Attached files

file filename
EX-3.6 - CERTIFICATE OF AMENDMENT TO CERTIFICATE OF FORMATION - Quicksilver Production Partners LPd264400dex36.htm
EX-10.8 - AMENDED AND RESTATED GAS GATHERING AGREEMENT, EFFECTIVE SEPTEMBER 1, 2008 - Quicksilver Production Partners LPd264400dex108.htm
EX-10.9 - FIRST AMENDMENT TO AMENDED AND RESTATED GAS GATHERING AGREEMENT - Quicksilver Production Partners LPd264400dex109.htm
EX-23.2 - CONSENT OF SCHLUMBERGER DATA & CONSULTING SERVICES - Quicksilver Production Partners LPd264400dex232.htm
EX-21.1 - LIST OF SUBSIDIARIES OF QUICKSILVER PRODUCTION PARTNERS LP - Quicksilver Production Partners LPd264400dex211.htm
EX-23.1 - CONSENT OF DELOITTE & TOUCHE LLP - Quicksilver Production Partners LPd264400dex231.htm
EX-10.10 - SECOND AMENDMENT TO GAS GATHERING AGREEMENT - Quicksilver Production Partners LPd264400dex1010.htm
Table of Contents
Index to Financial Statements

As filed with the Securities and Exchange Commission on June 22, 2012

Registration No. 333-179454

 

 

 

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

 

 

Quicksilver Production Partners LP

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware   1311   38-3859129
(State or Other Jurisdiction of
Incorporation or Organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification Number)

801 Cherry Street

Suite 3700, Unit 19

Fort Worth, Texas 76102

(817) 665-5000

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)

 

 

Glenn Darden

President and Chief Executive Officer

Quicksilver Production Partners GP LLC

801 Cherry Street

Suite 3700, Unit 19

Fort Worth, Texas 76102

(817) 665-5000

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

 

 

Copies to:

 

Richard D. Truesdell, Jr., Esq.

Davis Polk & Wardwell LLP

450 Lexington Avenue

New York, NY 10017

(212) 450-4000

 

Timothy C. Langenkamp, Esq.
Andrews Kurth LLP

600 Travis, Suite 4200

Houston, Texas 77002

(713) 220-4200

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this Registration Statement.

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.  ¨

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. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

  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 Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


Table of Contents
Index to Financial Statements

The information in this prospectus 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 prospectus is not an offer to sell these securities and it is not soliciting offers to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

Subject to completion, dated June 22, 2012

Preliminary Prospectus

LOGO

        Common Units

Common Units Representing Limited Partner Interests

This is the initial public offering of common units representing limited partner interests of Quicksilver Production Partners LP. Quicksilver Production Partners is selling         common units. The estimated initial public offering price is between $         and $         per common unit.

We have applied to list our common units on the New York Stock Exchange under the symbol “QPP.”

We are an “emerging growth company” as defined in Section 2(a)(19) of the Securities Act of 1933, as amended, and will be subject to reduced public company reporting requirements. Investing in our common units involves risks. Please read “Risk factors” beginning on page 24.

These risks include the following:

 

 

We may not have sufficient cash to pay the minimum quarterly distribution on our units following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates.

 

 

Our and Quicksilver’s proved reserve and production estimates depend on many assumptions that may turn out to be inaccurate and any material inaccuracies in these estimates or underlying assumptions may materially affect the quantities and present value of our and Quicksilver’s proved reserves and our forecasted production.

 

 

Commodity prices fluctuate widely, and low prices could adversely affect our ability to borrow under and comply with our new revolving credit facility and have a material adverse impact on our business, financial condition and results of operations, which could cause us to reduce our distributions or cease paying distributions altogether.

 

 

Our general partner and its affiliates will own a controlling interest in us and will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of our unitholders.

 

 

Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors. Quicksilver, as the owner of our general partner, has the power to appoint and remove our general partner’s directors.

 

 

Even if our unitholders are dissatisfied, they cannot remove our general partner without Quicksilver’s consent.

 

 

Neither we nor our general partner have any employees and we will rely solely on the employees of Quicksilver to manage our business. The employees of Quicksilver who will manage our business will also perform substantially similar services for Quicksilver, and thus will not be solely focused on our business.

 

 

Because a unitholder will be treated as a partner, a unitholder will be required to pay taxes on its share of our income even if it does not receive any cash distributions from us, and the tax liability the unitholder incurs on the disposition of our common units could be more or less than expected.

 

 

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, our cash available for distribution to our unitholders would be substantially reduced.

 

      Per common unit      Total  

Initial public offering price

   $                                $                

Underwriting discounts and commissions(1)

   $         $     

Proceeds to Quicksilver Production Partners, before expenses

   $         $     

 

(1)   Excludes a structuring fee equal to    % of the gross proceeds of this offering payable to J.P. Morgan Securities LLC.

We have granted the underwriters an option for a period of 30 days from the date of this prospectus to purchase up to an additional        common units.

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.

 

J.P. Morgan    Credit Suisse

 

BofA Merrill Lynch   Citigroup   Deutsche Bank Securities
RBC Capital Markets     Wells Fargo Securities

 

Goldman, Sachs & Co.   UBS Investment Bank   Baird

 

BB&T Capital Markets     Comerica Securities

                    , 2012


Table of Contents
Index to Financial Statements

LOGO


Table of Contents
Index to Financial Statements

Table of contents

 

     Page  

Summary

     1   

Overview

     1   

Our business strategies

     3   

Our competitive strengths

     3   

Our relationship with Quicksilver

     4   

Risk factors

     5   

Our partnership structure and formation transactions

     7   

Our ownership and organizational structure

     9   

Management and operation of the partnership

     10   

Summary of fiduciary and other duties

     11   

Emerging growth company status

     12   

Principal executive offices and internet address

     13   

The offering

     14   

Summary historical financial data

     19   

Summary reserve and operating data

     22   

Risk factors

     24   

Risks related to our business

     24   

Risks inherent in an investment in us

     40   

Tax risks to unitholders

     53   

Use of proceeds

     59   

Capitalization

     60   

Dilution

     61   

Our cash distribution policy and restrictions on distributions

     62   

General

     62   

Our minimum quarterly distribution

     65   

Unaudited pro forma available cash for the year ended December 31, 2011

     67   

Estimated Adjusted EBITDA for the twelve months and four-quarter period ending June 30, 2013

     70   

Assumptions and considerations

     73   

Sensitivity analysis

     80   

Provisions of our partnership agreement relating to cash distributions

     85   

Distributions of available cash

     85   

Operating surplus and capital surplus

     86   

Capital expenditures

     88   

Subordination period

     90   

Distributions of available cash from operating surplus during the subordination period

     92   

Distributions of available cash from operating surplus after the subordination period

     93   

 

i


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Index to Financial Statements
     Page  

General partner interest and incentive distribution rights

     93   

Percentage allocations of available cash from operating surplus

     94   

General partner’s right to reset incentive distribution levels

     94   

Distributions from capital surplus

     97   

Adjustment to the minimum quarterly distribution and target distribution levels

     98   

Distributions of cash upon dissolution

     99   

Adjustments to capital accounts

     101   

Selected historical financial data

     102   

Management’s discussion and analysis of financial condition and results of operations

     104   

Overview

     104   

Quantitative and qualitative disclosure about market risk

     108   

Results of operations—three months ended March 31, 2012 and 2011

     111   

Results of operations—years ended December 31, 2011, 2010 and 2009

     113   

Liquidity and capital resources

     117   

Our and our predecessor’s critical accounting policies

     123   

Internal controls and procedures

     127   

Recently issued accounting standards

     128   

Business and properties

     130   

Overview

     130   

Our business strategies

     131   

Our competitive strengths

     132   

Our relationship with Quicksilver

     134   

Partnership Properties

     135   

Environmental matters

     143   

Government regulation

     145   

Employees

     145   

Offices

     145   

Legal proceedings

     145   

Management

     146   

Management of Quicksilver Production Partners LP

     146   

Directors and executive officers

     148   

Biographical information

     148   

Reimbursement of expenses of our general partner

     151   

Executive compensation

     151   

2012 Equity Plan

     152   

Director compensation

     155   

Relation of compensation policies and practices to risk management

     156   

Security ownership of certain beneficial owners and management

     157   

Quicksilver Production Partners LP

     157   

Quicksilver Resources Inc.

