distortions.

 

  (xi) Corrective Allocations. In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:

 

  (A) The General Partner shall allocate Additional Book Basis Derivative Items consisting of depreciation, amortization, depletion and any other form of cost recovery (other than Additional Book Basis Derivative Items included in Net Termination Gain or Net Termination Loss with respect to any Adjusted Property) to the Unitholders, Pro Rata, the holders of the Incentive Distribution Rights and the General Partner, all in the same proportions as the Net Termination Gain or Net Termination Loss resulting from the event that gave rise to such Additional Book Basis Derivative Items was allocated to them pursuant to § 5.01(d).

 

  (B)

If a sale or other taxable disposition of an Adjusted Property, including, for this purpose, inventory (“Disposed of Adjusted Property”) occurs other than in connection with an event giving rise to Net Termination Gain or Net Termination Loss, the General Partner shall allocate additional items of gross income and gain away from the holders of Incentive Distribution Rights to the Unitholders, or additional items of deduction and loss away from the Unitholders to the holders of Incentive Distribution Rights and the General Partner, to the extent that the Additional Book Basis Derivative Items with respect to the Disposed of Adjusted Property (determined in accordance with the last sentence of the definition of Additional Book Basis Derivative Items) treated as having been allocated to the Unitholders pursuant to this § 5.02(d)(xi)(B) exceed their Share of Additional Book Basis Derivative Items with respect to such Disposed of Adjusted Property. For this purpose, the Unitholders shall be treated as being allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that would otherwise have been allocated to the Unitholders under this Agreement (e.g., Additional Book Basis Derivative Items taken into account in computing cost of goods sold would reduce the amount of book income otherwise available for allocation

 

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  among the Partners). Any allocation made pursuant to this § 5.02(d)(xi)(B) shall be made after all of the other Agreed Allocations have been made as if this § 5.02(d)(xi) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.

 

  (C) Net Termination Loss in an amount equal to the lesser of (1) such Net Termination Loss and (2) the Aggregate Remaining Net Positive Adjustments shall be allocated in such a manner, as determined by the General Partner, that to the extent possible, the Capital Account balances of the Partners will equal the amount they would have been had no prior Book-Up Events occurred, and any remaining Net Termination Loss shall be allocated pursuant to § 5.02(c) hereof. In allocating Net Termination Loss pursuant to this § 5.02(d)(xi)(C), the General Partner shall attempt, to the extent possible, to cause the Capital Accounts of the Unitholders, on the one hand, and holders of the Incentive Distribution Rights, on the other hand, to equal the amount they would equal if (i) the Carrying Values of the Partnership’s property had not been previously adjusted in connection with any prior Book-Up Events, (ii) Unrealized Gain and Unrealized Loss (or, in the case of a liquidation, actual gain or loss) with respect to such Partnership Property were determined with respect to such unadjusted Carrying Values, and (iii) any resulting Net Termination Gain had been allocated pursuant to § 5.02(c) (including, for the avoidance of doubt, taking into account the provisions set forth in the last sentence of § 5.02(c)(i)).

 

  (D) In making the allocations required under this § 5.02(d)(xi), the General Partner may apply whatever conventions or other methodology it determines will satisfy the purpose of this § 5.02(d)(xi). Without limiting the foregoing, if an Adjusted Property is contributed by the Partnership to another entity classified as a partnership for federal income tax purposes (the “lower tier partnership”), the General Partner may make allocations similar to those described in §§ 5.02(d)(xi)(A)-(C) to the extent the General Partner determines such allocations are necessary to account for the Partnership’s allocable share of income, gain, loss and deduction of the lower tier partnership that relate to the contributed Adjusted Property in a manner that is consistent with the purpose of this § 5.02(d)(xi).

 

  (xii) Allocations Upon Exercise of Warrants. Upon the exercise of a warrant by a Partner, the General Partner shall make the adjustments and allocations, and take other actions, required by Treasury Regulations Section 1.704-1(b)(2) and (4) and other Treasury Regulations referred to therein.

5.02(e). Simulated Depletion and Simulated Loss.

5.02(e)(1). In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(k), Simulated Depletion with respect to each oil and gas property shall be allocated among the General Partner and the Unitholders Pro Rata.

5.02(e)(2). Simulated Loss with respect to the disposition of an oil and gas property shall be allocated among the Partners in proportion to their allocable share of total amount realized from such disposition under § 5.03(c)(i).

5.03. Allocations for Tax Purposes.

5.03(a). Except as otherwise provided herein, for U.S. federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to § 5.02.

5.03(b). The deduction for depletion with respect to each separate oil and gas property (as defined in Section 614 of the Code) shall be computed for U.S. federal income tax purposes separately by the Partners rather than by the Partnership in accordance with Section 613A(c)(7)(D) of the Code. Except as provided in § 5.03(c)(iii), for purposes of such computation (before taking into account any adjustments resulting from an election made by the Partnership under Section 754 of the Code), the adjusted tax basis of each oil and gas property (as defined in Section 614 of the Code) shall be allocated among the Partners Pro Rata. Each Partner shall separately keep

 

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records of his share of the adjusted tax basis in each oil and gas property, allocated as provided above, adjust such share of the adjusted tax basis for any cost or percentage depletion allowable with respect to such property, and use such adjusted tax basis in the computation of its cost depletion or in the computation of his gain or loss on the disposition of such property by the Partnership.

5.03(c). Except as provided in § 5.03(c)(iii), for the purposes of the separate computation of gain or loss by each Partner on the sale or disposition of each separate oil and gas property (as defined in Section 614 of the Code), the Partnership’s allocable share of the “amount realized” (as such term is defined in Section 1001(b) of the Code) from such sale or disposition shall be allocated for U.S. federal income tax purposes among the Partners as follows:

 

  (i) first, to the extent such amount realized constitutes a recovery of the Simulated Basis of the property, to the Partners in the same proportion as the depletable basis of such property was allocated to the Partners pursuant to § 5.03(b) (without regard to any special allocation of basis under § 5.03(c)(iii)).

 

  (ii) second, the remainder of such amount realized, if any, to the Partners so that, to the maximum extent possible, the amount realized allocated to each Partner under this § 5.03(c)(ii) will equal such Partner’s share of the Simulated Gain recognized by the Partnership from such sale or disposition.

 

  (iii) The Partners recognize that with respect to Contributed Property and Adjusted Property there will be a difference between the Carrying Value of such property at the time of contribution or revaluation, as the case may be, and the adjusted tax basis of such property at that time. All items of tax depreciation, cost recovery, amortization, adjusted tax basis of depletable properties, amount realized and gain or loss with respect to such Contributed Property and Adjusted Property shall be allocated among the Partners to take into account the disparities between the Carrying Values and the adjusted tax basis with respect to such properties in accordance with the principles of Treasury Regulation Section 1.704-3(d).

5.03(d). In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property other than an oil and gas property pursuant to § 5.03(c), items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for U.S. federal income tax purposes among the Partners as follows:

 

  (i) (A) In the case of a Contributed Property, such items attributable thereto shall be allocated among the Partners in the manner provided under Section 704(c) of the Code that takes into account the variation between the Agreed Value of such property and its adjusted basis at the time of contribution; and (B) any item of Residual Gain or Residual Loss attributable to a Contributed Property shall be allocated among the Partners in the same manner as its correlative item of “book” gain or loss is allocated pursuant to § 5.02.

 

  (ii) (A) In the case of an Adjusted Property, such items shall (1) first, be allocated among the Partners in a manner consistent with the principles of Section 704(c) of the Code to take into account the Unrealized Gain or Unrealized Loss attributable to such property and the allocations thereof pursuant to §§ 5.01(d)(i) or 5.01(d)(ii), and (2) second, in the event such property was originally a Contributed Property, be allocated among the Partners in a manner consistent with § 5.03(d)(i)(A); and (B) any item of Residual Gain or Residual Loss attributable to an Adjusted Property shall be allocated among the Partners in the same manner as its correlative item of “book” gain or loss is allocated pursuant to § 5.02.

 

  (iii) The General Partner shall apply the principles of Treasury Regulation Section 1.704-3(d) to eliminate Book-Tax Disparities.

5.03(e). For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations for U.S. federal income tax purposes of income (including gross income) or deductions; and

 

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(iii) amend the provisions of this Agreement as appropriate (A) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (B) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this § 5.03(e) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Limited Partner Interests issued and outstanding or the Partnership, and if such allocations are consistent with the principles of Section 704 of the Code.

5.03(f). The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the Partnership’s common basis of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-1(a)(6), Treasury Regulation Section 1.197-2(g)(3), or any successor regulations thereto. If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership’s property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Limited Partner Interests, so long as such conventions would not have a material adverse effect on the Limited Partners or the Record Holders of any class or classes of Limited Partner Interests.

5.03(g). In accordance with Treasury Regulation Sections 1.1245-1(e) and 1.1250-1(f), any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this § 5.03, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

5.03(h). All items of income, gain, loss, deduction and credit recognized by the Partnership for U.S. federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code which may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

5.03(i). Each item of Partnership income, gain, loss and deduction shall, for U.S. federal income tax purposes, be determined on an annual basis and prorated on a monthly basis and shall be allocated to the Partners as of the opening the first Business Day of each month; provided, however, that gain or loss on a sale or disposition of any asset of the Partnership or any other extraordinary item of income or loss realized or recognized other than in the ordinary course of business, as determined by the General Partner in its sole discretion, shall be allocated to the Partners as of the date on which such gain or loss is recognized for federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

5.03(j). Allocations that would otherwise be made to a Limited Partner under the provisions of this Article V shall instead be made to the beneficial owner of Limited Partner Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

5.03(k). If, as a result of an exercise of a warrant, a Capital Account reallocation is required under Treasury Regulation Section 1.704-1(b)(2)(iv)(s)(3), the General Partner shall make corrective allocations pursuant to Treasury Regulation Section 1.704-1(b)(4)(x).

 

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5.04. Requirement and Characterization of Distributions; Distributions to Record Holders.

5.04(a). Except as described in § 5.04(b), within 45 days following the end of each Quarter (or if such 45th day is not a Business Day, then the Business Day immediately following such 45th day), an amount equal to 100% of Available Cash with respect to such Quarter shall, subject to Section 17-607 of the Delaware Act, be distributed in accordance with this Article VI by the Partnership to the Partners as of the Record Date selected by the General Partner. All amounts of Available Cash distributed by the Partnership on any date from any source shall be deemed to be Operating Surplus until the sum of all amounts of Available Cash theretofore distributed by the Partnership to the Partners pursuant to § 5.05 equals the Operating Surplus from the Initial Offering Initial Closing Date through the close of the immediately preceding Quarter. Any remaining amounts of Available Cash distributed by the Partnership on such date shall, except as otherwise provided in § 5.06, be deemed to be “Capital Surplus.” All distributions required to be made under this Agreement shall be made subject to Section 17-607 of the Delaware Act.

5.04(b). Notwithstanding § 5.04(a), in the event of the dissolution and liquidation of the Partnership, all cash received during or after the Quarter in which the date of Final Terminating Event occurs, other than from borrowings described in (a)(ii) of the definition of Available Cash, shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, § 5.08.

5.04(c). The General Partner may treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners, as determined by the General Partner.

5.04(d). Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through the transfer agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

5.05. Distributions of Available Cash from Operating Surplus.

Subject to § 5.08, Available Cash with respect to any Quarter that is deemed to be Operating Surplus pursuant to the provisions of §§ 5.04 or 5.06 shall, subject to Section 17-607 of the Delaware Act, be distributed as follows, except as otherwise required by § 4.07(b) in respect of additional Partnership Interests issued pursuant thereto: 2% to the holders of GP Units, Pro Rata and 98% to the holders of Common Units, Pro Rata; provided, however, that, with respect to the first Quarter for which each Common Unit is outstanding, all amounts shall be prorated based on the number of days in such Quarter such Common Unit was outstanding.

5.06. Distributions of Available Cash from Capital Surplus.

Subject to § 5.08, Available Cash that is deemed to be Capital Surplus pursuant to the provisions of § 5.04(a) shall, subject to Section 17-607 of the Delaware Act, be distributed, unless the provisions of § 5.04 require otherwise, as follows:

 

  (i) First, 2% to the holders of GP Units, Pro Rata, and 98% to the holders of Common Units, Pro Rata, until a hypothetical holder of a Common Unit acquired on the Initial Offering Initial Closing Date has received with respect to such Common Unit, during the period since the Initial Offering Initial Closing Date through such date, distributions of Available Cash that are deemed to be Capital Surplus in an aggregate amount equal to the Initial Unit Price; and

 

  (ii) Second, any remaining Available Cash shall be distributed as if it were Operating Surplus and shall be distributed in accordance with § 5.05.

 

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5.07. Special Provisions Relating to the Holders of Incentive Distribution Rights.

Notwithstanding anything to the contrary set forth in this Agreement, the holders of the Incentive Distribution Rights (a) shall (i) possess the rights and obligations provided in this Agreement with respect to a Limited Partner and (ii) have a Capital Account as a Partner pursuant to § 5.01 and all other provisions related thereto and (b) shall not (i) be entitled to vote on any matters requiring the approval or vote of the holders of outstanding Units, except as required by law, (ii) be entitled to any distributions from the Partnership prior to a Listing Event, except as set forth in § 5.08 or § 5.09 or (iii) be allocated items of income, gain, loss or deduction other than as specified in this Article V.

5.08. Distributions of Available Cash from Sale of All or Substantially All Assets.

Available Cash with respect to the sale of all or substantially all of the Partnership’s assets (an “Asset Sale”) shall, subject to Section 17-607 of the Delaware Act, be distributed as follows:

 

  (i) First, 100% to the holders of Common Units, Pro Rata, until there has been distributed in respect of each Common Unit an amount equal to the sum of the Initial Unit Price plus the Target Distribution for each Quarter since the Initial Offering Initial Closing Date of such Common Unit less amounts previously distributed with respect to such Common Unit pursuant to § 5.05 or § 5.06 or this § 5.08(i);

 

  (ii) Second, 100% to the holders of the GP Units, Pro Rata, until there has been distributed in respect of the GP Units, including amounts previously distributed pursuant to § 5.05, an amount equal to the excess of (A) 2.04% of the excess of (1) amounts distributed to the holders of Common Units pursuant to § 5.05 and § 5.08(i), over (2) the Initial Unit Price multiplied by the number of Common Units outstanding at the time of the Asset Sale, less (B) the amounts previously distributed with respect to the GP Units pursuant to this § 5.08(ii);

 

  (iii) Third, 100% to the holders of the Incentive Distribution Rights, Pro Rata, until there has been distributed in respect thereof an amount equal to the sum of (A) the product of 25% multiplied by the sum of (x) the amount distributed to the Common Units pursuant to clause First above plus (y) amounts previously distributed with respect to the Common Units pursuant to § 5.05 and § 5.06 less (z) the product of the Initial Unit Price multiplied by the number of Common Units then outstanding, plus (B) the sum of all capital contributions with respect to the GP Units less (C) amounts previously distributed to the holders of GP Units and Incentive Distribution Rights pursuant to this § 5.08(iii); and

 

  (iv) Thereafter, (A) 80% to the holders of the Common Units, Pro Rata, and (B) 20% to the holders of the Incentive Distribution Rights, Pro Rata.

5.09. Distributions in the Event of Merger.

Consideration to be received in the event of a Merger shall be valued based on the price attributed thereto in the Merger Agreement and be distributed in accordance with § 5.08.

5.10. Distribution Reinvestment Plans.

The General Partner may establish, from time to time, a distribution reinvestment plan or plans (a “Reinvestment Plan”). Under any such Reinvestment Plan, (i) all material information regarding distributions to the Participants and the effect of reinvesting such distributions, including the tax consequences thereof, shall be provided to the Participants at least annually, and (ii) each Participant participating in such Reinvestment Plan shall have a reasonable opportunity to withdraw from the Reinvestment Plan at least annually after receipt of the information required in clause (i) above. To the extent economically feasible, money held for reinvestment must be placed in an income-producing account which provides an appropriate safety for the principal and must be subject to withdrawal by the Participant upon not less than 10 days notice. If the funds are not reinvested within 180 days of the date of distribution, they must be distributed, with such income, if any, to the Participants participating in such Reinvestment Plan. No sales commissions may be deducted directly or indirectly from the reinvested funds.

 

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ARTICLE VI TRANSFER OF UNITS

6.01. Transferability of Common Units.

Except as provided in § 3.05(c) with respect to the General Partner if it buys Common Units, a Participant’s transfer of a portion or all his Common Units, or any interest in his Common Units, is subject to all of the provisions of this Article VI. For purposes of this Article VI, the term “transfer” shall include any sale, exchange, gift, assignment, pledge, mortgage, hypothecation, redemption or other form of transfer of a Common Unit, or any interest in a Common Unit, by a Participant or by operation of law. Unless a transferee of a Participant’s Common Unit becomes a substitute Participant with respect to that Common Unit in accordance with the provisions of § 6.02(a)(3)(a), he shall not be entitled to any of the rights granted to a Participant under this Agreement, other than the right to receive all or part of the share of the profits, losses, income, gains, deductions, credits and depletion allowances, or items thereof, and cash distributions or returns of capital to which his transferor would otherwise be entitled under this Agreement.