     157   

 

ii


Table of Contents
Index to Financial Statements
     Page  

Certain relationships and related party transactions

     159   

Distributions and payments to our general partner and its affiliates

     159   

Second Amended and Restated Limited Liability Company Agreement of Quicksilver Production Partners GP

     161   

Agreements governing the transactions

     161   

Review, approval or ratification of transactions with related persons

     163   

Fiduciary and other duties

     166   

Limitations on duties and liabilities

     166   

Conflicts of interest

     168   

Fiduciary duties

     176   

Description of the common units

     179   

The units

     179   

Transfer agent and registrar

     179   

Transfer of common units

     179   

The partnership agreement

     181   

Organization and duration

     181   

Purpose

     181   

Cash distributions

     181   

Capital contributions

     182   

Limited voting rights

     182   

Applicable law; forum, venue and jurisdiction

     183   

Limited liability

     184   

Issuance of additional partnership interests

     185   

Amendment of the partnership agreement

     186   

Merger, consolidation, conversion, sale or other disposition of assets

     188   

Termination and dissolution

     189   

Dissolution and distribution of proceeds

     189   

Withdrawal or removal of our general partner

     190   

Transfer of general partner units

     191   

Transfer of incentive distribution rights, common or subordinated units by our general partner

     192   

Transfer of ownership interests in our general partner

     192   

Change of management provisions

     192   

Limited call right

     192   

Meetings; voting

     193   

Status as limited partner

     193   

Non-citizen and non-taxpaying unitholders; redemption

     194   

Indemnification

     194   

Reimbursement of expenses

     195   

Books and reports

     195   

Right to inspect our books and records

     196   

Registration rights

     196   

 

iii


Table of Contents
Index to Financial Statements
     Page  

Units eligible for future sale

     197   

Tax considerations

     199   

Partnership status

     200   

Limited partner status

     201   

Tax consequences of unit ownership

     202   

Tax treatment of our operations

     209   

Disposition of common units

     214   

Uniformity of units

     217   

Tax-exempt organizations and other investors

     217   

Administrative matters

     218   

State, local and other tax considerations

     219   

Investment in Quicksilver Production Partners LP by employee benefit plans

     221   

Underwriting

     223   

Validity of the common units

     231   

Experts

     231   

Where you can find more information

     231   

Forward-looking statements

     233   

Quicksilver Production Partners LP Predecessor Index to financial statements

     F-1   

Appendix A Form of First Amended and Restated Agreement of Limited Partnership of Quicksilver Production Partners LP

     A-1   

Appendix B Glossary of terms

     B-1   

Appendix C Summary reserve reports

     C-1   

 

iv


Table of Contents
Index to Financial Statements

We have not authorized anyone to provide any information other than that contained in this prospectus or in any free writing prospectus prepared by or on behalf of us or to which we have referred you. We take no responsibility for, and can provide no assurance as to the reliability of, any other information which others may give you. This prospectus may only be used where it is legal to sell these securities. The information in this prospectus may only be accurate on the date of this prospectus regardless of the time of delivery of this prospectus or any sale of our common units.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk factors” and “Forward-looking statements.”

Industry and market data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Although we believe that these third-party sources are reliable and that the third-party information used in this prospectus is accurate and complete, we have not independently verified the information nor have we ascertained the economic assumptions underlying such information. Some data is also based on our good faith estimates based on our knowledge and experience in the industry in which we operate.

Commonly used defined terms

As used in this prospectus, unless we indicate otherwise, the following terms have the following meanings:

 

 

“Barnett Shale” refers to a marine basinal shale deposit located in the Fort Worth Basin of North Texas;

 

 

“Barnett Shale Counties” refers to Wise, Montague, Cook, Denton, Tarrant, Dallas, Ellis, Parker, Jack, Palo Pinto, Hood, Somervell, Johnson, Hill, Bosque and Erath Counties in North Texas;

 

 

“formation transactions” refers to Quicksilver’s contribution of the Partnership Properties to Quicksilver Production Partners Operating Ltd., Quicksilver’s subsequent contribution of Quicksilver Production Partners Operating Ltd. to QPP Holdings LLC, QPP Holdings LLC’s subsequent contribution of Quicksilver Production Partners Operating Ltd. to us at the closing of this offering and Quicksilver’s novation of certain commodity derivatives to us at the closing of this offering, including each of the transactions related thereto, which are described on page 7;

 

 

“our general partner” or “Quicksilver Production Partners GP” refers to Quicksilver Production Partners GP LLC, our general partner;

 

 

“our management,” “our employees,” or similar terms refer to the management or other personnel of Quicksilver provided to our general partner or us, as applicable, by Quicksilver under an omnibus agreement among us, our general partner and Quicksilver;

 

 

“our predecessor” refers to the Partnership Properties and certain commodity derivatives owned by Quicksilver prior to the closing of this offering, which assets are our predecessor for accounting purposes;

 

v


Table of Contents
Index to Financial Statements
 

“Partnership Properties” or “our properties” refers to the properties, producing wells and related oil and gas interests owned by Quicksilver prior to the closing of this offering, which will be contributed to us as part of the formation transactions, which properties are our predecessor for accounting purposes;

 

 

“proved reserves” refers to the estimated quantities of natural gas, NGLs and crude oil that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic conditions and operating conditions. This definition of proved reserves has been abbreviated from the applicable definition contained in Appendix B of this prospectus;

 

 

“Quicksilver” refers collectively to Quicksilver Resources Inc. and its consolidated subsidiaries other than our general partner and us and our subsidiaries; and

 

 

“Quicksilver Production Partners LP,” “the partnership,” “we,” “our,” “us” or like terms, when used in a historical context, refer to our predecessor, which will be contributed to us in connection with this offering. When used in the present tense or prospectively, those terms refer collectively to Quicksilver Production Partners LP, a Delaware limited partnership and its subsidiaries.

 

vi


Table of Contents
Index to Financial Statements

Summary

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including “Risk factors” beginning on page 24 and the historical carve out financial statements and the notes to those financial statements. The information presented in this prospectus assumes (i) an initial public offering price of $        per common unit (the midpoint of the price range set forth on the cover of this prospectus) and (ii) that the underwriters do not exercise their option to purchase additional common units, unless otherwise indicated. We include a glossary of some of the oil and gas industry terms used in this prospectus in Appendix B.

The proved reserve information for the Partnership Properties as of December 31, 2011, 2010, 2009 and 2008 contained in this prospectus is based on reserve reports relating to our assets in the Barnett Shale prepared by the independent petroleum engineers of Schlumberger Data & Consulting Services, or Schlumberger, summaries of which are included in this prospectus as Appendix C. We refer to these reports as our “reserve report.” The proved reserve information for Quicksilver’s U.S. oil and gas properties as of December 31, 2011 contained in this prospectus is based on a reserve report relating to those properties prepared by Schlumberger.

Quicksilver Production Partners LP

Overview

We are a Delaware limited partnership formed in November 2011 by Quicksilver to own and acquire oil and gas properties in North America that fit our acquisition criteria, which are mature onshore properties with long-lived reserves, predictable production profiles and modest capital requirements. Our primary business objective is to generate stable cash flows, allowing us to make quarterly cash distributions to our unitholders and, over time, to increase those quarterly cash distributions. We believe our properties are well-suited for our partnership because they consist of mature onshore oil and gas properties that fit our acquisition criteria. As of December 31, 2011, our total proved reserves were 368.3 Bcfe, of which approximately 85% were classified as proved developed reserves. All of our oil and gas reserves are in the Barnett Shale. Excluding the effect of commodity derivatives, 29.2%, 65.7% and 5.1% of our revenue for the three months ended March 31, 2012 was from natural gas, NGLs and oil, respectively. Based on our average net production for the three months ended March 31, 2012 of 59.6 Mmcfed, our total proved reserves as of December 31, 2011 had an annualized reserve-to-production ratio of 16.9 years. We operate all of the properties in which we have interests, and we own an average working interest of 98.8% in the wells and properties included in the Partnership Properties, based on our proved reserves as of December 31, 2011. We intend to maintain a portfolio of commodity derivatives covering approximately 60% to 85% of our estimated production over a three-to-five year period at any given point in time, although we may from time to time hedge more or less than the approximate range or change the range. At the closing of this offering, the derivatives covering our natural gas production will set a NYMEX price of $6.00 per Mmbtu through 2015 and the derivatives covering our NGL production will set a weighted average price of $46.16 per Bbl for 2012. The natural gas derivatives represent an average of approximately 96% of our anticipated gas production through 2015. For additional information about our commodity derivatives, please read “Summary—Our partnership structure and formation transactions” and “Management’s discussion and analysis of financial condition and results of operations—Overview—Commodity derivatives.”

 

 

1


Table of Contents
Index to Financial Statements

The following table presents summary data for the Partnership Properties as of December 31, 2011.

 

Property type    Proved
reserves
(Bcfe)
     % Natural
gas
     % NGL      % Oil      Number of
locations(1)
     Average
working
interest
     Net
revenue
interest
 

 

 

Proved developed

     316.7         53.5%         46.3%         0.2%         258         98.6%         78.7%   

Proved undeveloped

     51.6         51.0%         48.4%         0.6%         32         100.0%         79.8%   
  

 

 

             

 

 

       

Total Proved

     368.3         53.2%         46.6%         0.2%         290         98.8%         78.9%   

 

 

 

(1)  

In addition to the proved locations, we also have identified 12 unproved locations to drill on acreage that we have under lease within the Partnership Properties.

Quicksilver is a Fort Worth-based independent oil and gas company engaged primarily in the acquisition, exploration, development and production of onshore oil and gas in North America. Quicksilver was organized as a Delaware corporation in 1997 and has been a public company since 1999. We believe our business relationship with Quicksilver, which owns our general partner and, indirectly, will own approximately         % of our outstanding common units and all of our subordinated units, general partner units and incentive distribution rights, will enhance our ability to maintain or grow our production and expand our proved reserve base over time. Following the contribution of the Partnership Properties to us, Quicksilver will retain over 2.1 Tcfe of its proved reserves in the United States as of December 31, 2011, almost all of which is in the Barnett Shale, that may be suitable for us to acquire in the future.

Quicksilver has been producing from unconventional shale plays since 1999 and established its initial acreage position in the Barnett Shale in 2003. Since then, Quicksilver has grown its leasehold to approximately 140,000 net acres in the Fort Worth Basin as of December 31, 2011. Quicksilver had 1,008 gross (823.7 net) producing wells in the Fort Worth Basin and had produced over 440 Bcfe as of December 31, 2011. Since 2003, Quicksilver has grown its Barnett Shale average net production from no production to over 335 Mmcfed for 2011.

At the closing of this offering, Quicksilver will contribute to us the Partnership Properties and novate to us certain commodity derivatives. Please read “Summary—Our partnership structure and formation transactions” for more information.

 

 

2


Table of Contents
Index to Financial Statements

Our business strategies

Our primary business objective is to generate stable cash flows through cost-effective growth in production and proved reserves and enhanced operating results, allowing us to make quarterly cash distributions to our unitholders after servicing our debt and, over time, to increase those quarterly cash distributions. We currently focus our strategy in the Barnett Shale. To achieve our objective, we intend to execute the following business strategies:

 

 

Maintain and grow a stable production profile through low-risk development;

 

 

Acquire assets from Quicksilver through negotiated transactions;

 

 

Acquire assets from third parties either independently or jointly with Quicksilver;

 

 

Leverage Quicksilver’s size and technical understanding of the Barnett Shale to manage our costs and achieve optimum recovery;

 

 

Reduce exposure to commodity price risk and stabilize cash flows through a disciplined hedging policy; and

 

 

Maintain a prudent capital structure to ensure financial flexibility for acquisitions and development.

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

Our competitive strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our objective of generating and growing cash available for distribution:

 

 

Our relationship with Quicksilver:

 

   

Quicksilver will have a significant retained interest in the Barnett Shale, which we anticipate will give us access to a multi-year inventory of drop-down acquisitions from Quicksilver comprised of existing producing properties and drilling opportunities in the Barnett Shale, though there is no assurance we would be able to complete any such acquisitions;

 

   

Quicksilver has extensive technical experience and familiarity with developing and operating Barnett Shale properties and other unconventional resources;

 

   

Quicksilver increases our competitiveness for third-party acquisitions;

 

   

The executive management team of our general partner includes some of the most senior officers of Quicksilver, each of whom has extensive industry experience, including experience managing a master limited partnership;

 

 

Our asset base is characterized by low-declining, predictable and long-lived production with a significant NGL component; and

 

 

Our competitive cost of capital and financial flexibility.

For a more detailed discussion of our competitive strengths, please read “Business and properties—Our competitive strengths.”

 

 

3


Table of Contents
Index to Financial Statements

Our relationship with Quicksilver

We view our relationship with Quicksilver as a significant competitive strength. We believe this relationship will provide us with potential acquisition opportunities from a portfolio of oil and gas properties that meet our acquisition criteria, as well as access to personnel with extensive technical expertise and industry relationships.

Following the completion of this offering, Quicksilver will indirectly be our largest unitholder, holding              common units (approximately         % of all outstanding common units) and all of our subordinated units. Through its ownership of our general partner, Quicksilver will also hold all of the incentive distribution rights.

We believe that all of Quicksilver’s reserves in the United States are (or after additional capital is invested will become) suitable for us, based on our acquisition criteria. We also believe the largely contiguous and overlapping nature of Quicksilver’s and our Partnership Properties acreage will provide key operational, logistical and technical benefits, as well as cost savings, derived from our aligned interests.

The following table summarizes information about Quicksilver’s U.S. proved reserves as of the year ended December 31, 2011, excluding the Partnership Properties.

 

     Estimated proved reserves      Average Net
Production
   

Average

Reserve-to-
production
ratio(1)

    Producing
wells
 
    Bcfe     % Natural
gas
    % Proved
developed
    % Total
proved
     Mmcfed     % Total
production
      Gross     Net  

 

 

Barnett Shale

    2,053.5        78.7%        62.3%        99.2%         244.4        98.5%        20.9        758        577.4   

Other U.S.

    16.7        7.7%        100.0%        0.8%         3.8        1.5%        10.9        281        275.9   
 

 

 

       

 

 

     

 

 

 

Total U.S.

    2,070.2        78.1%        62.6%        100.0%         248.2        100.0%        20.7        1,039        853.3   

 

 

 

(1)   The annualized average reserve-to-production ratio is calculated by dividing proved reserves as of December 31, 2011 by the average net production for the three months ended March 31, 2012.

As a result of its significant ownership interests in us and our general partner, we believe Quicksilver will be motivated to support the successful execution of our primary business objective and will provide us with opportunities to pursue acquisitions that we believe will be accretive to our unitholders. Quicksilver has informed us that it views our relationship as part of its growth strategy, and we believe that Quicksilver has an incentive to sell additional assets to us and to pursue acquisitions jointly with us in the future.

Under the terms of our right of first offer in our omnibus agreement, Quicksilver will commit to offer us the first opportunity to acquire any properties in the Barnett Shale Counties that Quicksilver or any of its controlled subsidiaries may offer for sale. It is difficult to predict whether Quicksilver will seek to sell any of such properties, and, if so, which ones.

Under our omnibus agreement, Quicksilver will also provide general, administrative and operational services to us and our general partner. Under this agreement, we will utilize Quicksilver’s management and staff of engineers, geologists and administrative personnel.

 

 

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Risk factors

An investment in our common units involves risks. Below is a summary of certain key risk factors that you should consider in evaluating an investment in our common units. This list is not exhaustive. Please read the full discussion of these risks and other risks described under “Risk factors” beginning on page 24.

Risks related to our business

 

 

We may not have sufficient cash to pay the minimum quarterly distribution on our units following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates.