6.02. Special Restrictions on Transfers of Units by Participants.

6.02(a). In General. Transfers of Common Units by Participants are subject to the following general conditions:

 

  (i) except as provided by operation of law:

 

  (a) only whole Common Units may be transferred unless the Participant owns less than a whole Common Unit, in which case his entire fractional interest must be transferred; and

 

  (b) Common Units may not be transferred to a person who is under the age of 18 or incompetent (unless an attorney-in-fact, guardian, custodian or conservator has been appointed to handle the affairs of that person) without the General Partner’s consent;

 

  (ii) the costs and expenses associated with the transfer must be paid by the assignor Participant;

 

  (iii) the transfer documents must be in a form satisfactory to the General Partner; and

 

  (iv) the terms of the transfer must not contravene those of this Agreement.

Transfers of Common Units by Participants are subject to the following additional restrictions set forth in §§ 6.02(a)(1) and 6.02(a)(2).

6.02(a)(1). Tax Law Restrictions. Subject to transfers permitted by § 6.03 and transfers by operation of law, no transfer of a Common Unit by a Participant shall be made which, in the opinion of counsel to the Partnership, unless this requirement for an opinion of counsel is waived by the General Partner, would result in the Partnership being either:

 

  (i) terminated for tax purposes under Section 708 of the Code; or

 

  (ii) treated as a “publicly traded” partnership for purposes of Section 7704(b) of the Code.

6.02(a)(2). Securities Laws Restriction. Subject to transfers permitted by § 6.03 and transfers by operation of law, no Common Unit shall be transferred by a Participant unless there is either:

 

  (i) an effective registration of the Common Unit under the Securities Act of 1933, as amended, and qualification under applicable state securities laws; or

 

  (ii) an opinion of counsel acceptable to the General Partner that the registration and qualification of the Common Unit is not required, unless this requirement for an opinion of counsel is waived by the General Partner.

 

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Transfers of Common Units by Participants are also subject to any conditions contained in the Subscription Agreement.

6.02(a)(3). Substitute Participant.

6.02(a)(3)(a). Procedure to Become Substitute Participant. Subject to §§ 6.02(a)(1) and 6.02(a)(2), a transferee of a Participant’s Common Unit shall become a substitute Participant entitled to all the rights of a Participant if, and only if:

 

  (i) the transferor gives the transferee the right;

 

  (ii) the transferee pays to the Partnership all costs and expenses incurred by the Partnership in connection with the substitution; and

 

  (iii) the transferee executes and delivers the instruments necessary to establish that a legal transfer has taken place and to confirm the agreement of the transferee to be bound by all of the terms of this Agreement, in a form acceptable to the General Partner.

6.02(a)(3)(b). Rights of Substitute Participant. A substitute Participant shall be entitled to all of the rights attributable to full ownership of the assigned Common Units, including the right to vote.

6.02(b). Effect of Transfer.

6.02(b)(1). Amendment of Records. The Partnership shall amend its records at least once each calendar quarter to effect the substitution of substitute Participants. Any transfer of a Common Unit by a Participant which is permitted under this Article VI, when the transferee does not become a substitute Participant, shall be effective as follows:

 

  (i) midnight of the last day of the calendar month in which it is made; or

 

  (ii) at the General Partner’s election, 7:00 A.M. of the following day.

6.02(b)(2). A Transfer of Common Units Does Not Relieve the Transferor of Certain Costs. No transfer of a Common Unit by a Participant, including a transfer of less than all of a Participant’s Common Units or the transfer of a Participant’s Common Units to more than one party, shall relieve the transferor of its responsibility for its proportionate part of any expenses, obligations and liabilities under this Agreement related to the Common Units so transferred, whether arising before or after the transfer.

6.02(b)(3). A Transfer of Common Units Does Not Require A Partnership Accounting. No transfer of a Common Unit by a Participant shall require an accounting of the Partnership. Also, no transfer of a Common Unit shall grant rights under this Agreement, including the exercise of any elections, as between the transferring Participant and the Partnership, the General Partner and the remaining Participants to more than one Person unanimously designated by the transferee(s) of the Common Unit, and, if he has retained an interest in the transferred Common Unit, the transferor of the Common Unit.

6.02(b)(4). Required Notice to General Partner of Transfer of Common Units. Until the General Partner receives a written notice from the transferring Participant in a form acceptable to the General Partner that designates the transferee(s) of a Common Unit, the General Partner shall continue to account only to the Person to whom it was furnishing notices pursuant to § 8.01 and its subsections before the purported transfer of the Common Unit. This party shall continue to exercise all rights under this Agreement applicable to the Common Units owned by the purported transferor of the Common Unit.

6.03. Redemption of Common Units from Non-Citizens.

If the Partnership, the General Partner or any of its Affiliates become subject to federal, state or local laws or regulations that, in the reasonable determination of the General Partner, create a substantial risk of cancellation or forfeiture of any property that they have an interest in because of the nationality, citizenship or other related

 

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status of any Participant or assignee of a Participant’s Common Units, the Partnership may redeem, or the General Partner may purchase, the Participant’s Common Units or the Common Units held by the assignee of a Participant, on 30 days’ advance notice to the Participant, at a reasonable redemption or purchase price per Common Unit, as the case may be, as determined by the General Partner in its sole discretion.

ARTICLE VII DURATION, DISSOLUTION, AND WINDING UP

7.01. Duration.

7.01(a). Term. The Partnership shall continue in existence for a term of 10 years from the Initial Offering Termination Date, subject to extension for up to two additional years in the sole discretion of the General Partner, unless sooner terminated as set forth below.

 

7.01(b). Termination. The Partnership shall terminate following the occurrence of:

 

  (i) a Final Terminating Event; or

 

  (ii) any event that causes the dissolution of a limited partnership under the Delaware Act.

7.01(c). Continuance of Partnership Except on Final Terminating Event. Other than the occurrence of a Final Terminating Event, the Partnership or any successor limited partnership shall not be wound up, but shall be continued by the parties and their respective successors as a successor limited partnership under all of the terms of this Agreement. The successor limited partnership shall succeed to all of the assets of the Partnership. As used throughout this Agreement, the term “Partnership” shall include the successor limited partnership and the parties to the successor limited partnership.

7.02. Dissolution and Winding Up.

7.02(a). Final Terminating Event. On the occurrence of a Final Terminating Event the affairs of the Partnership shall be wound up and there shall be distributed to each of the parties its Distribution Interest in the remaining Partnership assets.

7.02(b). Time of Liquidating Distribution. To the extent practicable and in accordance with sound business practices in the judgment of the General Partner, liquidating distributions shall be made by:

 

  (i) the end of the taxable year in which liquidation occurs, determined without regard to Section 706(c)(2)(A) of the Code; or

 

  (ii) if later, within 90 days after the date of the liquidation.

Notwithstanding, the following amounts are not required to be distributed within the foregoing time periods so long as the withheld amounts are distributed as soon as practical:

 

  (i) amounts withheld for reserves reasonably required for liabilities of the Partnership; and

 

  (ii) installment obligations owed to the Partnership.

7.02(c). In-Kind Distributions. The General Partner shall not be obligated to offer in-kind property distributions to the Participants, but may do so, in its discretion. Any in-kind property distributions to the Participants shall be made to a liquidating trust or similar entity for the benefit of the Participants, unless at the time of the distribution:

 

  (i) the General Partner offers the individual Participants the election of receiving in-kind property distributions and the Participants accept the offer after being advised of the risks associated with direct ownership; or

 

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  (ii) there are alternative arrangements in place which assure the Participants that they will not, at any time, be responsible for the operation or disposition of Partnership properties.

If the General Partner has not received a Participant’s consent within 30 days after the General Partner mailed the request for consent, then it shall be presumed that the Participant has refused to give his consent.

7.02(d). Sale If No Consent. Any Partnership asset which would otherwise be distributed in-kind to a Participant, except for the failure or refusal of the Participant to give his written consent to the distribution, may instead be sold by the General Partner at the best price reasonably obtainable from an independent third-party, who is not an Affiliate of the General Partner, or to the General Partner itself or its Affiliates, including an Income Program sponsored by an Affiliate of the General Partner, at fair market value as determined by an Independent Expert.

ARTICLE VIII MISCELLANEOUS PROVISIONS

8.01. Notices.

8.01(a). Method. Any notice required under this Agreement shall be:

 

  (i) in writing; and

 

  (ii) given by mail or delivered by an overnight delivery company (although one-day delivery is not required) addressed to the party to receive the notice at the address designated in § 1.02(b).

If there is a transfer of Common Units under this Agreement, no notice to the transferee shall be required, nor shall the transferee have any rights under this Agreement, until notice of the transfer has been given to the General Partner. Any transfer of Common Units under this Agreement shall not increase the General Partner’s or the Partnership’s duty to give notice. If there is a transfer of Common Units under this Agreement to more than one party, then notice to any owner of any interest in the Common Units shall be notice to all of the owners of the Common Units.

 

8.01(b). Change in Address. The address of any party to this Agreement may be changed by notice as follows:

 

  (i) to the Participants, if there is a change of address by the General Partner; or

 

  (ii) to the General Partner, if there is a change of address by a Participant.

8.01(c). Time Notice Deemed Given. If the notice is given by the General Partner, then the notice shall be considered given, and any applicable time shall run, from the date the notice is placed in the mail or delivered to the overnight delivery company. If the notice is given by any Participant, then the notice shall be considered given and any applicable time shall run from the date the notice is received.

8.01(d). Effectiveness of Notice. Any notice to a party other than the General Partner, including a notice requiring concurrence or nonconcurrence, shall be effective, and any failure to respond binding, irrespective of the following:

 

  (i) whether or not the notice is actually received; or

 

  (ii) any disability or death on the part of the noticee, even if the disability or death is known to the party giving the notice.

8.01(e). Failure to Respond. Except pursuant to § 7.02(c) or when this Agreement expressly requires affirmative approval of a Participant, any Participant who fails to respond in writing within the time specified to a request by the General Partner as set forth below, for approval of, or concurrence in, a proposed action shall be conclusively

 

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deemed to have approved the action. Except pursuant to § 7.02(c), when this Agreement expressly requires affirmative approval of a Participant, the General Partner shall send a first request and the time period for the Participant’s written response shall not be less than 15 business days from the date of mailing of the request. If the Participant does not respond in writing to the first request, then the General Partner shall send a second request. If the Participant does not respond in writing to the second request within seven calendar days from the date of mailing the second request, then the Participant shall be conclusively deemed to have approved the action.

8.02. Time.

Time is of the essence of each part of this Agreement.

8.03. Applicable Law.

The terms and provisions of this Agreement shall be construed under the laws of the State of Delaware, other than its conflict of law provisions, however, this section shall not be deemed to limit causes of action for alleged violations of federal or state securities law to the laws of the State of Delaware. Neither this Agreement nor the Subscription Agreement shall require mandatory venue or mandatory arbitration of any or all claims by Participants against the Sponsor.

8.04. Agreement in Counterparts.

This Agreement may be executed in counterpart and shall be binding on all of the parties executing this or similar agreements from and after the date of execution by each party.

8.05. Amendment.

8.05(a). Procedure for Amendment. Subject to §§ 8.05(b) and 8.05(c), below, no changes in this Agreement shall be binding unless:

 

  (i) proposed in writing by the General Partner, and adopted with the consent of Participants whose Common Units equal a majority of the total Common Units; or

 

  (ii) proposed in writing by Participants whose Common Units equal 10% or more of the total Common Units and approved by an affirmative vote of Participants whose Common Units equal a majority of the total Common Units.

8.05(b). Circumstances Under Which the General Partner Alone May Amend. The General Partner is authorized to amend this Agreement and its exhibits, without the consent of Participants, in any way deemed necessary or desirable by it to reflect:

 

  (i) a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;

 

  (ii) admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;

 

  (iii) a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for U.S. federal income tax purposes;

 

  (iv)

a change that the General Partner determines (A) does not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect, (B) to be necessary or appropriate to (x) satisfy any requirements,

 

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  conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (y) facilitate the trading of the Limited Partner Interests or Units (including the division of any class or classes of outstanding Limited Partner Interests into different classes to facilitate uniformity of tax consequences within such classes of Limited Partner Interests) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Limited Partner Interests or Units are or will be listed or admitted to trading, (C) to be necessary or appropriate in connection with action taken by the General Partner pursuant to § 4.08 or to implement the tax-related provisions of this Agreement or (D) to be required to effect the intent expressed in the offering memorandum for the Initial Offering or the prospectus for the Second Offering or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

 

  (v) a change in the fiscal year or taxable year of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable year of the Partnership including, if the General Partner shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Partnership;

 

  (vi) an amendment that is necessary, in the opinion of counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

 

  (vii) an amendment that the General Partner determines to be necessary or appropriate in connection with the authorization or issuance of any class or series of Partnership Interests, or any options, warrants, rights and/or appreciation rights relating to any Partnership Interest, pursuant to § 4.07;

 

  (viii) an amendment expressly permitted in this Agreement to be made by the General Partner acting alone;

 

  (ix) an amendment effected, necessitated or contemplated by a merger agreement or plan of conversion approved in accordance with this Agreement;

 

  (x) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of § 1.03; or

 

  (xi) any other amendments substantially similar to the foregoing.

8.05(c). Amendment Upon the Listing Event. Simultaneously with the Listing Event, this Agreement shall automatically be amended and restated in its entirety to be the Second Amended and Restated Agreement of Limited Partnership in the form attached hereto as Annex A. Each Limited Partner, by execution hereof or its subscription agreement, shall be deemed to have consented to such amendment, and authorizes the General Partner to execute the same on its behalf as attorney in fact pursuant to § 4.03(d).

8.06. Legal Effect.

This Agreement shall be binding on and inure to the benefit of the parties, their heirs, devisees, personal representatives, successors and assigns, and shall run with the interests subject to this Agreement. The terms “Partnership,” “Limited Partner,” “Participant,” “Partner,” “General Partner,” or “parties” shall equally apply to any successor limited partnership, and any heir, devisee, personal representative, successor or assign of a party.

 

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IN WITNESS WHEREOF, the parties hereto set their hands as of the      day of                     , 201    .

 

ATLAS GROWTH PARTNERS GP, LLC

 

General Partner

By:    

Name:

 

Its:

 

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Annex A

Post-Listing Partnership Agreement

 

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Exhibit B to Prospectus

POST-LISTING PARTNERSHIP AGREEMENT

 

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Exhibit C to Prospectus

SUBSCRIPTION AGREEMENT

 

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ATLAS GROWTH PARTNERS, L.P.

SUBSCRIPTION AGREEMENT

INSTRUCTION PAGE

(For optional electronic delivery, see page B-5)

In no event may a subscription of common units be accepted until at least five business days after the date the subscriber receives the final prospectus. You will receive a confirmation of your purchase.

PROCEDURES PRIOR TO ESCROW BREAK:

Until we have raised the minimum offering amount, your broker-dealer or registered investment advisor should MAIL properly completed and executed ORIGINAL documents, along with your check payable to “UMB Bank, N.A., escrow agent for Atlas Growth Partners, L.P.” to UMB Bank, N.A. at the following address:

1010 Grand Blvd, 4th Floor

Mail Stop: 1020409

Kansas City, MO 64106

Attn: Lara Stevens

Phone: (816) 860-3017

 

* For IRA and other tax-exempt accounts, mail investor signed documents to the IRA Custodian or other fiduciary of your qualified plan for signatures.

If you have any questions, please call your registered representative or Anthem Securities, Inc. at (800) 251-0171.

PROCEDURES POST-ESCROW BREAK:

Once we have raised $1 million, your broker-dealer or registered investment advisor should MAIL properly completed and executed ORIGINAL documents, along with your check payable to “Atlas Growth Partners, L.P.” to the following address. (see “Summary” in the prospectus):

 

 

* For IRA and other tax-exempt accounts, mail investor signed documents to the IRA Custodian or other fiduciary of your qualified plan for signatures.

If you have any questions, please call your registered representative or Anthem Securities, Inc. at (800) 251-0171.

Instructions to Subscribers

You are required to execute your own Subscription Agreement and our general partner will not accept any Subscription Agreement that has been executed by someone other than you unless, in the case of fiduciary accounts, the person has been given your legal power of attorney to sign on your behalf, and you meet all of the conditions in the Prospectus and the Subscription Agreement.

 

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Section 1: Indicate investment amount and type of purchase (Make all checks payable as described above.)

Section 2: Choose type of ownership

Non-Custodial Ownership

Accounts with more than one owner must have ALL PARTIES SIGN where indicated on page 8.

Be sure to attach copies of all plan documents for Pension Plans, Trusts, Corporations or Partnerships required in section 2.