 

 

Our and Quicksilver’s proved reserve and production estimates depend on many assumptions that may turn out to be inaccurate and any material inaccuracies in these estimates or underlying assumptions may materially affect the quantities and present value of our and Quicksilver’s proved reserves and our forecasted production.

 

 

The assumptions underlying the forecast of cash available for distribution that we include in “Our cash distribution policy and restrictions on distributions” may prove inaccurate and are subject to significant risks and uncertainties, which could cause actual results to differ materially from our forecasted results.

 

 

Drilling locations that we decide to drill may not meet our pre-drilling expectations, may not yield oil or natural gas in commercially viable quantities and are susceptible to uncertainties that could materially alter the occurrence, timing or success of drilling.

 

 

Commodity prices fluctuate widely, and low prices could adversely affect our ability to borrow under and comply with our new revolving credit facility and have a material adverse impact on our business, financial condition and results of operations, which could cause us to reduce our distributions or cease paying distributions altogether.

Risks inherent in an investment in us

 

 

Our general partner and its affiliates will own a controlling interest in us and will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of our unitholders.

 

 

Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors. Quicksilver, as the owner of our general partner, has the power to appoint and remove our general partner’s directors.

 

 

Even if our unitholders are dissatisfied, they cannot remove our general partner without Quicksilver’s consent.

 

 

Certain of the directors and all of the officers who have responsibility for our management have significant duties with, and will spend significant time serving, entities that compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

 

 

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Neither we nor our general partner have any employees and we will rely solely on the employees of Quicksilver to manage our business. The employees of Quicksilver who will manage our business will also perform substantially similar services for Quicksilver, and thus will not be solely focused on our business.

 

 

We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval, which would dilute unitholders’ ownership interests.

 

 

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distributions and target distribution levels related to our incentive distribution rights without the approval of the conflicts committee or our unitholders. This election would dilute unitholders’ ownership interest in us.

 

 

Control of our general partner and its incentive distribution rights may be transferred to a third party without unitholder consent or approval from our general partner’s conflicts committee.

Tax risks to unitholders

 

 

Because a unitholder will be treated as a partner, a unitholder will be required to pay taxes on its share of our income even if it does not receive any cash distributions from us, and the tax liability the unitholder incurs on the disposition of our common units could be more or less than expected.

 

 

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, our cash available for distribution to our unitholders would be substantially reduced.

 

 

The IRS may challenge our treatment of each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased, which could adversely affect the value of our common units.

 

 

Because of the special and potentially adverse tax rules that apply to tax-exempt entities and non-U.S. persons that own our units, our units may not be an appropriate investment for these types of investors.

 

 

A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered to have disposed of those common units. If so, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

 

 

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Our partnership structure and formation transactions

We are a Delaware limited partnership formed by Quicksilver to acquire, own and operate oil and gas properties. In connection with this offering, the following transactions, which we refer to as the formation transactions, will occur:

Prior to the closing of this offering:

 

 

Quicksilver will have contributed the Partnership Properties to Quicksilver Production Partners Operating Ltd., a Cayman Islands exempted company and a wholly-owned subsidiary of Quicksilver, and Quicksilver will effect the contribution of 100% of the equity interests in Quicksilver Production Partners Operating Ltd. to QPP Holdings LLC.

At the closing of this offering:

 

 

Quicksilver will cause QPP Holdings LLC to contribute to us 100% of the equity interests in Quicksilver Production Partners Operating Ltd. and novate to us certain commodity derivatives. The derivatives we will receive will cover 30 Mmcfd of natural gas production for 2012, 2013, 2014 and 2015 and 3 Mbbld of NGL production for 2012. The derivatives covering our natural gas production will set a NYMEX price of $6.00 per Mmbtu through 2015, and the derivatives covering our NGL production will set a weighted average price of $46.16 per Bbl for 2012. Collectively, we refer to the contribution by Quicksilver to us of the equity interests in Quicksilver Production Partners Operating Ltd. and the novation of the derivative contracts as the “Quicksilver Contributions.” In exchange for the Quicksilver Contributions, we will issue to QPP Holdings LLC             common units and             subordinated units, representing an aggregate    % limited partner interest in us, together with a right to receive $             million in cash;

 

 

We will issue to our general partner, in consideration for $             million in cash,             general partner units, representing a 0.1% general partner interest in us, and, in consideration for the services our general partner will provide to us after the closing of this offering, all of the incentive distribution rights, which will entitle our general partner to increasing percentages of the cash we distribute in excess of $             per unit per quarter;

 

 

We expect to receive net proceeds of approximately $             million from the issuance and sale of            common units to the public (based on the midpoint of the price range set forth on the cover page of this prospectus), representing a     % limited partner interest in us, and we will use the net proceeds as described in “Use of proceeds”;

 

 

We expect to borrow approximately $150 million under a new $             million revolving credit facility (based upon the midpoint of the price range set forth on the cover of this prospectus), and we will use the proceeds as described in “Use of proceeds” (if the net proceeds from this offering increase or decrease, then our borrowing under our new revolving credit facility would correspondingly decrease or increase, respectively); and

 

 

We and our general partner will enter into an omnibus agreement with Quicksilver, pursuant to which, among other things, Quicksilver will provide us and our general partner with general, administrative and operational services.

 

 

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If the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from Quicksilver a number of common units equal to the number of common units issued upon such exercise, at a price per common unit equal to the proceeds per common unit before offering costs but after deducting underwriting discounts and commissions. If the underwriters exercise in full their option to purchase additional common units, the public unitholders will own              common units, representing an aggregate     % limited partner interest in us; our general partner will continue to own the same number of general partner units, representing a 0.1% general partner interest in us; and Quicksilver’s ownership interest will decrease to             common units and             subordinated units, representing an aggregate     % limited partner interest in us.

We expect to convert Quicksilver Production Partners Operating Ltd. into a Delaware limited liability company after the completion of this offering.

 

 

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Our ownership and organizational structure

The table and diagram below illustrate our ownership and organizational structure based on total units outstanding after giving effect to this offering and the related formation transactions and assuming that the underwriters do not exercise their option to purchase additional common units.

 

      Units    Ownership
interest
 

 

 

Common units held by the public

        %   

Common units held by Quicksilver

        %   

Subordinated units held by Quicksilver

        %   

General partner units

        0.1%   
  

 

 

Total

        100.0%   

 

 

 

LOGO

 

 

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Management and operation of the partnership

We are managed and operated by Quicksilver Production Partners GP, our general partner. The board of directors of our general partner has seven directors, including three independent directors. Quicksilver indirectly owns all of the membership interests in and controls our general partner and has the sole right to appoint its entire board of directors. Unlike stockholders in a publicly traded corporation, our unitholders will not be entitled to elect our general partner or the board of directors of our general partner. All of the executive officers and certain of the directors of our general partner currently serve as executive officers and directors of Quicksilver. For more information about the directors and officers of our general partner, please read “Management—Directors and executive officers.”

Neither we nor any of our subsidiaries will have any employees. Our general partner has the sole responsibility for providing the personnel necessary to conduct our operations, whether by hiring employees or by obtaining the services of personnel employed by Quicksilver or others. At the closing of this offering, we and our general partner will enter into an omnibus agreement with Quicksilver pursuant to which, among other things, Quicksilver will provide general, administrative and operational services for us and our general partner. Quicksilver will not be liable to us for its performance of, or failure to perform, services under our omnibus agreement unless there has been a final judicial decision determining that Quicksilver acted in bad faith or engaged in fraud, gross negligence or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful.

We will reimburse our general partner for all expenses it incurs or payments it makes on our behalf, including expenses incurred and payments made under our omnibus agreement, as well as other expenses or payments allocable to us and our subsidiaries as determined by the general partner. We currently expect our general partner to incur general and administrative expenses (including those to be allocated to us by Quicksilver) of approximately $6.2 million for the twelve months ending June 30, 2013. Please read “Certain relationships and related party transactions—Agreements governing the transactions—Omnibus agreement.”

As is common with publicly traded partnerships and in order to maintain operational flexibility, we will conduct our operations through subsidiaries. At the completion of this offering, we will initially have one direct subsidiary, Quicksilver Production Partners Operating Ltd., which we expect to convert to a Delaware limited liability company after the completion of this offering.

 

 

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Summary of fiduciary and other duties

Our general partner is entitled to make determinations that affect our ability to generate the cash flows necessary to make cash distributions to our unitholders, including determinations related to:

 

 

purchases and sales of oil and gas properties and other acquisitions and dispositions, including whether to pursue acquisitions that are also suitable for Quicksilver;

 

 

the manner in which our business is operated;

 

 

the level of our borrowings;

 

 

the amount, nature and timing of our capital expenditures; and

 

 

the amount of cash reserves necessary or appropriate to satisfy our general and administrative expenses, other expenses and debt service requirements, and to otherwise provide for the proper conduct of our business.

These determinations will have an effect on the amount of cash distributions we expect to make to the holders of our units, which in turn has an effect on whether our general partner receives incentive cash distributions. For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Risk factors—Risks inherent in an investment in us” and “Fiduciary and other duties.”

Delaware law provides that a Delaware limited partnership may, in its partnership agreement, expand, restrict or eliminate any fiduciary or other duties that might otherwise be applicable (except for the implied contractual covenant of good faith and fair dealing) and limit or eliminate any liability for breach of contract or breach of fiduciary or other duties (except for liability for a bad faith violation of the implied contractual covenant of good faith and fair dealing).

Our partnership agreement restricts, and in many instances eliminates, the fiduciary and other duties that our general partner, its board of directors (including any committee thereof), its affiliates and the directors and other persons who control our general partner or any of its affiliates might otherwise owe to us and our unitholders. Our partnership agreement also limits, or in many instances eliminates, the liability of our general partner, its board of directors (including any committee thereof), its affiliates and the directors and other persons who control our general partner or any of its affiliates, and the remedies available for a breach of contract or of any fiduciary or other duties that might exist.

Notwithstanding any fiduciary or other duty that might otherwise have been applicable under Delaware law, in most instances our general partner (and its board of directors, any committee of the board of directors, any of its directors and any other persons who control our general partner) only has a duty to act in good faith (which our partnership agreement defines, without reference to a reasonableness standard, as the actual belief that it is acting in, or not opposed to, our best interest). In some instances, our general partner (and its board of directors, any committee of the board of directors, any of its directors and any other persons who control our general partner), and in all instances Quicksilver (which is used in this prospectus to mean Quicksilver and its consolidated subsidiaries, except for our general partner and us) and its directors, officers, employees and other agents (in their capacities as such) have no fiduciary or

 

 

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other duties to us or our unitholders and can consider whatever interests or factors they desire, including their own interests, in determining whether and how to act, notwithstanding any fiduciary or other duty that any such person or entity might otherwise have had under Delaware law.

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Quicksilver) on the one hand, and us and our limited partners, on the other hand. For example, the interests of Quicksilver may, in certain circumstances, be different or inconsistent with the interests of the partnership, and there is nothing in the partnership or other agreement that requires Quicksilver to act in our interests or prevents Quicksilver from competing with us. While our general partner has a duty to act in good faith in managing the partnership (which is defined, without reference to a reasonableness standard, to mean the actual belief that it is acting in, or not opposed to, the best interest of the partnership), the directors and officers and other persons who control our general partner may also have independent fiduciary duties to our general partner and its owner, Quicksilver, including fiduciary duties which require them to manage our general partner in the best interest of its owner, Quicksilver. Certain of the directors and all of the officers of our general partner also serve in similar capacities with Quicksilver and may have fiduciary duties to Quicksilver and its stockholders. In addition, these directors and officers will be compensated by Quicksilver and may have interests and other economic incentives in Quicksilver, which may lead to additional conflicts of interest.

By purchasing a common unit, unitholders agree to be bound by the terms of our partnership agreement and, pursuant to the terms of our partnership agreement, are treated as having consented to various actions contemplated in our partnership agreement (including the reduction or elimination of fiduciary and other duties, the reduction or elimination of liability for breaches and the mechanisms for resolving potential conflicts of interests). Please read “Risk factors—Risks inherent in an investment in us” and “Fiduciary and other duties—Fiduciary duties” for a more detailed description of the fiduciary duties that might otherwise have been imposed under Delaware law, the material modifications or elimination of these duties and potential liabilities, including in respect of conflicts of interest, with respect to the general partner and others contained in our partnership agreement and certain legal rights and remedies available to our unitholders.

Emerging growth company status

We are an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act, which we refer to as the JOBS Act, and we are eligible to take advantage of certain exemptions from various reporting requirements that are applicable to public companies that are not emerging growth companies including, but not limited to, exemptions from complying with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002, reduced disclosure obligations regarding executive compensation in our periodic reports and exemptions from the requirements to hold nonbinding, advisory votes on executive compensation, frequency of approval of executive compensation and golden parachute payments made in connection with any unitholder vote to approve a merger or acquisition.

In addition, Section 107 of the JOBS Act also provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities

 

 

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Act for complying with new or revised accounting standards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We are choosing to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

We could remain an emerging growth company for up to five years, or until the earliest of:

 

 

the last day of the first fiscal year in which our annual gross revenues exceed $1 billion;

 

 

the date that we become a “large accelerated filer” as defined in Rule 12b-2 under the Securities Exchange Act of 1934, as amended, which would occur if the market value of our common units that are held by non-affiliates exceeds $700 million as of the last business day of our most recently completed second fiscal quarter; or

 

 

the date on which we have issued more than $1 billion in non-convertible debt during the preceding three-year period.

Please read “Risk factors—Risks inherent in an investment in us—As an ‘emerging growth company’ under the Jumpstart Our Business Startups Act, we are permitted to, and intend to, rely on exemptions from certain disclosure requirements.”

Principal executive offices and internet address

Our principal executive offices are located at 801 Cherry Street, Suite 3700, Unit 19, Fort Worth, Texas 76102, and our registered office in the State of Delaware is at Corporation Trust Center, 1209 Orange Street, in the City of Wilmington, County of New Castle. The name of our registered agent at such address is The Corporation Trust Company. Our telephone number is (817) 665-5000.

Our website address is www.qpplp.com and will be activated in connection with the closing of this offering. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as 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, and does not constitute a part of, this prospectus.

 

 

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The offering

 

Common units offered hereby

             common units (or              common units if the underwriters exercise in full their option to purchase additional common units).

 

Units outstanding after this offering

             common units and              subordinated units, representing     % and     %, respectively, limited partner interests in us. Our general partner will own              general partner units, representing a 0.1% general partner interest in us.

 

Use of proceeds

We intend to use the estimated net proceeds of approximately $             million from this offering (based upon the assumed initial public offering price of $             per common unit (the midpoint of the price range set forth on the cover of this prospectus), after deducting underwriting discounts, a structuring fee and offering costs), together with borrowings of approximately $150 million under our new revolving credit facility (based upon the assumed midpoint of the price range set forth on the cover of this prospectus), as partial consideration (together with our issuance to Quicksilver of              common units and              subordinated units) for the Quicksilver Contributions, and to pay fees and costs associated with such transactions and our new revolving credit facility. Please read “Summary—Our partnership structure and formation transactions” and “Use of proceeds.”

 

Cash distributions

We expect to make a minimum quarterly distribution of $             per unit per quarter on all common, subordinated and general partner units ($             per unit on an annualized basis) to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as “available cash,” and it is defined in our partnership agreement included in this prospectus as Appendix A. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Our cash distribution policy and restrictions on distributions.” For the first quarter that we are publicly traded, we expect to pay our unitholders a prorated distribution covering the period from the completion of this offering through the end of that quarter, based on the actual length of that period.

 

  Assuming our general partner maintains its 0.1% general partner interest in us, our partnership agreement requires us to distribute all of our available cash each quarter in the following manner during the subordination period:

 

  first, 99.9% to the holders of common units and 0.1% to our general partner, until each common unit has received the minimum quarterly distribution of $             plus any arrearages from prior quarters;

 

 

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  second, 99.9% to the holders of subordinated units and 0.1% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $            ; and

 

  third, 99.9% to all common and subordinated unitholders, pro rata, and 0.1% to our general partner, until each common and subordinated unit has received a distribution of $            .