Custodial Ownership

For New IRA/Qualified Plan Accounts, please complete the form/application provided by your custodian of choice in addition to this subscription document and forward to the custodian for processing.

For existing IRA Accounts and other Custodial Accounts, information must be completed BY THE CUSTODIAN. Have all documents signed by the appropriate officers as indicated in the Corporate Resolution (which are also to be included).

Complete Section 1 below by completing all applicable blanks and checking any applicable box.

Section 2: Check the applicable box and complete all applicable blanks

Section 3: All names, addresses, Dates of Birth, Social Security or Tax I.D. numbers of all investors or Trustees

Section 4: Choose Distribution Allocation option

Section 5: Check the box, sign and date if you elect Electronic Delivery

Section 6: To be signed and completed by your Broker-Dealer/Financial Advisor (be sure to include CRD number for FA and BD Firm and the Branch Manager’s signature)

Section 7: Have ALL owners initial and sign where indicated on Page 8

Section 8: All investors must complete and sign the W-9

ATLAS GROWTH PARTNERS, L.P. SUBSCRIPTION AGREEMENT

 

1. YOUR INITIAL INVESTMENT All subscription payments will be placed in an account held by the escrow agent, UMB Bank, in trust for subscribers’ benefit, and will be released to us only if we have sold a minimum of $1.0 million of our common units to the public by                     , 2018, which is two years from the effective date of this offering. Funds in escrow will be invested in short-term investments that mature on or before                     , 2018, which is two years from the effective date of this offering, or that can be readily sold or otherwise disposed of for cash by that date without any dissipation of the offering proceeds invested.

Make all checks payable as described in the foregoing instructions.

 

Investment Amount $

   Brokerage Account Number

The minimum initial investment is 500 common units ($5,000)

   (If applicable)

 

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Type of Purchase: Please consult with your financial advisor regarding the type of purchase and commission structure of your investment and check one of the following options. Please see the Prospectus for additional details regarding the different unit classes.

 

¨ Class A common units

 

¨ Class T common units

Cash, cashier’s checks/official bank checks in bearer form, foreign checks, money orders, third party checks, or traveler’s checks will not be accepted.

 

¨ I/WE AM/ARE EMPLOYEE(S) OF OUR GENERAL PARTNER OR ANTHEM SECURITIES, INC., AN AFFILIATE BROKER AND/OR AN IMMEDIATE FAMILY MEMBER OF ONE OF THE ABOVE. I/WE ACKNOWLEDGE THAT NO COMMISSION WILL BE PAID FOR THIS PURCHASE, BUT I/WE WILL RECEIVE ADDITIONAL COMMON UNITS OR FRACTIONS THEREOF.

 

¨ CHECK HERE IF ADDITIONAL PURCHASE AND COMPLETE NUMBER 3 BELOW.

 

2. FORM OF OWNERSHIP (Select only one)

 

    

Non-Custodial Ownership

  

Custodial Ownership

¨    Individual    Third Party
¨    Joint Tenant (Joint accounts will be registered as joint tenants with rights of survivorship unless otherwise indicated)   

Administered

Custodial Plan

¨    Tenants in Common   
¨    TOD—Optional designation of beneficiaries for individual and joint owners with rights of survivorship. (Please complete Transfer on Death Registration Form—Exhibit C.) (You may download the form at www. .com)   

new IRA accounts will require an additional application)

¨ IRA ¨ ROTH/IRA ¨ SEP/IRA

¨ SIMPLE IRA ¨ OTHER

¨    Uniform Gift/Transfer to Minors (UGMA/UTMA) Under the UGMA/UTMA of the State of Pension or other Retirement Plan (Include Plan Documents)   

Name of Custodian

Mailing Address

City, State, Zip

¨    Trust (Include title and signature pages of Trust Documents)   

Custodian Information

(To be completed by Custodian above)

¨    Corporation or Partnership (Include Corporate Resolution or Partnership Agreement, as applicable)   

Custodian Tax ID #

Custodian Account #

Custodian Phone

¨    Other (Include title and signature pages)   

 

3. INVESTOR INFORMATION (Please print name(s) in which common units are to be registered).

 

A. Individual/Trust/Beneficial Owner

 

First Name:

   Middle Name:      

Last Name:

   Tax ID or SS#:      

Street Address

   City:    State:    Zip:

 

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Please do not provide a P.O. Box Number

 

Date of Birth: (mm/dd/yyyy)

   If Non-U.S. Citizen, specify Country of Citizenship:

Daytime Phone #:

Email Address:

     U.S. Driver’s License Number (if available):      State of Issue:

CALIFORNIA INVESTORS: ALL CERTIFICATES REPRESENTING COMMON UNITS WHICH ARE SOLD IN THE STATE OF CALIFORNIA WILL BEAR THE FOLLOWING LEGEND CONDITIONS: IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY OR ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER OF CORPORATIONS FOR THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN THE COMMISSIONER’S RULES.

Any subscriber seeking to purchase common units pursuant to a discount offered by us must submit the request in writing and set forth the basis for the request. Any such request will be subject to our verification.

 

B. Joint Owner/Co-Trustee/Minor

 

First Name:

   Middle Name:

Last Name:

   Tax ID or SS#:

Street Address

   City:    State:    Zip:

Date of Birth: (mm/dd/yyyy)

  If Non-U.S. Citizen, specify Country of Citizenship:

Daytime Phone #:

  

Email Address:

        

 

C. Residential Street Address (This section must be completed for verification purposes if mailing address in section 3A is a P.O. Box)

 

Street Address

     

City:

   State:    Zip:

 

D. Trust/Corporation/Partnership/Other (Trustee’s information must be provided in sections 3A and 3B)

 

Date of Trust:

  

Entity Name/Title of Trust:

   Tax ID Number:

 

E. Government ID (Foreign Citizens only) Identification documents must have a reference number and photo. Please attach a photocopy.

 

Place of Birth:

         

City

     State/Providence      Country

Immigration Status: Permanent resident ¨

     Non-permanent resident ¨      Non-resident ¨

Check which type of document you are providing:

 

¨ U.S. Driver’s License

   ¨ INS Permanent resident alien card    ¨ Passport with U.S. Visa

¨ Passport without U.S. Visa Bank Name (required):

   Account No. (required):

¨ Foreign national identity documents Bank address (required):

   Phone No. required:

 

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Number for the document checked above and country of issuance:

 

F.     Employer:

   Retired: ¨

 

4. DISTRIBUTIONS (Select only one)

Complete this section to elect how you wish to receive your distributions.

IRA accounts may not direct distributions without the custodian’s approval.

Unitholders may not be able to sell their common units.

I hereby subscribe for common units of Atlas Growth Partners, L.P. and elect the distribution option indicated below:

 

A. ¨ Distribution Reinvestment Plan (See Prospectus for details)

 

B. ¨ Mail Check to the address of record

 

C. ¨ Credit Distribution to my IRA or Other Custodian Account

 

D. ¨ Cash/Direct Deposit (Please attach a pre-printed voided check (Non-Custodian Investors only). I authorize Atlas Growth Partners, L.P. or its agent to deposit my distribution to my checking or savings account. This authority will remain in force until I notify Atlas Growth Partners, L.P. in writing to cancel it. If Atlas Growth Partners, L.P. deposits funds erroneously into my account, they are authorized to debit my account for an amount not to exceed the amount of the erroneous deposit.)

 

Name/Entity Name Financial Institution:

     Middle Name:     

Mailing Address

     City:      State:      Zip:

Account Number:

     Your Bank’s ABA/Routing Number:

Your Bank’s Account Number:

     Checking Acct:      Savings Acct:

PLEASE ATTACH COPY OF VOIDED CHECK TO THIS FORM IF FUNDS ARE TO BE SENT TO A BANK

 

* The above services cannot be established without a pre-printed voided check. For electronic funds transfers, signatures of bank account owners are required exactly as they appear on the bank records. If the registration at the bank differs from that on this Subscription Agreement, all parties must sign below.

 

Signature    Signature

 

5. ELECTRONIC DELIVERY

Initial this paragraph in the preceding space and sign below if you consent to the electronic delivery of documents including the prospectus, prospectus supplements, annual and quarterly reports, proxy statements, distribution notices and other limited partner communications and reports. E-mail address in Section 3 is required. Please carefully read the following representations before consenting to receive documents electronically. By checking this box and consenting to receive documents electronically, you represent the following:

 

  (a) I acknowledge that access to both e-mail and the Internet is required in order to access documents electronically. I may receive by e-mail notification the availability of a document in electronic format. The notification e-mail will contain a web address (or hyperlink) where the document can be found. By entering this address into my web browser, I can view, download and print the document from my computer. I acknowledge that there may be costs associated with the electronic access, such as usage charges from my Internet provider and telephone provider, and that these costs are my responsibility.

 

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  (b) I acknowledge that documents distributed electronically may be provided in Adobe’s Portable Document Format (PDF). The Adobe Reader® software is required to view documents in PDF format. The Reader software is available free of charge from Adobe’s website at www.adobe.com. The Reader software must be correctly installed on my system before I will be able to view documents in PDF format. Electronic delivery also involves risks related to system or network outage that could impair my timely receipt of or access to communications from Atlas Growth Partners, L.P.

 

  (c) I acknowledge that I may receive at no cost from Atlas Growth Partners, L.P. a paper copy of any documents delivered electronically by calling Anthem Securities, Inc. at (800) 251-0171 from 9:00 am to 5:00 pm EST Monday – Friday.

 

  (d) I acknowledge that if the e-mail notification is returned to Atlas Growth Partners, L.P. as “undeliverable,” a letter will be mailed to me with instructions on how to update my e-mail address to begin receiving communication via electronic delivery. I further understand that if Atlas Growth Partners, L.P. is unable to obtain a valid e-mail address for me, Atlas Growth Partners, L.P. will resume sending a paper copy of its filings by U.S. mail to my address of record.

 

  (e) I acknowledge that my consent may be updated or cancelled, including any updates in e-mail address to documents are delivered, at any time by calling Anthem Securities, Inc. at (800) 251-0171 from 9:00 am to 5:00 pm EST Monday – Friday.

Owner Signature Date (mm/dd/yy)

Co-Owner Signature (if applicable) Date (mm/dd/yy)

 

6. BROKER-DEALER/FINANCIAL ADVISOR INFORMATION (All fields must be completed)

The Financial Advisor, Registered Investment Advisor or the Authorized Representative (the “Advisor”) must sign below to complete order. The undersigned broker-dealer or Advisor warrants that it is a duly licensed broker-dealer (or non-commission based financial advisor) and may lawfully offer the common units in the state designated as the investor’s address or the state in which the sale is to be made, if different. The broker-dealer or Advisor warrants that he or she has (a) reasonable grounds to believe this investment is suitable for the investor as defined by Rule 2310 of the FINRA Rules, (b) informed the investor of all aspects of liquidity and marketability of this investment as required by Rule 2310 of the FINRA Rules, (c) delivered the Prospectus to the investor the requisite number of days prior to the date that the investor will deliver this Subscription Agreement to the issuer as specified under the laws of the investor’s state of residence, (d) verified the identity of the investor through appropriate methods and will retain proof of such verification process as required by applicable law, and (e) verified that the investor and the registered owner do not appear on the Office of Foreign Assets Control list of foreign nations, organizations and individuals subject to economic and trade sanctions.

 

BROKER DEALER

   Financial Advisor Name/RIA

Advisor Mailing Address

  

City

   Zip

Advisor No.

   Telephone No.

Email Address

   Fax No.

Broker-Dealer CRD Number

   Financial Advisor CRD Number

 

¨ AFFILIATED REGISTERED INVESTMENT ADVISOR (RIA): All sales of securities must be made through a Broker-Dealer. If an RIA introduces a sale, the sale must be conducted through the RIA in his or her capacity as a Registered Representative of Broker-Dealer (Section 6 must be filled in).

I understand that by checking the above box, I WILL NOT RECEIVE A COMMISSION.

 

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The undersigned FINANCIAL ADVISOR further represents and certifies that in connection with this subscription for common units, he/she has complied with and has followed all applicable policies and procedures under his or her firm’s existing Anti-Money Laundering Program and Customer Identification Program.

Financial Advisor and/or RIA Signature:            Date:

Branch Manager Signature:            Date:

 

7. SUBSCRIBER SIGNATURES

Items (a), (b) and (g) do not apply to you if you qualify as an “institutional investor” for the purposes of a state exemption from registration in your state of residence.

The undersigned further acknowledges and/or represents (or in the case of fiduciary accounts, the person authorized to sign on the subscriber’s behalf) the following: (you must initial each of the representations below).

 

____Owner

   ____Co-Owner    a) I/we have a minimum net worth (not including home, home furnishings and personal automobiles) of at least $85,000 and estimate that I/we have a gross income due in the current year of at least $85,000; or I/we have a net worth (excluding home, home furnishings and automobiles) of at least $330,000, or such higher suitability as may be required by certain states and set forth on the reverse side hereof.

____Owner

   ____Co-Owner    b) I/we have received the final prospectus and any applicable supplements of Atlas Growth Partners, L.P. at least five business days before signing this subscription agreement.

____Owner

   ____Co-Owner    c) I/we am/are purchasing common units for my/our own account.

____Owner

   ____Co-Owner    d) I/we acknowledge that common units are not liquid.

____Owner

   ____Co-Owner    e) If an affiliate of Atlas Growth Partners, L.P., I/we represent that the common units are being purchased for investment purposes only and not for immediate resale.

____Owner

   ____Co-Owner    f) I acknowledge that the Selling Agent or registered representative is required to inform me and the other potential investors of all pertinent facts relating to the Units, including the background of our general partner and the tax consequences of my investment.

Owner Signature:

   Date:

Co-Owner Signature:

   Date:

Signature of Custodian(s) or Trustee(s) (if applicable). Current Custodian must sign if investment is for an IRA Account.

The above representations do not constitute a waiver of any rights that I may have under the Acts administered by the SEC or by any state regulatory agency administering statutes bearing on the sale of securities.

Authorized Signature (Custodian or Trustee): Date:

In the case of sales to fiduciary accounts, the suitability standards must be met by the beneficiary, the fiduciary account or by the donor or grantor who directly or indirectly supplies the funds for the purchase of the common units.

 

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8. POWER OF ATTORNEY

Each limited partner and each person who acquires a Unit from a unitholder, by accepting the Unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our Partnership Agreement.

Owner Signature:             

Co-Owner Signature:             

General Standards for all Investors

 

    An investor must have either (a) a net worth of at least $330,000 or (b) an annual gross income of at least $85,000 and a minimum net worth of at least $85,000 and (c) a net worth of not less than $85,000.

California Investors

 

    IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY, OR ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION THEREFORE, WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN THE COMMISSIONER’S RULES.

 

    Although the Farmout provisions do not comply with the California Corporate Securities Law of 1968, the Farmout provisions are consistent with the NASAA Oil and Gas Guidelines.

Idaho Residents

 

    Your total investment in Atlas Growth Partners, L.P. may not exceed 10% of your net worth.

Kansas Residents

 

    It is recommended by the Office of the Kansas Securities Commissioner that Kansas investors limit their aggregate investment in the securities of the issuer and other non-traded oil and gas programs to not more than 10% of their liquid net worth (total assets minus total liabilities) that is comprised of cash, cash equivalents and readily marketable securities.

Maine Residents

 

    The Maine Office of Securities recommends that your aggregate investment in Atlas Growth Partners, L.P. and similar direct participation investments not exceed 10% of your liquid net worth. For this purpose, “liquid net worth” is defined as that portion of net worth that consists of cash, cash equivalents and readily marketable securities.

North Dakota Residents

 

    You must represent that, in addition to the stated net income and net worth standards, you have a net worth of at least ten times your investment in Atlas Growth Partners, L.P.

Oregon Residents

 

    You must not make an investment in Atlas Growth Partners, L.P. greater than 10% of your liquid net worth, exclusive of home, home furnishings and automobiles.

 

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WE INTEND TO ASSERT THE FOREGOING REPRESENTATIONS AS A DEFENSE IN ANY SUBSEQUENT LITIGATION WHERE SUCH ASSERTION WOULD BE RELEVANT. WE HAVE THE RIGHT TO ACCEPT OR REJECT THIS SUBSCRIPTION IN WHOLE OR IN PART, SO LONG AS SUCH PARTIAL ACCEPTANCE OR REJECTION DOES NOT RESULT IN AN INVESTMENT OF LESS THAN THE MINIMUM AMOUNT SPECIFIED IN THE PROSPECTUS. AS USED ABOVE, THE SINGULAR INCLUDES THE PLURAL IN ALL RESPECTS IF COMMON UNITS ARE BEING ACQUIRED BY MORE THAN ONE PERSON. AS USED IN THIS SUBSCRIPTION AGREEMENT, THIS SUBSCRIPTION AGREEMENT AND ALL RIGHTS HEREUNDER SHALL BE GOVERNED BY, AND INTERPRETED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK WITHOUT GIVING EFFECT TO THE PRINCIPLES OF CONFLICT OF LAWS.