 

  If cash distributions to our unitholders exceed $             per common unit and subordinated unit in any quarter, our unitholders and our general partner will receive distributions according to the following percentage allocations:

 

      Marginal percentage
interest in distributions
 
Total quarterly distribution target amount    Unitholders      General
partner
 

 

 

above $             up to $            

     85.0%         15.0%   

above $            

     75.0%         25.0%   

 

 

 

  The percentage interests shown for our general partner include its 0.1% general partner interest. We refer to the additional increasing distributions to our general partner in excess of its 0.1% general partner interest as “incentive distributions.” Please read “Provisions of our partnership agreement relating to cash distributions.”

 

  Assuming we completed the formation transactions contemplated in this prospectus, including the Quicksilver Contributions, on January 1, 2011, our pro forma cash available for distribution generated during the year ended December 31, 2011 would have been approximately $            million, which would have been sufficient to allow us to pay the full minimum quarterly distribution on our common, subordinated and general partner units during that period.

 

  We have not calculated available cash on a pro forma quarter-by-quarter basis for the year ended December 31, 2011 to determine if we would have generated available cash sufficient to pay the minimum quarterly distribution for each quarter during those periods.

 

  For a calculation of our ability to have made distributions to our unitholders based on our pro forma results of operations for the year ended December 31, 2011, please read “Our cash distribution policy and restrictions on distributions.”

 

  The amount of available cash we need to pay the minimum quarterly distribution for four quarters on the common, subordinated and general partner units to be outstanding immediately after this offering is approximately $             million (or an average of approximately $             million per quarter). Please read “Our cash distribution policy and restrictions on distributions.”

 

 

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  We believe, based on our financial forecast and related assumptions included in “Our cash distribution policy and restrictions on distributions—Estimated Adjusted EBITDA for the twelve months and four-quarter period ending June 30, 2013” and “Our cash distribution policy and restrictions on distributions—Assumptions and considerations,” that we will be able to pay cash distributions at the minimum quarterly distribution of $             per unit on all outstanding common, subordinated and general partner units for each full calendar quarter in the twelve months ending June 30, 2013.

 

  However, we do not have a legal obligation to pay distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement, and there is no guarantee that we will make quarterly cash distributions to our unitholders. Please read “Our cash distribution policy and restrictions on distributions.”

 

Subordinated units

QPP Holdings LLC will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that, in any quarter during the subordination period, the subordinated units are entitled to receive distributions only after the common units have received their minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Accordingly, holders of subordinated units may receive a smaller distribution than holders of common units or no distribution at all. Subordinated units will not accrue arrearages.

 

  The subordination period will begin on the closing date of this offering and extend until the earlier of:

 

   

the date on which we have earned and paid distributions from operating surplus at least equal to the minimum quarterly distribution payable on all outstanding common, subordinated and general partner units (and any other partnership interests that are senior or equal in right of distribution to the subordinated units) with respect to a period of 12 consecutive quarters ending on or after                     , 2015, provided there are no arrearages in the minimum quarterly distribution on our common units; or

 

   

the date on which we have earned and paid distributions from operating surplus at least equal to $             (125% of the minimum quarterly distribution) on each outstanding common, subordinated and general partner unit (and any other partnership interest that is senior or equal in right of distribution to the subordinated units), plus corresponding distributions on incentive distribution rights, for each of the four consecutive quarters ending on or after                     , 2013, provided there are no arrearages in the minimum quarterly distribution on our common units.

 

 

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  The subordination period will also end if our general partner is removed other than for cause, and the units held by our general partner and its affiliates are not voted in favor of such removal.

 

  When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis and all common units thereafter will no longer be entitled to arrearages. Please read “Provisions of our partnership agreement relating to cash distributions—Subordination period.”

 

Issuance of additional units

We can issue an unlimited number of additional units, including units that are senior to the common units in right of distributions, liquidation and voting, on terms and conditions determined by our general partner, without the approval of our unitholders. Please read “Units eligible for future sale” and “The partnership agreement—Issuance of additional partnership interests.”

 

Limited voting rights

Our general partner will manage us and operate our business. Unlike stockholders of a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors. Our general partner may not be removed except by a vote of the holders of at least 66 2/3% of the outstanding common and subordinated units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, Quicksilver will indirectly own an aggregate of approximately     % of our outstanding common and subordinated units (or     % of our outstanding common and subordinated units if the underwriters exercise their option to purchase additional common units in full) and will therefore be able to prevent the removal of our general partner. Please read “The partnership agreement—Limited voting rights.”

 

Limited call right

If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a purchase price not less than the then-current market price of the common units, as calculated pursuant to the terms of our partnership agreement. Upon the consummation of this offering, affiliates of our general partner will own approximately     % of our outstanding common units (or     % of our outstanding common units if the underwriters exercise their option to purchase additional common units in full) and 100% of our subordinated units. Please read “The partnership agreement—Limited call right.”

 

Estimated ratio of taxable income to distributions

We estimate that if our unitholders own the common units purchased in this offering through the record date for distributions for the

 

 

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period ending             , such unitholders will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than     % of the cash distributed to such unitholders with respect to that period. Please read “Tax considerations” for information regarding the bases for this estimate.

 

Tax considerations

For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Tax considerations.”

 

Agreement to be bound by the partnership agreement

By purchasing a common unit, you will be admitted as a unitholder of our partnership and will be deemed to have agreed to be bound by all of the terms of our partnership agreement.

 

Listing and trading symbol

We have applied to list our common units on the NYSE under the symbol “QPP.”

 

 

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Summary historical financial data

We were formed in November 2011 and do not have historical financial operating results. Therefore, in this prospectus, we present the historical carve out financial statements of our predecessor. The following table shows the summary financial data of our predecessor. The summary historical financial data as of December 31, 2011 and 2010 and for the years ended December 31, 2011, 2010 and 2009 are derived from the audited historical carve out financial statements of our predecessor included elsewhere in this prospectus. The summary historical financial data as of December 31, 2009 are derived from the historical carve out financial statements of our predecessor not included in this prospectus. The summary historical financial data as of March 31, 2012 and for the three months ended March 31, 2012 and 2011 are derived from the unaudited historical carve out interim financial statements of our predecessor included elsewhere in this prospectus.

You should read the following table in conjunction with “—Our partnership structure and formation transactions,” “Use of proceeds,” “Management’s discussion and analysis of financial condition and results of operations” and the historical carve out financial statements of our predecessor included elsewhere in this prospectus. Among other things, those historical carve out financial statements include more detailed information regarding the basis of presentation.

The following table presents Adjusted EBITDA, which we use in evaluating the operating risks of our business. This financial measure is not calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain this measure below and reconcile it to net income, its most directly comparable financial measure calculated and presented in accordance with GAAP.

 

     Our predecessor  
    Three months
ended March 31,
    Year ended
December 31,
 
(in thousands, except per unit amounts)       2012             2011             2011             2010             2009      

 

 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income statement data:

         

Production Revenue:

         

Natural gas(1)

  $ 16,259      $ 16,321      $ 70,765      $ 54,995      $ 68,664   

NGL(2)

    17,588        16,593        75,827        67,117        65,218   

Oil

    1,332        1,252        4,876        5,803        8,142   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total production revenue

  $ 35,179      $ 34,166      $ 151,468      $ 127,915      $ 142,024   

Total revenue

  $ 41,867      $ 34,166      $ 151,468      $ 127,915      $ 142,024   

Operating expense:

         

Lease operating

  $ 5,079      $ 5,308      $ 22,125      $ 20,257      $ 19,023   

Gathering, processing and transportation

    7,543        7,651        30,841        32,705        41,891   

Production and ad valorem taxes

    957        1,025        4,266        5,565        6,673   

Depletion and accretion

    6,217        5,077        22,629        21,050        37,978   

Impairment

                                60,045   

Net income (loss)

  $ 18,789      $ 12,252      $ 59,610      $ 35,111      $ (39,804

Pro forma general partner’s interest in net income (loss)

    19        12        60        35        (40

Pro forma limited partners’ interest in net income (loss)

    18,770        12,240        59,550        35,076        (39,764

Pro forma earnings per unit:

         

Pro forma net income (loss) per limited partner units:

         

Common units (basic)

  $        $        $      $      $   

Subordinated units

  $        $        $      $      $   

Common units (diluted)

  $        $        $      $      $   

Weighted average limited partner units outstanding:

         

Common units (basic)

         

Subordinated units

         

Common units (diluted)

         

Other financial data:

         

Adjusted EBITDA(3)

  $ 18,797      $ 17,507      $ 83,277      $ 56,999      $ 58,305   

 

 

 

(1)   For the three months ended March 31, 2012 and 2011 and the twelve months ended December 31, 2011, natural gas revenue included increases of $8.6 million, $5.1 million and $21.5 million, respectively, attributable to realized effects from derivatives.

 

(2)   For the three months ended March 31, 2012, NGL revenue included an increase of $0.5 million attributable to realized effects from derivatives.

 

(3)   An unaudited non-GAAP financial measure. See “—Non-GAAP financial measure.”

 

 

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      Our predecessor  
    

As of

March 31,

     As of December 31,  
(in thousands)    2012      2011      2010      2009  

 

 

Balance sheet data:

           

Total assets

   $ 416,089       $ 395,649       $ 336,088       $ 275,677   

Long-term debt

   $       $       $       $   

 

 

Non-GAAP financial measure

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies.

We define Adjusted EBITDA as the sum of net income adjusted by the following to the extent included in calculating such net income:

 

 

Plus:

   

Interest expense;

   

Income tax expense;

   

Depreciation, depletion and accretion;

   

Impairment of goodwill and long-lived assets (including oil and gas properties);

   

Accretion of asset retirement obligations;

   

Unrealized losses on derivatives;

   

Losses on sale of assets and other, net;

   

Equity compensation;

   

Acquisition-related costs; and

   

Non-cash expense.

 

 

Less:

   

Interest income;

   

Income tax benefit;

   

Unrealized gain on derivatives; and

   

Gains on sale of assets and other, net.

Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP. Management believes Adjusted EBITDA is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Adjusted EBITDA will also be used by our management as a factor to evaluate actual cash flow available to pay distributions to our unitholders. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the acquisition methodology.

Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an

 

 

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indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing an entity’s financial performance, such as an entity’s cost of capital and tax structure, as well as the historical costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance.

The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income.

 

      Three months ended
March 31,
     Year ended
December 31,
 
(in thousands)    2012     2011      2011      2010      2009  

 

  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

Net income (loss)

   $ 18,789      $ 12,252       $ 59,610       $ 35,111       $ (39,804

Interest expense

                                      

Depletion and accretion

     6,217        5,077         22,629         21,050         37,978   

Impairment of oil and gas properties

                                    60,045   

Unrealized gains on derivative instruments

     (6,419                               

Income tax expense

     210        178         1,038         838         86   
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

Adjusted EBITDA

   $ 18,797      $ 17,507       $ 83,277       $ 56,999       $ 58,305   

 

 

The following table presents a reconciliation of Adjusted EBITDA to the GAAP financial measure of net cash provided by operating activities.

 

      Three months ended
March 31,
    Year ended
December 31,
 
(in thousands)    2012     2011     2011     2010     2009  

 

 

Net cash provided by operating activities

   $ 16,722      $ 13,205      $ 83,011      $ 57,391      $ 62,345   

Changes in assets and liabilities:

          

Accounts receivable

     (619     497        (1,312     (2,014     (4,529

Accrued liabilities

     2,727        3,721        745        1,346        98   

Deferred income taxes

     (243     (94     (205     (562     305   

Income tax expense

     210        178        1,038        838        86   
  

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 18,797      $ 17,507      $ 83,277      $ 56,999      $ 58,305   

 

 

 

 

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Summary reserve and operating data

The proved reserve estimates as of December 31, 2011 presented in the table below are based on a report prepared by Schlumberger and were prepared consistent with the rules and regulations of the SEC regarding oil and gas reporting that are currently in effect. The summary historical proved reserve data below are estimates and are subject to inherent uncertainties.

Please read “Management’s discussion and analysis of financial condition and results of operations,” “Business and properties—Partnership Properties—Proved reserves” and the reserve report summaries included in this prospectus in evaluating the material presented below. The reserve report summaries are included as Appendix C of this prospectus.

The following tables present proved reserve and operating data for the Partnership Properties.

Proved reserve data

 

December 31, 2011   

Partnership
Properties

 

 

 

Proved reserves(1)

  

Natural gas (Mmcf)

     195,771   

NGL (Mbbl)

     28,599   

Oil (Mbbl)

     149   

Total (Mmcfe)

     368,259   

Proved developed (Mmcfe)

     316,648   

Proved undeveloped (Mmcfe)

     51,610   

Proved developed reserves as a percentage of total proved reserves

     86.0%   

Standardized Measure (in thousands)(2)

   $ 409,859   

Commodity prices(3)

  

Natural gas (per Mmbtu)

   $ 4.12   

Oil (per Bbl)

   $ 95.71   

 

 

 

(1)   Proved reserves and related future net revenue and Standardized Measure are presented on a gas-equivalent basis using a conversion of six Mcf “equivalent” per barrel of oil or NGL. This conversion is based on energy equivalence and not on price equivalence. Prices were adjusted for transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

 

(2)   Standardized Measure represents the present value of estimated future net cash inflows from our proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expense (if applicable), discounted at 10% per annum to reflect timing of future cash flows. Future calculations of Standardized Measure will include the effects of income taxes on future net revenue. For further discussion of income taxes, see “Tax considerations.”

 

(3)   Our estimated proved reserves and related Standardized Measure were determined using index prices for oil and natural gas, without giving effect to commodity derivatives, held constant throughout the life of the properties. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

 

 

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Operating data

 

      Three months  ended
March 31,
     Year ended
December 31,
 
   2012      2011      2011      2010      2009  

 

 

Production and operating data:

              

Net production volumes:

              

Natural gas (Mmcf)

     2,925         2,787         12,440         12,727         17,651   

NGL (Mbbl)

     403         378         1,565         1,814         2,404   

Oil (Mbbl)

     13         14         53         78         156   

Total (Mmcfe)

     5,421         5,139         22,148         24,079         33,011   

Average daily net production (Mmcfed)

     59.6         57.1         60.7         66.0         90.4   

Total production revenue (excluding derivatives)

   $ 26,076       $ 29,040       $ 130,005       $ 127,915       $ 142,024   

Average realized sales prices:

              

Natural gas (per Mcf)

   $ 2.61       $ 4.02       $ 3.96       $ 4.32       $ 3.89   

NGL (per Bbl)

   $ 42.51       $ 43.88       $ 48.45       $ 37.00       $ 27.13   

Oil (per Bbl)

   $ 98.66       $ 91.31       $ 91.79       $ 74.42       $ 52.23   

Average price (per Mcfe)

   $ 4.81       $ 5.65       $ 5.87       $ 5.31       $ 4.30   

Realized derivative effects (per Mcfe)

   $ 1.68       $ 1.00       $ 0.97       $       $   

Average price (per Mcfe after derivatives)

   $ 6.49       $ 6.65       $ 6.84       $ 5.31       $ 4.30   

Average unit cost (per Mcfe):

              

Lease operating

   $ 0.94       $ 1.03       $ 1.00       $ 0.84       $ 0.58   

Gathering, processing and transportation

   $ 1.39       $ 1.49       $ 1.39       $ 1.36       $ 1.27   

Production and ad valorem taxes

   $ 0.18       $ 0.20       $ 0.19       $ 0.23       $ 0.20   

General and administrative

   $ 0.57       $ 0.52       $ 0.49       $ 0.51       $ 0.49   

Depletion and accretion

   $ 1.15       $ 0.99       $ 1.02       $ 0.87       $ 1.15   

 

 

 

 

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Risk factors

Limited partner interests are inherently different from the 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 a business similar to ours. Prospective unitholders should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our units.

If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and our unitholders could lose all or part of their investment.