By executing this Subscription Agreement, the subscriber is not waiving any rights under federal or state law.

 

9. IRS FORM W-9

To prevent backup withholding on any payment made to an investor with respect to subscription proceeds held in escrow, the investor is generally required to provide current taxpayer identification number, or TIN (or the TIN of any other payee), and certain other information by completing the form below, certifying that the TIN provided on Substitute Form W-9 is correct (or that such investor is awaiting a TIN), that the investor is a U.S. person, and that the investor is not subject to backup withholding because (i) the investor is exempt from backup withholding, (ii) the investor has not been notified by the IRS that the investor is subject to backup withholding as a result of failure to report all interest or dividends or (iii) the IRS has notified the investor that the investor is no longer subject to backup withholding. If the box in Part 3 is checked and a TIN is not provided by the time any payment is made in connection with the proceeds held in escrow, the percentage required under the Internal Revenue Code of all such payments will be withheld until a TIN is provided and if a TIN is not provided within 60 days, such withheld amounts will be paid over to the IRS. See the instructions provided below with the Form W-9 on how to fill out the Form W-9. FOR ADDITIONAL INFORMATION CONTACT YOUR TAX CONSULTANT OR THE IRS.

 

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Exhibit D to Prospectus

WARRANT AGREEMENT

 

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THIS WARRANT AND THE SECURITIES FOR WHICH THIS WARRANT MAY BE EXERCISED (COLLECTIVELY, THE “SECURITIES”) HAVE NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED (THE “SECURITIES ACT”), OR APPLICABLE STATE SECURITIES LAWS. THE SECURITIES MAY NOT BE OFFERED, SOLD, PLEDGED OR OTHERWISE TRANSFERRED EXCEPT PURSUANT TO AN EFFECTIVE REGISTRATION STATEMENT UNDER, OR AN EXEMPTION FROM THE REGISTRATION REQUIREMENTS OF, THE SECURITIES ACT AND IN ACCORDANCE WITH ANY APPLICABLE STATE SECURITIES LAWS.

ATLAS GROWTH PARTNERS, L.P.

Warrant To Purchase Common Units

Atlas Growth Partners, L.P., a Delaware limited partnership (the “Partnership”), hereby certifies that, for good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the beneficial holders hereof, through Atlas Resources, LLC, as their nominee and custodian, are entitled, subject to the terms set forth below, to purchase from the Partnership, at any time or times on or after the Warrant Date (as defined in Section 1 (xiii)), but not after 11:59 P.M. New York Time on the Expiration Date (as defined herein) that number of Common Units (as defined in Section 1(iii) below) of the Partnership as are set forth in the books and records of the Transfer Agent (as defined in Section (XIV), below) (the “Warrant Units”) at the Warrant Units Exercise Price (as defined in Section 1(xvi) below).

Section 1. Definitions. The following words and terms as used in this Warrant shall have the following meanings:

(i) “Business Combination” means a merger, consolidation, statutory share exchange or similar transaction that requires approval of the limited partners of the Partnership.

(ii) “Business Day” means any day other than Saturday, Sunday or other day on which commercial banks in the City of New York are authorized or required by law to remain closed.

(iii) “Common Units” means (i) the Partnership’s common units of limited partnership interest, and (ii) any capital securities into which such Common Units shall have been changed or any capital securities resulting from a reclassification of such Common Units.

(iv) “Expiration Date” means the date that is one day prior to the date upon which a Liquidity Event occurs or, if such date does not fall on a Business Day, then the preceding Business Day; except that, if the Liquidity Event is a listing on a national securities exchange, then the Expiration Date shall be 30 days after the Liquidity Event occurs, or, if such date does not fall on a Business Day, then the next Business Day.

(v) “Holder” means a Person who is registered as an owner of Warrants in the books and records of the Transfer Agent, or any permitted assignee or transferee.

(vi) “Liquidity Event” means any one of the following: (a) a listing of the Common Units on a national securities exchange, (b) a Business Combination with or into an existing publicly traded entity, or (c) a sale of all or substantially all of the Partnership’s assets.

(vii) “Ordinary Cash Distribution” means a cash distribution to Common Units out of available cash from operations, as such term is defined in the Partnership Agreement.

(viii) “Partnership Agreement” means the Partnership Agreement of the Partnership, as the same may be amended from time to time.

 

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(ix) “Person” means an individual, a limited liability Partnership, a partnership, a joint venture, a corporation, a trust, an unincorporated organization or a government or any department or agency thereof or any other legal entity.

(x) “Securities Act” means the Securities Act of 1933, as amended.

(xi) “Transfer Agent” means Atlas Resources, LLC.

(xii) “Warrant” means this Warrant and all Warrants issued in exchange, transfer or replacement hereof pursuant to the terms of this Warrant.

(xiii) “Warrant Date” means the date upon which the Partnership sends notice to the Holder of a Liquidity Event, which such notice shall be sent not less than 30 calendar days prior to the date upon which the Partnership expects the Liquidity Event will occur.

(xiv) “Warrant Exercise Price” shall be equal to, with respect to any Warrant Share, $10.00, subject to adjustment as hereinafter provided.

Section 2. Exercise of Warrant.

(a) Subject to the terms and conditions hereof, Warrants may be exercised by the Holder, in whole or in part, at any time on any Business Day on or after the opening of business on the Warrant Date and prior to 11:59 P.M. New York Time on the Expiration Date by (i) delivery of a written notice, in the form of the subscription form attached as Exhibit A hereto (the “Exercise Notice”), of such holder’s election to exercise his Warrants, which notice shall specify the number of Warrant Units to be purchased and, (ii) payment to the Partnership of an amount equal to the Warrant Exercise Price multiplied by the number of Warrant Units as to which his Warrant is being exercised (the “Aggregate Exercise Price”) by wire transfer of immediately available funds (or by check if the Partnership has not provided the holder with wire transfer instructions for such payment). In the event of any exercise of the rights represented by the Warrant in compliance with this Section 2(a), the Partnership shall on the second (2nd) Business Day (the “Warrant Unit Delivery Date”) following the date of its receipt of the later of the Exercise Notice and the Aggregate Exercise Price (the “Exercise Delivery Documents”), issue the Warrant Units to which the Holder shall be entitled by registering Warrant Units in the name of the Holder or its designee upon the books and records of the Transfer Agent, the number of Common Units to which the Holder shall be entitled. Upon the later of the date of delivery of (x) the Exercise Notice and (y) the Aggregate Exercise Price referred to in clause (ii) above, a Holder of Warrants shall be deemed for all purposes to have become the Holder of record of the Warrant Units with respect to which his Warrant has been exercised (the date thereof being referred to as the “Deemed Issuance Date”), irrespective of the date of delivery of the Warrant Units. In the case of a dispute as to the determination of the Warrant Exercise Price, or the arithmetic calculation of the number of Warrant Units, the Partnership shall promptly issue to the Holder the number of Warrant Units that is not disputed and shall submit the disputed determinations or arithmetic calculations to the Holder via facsimile within two (2) Business Days of receipt of the Holder’s Exercise Notice. If the Holder and the Partnership are unable to agree upon the determination of the Warrant Exercise Price, or arithmetic calculation of the number of Warrant Units within one (1) Business Day of such disputed determination or arithmetic calculation being submitted to the Holder, then the Partnership shall promptly submit via facsimile (i) the disputed determination of the Warrant Exercise Price to an independent, reputable investment banking firm agreed to by the Partnership and the Holder of the Warrant or (ii) the disputed arithmetic calculation of the number of Warrant Units to its independent, outside public accountant. The Partnership shall direct the investment banking firm or the accountant, as the case may be, to perform the determinations or calculations and notify the Partnership and the Holder of the results no later than two (2) Business Days after the date it receives the disputed determinations or calculations. Such investment banking firm’s or accountant’s determination or calculation, as the case may be, shall be deemed conclusive absent demonstrable error.

 

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(b) If a Holder exercises his Warrant for less than all of the Warrant Units for which his Warrant is then exercisable the Transfer Agent shall mark its records to show the number of Warrant Units remaining unexercised.

(c) No fractional Warrant Units are to be issued upon the exercise by a Holder of his Warrants, but rather a Warrant may be exercised for whole Warrant Units only; provided, however, that if any of the adjustments provided in Section 8 hereof would result in a fractional Warrant Unit being issued but for the provisions of this paragraph, then upon the Holder’s exercise of his Warrant for all Warrant Units remaining thereunder, the Partnership shall purchase the fractional Warrant Unit for a price equal to the difference between the Warrant Exercise Price and the value of the consideration received or receivable in the Liquidity Event giving rise to the Warrant exercise (as determined in the sole good faith discretion of the Partnership) multiplied by the Warrant Unit fraction, except where the Liquidity Event is a listing on a national securities exchange, for which the price shall be the difference between the Warrant Exercise Price and the book value per Common Unit multiplied by the Warrant Unit fraction. For these purposes, book value per Common Unit shall mean the total capital of the Partnership allocated to the limited partners thereof divided by the number of outstanding Common Units as of the end of the Partnership’s most recent fiscal quarter, as determined by the Partnership.

(d) Uncertificated Security; Book-Entry; Recordation of Transfers. Warrants shall be issued in global form only. Each global Warrant shall represent all of the outstanding Warrants from time to time endorsed thereon; the aggregate number of Warrants may from time to time be reduced or increased to reflect adjustments or exercises as provided in the Warrant. Any such changes shall be made by the Transfer Agent as an endorsement to the global Warrant. The Transfer Agent shall preserve a list of the Holders of Warrants, including their names, addresses and number of Warrant Units remaining unexercised by each. In the event of any dispute or discrepancy, such records of the Transfer Agent establishing the number of Warrant Units to which the Holder is entitled to receive upon exercise of his Warrants shall be controlling and determinative in the absence of demonstrable error. The Holder may not transfer his Warrants unless the Holder provides to the Partnership such documents pertaining to the transfer, including opinions of counsel regarding compliance with applicable securities or other laws, as the Partnership may require in its sole discretion. Upon acceptance of the transfer by the Partnership, the Transfer Agent will record such transfer in its books and records.

Section 3. Covenants. The Partnership hereby covenants and agrees as follows:

(a) The Warrants are duly authorized and validly issued.

(b) All Warrant Units that may be issued upon the exercise of the rights represented by the Warrants will, upon issuance, be validly issued, fully paid and nonassessable, subject to applicable provisions of the Delaware Revised Uniform Limited Partnership Act.

(c) During the period within which the rights represented by the Warrant may be exercised, the Partnership will at all times have authorized and reserved a sufficient number of Common Units to provide for the exercise of the rights then represented by the Warrants.

(d) The Partnership will not, by amendment of its Partnership Agreement or through any reorganization, transfer of assets, consolidation, merger, dissolution, issue or sale of securities, or any other voluntary action, avoid or seek to avoid the observance or performance of any of the terms to be observed or performed by it hereunder, but will at all times in good faith assist in the carrying out of all the provisions of the Warrants and in the taking of all such action as may reasonably be requested by the Holder of any Warrant in order to protect the exercise privilege of such Holder against impairment, consistent with the tenor and purpose of the Warrants. Without limiting the generality of the foregoing, the Partnership will take all such actions as may be necessary or appropriate in order that the Partnership may validly and legally issue Common Units upon the exercise of any Warrants.

 

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(e) The Warrants will be binding upon any entity succeeding to the Partnership by merger, consolidation or acquisition of all or substantially all of the Partnership’s assets.

Section 4. Taxes. The Partnership shall pay any and all taxes (excluding income taxes, franchise taxes or other taxes levied on gross earnings, profits or the like of Holders of Warrants) that may be payable with respect to the issuance and delivery of Warrant Units upon exercise of Warrants.

Section 5. Holder Not Deemed a Limited Partner. No Holder, as such, shall be entitled to vote or receive dividends or be deemed the Holder of Common Units for any purpose (other than to the extent that the holder is deemed to be a beneficial holder of Common Units under applicable securities laws after taking into account the limitation set forth in the first paragraph of the Warrant), nor shall anything contained in the Warrant be construed to confer upon a Holder, as such, any of the rights of a limited partner of the Partnership or any right to vote, give or withhold consent to any Partnership action (whether any reorganization, issue of partnership units or interests, reclassification of partnership units of interests, consolidation, merger, conveyance or otherwise), receive notice of meetings, receive distributions or subscription rights, or otherwise, prior to the Deemed Issuance Date of the Warrant Units that such Holder is then entitled to receive upon the due exercise of this Warrant. In addition, nothing contained in this Warrant shall be construed as imposing any obligations or liabilities on such Holder to purchase any securities (upon exercise of this Warrant or otherwise) or as a Limited Partner of the Partnership, whether such liabilities are asserted by the Partnership or by creditors of the Partnership.

Section 6. Representations of Holder. Each Holder, by the acceptance hereof, represents that he, she or it is (i) an accredited investor, within the meaning or Rule 501 under the Securities Act, (ii) is acquiring his Warrants, and upon exercise thereof will acquire the Warrant Units, for his, her or its own account and not with a view towards, or for resale in connection with, the public sale or distribution Warrants or the Warrant Units, except pursuant to sales registered or exempted under the Securities Act; and (iii) has had the opportunity to ask questions of and receive answers from the Partnership regarding the Partnership, its business and financial condition, and has received and reviewed information the Partnership is required to deliver limited partners pursuant to its Partnership Agreement. Each delivery of an Exercise Notice, shall constitute confirmation at such time by the Holder of the representations concerning the Warrant Units set forth in this Section 6, unless contemporaneous with the delivery of such Exercise Notice, the Holder notifies the Partnership in writing that it is not making such representations (a “Representation Notice”). If the Holder delivers a Representation Notice in connection with an exercise, it shall be a condition to such Holder’s exercise of his Warrants and the Partnership’s obligations set forth in Section 2 in connection with such exercise, that the Partnership receive such other representations as the Partnership considers reasonably necessary to assure the Partnership that the issuance of its securities upon exercise of this Warrant shall not violate any United States or state securities laws, and the time periods for the Partnership’s compliance with its obligations set forth in Section 2 shall be tolled until such Holder provides the Partnership with such other representations.

Section 7. Adjustments. Stock Splits, Subdivisions,

(a) Reclassifications or Combinations. If the Partnership shall (i) declare and pay a dividend or make a distribution on its Common Units in Common Units, (ii) subdivide or reclassify the outstanding Common Units into a greater number of units, or (iii) combine or reclassify the outstanding Common Units into a smaller number of units, the number of Warrant Units issuable upon exercise of this Warrant at the time of the record date for such dividend or distribution or the effective date of such subdivision, combination or reclassification shall be proportionately adjusted so that a Warrant Holder after such date shall be entitled to purchase the number of Warrant Units which such Holder would have owned or been entitled to receive in respect of Common Units subject to this Warrant after such date had this Warrant been exercised immediately prior to such date. In such event, the Warrant Exercise Price in effect at the time of the record date for such dividend or distribution or the effective date of such subdivision, combination or reclassification shall be adjusted to the number obtained by dividing (x) the product of (1) the number of Warrant Units issuable upon the exercise of this Warrant before

 

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such adjustment and (2) the Warrant Exercise Price in effect immediately prior to the record or effective date, as the case may be, for the dividend, distribution, subdivision, combination or reclassification giving rise to this adjustment by (y) the new number of Warrant Units issuable upon exercise of the Warrant determined pursuant to the immediately preceding sentence.

(b) Statement Regarding Adjustments. Whenever the number of Warrant Units into which this Warrant is exercisable shall be adjusted as provided in this Section 7, the Partnership shall forthwith file with the Transfer Agent a statement showing in reasonable detail the facts requiring such adjustment and the number of Warrant Units into which Warrants shall be exercisable after such adjustment, and the Partnership shall also cause a copy of such statement to be sent by mail, first class postage prepaid, to the Holders at the addresses appearing in the Partnership’s records.

(c) Proceedings Prior to Any Action Requiring Adjustment. As a condition precedent to the taking of any action which would require an adjustment pursuant to this Section 7, the Partnership shall take any action which may be necessary, including obtaining regulatory, or limited partner approvals or exemptions, in order that the Partnership may thereafter validly and legally issue as fully paid and nonassessable all Warrant Units issuable pursuant to the Warrants.

(d) Adjustment Rules. Any adjustments pursuant to this Section 7 shall be made successively whenever an event referred to herein shall occur.

Section 8. Notice. Any notices, consents, waivers or other communications required or permitted to be given under the terms of this Warrant must be in writing and will be deemed to have been delivered: (i) upon receipt, when delivered personally; (ii) upon receipt, when sent by facsimile (provided confirmation of transmission is mechanically or electronically generated and kept on file by the sending party); or (iii) one (1) Business Day after deposit with a nationally recognized overnight delivery service, in each case properly addressed to the party to receive the same. The addresses and facsimile numbers for such communications shall be:

If to the Partnership:

Atlas Growth Partners, L.P.

c/o Atlas Growth Partners GP, LLC

Park Place Corporate Center One

1000 Commerce Drive, Suite 410

Pittsburgh, PA 15275

Telephone:   (412) 489-0006
Facsimile:   (412) 262-2820
Attention:   Chief Legal Officer

If to a Holder, to his, her or its address as it appears on the books and records of the Partnership.

Section 9. Amendment and Waiver. This Warrant may be amended and the Partnership may take any action herein prohibited, or omit to perform any act herein required to be performed by it, only with the written consent of the Holder of this Warrant; provided, however, that (i) the Partnership may, without the consent of the Holder, amend or supplement this Warrant to cure defects or inconsistencies and, (ii) except for amendments which would increase the Warrant Exercise Price or decrease the number of shares purchasable pursuant to this Warrant (except for those adjustments provided for herein), this Warrant may be amended upon the vote or consent of Holders, who, upon exercise in full would hold a majority of the Common Units issuable upon such an exercise.

Section 10. Descriptive Headings; Governing Law. The descriptive headings of the several sections and paragraphs of this Warrant are inserted for convenience only and do not constitute a part of this Warrant. All questions concerning the construction, validity, enforcement and interpretation of this Warrant shall be governed

 

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by the internal laws of the State of New York, without giving effect to any choice of law or conflict of law provision or rule (whether of the State of New York or any other jurisdiction) that would cause the application of the laws of any jurisdiction other than the State of New York.

Section 11. Rules of Construction. Unless the context otherwise requires, (a) all references to Sections, Schedules or Exhibits are to Sections, Schedules or Exhibits contained in or attached to this Warrant, (b) each accounting term not otherwise defined in this Warrant has the meaning assigned to it in accordance with accounting principles generally accepted in the United States, (c) words in the singular or plural include the singular and plural and pronouns stated in either the masculine, the feminine or neuter gender shall include the masculine, feminine and neuter and (d) the use of the word “including” in this Warrant shall be by way of example rather than limitation.

* * * * *

 

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IN WITNESS WHEREOF, the Partnership has caused this Warrant to be executed as of the date first written above.

 

ATLAS GROWTH PARTNERS, L.P.
By: Atlas Growth Partners GP, LLC
By:    
Name:  
Title:  

 

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EXHIBIT A TO WARRANT

EXERCISE NOTICE

TO BE EXECUTED BY THE REGISTERED HOLDER TO EXERCISE THIS WARRANT

ATLAS GROWTH PARTNERS, L.P.

The undersigned holder hereby exercises the right to purchase                 Common Units (“Warrant Units”) of Atlas Growth Partners, L.P., a Delaware limited partnership (the “Partnership”), pursuant to the Warrant registered in the name of the undersigned (the “Warrant”) on the books and records of the Partnership. Capitalized terms used herein and not otherwise defined shall have the respective meanings set forth in the Warrant.

1. Form of Warrant Exercise Price. The holder intends that payment of the Warrant Exercise Price shall be made as:

                    a “Cash Exercise with respect to                     Warrant Units; and/or

                    a Cashless Exercise with respect to                     Warrant Units.

2. Payment of Warrant Exercise Price. The holder shall pay the Aggregate Exercise Price in the sum of $            to the Partnership in accordance with the terms of the Warrant.

3. Delivery of Warrant Shares. The Partnership shall deliver                 Warrant Units in accordance with the terms of the Warrant in the following name and to the following address:

Issue to:                                                                                                                                    

Facsimile Number:                                                                                                           

Account Number (if electronic book entry transfer):                                                              

Date:                         ,                     

Name of Registered Holder

By:                                                               

Name:

Title:

 

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ACKNOWLEDGMENT

The Partnership hereby acknowledges this Exercise Notice and hereby directs Atlas Resources, LLC to issue the above indicated number of Common Units in accordance with the Transfer Agent Instructions dated                 , 20    from the Partnership and acknowledged and agreed to by Atlas Resources, LLC.

 

ATLAS GROWTH PARTNERS, L.P.
By:  Atlas Growth Partners GP, LLC
By:    
Name:    
Title:    

 

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EXHIBIT B TO WARRANT

FORM OF WARRANT POWER

FOR VALUE RECEIVED, the undersigned does hereby assign and transfer to                 , Federal Identification No.                 , a warrant to purchase                 Common Units of Atlas Growth Partners, L.P., a Delaware limited partnership standing in the name of the undersigned on the books of said limited partnership. The undersigned does hereby irrevocably constitute and appoint                 , attorney to transfer the warrants of said corporation, with full power of substitution in the premises.

Dated:                 , 20            

 
Name:    
Title:    

 

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Exhibit E to Prospectus

FORM OF DISTRIBUTION REINVESTMENT PLAN

 

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FORM OF DISTRIBUTION REINVESTMENT PLAN

ATLAS GROWTH PARTNERS, L.P.

EFFECTIVE AS OF                     , 2015

Atlas Growth Partners, L.P., a Delaware limited partnership (the “Partnership”), has adopted this Distribution Reinvestment Plan (the “Plan”), to be administered by the Partnership, Anthem Securities, Inc. (the “Dealer Manager”) or an unaffiliated third party (the “Administrator”), in each case as agent for participants in the Plan (“Participants”), on the terms and conditions set forth below.

1. Election to Participate. Any purchaser of Class A Common Units of the Partnership (“Class A Common Units”) or Class T Common Units of the Partnership (“Class T Common Units,” and, collectively with the “Class A Common Units,” the “Common Units”) may become a Participant by making a written election to participate on such purchaser’s subscription agreement at the time of subscription for Common Units or by delivering a completed and executed authorized form to the Administrator, which can be obtained from the Administrator. Any unitholder who has not previously elected to participate in the Plan may so elect at any time by completing and executing an authorization form obtained from the Administrator or any other appropriate documentation as may be acceptable to the Administrator. Participants in the Plan generally are required to have the full amount of their cash distributions (other than “Excluded Distributions” as defined below) with respect to all Common Units owned by them reinvested pursuant to the Plan. However, the Administrator shall have the sole discretion, upon the request of a Participant, to accommodate a Participant’s request for less than all of the Participant’s Common Units to be subject to participation in the Plan.

2. Distribution Reinvestment. The Administrator will receive all cash distributions (other than Excluded Distributions) paid by the Partnership with respect to Common Units of Participants (collectively, the “Distributions”). Participation will commence with the next Distribution payable after receipt of the Participant’s election pursuant to Paragraph 1 hereof, provided it is received at least ten (10) days prior to the last day of the period to which such Distribution relates. Subject to the preceding sentence, regardless of the date of such election, a holder of Common Units will become a Participant in the Plan effective on the first day of the period following such election, and the election will apply to all Distributions attributable to such period and to all periods thereafter. As used in this Plan, the term “Excluded Distributions” shall mean (a) those cash or other distributions designated as Excluded Distributions by the general partner of the Partnership and (b) any distribution and unitholder servicing fee payable to the Dealer Manager with respect to Class T Common Units.

3. General Terms of Plan Investments.

(a) The Partnership initially intends to offer Class A Common Units pursuant to the Plan at a price equal to 93.00% of the primary offering price of the Class A Common Units, regardless of the price per unit paid by the Participant for the Common Units in respect of which the Distributions are paid. Purchases of Class A Common Units will be made directly from the Partnership and shall be made in Class A Common Units, i.e., distributions paid on Class A Common Units and Class T Common Units, as applicable, will be used to purchase Class A Common Units. A unitholder may not participate in the Plan through distribution channels that would be eligible to purchase Class A Common Units in the public offering of Common Units pursuant to the Partnership’s prospectus outside of the Plan at prices below $9.30 per unit. From time to time, the Partnership may reset the purchase price of a Class A Common Unit to an amount that it determines to be the fair market value of such Common Unit.

(b) Sales commissions will not be paid for the Class A Common Units purchased pursuant to the Plan.

(c) Dealer Manager fees will not be paid for the Class A Common Units purchased pursuant to the Plan.

(d) For each Participant, the Administrator will maintain an account, which shall reflect for each period in which Distributions are paid (a “Distribution Period”) the Distributions received by the Administrator on behalf of such Participant. A Participant’s account shall be reduced as purchases of Class A Common Units are made on behalf of such Participant.

 

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(e) Distributions shall be invested in Class A Common Units by the Administrator promptly following the payment date with respect to such Distributions to the extent Class A Common Units are available for purchase under the Plan. If sufficient Class A Common Units are not available, any such funds that have not been invested in Class A Common Units within thirty (30) days after receipt by the Administrator and, in any event, by the end of the fiscal quarter in which they are received, will be distributed to Participants. Any interest earned on such accounts will be paid to the Partnership and will become property of the Partnership.

(f) Participants may acquire fractional Class A Common Units, computed to four decimal places, so that 100% of the Distributions will be used to acquire Class A Common Units. The ownership of the Class A Common Units shall be reflected on the books of Partnership or its transfer agent.

4. Absence of Liability. The Partnership, the Dealer Manager and the Administrator shall not have any responsibility or liability as to the value of the Class A Common Units or any change in the value of the Class A Common Units acquired for the Participant’s account. The Partnership, the Dealer Manager and the Administrator shall not be liable for any act done in good faith, or for any good faith omission to act hereunder.

5. Suitability. Each Participant shall notify the Administrator if, at any time during his participation in the Plan, there is any material change in the Participant’s financial condition or inaccuracy of any representation under the subscription agreement for the Participant’s initial purchase of Common Units. A material change shall include any anticipated or actual decrease in net worth or annual gross income or any other change in circumstances that would cause the Participant to fail to meet the suitability standards set forth in the Partnership’s prospectus for the Participant’s initial purchase of Common Units.

6. Reports to Participants. Within ninety (90) days after the end of each calendar year, the Administrator will mail to each Participant a statement of account describing, as to such Participant, the Distributions received, the number of Class A Common Units purchased and the per unit purchase price for such Class A Common Units pursuant to the Plan during the prior year. Each statement also shall advise the Participant that, in accordance with Paragraph 5 hereof, the Participant is required to notify the Administrator if there is any material change in the Participant’s financial condition or if any representation made by the Participant under the subscription agreement for the Participant’s initial purchase of Common Units becomes inaccurate. Tax information regarding a Participant’s participation in the Plan will be sent to each Participant by the Partnership or the Administrator at least annually.

7. Taxes. Participants in the Plan will be treated as receiving the cash distributions that they would have received if they had elected not to participate in the Plan. Class A Common Units received under the Plan will have a holding period beginning on the day after purchase under the Plan, and a U.S. federal income tax basis equal to their cost, which will equal the gross amount of the deemed distribution. In addition, participants in the Plan will be treated as receiving taxable income in an amount by which the value of the Class A Common Units received under the Plan exceed $9.30 per unit or the then applicable purchase price.

8. Termination.

(a) A Participant may terminate or modify his participation in the Plan at any time by written notice to the Administrator. To be effective for any Distribution, such notice must be received by the Administrator at least ten (10) days prior to the last day of the Distribution Period to which it relates.

(b) Prior to the listing of the Common Units on a national securities exchange, a Participant’s transfer of Common Units will terminate participation in the Plan with respect to such transferred Common Units as of the first day of the Distribution Period in which such transfer is effective, unless the transferee of such Common Units in connection with such transfer demonstrates to the Administrator that such transferee meets the requirements for participation hereunder and affirmatively elects participation by delivering an executed authorization form or other instrument required by the Administrator.

 

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(c) Notwithstanding Section 8(a) and (b) above, the Plan shall automatically terminate at the time when the Common Units are listed on a national securities exchange.

9. State Regulatory Restrictions. The Administrator is authorized to deny participation in the Plan to residents of any state or foreign jurisdiction that imposes restrictions on participation in the Plan that conflict with the general terms and provisions of this Plan, including, without limitation, any general prohibition on the payment of broker-dealer commissions for purchases under the Plan. In this regard, no commissions will be paid to broker-dealers for Participants’ purchases in the Plan.

10. Amendment to or Suspension or Termination of the Plan.

(a) Except for Section 8(a) of this Plan, which shall not be amended prior to a listing of the Common Units on a national securities exchange, the terms and conditions of this Plan may be amended by the Partnership at any time, including but not limited to an amendment to the Plan to substitute a new Administrator to act as agent for the Participants, by mailing an appropriate notice at least ten (10) days prior to the effective date thereof to each Participant.

(b) The Administrator may terminate a Participant’s individual participation in the Plan and the Partnership may suspend or terminate the Plan itself, at any time.

(c) After termination of the Plan or termination of a Participant’s participation in the Plan, the Administrator will send to each Participant a check for the amount of any Distributions in the Participant’s account that have not been invested in Class A Common Units. Any future Distributions with respect to such former Participant’s Class A Common Units made after the effective date of the termination of the Participant’s participation will be sent directly to the former Participant.

11. Governing Law. This Plan and the Participants’ election to participate in the Plan shall be governed by the laws of the State of Delaware.

12. Notice. Any notice or other communication required or permitted to be given by any provision of this Plan shall be in writing and, if to the Administrator, addressed to Administrator, c/o [•], or such other address as may be specified by the Administrator by written notice to all Participants. Notices to a Participant may be given by letter addressed to the Participant at the Participant’s last address of record with the Administrator or by providing the relevant information in a press release or a report filed by the Partnership with the Securities and Exchange Commission. Each Participant shall notify the Administrator promptly in writing of any changes of address.

13. No Certificates. The ownership of the Common Units will be in book entry form.

 

 

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Exhibit F to Prospectus

LONG-TERM INCENTIVE PLAN

 

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ATLAS GROWTH PARTNERS, L.P.

LONG-TERM INCENTIVE PLAN

SECTION 1: PURPOSE OF THE PLAN.

The Atlas Growth Partners, L.P. Long-Term Incentive Plan (the “Plan”) is intended to promote the interests of Atlas Growth Partners, L.P., a Delaware limited partnership (the “Partnership”), by providing to officers, employees and board members of Atlas Growth Partners GP, LLC, a Delaware limited liability company (the “Company”), and employees of its Affiliates, consultants and joint venture partners who perform services for the Company or the Partnership, incentive awards for superior performance that are based on common units of limited partner interest of the Partnership (“Units”). It is also contemplated that the Plan will enhance the ability of the Company and its Affiliates to attract and retain the services of individuals who are essential for the growth and profitability of the Company or the Partnership and to encourage them to devote their best efforts to the business of the Company or the Partnership, thereby advancing the interests of the Company and the Partnership.

SECTION 2: DEFINITIONS.

As used in the Plan, the following terms shall have the meanings set forth below:

Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

Award” means an Option, Phantom Unit, or Restricted Unit granted under the Plan, and shall include any tandem DERs granted with respect to a Phantom Unit.

Award Agreement” means a written agreement setting forth the terms and conditions of a specific Award.

Board” means the board of directors of the Company.

Cause” means Cause (or a term of similar import) as defined in the employment, consulting, or similar agreement to which a Participant is party, or, if there is no such agreement, “Cause” means the Participant’s: (i) commission of a felony or a crime of moral turpitude; (ii) commission of any act of malfeasance or wrongdoing against the Partnership, the Company or any Affiliate; (iii) a material breach of the Company’s or any Affiliate’s applicable policies or procedures; (iv) willful and continued failure to perform the Participant’s material duties; (v) willful misconduct that causes material harm to the Partnership, the Company or any Affiliate or their respective business reputations, including due to any adverse publicity; or (vi) material breach of the Participant’s obligations under any agreement (including any covenant not to compete) entered into between the Participant and the Company or any Affiliate. Notwithstanding Section 3(a) of the Plan, following a Change in Control, any determination by the Committee as to whether “Cause” exists shall be subject to de novo review.

Change in Control” means the occurrence of any of the following:

(a) neither the Company nor any of its Affiliates is the general partner of the Partnership;

(b) a merger, consolidation, share exchange, division or other reorganization or transaction of the Partnership, Atlas Energy Group, L.L.C., or the Company with any entity, other than such a transaction that would result in the voting securities of the Partnership, Atlas Energy Group, L.L.C., or the Company, as appropriate, outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 60% of the combined voting power

 

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immediately after such transaction of the surviving entity’s outstanding securities or, in the case of a division, the outstanding securities of each entity resulting from the division;

(c) the equity holders of the Partnership, the Company, or Atlas Energy, L.L.C. approve a plan of complete liquidation or winding-up of, as appropriate, the Partnership, the Company, or Atlas Energy Group, L.L.C.;

(d) a sale or disposition (in one transaction or a series of transactions) of all or substantially all of the assets of the Partnership, the Company, or Atlas Energy Group, L.L.C.;

(e) during any period of 24 consecutive months, individuals who at the beginning of such period constituted the Board (including for this purpose any new director whose election or nomination for election or appointment was approved by a vote of at least 2/3 of the directors then still in office who were directors at the beginning of such period) cease for any reason to constitute at least a majority of the Board; or

(f) any other sale of assets or restructuring transaction that has the effect of the enumerated transactions or events described in any of clauses (a) through (e) above.

Notwithstanding the foregoing, with respect to any Award that is subject to Section 409A of the Code, Change in Control shall mean a “change of control event,” as defined in the regulations and guidance issued under Section 409A of the Code. In addition, notwithstanding the foregoing, the Committee may specify a more limited definition of Change in Control for a particular Award, as the Committee deems appropriate.

Code” means the Internal Revenue Code of 1986, as amended, or any successor thereto, and the regulations promulgated thereunder.

Committee” means the Board or such committee of the Board or the board (or committee of the board) of an Affiliate of the Partnership appointed by the Board to administer the Plan.

DER” means a right, granted in tandem with a specific Phantom Unit, to receive an amount in cash, securities, or property equal to, and at the same time as, the cash distributions or other distributions of securities or property made by the Partnership with respect to a Unit during the period such Phantom Unit is outstanding.

Director” means a “non-employee director” of the Company as defined in Rule 16b-3 under the Exchange Act.

Disability” means, unless provided otherwise in an Award Agreement, (i) “Disability” as defined in any individual employment agreement to which the Participant is a party, or (ii) if there is no such individual employment agreement or it does not define “Disability,” “permanent and total disability” as defined in Section 22(e)(3) of the Code. Notwithstanding the above, with respect to any Award, to the extent necessary to avoid accelerated taxation or tax penalties under Section 409A of the Code, Disability shall mean “disability” within the meaning of Section 409A of the Code.

Employee” means any officer or employee of the Company, its Affiliates, consultants or joint venture partners who performs services for the Company, the Partnership, or an Affiliate of the Company or the Partnership or in furtherance of the Company’s or the Partnership’s business.

Exchange Act” means the Securities Exchange Act of 1934, as amended.

Fair Market Value” means the closing sales price of a Unit on the applicable date (or if there is no trading in the Units on such date, the closing sales price on the last date Units were traded). In the event Units are not publicly traded at the time a determination of fair market value is required to be made hereunder, the

 

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determination of fair market value shall be made in good faith by the Committee in manner which, if necessary to avoid accelerated taxation or tax penalties pursuant to Section 409A of the Code, meets the requirements of Section 409A of the Code.

Listing Event” means the Units are listed on a national securities exchange, whether or not in connection with a public offering of Units.

Option” means an option to purchase Units granted under the Plan.

Participant” means any Employee or Director granted an Award under the Plan.

Person” means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

Phantom Unit” means a phantom (notional) unit granted under the Plan that, upon vesting, entitles the Participant to receive a Unit or its then-Fair Market Value in cash or other securities or property, as determined by the Committee.

Restricted Period” means the period established by the Committee with respect to an Award during which the Award remains subject to forfeiture or is not exercisable by the Participant.

Restricted Unit” means an Award granted under Section 6(c).

Rule 16b-3” means Rule 16b-3 promulgated by the SEC under the Exchange Act, or any successor rule or regulation thereto as in effect from time to time.

SEC” means the Securities and Exchange Commission, or any successor thereto.

Securities Act” means the Securities Act of 1933, as amended.

SECTION 3: ADMINISTRATION.

(a) General Authority and Determinations. The Plan shall be administered by the Committee. A majority of the Committee shall constitute a quorum, and the acts of a majority of the members of the Committee who are present at any meeting thereof at which a quorum is present, or acts unanimously approved by the members of the Committee in writing, shall be the acts of the Committee. Subject to the following and any applicable law, the Committee, in its sole discretion, may delegate any or all of its powers and duties under the Plan, including the power to grant Awards under the Plan, to the Chief Executive Officer of the Company, subject to such limitations on such delegated powers and duties as the Committee may impose, if any; provided, however, that such delegation shall not limit the Chief Executive Officer’s right to receive Awards under the Plan, and the Chief Executive Officer may not grant Awards to, or take any action with respect to any Award previously granted to, himself or a Person who is an Employee or Director subject to Rule 16b-3. Subject to the terms of the Plan and applicable law, and in addition to other express powers and authorizations conferred on the Committee by the Plan, the Committee shall have full power and authority to: (i) designate Participants; (ii) determine the type or types of Awards to be granted to a Participant; (iii) determine the terms and conditions of any Award; (iv) determine whether, to what extent, and under what circumstances Awards may be settled, exercised, canceled, or forfeited; (v) interpret and administer the Plan and any instrument or agreement relating to an Award made under the Plan; (vi) establish, amend, suspend, or waive such rules and regulations and appoint such agents as it shall deem appropriate for the proper administration of the Plan; (vii) accelerate the vesting or lapse of restrictions of any outstanding Award, in each case based on such considerations as the Committee in its sole discretion determines; and (viii) make any other determination and take any other action that the Committee deems necessary or desirable for the administration of the Plan. The Committee shall have

 

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full power and express discretionary authority to make factual determinations and to adopt or amend such rules, regulations, agreements and instruments for implementing the Plan and for the conduct of its business as it deems necessary or advisable, in its sole discretion. Unless otherwise expressly provided in the Plan, all designations, determinations, interpretations, and other decisions under or with respect to the Plan or any Award shall be within the sole discretion of the Committee, may be made at any time and shall be final, conclusive, and binding upon all Persons, including the Company, the Partnership, any Affiliate, any Participant, and any beneficiary of any Award. All powers of the Committee shall be executed in the best interests of the Company, not as a fiduciary, in keeping with the objectives of the Plan, and need not be uniform as to similarly situated Participants.

(b) Award Agreements. All Awards under the Plan shall be made conditional on the Participant’s entering into an Award Agreement, and a Participant shall have no rights under the Plan until an Award Agreement is entered into by the Participant and the Company. The terms and conditions of each Award, as determined by the Committee, shall be set forth in an Award Agreement, which shall be delivered to the Participant receiving such Award upon, or as promptly as is reasonably practicable following, the grant of such Award. All Awards under the Plan shall be made conditional upon the Participant’s acknowledgement, in writing or by acceptance of the Award, that all decisions and determinations of the Committee shall be final and binding on the Participant, his or her beneficiaries and any other person having or claiming an interest in such Award. Awards made under a particular Section of the Plan need not be uniform as among Participants.

SECTION 4: UNITS.

(a) Units Available. Subject to further adjustment as provided in Section 4(c), prior to a Listing Event, no Awards may be granted under the Plan. After a Listing Event, the maximum amount of Phantom Units, Options, and Restricted Units that may be granted under the Plan shall be fixed at a number equal to 10% of the total number of outstanding Units at such Listing Event, which shall include Units issued in a contemporaneous offering with the Listing Event. If any Option, Phantom Unit, or Restricted Unit is forfeited or otherwise terminates or is canceled or paid without the delivery of Units, then the Units covered by such Award, to the extent of such forfeiture, termination, payment or cancellation, shall again be Units with respect to which Awards may be granted. Units surrendered in payment of the Exercise Price of an Option, and Units withheld or surrendered for payment of taxes, shall not be available for re-issuance under the Plan.

(b) Sources of Units Deliverable under Awards. Any Units delivered pursuant to an Award shall consist, in whole or in part, of Units newly issued by the Partnership, Units acquired in the open market or from any Affiliate of the Partnership or the Company, or any other Person, or any combination of the foregoing, as determined by the Committee in its discretion.

(c) Adjustments. In the event that any distribution (whether in the form of cash, Units, other securities or other property), recapitalization, split, reverse split, reorganization, merger, consolidation, split-up, spin-off, combination, repurchase, or exchange of Units or other securities of the Partnership, issuance of warrants or other rights to purchase Units or other securities of the Partnership, or other similar transaction or event affects the Units such that an adjustment is necessary in order to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under the Plan, then the Committee shall equitably adjust (i) the number and type of Units (or other securities or property) with respect to which Awards may be granted, (ii) the number and type of Units (or other securities or property, including cash) subject to outstanding Awards, and (iii) the grant or exercise price with respect to any Award; provided, however, that the number of Units subject to any Award shall always be a whole number. The Committee may make provision for a cash payment to the holder of an outstanding Award in connection with any event listed in this Section 4(c).

SECTION 5: ELIGIBILITY.

Any Employee or Director shall be eligible to be designated a Participant and receive an Award under the Plan.

 

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SECTION 6: AWARDS.

(a) Options. The Committee shall have the authority to determine the Employees and Directors to whom Options shall be granted, the number of Units to be covered by each Option, the exercise price therefor, the Restricted Period and the conditions and limitations applicable to the exercise of the Option, as the Committee shall determine, that are not inconsistent with the provisions of the Plan.

(I) EXERCISE PRICE. THE EXERCISE PRICE PER UNIT PURCHASABLE UNDER AN OPTION SHALL BE DETERMINED BY THE COMMITTEE AT THE TIME THE OPTION IS GRANTED AND MAY NOT BE LESS THAN FAIR MARKET VALUE AS OF THE DATE OF GRANT.

(II) RESTRICTIONS ON EXERCISE AND METHOD OF EXERCISE. THE COMMITTEE SHALL DETERMINE THE RESTRICTED PERIOD AND THE METHOD OR METHODS BY WHICH PAYMENT OF THE EXERCISE PRICE MAY BE MADE OR DEEMED TO HAVE BEEN MADE, WHICH MAY INCLUDE, WITHOUT LIMITATION, CASH, CHECK ACCEPTABLE TO THE BOARD, A TENDER OF UNITS BY THE PARTICIPANT HAVING A FAIR MARKET VALUE ON THE DATE OF EXERCISE EQUAL TO THE EXERCISE PRICE, A “CASHLESS-BROKER”–ASSISTED EXERCISE IN ACCORDANCE WITH PROCEDURES PERMITTED BY REGULATION T OF THE FEDERAL RESERVE BOARD OR THROUGH PROCEDURES APPROVED BY THE BOARD, A RECOURSE NOTE FROM THE PARTICIPANT IN A FORM ACCEPTABLE TO THE BOARD AND WHICH DOES NOT VIOLATE THE SARBANES-OXLEY ACT OF 2002, A “NET EXERCISE” THAT PERMITS THE PARTNERSHIP TO WITHHOLD A NUMBER OF UNITS THAT OTHERWISE WOULD BE ISSUED TO THE PARTICIPANT PURSUANT TO THE EXERCISE OF THE OPTION HAVING A FAIR MARKET VALUE ON THE DATE OF EXERCISE EQUAL TO THE EXERCISE PRICE, OR ANY COMBINATION THEREOF.

(b) Phantom Units. The Committee shall have the authority to determine the Employees and Directors to whom Phantom Units shall be granted, the number of Phantom Units to be granted to each such Participant, the Restricted Period, the conditions under which the Phantom Units may become vested or forfeited, whether DERs are granted with respect to an Award of Phantom Units and such other terms and conditions, as the Committee may determine, that are not inconsistent with the provisions of the Plan.

(I) PAYMENT WITH RESPECT TO PHANTOM UNITS. PAYMENT WITH RESPECT TO PHANTOM UNITS SHALL BE MADE IN CASH, IN UNITS, OR IN A COMBINATION OF CASH AND UNITS, AS DETERMINED BY THE COMMITTEE. THE AWARD AGREEMENT SHALL SPECIFY THE MAXIMUM NUMBER OF UNITS THAT CAN BE ISSUED PURSUANT TO THE AWARD OF PHANTOM UNITS.

(II) DERS. THE COMMITTEE MAY GRANT DERS IN CONNECTION WITH AN AWARD OF PHANTOM UNITS, UNDER SUCH TERMS AND CONDITIONS AS THE COMMITTEE DEEMS APPROPRIATE. DERS MAY BE PAID TO PARTICIPANTS CURRENTLY OR MAY BE DEFERRED, AS REFLECTED IN THE APPLICABLE AWARD AGREEMENT. ALL DERS THAT ARE NOT PAID CURRENTLY SHALL BE CREDITED TO BOOKKEEPING ACCOUNTS ON THE COMPANY’S RECORDS FOR PURPOSES OF THE PLAN. DERS MAY BE ACCRUED AS A CASH OBLIGATION OR MAY CONVERTED TO ADDITIONAL PHANTOM UNITS FOR THE PARTICIPANT, AND DEFERRED DERS MAY ACCRUE INTEREST, IN EACH CASE AS DETERMINED BY THE COMMITTEE. THE COMMITTEE MAY PROVIDE THAT DERS SHALL BE PAYABLE BASED ON THE ACHIEVEMENT OF SPECIFIC PERFORMANCE GOALS. DERS MAY BE PAYABLE IN CASH OR UNITS OR IN A COMBINATION OF CASH AND UNITS, AS DETERMINED BY THE COMMITTEE.

 

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(c) Restricted Units. Restricted Units are actual Units issued to a Participant that are subject to vesting restrictions and evidenced in such manner as the Committee may deem appropriate, including book-entry registration or issuance of one or more unit certificates. Any certificate issued in respect of Restricted Units shall be registered in the name of the applicable Participant and shall bear an appropriate legend referring to the terms, conditions, and restrictions applicable to such Restricted Units. The Committee may require that the certificates evidencing such Units be held in custody by the Company until the restrictions thereon shall have lapsed and that, as a condition of any Award of Restricted Units, the applicable Participant shall have endorsed the certificates in blank, relating to the Units covered by such Award.

(I) TERMS AND CONDITIONS. RESTRICTED UNITS SHALL BE SUBJECT TO THE FOLLOWING TERMS AND CONDITIONS:

(A) The Committee shall have the authority to determine the Employees and Directors to whom Restricted Units shall be granted, the number of Units to be granted to each such Participant, the Restricted Period, the conditions under which the Restricted Units may become vested or forfeited, and such other terms and conditions, as the Committee may determine, that are not inconsistent with the provisions of the Plan. The conditions for grant, vesting or transferability and the other provisions of Restricted Units (including without limitation any performance goals) need not be the same with respect to each Participant. The Committee may at any time, in its sole discretion, accelerate or waive, in whole or in part, any of the foregoing restrictions.

(B) Subject to the provisions of the Plan and the applicable Award Agreement, during the Restricted Period, the Participant shall not be permitted to sell, assign, transfer, pledge or otherwise encumber Restricted Units.

(C) Except as provided in this Section 6 and in an applicable Award Agreement, the applicable Participant shall have, with respect to the Restricted Units, all of the rights of holders of Units, including the right to vote the Units. If so determined by the Committee in the applicable Award Agreement, (i) cash dividends on the Units that are the subject of the Restricted Unit Award shall be automatically deferred and/or reinvested in additional Restricted Units and held subject to the vesting of the underlying Restricted Units, and (ii) subject to any adjustment pursuant to the terms of Section 4(c) of the Plan, dividends payable in Units shall be paid in the form of Restricted Units of the same class as the Units with which such dividend was paid, held subject to the vesting of the underlying Restricted Units.

(D) If and when the applicable performance goals, if any, are determined by the Committee to be satisfied and the Restricted Period expires without a prior forfeiture of the Restricted Units for which legended certificates have been issued, unlegended certificates for such Units shall be delivered to the Participant upon surrender of the legended certificates.

(d) General.

(I) FORFEITURE. EXCEPT AS OTHERWISE PROVIDED IN THE TERMS OF AN AWARD AGREEMENT, UPON TERMINATION OF A PARTICIPANT’S EMPLOYMENT WITH THE COMPANY OR ITS AFFILIATES OR MEMBERSHIP ON THE BOARD DURING THE APPLICABLE RESTRICTED PERIOD, ALL UNVESTED OPTIONS, PHANTOM UNITS, AND RESTRICTED UNITS SHALL BE FORFEITED BY THE PARTICIPANT; PROVIDED, HOWEVER, THAT IF THE REASON FOR THE TERMINATION IS THE PARTICIPANT’S DEATH OR DISABILITY, ALL OPTIONS AWARDED TO THE PARTICIPANT SHALL BECOME EXERCISABLE AND ALL PHANTOM UNITS AND RESTRICTED UNITS SHALL VEST AUTOMATICALLY. THE COMMITTEE MAY, IN ITS DISCRETION, WAIVE IN WHOLE OR IN PART ANY FORFEITURE.

 

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(II) AWARDS MAY BE GRANTED SEPARATELY OR TOGETHER. AWARDS MAY, IN THE DISCRETION OF THE COMMITTEE, BE GRANTED EITHER ALONE OR IN ADDITION TO, IN TANDEM WITH, OR IN SUBSTITUTION FOR ANY OTHER AWARD GRANTED UNDER THE PLAN OR ANY AWARD GRANTED UNDER ANY OTHER PLAN OF THE COMPANY OR ANY AFFILIATE.

(III) LIMITS ON TRANSFER OF AWARDS.

(A) Except as provided in (C) below, each Option shall be exercisable only by the Participant during the Participant’s lifetime, or by the person to whom the Participant’s rights shall pass by will or the laws of descent and distribution.

(B) Except as provided in (C) below, no Award and no right under any such Award may be assigned, alienated, pledged, attached, sold or otherwise transferred or encumbered by a Participant and any such purported assignment, alienation, pledge, attachment, sale, transfer or encumbrance shall be void and unenforceable against the Partnership, the Company or any Affiliate thereof.

(C) To the extent specifically provided by the Committee with respect to an Option grant, an Option may be transferred by a Participant without consideration to immediate family members or related family trusts, limited partnerships or similar entities or on such terms and conditions as the Committee may from time to time establish. In addition, Awards may be transferred by will and the laws of descent and distribution.

(IV) UNIT CERTIFICATES. ALL CERTIFICATES FOR UNITS OR OTHER SECURITIES OF THE PARTNERSHIP DELIVERED UNDER THE PLAN PURSUANT TO ANY AWARD OR THE EXERCISE THEREOF SHALL BE SUBJECT TO SUCH STOP TRANSFER ORDERS AND OTHER RESTRICTIONS AS THE COMMITTEE MAY DEEM ADVISABLE UNDER THE PLAN OR THE RULES, REGULATIONS, AND OTHER REQUIREMENTS OF THE SEC, ANY STOCK EXCHANGE UPON WHICH SUCH UNITS OR OTHER SECURITIES ARE THEN LISTED, AND ANY APPLICABLE FEDERAL OR STATE LAWS, AND THE COMMITTEE MAY CAUSE A LEGEND OR LEGENDS TO BE PUT ON ANY SUCH CERTIFICATES TO MAKE APPROPRIATE REFERENCE TO SUCH RESTRICTIONS.

(V) DELIVERY OF UNITS OR OTHER SECURITIES AND PAYMENT BY PARTICIPANT OF CONSIDERATION. NOTWITHSTANDING ANYTHING IN THE PLAN OR ANY GRANT AGREEMENT TO THE CONTRARY, DELIVERY OF UNITS PURSUANT TO THE EXERCISE OR VESTING OF AN AWARD MAY BE DEFERRED FOR ANY PERIOD DURING WHICH, IN THE GOOD FAITH DETERMINATION OF THE COMMITTEE, THE PARTNERSHIP IS NOT REASONABLY ABLE TO OBTAIN OR ISSUE UNITS PURSUANT TO SUCH AWARD WITHOUT VIOLATING THE RULES OR REGULATIONS OF ANY APPLICABLE LAW OR SECURITIES EXCHANGE. NO UNITS OR OTHER SECURITIES SHALL BE DELIVERED PURSUANT TO ANY AWARD UNTIL PAYMENT IN FULL OF ANY AMOUNT REQUIRED TO BE PAID PURSUANT TO THE PLAN OR THE APPLICABLE AWARD GRANT AGREEMENT (INCLUDING, WITHOUT LIMITATION, ANY EXERCISE PRICE OR TAX WITHHOLDING) IS RECEIVED BY THE PARTNERSHIP. WITH RESPECT TO ANY AWARD THAT IS SUBJECT TO SECTION 409A OF THE CODE, ANY DELAY UNDER THIS PARAGRAPH IS INTENDED TO APPLY ONLY IF NO ACCELERATED TAXATION OR TAX PENALTIES UNDER SECTION 409A OF THE CODE WOULD APPLY.

(VI) RULE 16B-3. IT IS INTENDED THAT THE PLAN AND ANY AWARD MADE TO A PARTICIPANT SUBJECT TO SECTION 16 OF THE EXCHANGE ACT MEET ALL OF THE REQUIREMENTS OF RULE 16B-3. IF ANY PROVISION OF THE PLAN OR ANY SUCH AWARD WOULD DISQUALIFY THE PLAN OR SUCH AWARD UNDER, OR WOULD

 

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OTHERWISE NOT COMPLY WITH RULE 16B-3, SUCH PROVISION OR AWARD SHALL BE CONSTRUED OR DEEMED AMENDED TO CONFORM TO RULE 16B-3.

(VII) STATUS OF ORIGINAL ISSUE UNITS. THE PARTNERSHIP INTENDS, BUT SHALL NOT BE OBLIGATED, TO REGISTER FOR SALE UNDER THE SECURITIES ACT THE UNITS ACQUIRABLE PURSUANT TO AWARDS, AND TO KEEP SUCH REGISTRATION EFFECTIVE THROUGHOUT THE PERIOD ANY AWARDS ARE IN EFFECT. IN THE ABSENCE OF SUCH EFFECTIVE REGISTRATION OR AN AVAILABLE EXEMPTION FROM REGISTRATION UNDER THE SECURITIES ACT, DELIVERY OF UNITS ACQUIRABLE PURSUANT TO AWARDS SHALL BE DELAYED UNTIL REGISTRATION OF SUCH UNITS IS EFFECTIVE OR AN EXEMPTION FROM REGISTRATION UNDER THE SECURITIES ACT IS AVAILABLE. IN THE EVENT EXEMPTION FROM REGISTRATION UNDER THE SECURITIES ACT IS AVAILABLE, A PARTICIPANT (OR A PARTICIPANT’S ESTATE OR PERSONAL REPRESENTATIVE IN THE EVENT OF THE PARTICIPANT’S DEATH OR INCAPACITY), IF REQUESTED BY THE PARTNERSHIP TO DO SO, WILL EXECUTE AND DELIVER TO THE PARTNERSHIP IN WRITING AN AGREEMENT CONTAINING SUCH PROVISIONS AS THE PARTNERSHIP MAY REQUIRE TO ASSURE COMPLIANCE WITH APPLICABLE SECURITIES LAWS. NO SALE OR DISPOSITION OF UNITS ACQUIRED PURSUANT TO AN AWARD BY A PARTICIPANT SHALL BE MADE IN THE ABSENCE OF AN EFFECTIVE REGISTRATION STATEMENT UNDER THE SECURITIES ACT WITH RESPECT TO SUCH UNITS UNLESS AN OPINION OF COUNSEL SATISFACTORY TO THE PARTNERSHIP THAT SUCH SALE OR DISPOSITION WILL NOT CONSTITUTE A VIOLATION OF THE SECURITIES ACT OR ANY OTHER APPLICABLE SECURITIES LAWS IS FIRST OBTAINED. WITH RESPECT TO ANY AWARD THAT IS SUBJECT TO SECTION 409A OF THE CODE, ANY DELAY UNDER THIS PARAGRAPH IS INTENDED TO APPLY ONLY IF NO ACCELERATED TAXATION OR TAX PENALTIES UNDER SECTION 409A OF THE CODE WOULD APPLY.

(VIII) CHANGE IN CONTROL.

(A) General Authority. In connection with any Change in Control, the Committee may, in its sole and absolute discretion and authority and without obtaining the approval or consent of the Partnership’s unitholders or any Participant with respect to such Participant’s outstanding Awards, subject to the terms of any Award Agreements or employment agreements between the Company or any Affiliate and any Participant, take one or more of the following actions (with respect to any or all of the Awards, and with discretion to differentiate between individual Participants and Awards for any reason):

 

  (1) Cause Awards to be assumed or a substantially equivalent award to be substituted by the surviving or successor entity or a parent, subsidiary, or affiliate of such successor entity;

 

  (2) Accelerate the vesting of Awards as of immediately prior to the consummation of the transaction that constitutes such Change in Control so that Awards shall vest (and, to the extent applicable, become exercisable) as to the Units that otherwise would have been unvested, in a manner which allows the resulting Units to participate in such transaction;

 

  (3) Arrange or otherwise provide for the payment of cash or other consideration to Participants in exchange for the cancellation of outstanding Awards (with the Committee determining the amount payable to each Participant based on, in the case of an Award of Phantom Units or Restricted Units being cancelled, the Fair Market Value, on the date of the Change in Control, of the Units subject to such Award and, in the case of an Award of Options, the excess, if any, of the Fair Market Value on the date of the Change in Control of the Units issuable with respect to such Options less the aggregate exercise price of such Options);

 

  (4)

Terminate all or some Awards upon the consummation of the transaction that constitutes a Change in Control, provided that the Committee shall provide for vesting of such Awards in full as of immediately

 

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  prior to the consummation of the transaction that constitutes such Change in Control (to the extent that, where applicable, an Award is not exercised prior to consummation of such a transaction in which the Award is not being assumed or substituted, such Award shall terminate upon such consummation); and

 

  (5) Make such other modifications, adjustments, or amendments to outstanding Awards or this Plan as the Committee deems necessary or appropriate.

(B) Vesting in Connection With a Change in Control. Upon a Change in Control, all Awards held by Directors shall, to the extent previously unvested, immediately vest in full. In the case of Participants who are Employees, upon the Participant’s termination of employment by the Company without “Cause” (as defined herein), or upon any other type of termination specified in the applicable Award Agreement, in any case following a Change in Control, any unvested portion of an Award shall immediately vest in full and, in the case of Options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the Option.

SECTION 7: AMENDMENT.

Except to the extent prohibited by applicable law:

(a) Amendments to the Plan. Except as required by the rules of the principal securities exchange on which the Units are traded and subject to Section 7(b) below, the Board or the Committee may amend, alter, suspend, discontinue, or terminate the Plan in any manner without the consent of any partner, Participant, other holder or beneficiary of an Award, or other Person.

(b) Amendments to Awards. Subject to Sections 6(d)(viii) and 7(a), the Committee may waive any conditions or rights under, amend any terms of, or alter any Award theretofore granted, provided no change, other than pursuant to Sections 6(d)(viii) or 7(c), to any Award shall materially reduce the benefit to a Participant without the consent of such Participant.

(c) Adjustment of Awards upon the Occurrence of Certain Unusual or Nonrecurring Events. The Committee is hereby authorized to make adjustments in the terms and conditions of, and the criteria included in, Awards in recognition of unusual or nonrecurring events (including, without limitation, the events described in Section 4(c) of the Plan) affecting the Partnership or the financial statements of the Partnership, or of changes in applicable laws, regulations, or accounting principles, whenever the Committee determines that such adjustments are appropriate in order to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under the Plan.

SECTION 8: GENERAL PROVISIONS.

(a) No Rights to Award. No Person shall have any claim to be granted any Award under the Plan, and there is no obligation for uniformity of treatment of Participants. The terms and conditions of Awards need not be the same with respect to each Participant.

(b) Withholding. All Awards under the Plan shall be subject to applicable federal (including FICA), state and local tax withholding requirements. The Company may require that the Participant or other person receiving or exercising Awards pay to the Company the amount of any federal, state or local taxes that the Company is required to withhold with respect to such Awards, or the Company may deduct from other wages paid by the Company the amount of any withholding taxes due with respect to such Awards. The Company may require forfeiture of any Award for which the Participant does not timely pay the applicable withholding taxes. If the Committee so permits, Units may be withheld to satisfy the Company’s tax withholding obligation with respect to Awards paid in Units, at the time such Awards become subject to employment taxes and tax withholding, as applicable, up to an amount that does not exceed the minimum required withholding for federal (including FICA), state and local tax liabilities.

 

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(c) No Right to Employment. The grant of an Award shall not be construed as giving a Participant the right to be retained in the employ of the Company or any Affiliate or to remain on the Board. Further, the Company or an Affiliate may at any time dismiss a Participant from employment, free from any liability or any claim under the Plan, unless otherwise expressly provided in the Plan or in any Award agreement.

(d) Governing Law. The validity, construction, and effect of the Plan and any rules and regulations relating to the Plan shall be determined in accordance with the laws of the State of Delaware (without regard to any choice of law provision that might refer interpretation of the Plan to the substantive law of another jurisdiction) and applicable federal law.

(e) Severability. If any provision of the Plan or any Award is or becomes or is deemed to be invalid, illegal, or unenforceable in any jurisdiction or as to any Person or Award, or would disqualify the Plan or any Award under any law deemed applicable by the Committee, such provision shall be construed or deemed amended to conform to the applicable laws, or if it cannot be construed or deemed amended without, in the determination of the Committee, materially altering the intent of the Plan or the Award, such provision shall be stricken as to such jurisdiction, Person or Award and the remainder of the Plan and any such Award shall remain in full force and effect.

(f) Compliance with Other Laws. The Committee may refuse to issue or transfer any Units or other consideration under an Award if, in its sole discretion, it determines that the issuance or transfer or such Units or such other consideration might violate any applicable law or regulation, the rules of the principal securities exchange on which the Units are then traded, or entitle the Partnership or an Affiliate to recovery of “short swing profits” under Section 16(b) of the Exchange Act, and any payment tendered to the Partnership by a Participant, other holder or beneficiary in connection with the exercise of such Award, shall be promptly refunded to the relevant Participant, holder or beneficiary. It is intended that, to the extent applicable, Awards made under the Plan comply with the requirements of Section 409A of the Code and the regulations thereunder so as to avoid any accelerated income tax or tax penalty imposed under Section 409A of the Code, and the Plan and Award Agreements shall be interpreted consistently with this intent.

(g) No Trust or Fund Created. Neither the Plan nor any Award shall create or be construed to create a trust or separate fund of any kind or a fiduciary relationship between the Partnership, the Company or any participating Affiliate and a Participant or any other Person.

(h) No Fractional Units. No fractional Units shall be issued or delivered pursuant to the Plan or any Award, and the Committee shall determine whether cash, other securities, or other property shall be paid or transferred in lieu of any fractional Units or whether such fractional Units or any rights thereto shall be canceled, terminated, or otherwise eliminated.

(i) Headings. Headings are given to the sections and subsections of the Plan solely as a convenience to facilitate reference. Such headings shall not be deemed in any way material or relevant to the construction or interpretation of the Plan or any provision thereof.

(j) Facility of Payment. Any amounts payable hereunder to any Person under legal disability or who, in the judgment of the Committee, is unable to properly manage his financial affairs, may be paid to the legal representative of such Person, or may be applied for the benefit of such Person in any manner which the Committee may select, and the Company shall be relieved of any further liability for payment of such amounts.

SECTION 9: TERM OF THE PLAN.

The Plan shall be effective on the date of its approval by the Unit holders, subject to the requirement that no Awards be granted hereunder until the occurrence of a Listing Event, and shall continue until the earlier of (i) the

 

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date terminated by the Board, in its sole discretion, (ii) the date Units are no longer available for the grant of Awards under the Plan, or (iii) 10 years after a Listing Event. However, unless otherwise expressly provided in the Plan or in an applicable Award agreement, any Award granted prior to such termination, and the authority of the Board or the Committee to amend, alter, adjust, suspend, discontinue, or terminate any such Award or to waive any conditions or rights under such Award, shall extend beyond such termination date.

 

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Exhibit G to Prospectus

TRANSFER ON DEATH FORM

 

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TRANSFER ON DEATH DESIGNATION

Atlas Growth Partners, L.P. TRANSFER ON DEATH FORM (TOD) This form is NOT VALID for Trust or IRA accounts. Both pages of this form must accompany the subscription agreement.

As our transfer agent, American National Stock Transfer, LLC, is located in New York, and a Transfer on Death designation, or TOD pursuant to this form and all rights related thereto shall be governed by the laws of the State of New York. Any beneficiary wanting to purchase additional common units of Atlas Growth Partners, L.P. must meet applicable suitability standards.

PLEASE REVIEW THE FOLLOWING IN ITS ENTIRETY BEFORE COMPLETING THE TRANSFER ON DEATH FORM:

 

1. Eligible accounts: Individual accounts and joint accounts with rights of survivorship are eligible. A TOD designation will not be accepted from residents of Louisiana, Puerto Rio or Texas.

 

2. Designation of beneficiaries: The account owner may designate one or more beneficiaries of the TOD account. Beneficiaries are not “account owners” as the term is used herein.

 

3. Primary and contingent beneficiaries: The account owner may designate primary and contingent beneficiaries of the TOD account. Primary beneficiaries are the first in line to receive the account upon the death of the account owner. Contingent beneficiaries, if any are designated, receive the account upon the death of the account owner if, and only if, there are no surviving primary beneficiaries.

 

4. Minors as beneficiaries: Minors may be beneficiaries of a TOD account only if a custodian, trustee, or guardian is set forth for the minor on the transfer on death form. By not providing a custodian, trustee, or guardian, the account owner is representing that all of the named beneficiaries are not minors.

 

5. Status of beneficiaries: Beneficiaries have no rights to the account until the death of the account owner or last surviving joint owner.

 

6. Joint owners: If more than one person is the owner of an account registered or to be registered TOD, the joint owners of the account must own the account as joint tenants with rights of survivorship.

 

7. Transfer to designated beneficiaries upon the owner’s death:

 

  a. Percentage designation: Unless the account owner designates otherwise by providing a percentage for each beneficiary on the Transfer on Death Form, all surviving beneficiaries will receive equal portions of the account upon the death of the account owner.

 

  b. Form of ownership: Multiple beneficiaries will be treated as tenants in common unless the account owner expressly indicates otherwise.

 

  c. Predeceasing beneficiaries: If the account owner wishes to have the account pass to the children of the designated beneficiaries if the designated beneficiaries predecease the account owner, the account owner must check the box labeled Lineal Descendants per Stirpes, or LDPS, in Section B of this form. If the box is not checked, the children of beneficiaries who die before you will not receive a portion of your account. If the account is registered LDPS and has contingent beneficiaries, LDPS takes precedence. If a TOD account with multiple beneficiaries is registered LDPS, the LDPS registration must apply to all beneficiaries. If the account is not registered LDPS, a beneficiary must survive the account owner to take the account or his or her part of the account. In the case of multiple beneficiaries, if one of the beneficiaries does not survive the account owner, the deceased beneficiary’s share of the account will be divided equally among the remaining beneficiaries upon the death of the account owner. If no beneficiary survives the account owner, the account will be treated as part of the estate of the account owner.

 

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  d. Notice of dispute: Should the transfer agent receive written notice of a dispute over the disposition of a TOD account, re-registration of the account to the beneficiaries may be delayed.

 

8. Revocation or changes: An account owner or all joint owners may revoke or change a beneficiary designation. The Change of Transfer on Death Form is available for this purpose at from your registered representative.

 

9. Controlling terms: The language as set forth in the TOD account registration shall control at all times. Unless the transfer agent is expressly instructed by the account owner to change the status of the account or the beneficiary designation prior to the account owner’s death, the person or persons set forth as the beneficiaries of the account shall remain the beneficiaries of the account, and events subsequent to the registration of the account as a TOD account shall not change either the rights of the persons designated as beneficiaries or the status of the account as a TOD account.

 

  a. Divorce: If the account owner designated his or her spouse as a TOD beneficiary of the account, and subsequently the account owner and the beneficiary are divorced, the fact of the divorce will not automatically revoke the beneficiary designation. If the account owner wishes to revoke the beneficiary designation, the account owner must notify Atlas Growth Partners, L.P. of the desired change in writing as specified in paragraph 8 above.

 

  b. Will or other testamentary document: The beneficiary designation may not be revoked by the account owner by the provisions of a will or a codicil to a will.

 

  c. Interest, capital gains and other distributions after the account owner’s death:

 

  i. Accruals to the account that occur after the death of the account owner or last surviving joint owner, and are still in the account when it is re-registered to the beneficiaries, stay with the account and pass to the beneficiaries.

 

  ii. If cash distributions have actually been paid out prior to notice to the transfer agent of the death of the account owner, such distributions are deemed to be the property of the estate of the original account owner and do not pass with the account to the designated beneficiaries.

 

10. TOD registrations may not be made irrevocable.

A—UNITHOLDER INFORMATION

Name of unitholder(s) exactly as indicated on subscription agreement:

 

   Mr.    Mrs.    Ms.   

 

 

 

  

 

Unitholder Name

   ¨    ¨    ¨    First   Middle    Last

Co-Unitholder Name (if
applicable)

   Mr.    Mrs.    Ms.   

 

 

 

  

 

   ¨    ¨    ¨    First   Middle    Last

Social Security Number(s) of Unitholder(s)

Daytime Telephone

            Unitholder State
of Residence

(Not accepted
from residents of
Louisiana, Puerto
Rico or Texas)

     Co-Unitholder

 

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B—TRANSFER ON DEATH (Not permitted in Louisiana, Puerto Rico or Texas)

I (we) authorize Atlas Growth Partners, L.P. to register the percentage of common units set forth below in beneficiary form, assigning investorship on my (our) death to the TOD beneficiary(ies) named below. Use an additional sheet of paper if space is needed to designate more TOD beneficiaries. Complete information must be provided for all TOD beneficiaries.

 

PRIMARY Beneficiary Name

              
               TOD Unit Percentage %
Social Security or Tax ID #      Birth Date      Relationship     
     / /          
PRIMARY Beneficiary Name               
               TOD Unit Percentage %
Social Security or Tax ID #      Birth Date      Relationship     
     / /          

PRIMARY Beneficiary Name

              
               TOD Unit Percentage %
Social Security or Tax ID #      Birth Date      Relationship     
     / /          
Contingent Beneficiary Name (Optional)               
               TOD Unit Percentage %
Social Security or Tax ID #      Birth Date      Relationship     
     / /          
Contingent Beneficiary Name (Optional)               
               TOD Unit Percentage %
Social Security or Tax ID #      Birth Date      Relationship     
     / /          

 

¨ LDPS: Check if you wish to have the account pass to children of the above-designated beneficiary(ies) if the designated beneficiary(ies) predeceases the unitholder. The LDPS designation will apply to all designated beneficiaries.

C—SIGNATURE

By signing below, I (we) authorize Atlas Growth Partners, L.P. to register the common units in beneficiary form as designated above. I (we) agree on behalf of myself (ourselves) and my (our) heirs, assigns, executors, administrators and beneficiaries to indemnify and hold harmless Atlas Growth Partners, L.P. and any and all of its affiliates, agents, successors and assigns, and their respective directors, officers and employees, from and against any and all claims, liabilities, damages, actions and expenses arising directly or indirectly relating to this TOD designation or the transfer of my (our) shares in accordance with this TOD designation. If any claims are made or disputes are raised in connection with this TOD designation or account, Atlas Growth Partners, L.P. reserves the right to require the claimants or parties in interest to arrive at a final resolution by adjudication, arbitration, or other acceptable method, prior to transferring any TOD account assets. I (we) have reviewed all the information set forth on pages 1 and 2 of this form.

I (we) further understand that Atlas Growth Partners, L.P. cannot provide any legal advice and I (we) agree to consult with my (our) attorney, if necessary, to make certain that any TOD designation is consistent with my (our) estate and tax planning and is valid. Sign exactly as the name(s) appear(s) on the statement of account. All investors must sign. This TOD is effective subject to the acceptance of Atlas Growth Partners, L.P.

 

 

  

 

Signature—Investor (Required) Date

   Signature—Co-Investor (If Applicable) Date

 

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Exhibit H to Prospectus

LETTER OF DIRECTION

 

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LETTER OF DIRECTION

                    , 201

Atlas Growth Partners, L.P.

c/o Justin Atkinson

Park Place Corporate Center One, 1000

Commerce Drive, Suite 410

Pittsburgh, Pennsylvania 15275

Phone: (800) 251-0171

RE: Registered Investment Advisory Fees

Account No. (“Account”)

Ladies and Gentlemen:

You are hereby instructed and authorized by me to deduct advisory fees payable to my registered investment advisor, in the following amount from my Account, and to pay such amount by check to my registered investment advisor, upon each distribution by Atlas Growth Partners, L.P. on my Account, as payment for my registered investment advisor’s advisory fees (select only one):

$                ; or

        % of asset value (calculated on a 365-day calendar year basis) to be paid by the Partnership on my Account.

I acknowledge that any and all advisory fees payable to my registered investment advisor are my sole responsibility and you are paying the amounts directed by me as an accommodation.

This letter shall serve as an irrevocable instruction to you to pay such advisory fees from my Account until such time as I provide you with written notice of my election to revoke this instruction.

Sincerely,

 

* This election is not available for custodial ownership accounts, such as individual retirement accounts, Keogh plans and 401(k) plans, or Alabama, Maryland, North Dakota or Ohio investors.

 

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Exhibit I to Prospectus

NOTICE OF REVOCATION

 

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NOTICE OF REVOCATION

                    , 201

Atlas Growth Partners, L.P.

c/o Justin Atkinson

Park Place Corporate Center One, 1000

Commerce Drive, Suite 410

Pittsburgh, Pennsylvania 15275

RE: Revocation of Instruction

Account No. (“Account”)

Ladies and Gentlemen:

This letter shall serve as notice to you of my revocation of my instruction to you to deduct advisory fees from my Account and pay such fees directly to, my registered investment advisor, pursuant to my letter to you dated                 , 201 .

I hereby instruct you to cease any and all future deductions from my Account for the purpose of such advisory fee payments. I understand and acknowledge that this revocation will be effective within one business day of receipt by you.

Sincerely,

 

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PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee and the FINRA filing fee, the amounts set forth below are estimates.

 

Item

   Amount  

SEC registration fee

   $ 116,200   

FINRA filing fee

   $ 195,500   

Legal fees and expenses

   $ 1,000,000   

Blue sky fees and expenses

   $ 138,300   

Accounting fees and expenses

   $ 1,000,000   

Sales and advertising expenses

   $ 2,000,000   

Printing

   $ 1,000,000   

Due diligence expenses

   $ 2,000,000   

Miscellaneous expenses(1)

   $ 7,550,000   
  

 

 

 

Total

   $ 15,000,000   
  

 

 

 

 

(1) Miscellaneous expenses include costs related to transfer agent fees; escrow agent fees; fulfillment costs; office equipment and supplies; industry sponsorships and membership fees; telephone and internet; IT and software; and temporary employee services.

Item 14. Indemnification of Officers and Members of the Board of Directors.

The section of the prospectus entitled “Summary of the Partnership Agreement—The Partnership Agreement—Indemnification” discloses that we will generally indemnify our general partner and officers and directors of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Subject to any terms, conditions or restrictions set forth in the Partnership Agreement, Section 17-108 of the Delaware Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever.

Item 15. Recent Sales of Unregistered Securities

In connection with our formation, we issued to (i) our general partner 100 GP units representing a 2.00% general partner interest in the Partnership for $1,000 and (ii) ATLS 10 common units representing a 98.00% limited partner interest in the Partnership for $100. The issuance was exempt from registration under Section 4(a)(2) of the Securities Act.

In connection with our initial private offering that commenced in May 2013 and closed in June 2015, we issued to our limited partners 23,300,410 common units in the Partnership for an aggregate offering price of $233.0 million. Anthem served as the dealer manager in our initial private offering and received aggregate commissions equal to $22.8 million. The initial private offering was exempt from registration under Regulation D of the Securities Act.

We have made no other sales of unregistered securities within the past three years.

 

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Item 16. Exhibits and Financial Statement Schedules.

 

(a) The following exhibits are filed as part of this Registration Statement:

 

Exhibit
Number

 

Description

  1.1****   Form of Exclusive Dealer Manager Agreement
  1.2****   Form of Soliciting Dealer Agreement
  2.1**   Purchase and Sale Agreement by and between Cinco Resources, Inc., Cima Resources, LLC, ARP Eagle Ford, LLC, Atlas Growth Eagle Ford, LLC and Atlas Resource Partners, L.P., dated as of September 24, 2014 (incorporated by reference to Exhibit 2.1 to Atlas Resource Partners, L.P.’s Current Report on Form 8-K filed September 30, 2014 (File No. 001-35317))
  2.2**   First Amendment to Purchase and Sale Agreement by and between Cinco Resources, Inc., Cima Resources, LLC, ARP Eagle Ford, LLC, Atlas Growth Eagle Ford, LLC and Atlas Resource Partners, L.P., dated as of October 27, 2014 (incorporated by reference to Exhibit 2.1 to Atlas Resource Partners, L.P.’s Current Report on Form 8-K filed November 6, 2014 (File No. 001-35317))
  2.3**   Second Amendment to Purchase and Sale Agreement by and between Cinco Resources, Inc., Cima Resources, LLC, ARP Eagle Ford, LLC, Atlas Growth Eagle Ford, LLC and Atlas Resource Partners, L.P., dated as of March 31, 2015 (incorporated by reference to Exhibit 2.1 to Atlas Resource Partners, L.P.’s Current Report on Form 8-K filed April 6, 2015 (File No. 001-35317))
  2.4**   Shared Acquisition and Operating Agreement by and among ARP Eagle Ford, LLC and Atlas Growth Eagle Ford, LLC, dated September 24, 2014 (incorporated by reference to Exhibit 2.2 to Atlas Resource Partners, L.P.’s Current Report on Form 8-K filed September 30, 2014 (File
No. 001-35317)). The schedules to the Shared Acquisition and Operating Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the SEC supplementally upon request.
  2.5**   Amended and Restated Shared Acquisition and Operating Agreement by and among ARP Eagle Ford, LLC, Atlas Growth Eagle Ford, LLC and Atlas Eagle Ford Operating Company, LLC, effective as of September 24, 2014 (incorporated by reference to Exhibit 2.4(b) to Atlas Resource Partners, L.P.’s Quarterly Report on Form 10-Q filed November 9, 2015 (File No. 001-35317)). The schedules to the Amended and Restated Shared Acquisition and Operating Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the SEC supplementally upon request.
  2.6**   Addendum #2 to the Amended and Restated Shared Acquisition and Operating Agreement by and among ARP Eagle Ford, LLC, Atlas Growth Eagle Ford, LLC and Atlas Eagle Ford Operating Company, LLC, effective as of July 1, 2015 (incorporated by reference to Exhibit 2.4(c) to Atlas Resource Partners, L.P.’s Quarterly Report on Form 10-Q filed November 9, 2015 (File No. 001-35317)). The schedules to Addendum #2 to the Amended and Restated Shared Acquisition and Operating Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request.
  2.7**   Addendum #3 to the Amended and Restated Shared Acquisition and Operating Agreement by and among ARP Eagle Ford, LLC, Atlas Growth Eagle Ford, LLC and Atlas Eagle Ford Operating Company, LLC, effective as of September 30, 2015 (incorporated by reference to Exhibit 2.4(d) to Atlas Resource Partners, L.P.’s Quarterly Report on Form 10-Q filed November 9, 2015 (File No. 001-35317)). The schedules to Addendum #3 to the Amended and Restated Shared Acquisition and Operating Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request.

 

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Exhibit
Number

 

Description

  3.1*   Certificate of Limited Partnership of Atlas Growth Partners, L.P.
  3.2*   Partnership Agreement of Atlas Growth Partners, L.P., dated February 11, 2013
  3.3*   Form of First Amended and Restated Limited Partnership Agreement of Atlas Growth Partners, L.P. (included as Exhibit A to the Prospectus included as part of this Registration Statement)
  3.4*   Certificate of Formation of Atlas Growth Partners GP, LLC
  3.5*   Amended and Restated Limited Liability Company Agreement of Atlas Growth Partners GP, LLC, dated as of November 26, 2013
  5.1***   Form of Opinion of Paul Hastings LLP as to legality of securities being issued
  8.1***   Form of Opinion of Paul Hastings LLP as to tax matters
10.1***   Form of Subscription Escrow Agreement
10.2*   Credit Agreement among Atlas Growth Partners, L.P., as borrower, the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent, dated as of May 1, 2015.
10.3*   Atlas Growth Partners, L.P. Long Term Incentive Plan (included as Exhibit F to the Prospectus included as part of this Registration Statement)
10.4*   Form of Atlas Growth Partners, L.P. Form of Distribution Reinvestment Plan (included as Exhibit E to the Prospectus included as part of this Registration Statement)
21.1*   List of Subsidiaries of Atlas Growth Partners, L.P.
23.1***   Consent of Paul Hastings LLP (included in Exhibits 5.1 and 8.1)
23.2****   Consent of Grant Thornton LLP
24.1*   Powers of Attorney (included on signature page to this registration statement)
24.2*   Power of Attorney for Matthew Finkbeiner

 

* Filed previously
** Incorporated by reference
*** To be filed by amendment
**** Filed herewith

Item 17. Undertakings.

 

(a) The undersigned registrant hereby undertakes:

 

  (1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

 

  (i) To include any prospectus required by section 10(a)(3) of the Securities Act of 1933;

 

  (ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement; and

 

  (iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

 

  (2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

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  (3) That all post-effective amendments will comply with the applicable forms, rules and regulations of the Securities and Exchange Commission in effect at the time such post-effective amendments are filed.

 

  (4) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

 

  (5) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, if the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

 

  (6) That, for the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities: The undersigned registrant undertakes that in an offering of securities of the undersigned registrant pursuant to this Registration Statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

 

  (i) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

 

  (ii) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

 

  (iii) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

 

  (iv) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

 

(b) The undersigned registrant hereby undertakes to provide to the underwriter at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriter to permit prompt delivery to each purchaser.

 

(c) Insofar as indemnification for liability arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Amendment No. 2 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Philadelphia, Commonwealth of Pennsylvania on January 8, 2016.

 

ATLAS GROWTH PARTNERS, L.P.
By: Atlas Growth Partners GP, LLC, its general partner
By:   /s/ Edward E. Cohen
  Name:  Edward E. Cohen
  Title:    Chairman of the Board, Chief Executive              Officer

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant’s Amendment No. 2 to the Registration Statement has been signed by the following persons in the capacities and on the dates indicated.

 

Signature

  

Title with our general partner

 

Date

/s/ Edward E. Cohen

Edward E. Cohen

   Chairman of the Board, Chief Executive Officer (principal Executive Officer)   January 8, 2016

*

Jonathan Z. Cohen

   Executive Vice Chairman of the Board   January 8, 2016

*

Jeffrey M. Slotterback

   Chief Financial Officer (principal Financial Officer)   January 8, 2016

*

Matthew Finkbeiner

   Chief Accounting Officer (principal Accounting Officer)  

January 8, 2016

*

Daniel C. Herz

   President and Director   January 8, 2016

*

Freddie M. Kotek

   Executive Vice President and Director  

January 8, 2016

*

William R. Bagnell

   Director  

January 8, 2016

*

William G. Karis

  

Director

  January 8, 2016

*

Joel R. Mesznik

  

Director

  January 8, 2016

 

*By:   /s/ Edward E. Cohen
  Edward E. Cohen
  Attorney-in-fact for persons listed

 

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