Risks related to our business

We may not have sufficient cash to pay the minimum quarterly distribution on our units following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates.

We may not have sufficient available cash each quarter to pay the minimum quarterly distribution of $         per unit (or $         million per quarter in the aggregate) or any other amount. Under the terms of our partnership agreement, the amount of cash available for distribution will be impacted by our operating expenses and the amount of any cash reserves established by our general partner to provide for future operations, future capital expenditures, including acquisitions of additional oil and gas properties, future debt service requirements and future cash distributions to our unitholders.

The amount of cash we distribute on our units principally depends on the cash we generate from operations, which depends on, among other things:

 

 

our production levels;

 

 

the prices we receive for our production;

 

 

the amount and timing of settlements of our commodity derivatives;

 

 

the level of our operating costs, including maintenance capital expenditures and payments to our general partner and its affiliates; and

 

 

the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon.

For a description of additional restrictions and factors that may affect our ability to make cash distributions to our unitholders, please read “Our cash distribution policy and restrictions on distributions.”

Our and Quicksilver’s proved reserve and production estimates depend on many assumptions that may turn out to be inaccurate and any material inaccuracies in these estimates or underlying assumptions may materially affect the quantities and present value of our and Quicksilver’s proved reserves and our forecasted production.

The process of estimating proved reserves and production is complex. In order to prepare these estimates, we, Quicksilver and our independent reserve engineers must project future production rates and the timing and amount of future development expenditures and such projections may

 

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be inaccurate. We, Quicksilver and the engineers must also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. In addition to interpreting available technical data, we, Quicksilver and the engineers must also analyze other various assumptions, including assumptions relating to economic factors. Any inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of proved reserves presented in this prospectus.

Actual future production, commodity prices, revenue, taxes, development expenditures, operating expenses and our estimated quantities of recoverable proved reserves most likely will vary from our estimates which could materially affect the estimated quantities and present value of proved reserves and the estimated production presented in this prospectus. In addition, we may adjust estimates of production and estimates of proved reserves to reflect production history, results of exploration and development, prevailing petroleum prices and other factors that may be beyond our control.

At December 31, 2011, 14.0% of our proved reserves were undeveloped. Recovery of undeveloped reserves requires significant additional capital expenditures and successful drilling and completion operations. Although we have prepared estimates of our proved reserves using SEC specifications, actual prices and costs may vary from these estimates, the development may not occur as scheduled or actual results of that development may not be as estimated prior to drilling.

The present value of future net cash flows disclosed in “Summary—Summary reserve and operating data” is not necessarily the fair value of our proved reserves. Actual future prices and costs may be materially higher or lower than the prices and costs used in our estimate, which are calculated in accordance with SEC requirements. Any changes in consumption by natural gas, NGL and oil purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the costs from the development and production of our oil and gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is specified by the SEC for calculating discounted future net cash flows, is not necessarily the most appropriate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor in arriving at the actual fair value of our proved reserves.

The assumptions underlying the forecast of cash available for distribution that we include in “Our cash distribution policy and restrictions on distributions” may prove inaccurate and are subject to significant risks and uncertainties, which could cause actual results to differ materially from our forecasted results.

The forecast of cash available for distribution set forth in “Our cash distribution policy and restrictions on distributions” includes our forecast of our operating results, Adjusted EBITDA and cash available for distribution for the twelve months and four-quarter period ending June 30, 2013. The assumptions underlying the forecast may prove inaccurate and are subject to significant risks and uncertainties that could cause actual results to differ materially from our forecasted results. If our actual results are significantly below forecasted results, or if our expenses are greater than forecasted, we may have insufficient cash available for distribution to pay the minimum quarterly distribution or any amount on our common, subordinated and general partner units, which may cause the market price of our common units to decline materially.

 

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Drilling locations that we decide to drill may not meet our pre-drilling expectations, may not yield oil or natural gas in commercially viable quantities and are susceptible to uncertainties that could materially alter the occurrence, timing or success of drilling.

Our management has identified and scheduled drilling locations on the Partnership Properties. As of December 31, 2011, we had 32 proved undeveloped locations with 51.6 Bcfe of proved undeveloped reserves in the Partnership Properties. These identified drilling locations represent an important part of our strategy. Our ability to execute our drilling program is subject to a number of uncertainties, including the availability of capital, regulatory approvals, commodity prices, costs and drilling results. In addition, the cost and timing of drilling, completing, and operating any well are often uncertain, and new wells may not be productive. We cannot assure you that the analogies we draw from available data from other wells will be applicable to our identified drilling locations. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. Because of these uncertainties, we do not know if the drilling locations we have identified will ever be drilled or if we will be able to produce commercially viable quantities of oil or natural gas from these or any other potential drilling locations, which could cause a decline in our proved reserves, adversely affect our results of operations and reduce our cash available for distribution to our unitholders.

Commodity prices fluctuate widely, and low prices could adversely affect our ability to borrow under and comply with our new revolving credit facility and have a material adverse impact on our business, financial condition and results of operations, which could cause us to reduce our distributions or cease paying distributions altogether.

Our revenue, profitability, future growth and ability to make distributions to our unitholders depend in part on prevailing commodity prices. These prices also affect the amount of cash flow available to service our debt, fund our capital program and our other liquidity needs, as well as our ability to borrow, raise additional capital and comply with the terms of our new revolving credit facility. Among other things, the amount we can borrow under our new revolving credit facility is subject to periodic redetermination based in part on expected future prices. Lower prices may also reduce the amount of natural gas, NGLs and oil that we can economically produce.

Prices for our production fluctuate widely, particularly as evidenced by price movements between 2008 and 2011. Among the factors that can cause these fluctuations are:

 

 

domestic and foreign demand for oil and natural gas;

 

 

the level and locations of domestic and foreign oil and natural gas supplies;

 

 

the quality, price and availability of alternative fuels;

 

 

the quantity of natural gas in storage;

 

 

weather conditions;

 

 

domestic and foreign governmental regulations, including environmental regulations;

 

 

impact of trade organizations, such as the Organization of Petroleum Exporting Countries, or OPEC;

 

 

political conditions in oil and natural gas producing regions;

 

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localized supply and demand fundamentals and transportation availability;

 

 

technological advances affecting energy consumption;

 

 

speculation by investors in oil and natural gas; and

 

 

worldwide economic conditions.

Due to the volatility of commodity prices and the inability to control the factors that influence them, we cannot predict future pricing levels. A significant decrease in commodity prices without an offsetting significant increase in production or cash received from our derivative program will cause us to reduce the distributions we pay to our unitholders or to cease paying distributions altogether.

The failure to replace our proved reserves could adversely affect our production, cash flows and our ability to make distributions to our unitholders.

We will be unable to sustain our minimum quarterly distribution without substantial capital expenditures that maintain our asset base. Producing oil and gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future success and our ability to make distributions are highly dependent on our success in efficiently developing our current proved reserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we drill additional wells or make acquisitions. Our proved reserves will generally decline as proved reserves are produced, except to the extent that we conduct successful development activities or acquire additional proved reserves. In order to maintain or increase proved reserves and production, we must continue our development drilling or undertake other replacement activities. Our planned development projects or any acquisition activities that we may undertake might not result in meaningful additional proved reserves, and we might not have continuing success drilling productive wells or midstream infrastructure required for development projects may not exist or may not be constructed, which could adversely impact our ability to benefit from those proved reserves. If our development efforts are unsuccessful, our leases covering acreage that is not already held by production could expire. If they do expire and if we are unable to renew the leases on acceptable terms, we will lose the right to conduct drilling activities and the resulting economic benefits associated therewith. If we are unable to develop or acquire additional proved reserves to replace our current and future production at economically acceptable terms, our business, financial condition, results of operations and cash available for distribution to our unitholders would be adversely affected.

Many of our properties are in areas that may have been partially depleted or drained by offset wells.

Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests, including Quicksilver, lying contiguous or adjacent to or adjoining any of our properties could take actions, such as drilling additional wells, that could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves.

 

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None of the proceeds of this offering will be used to maintain or grow our asset base or be reserved for future distributions.

The proceeds of this offering, together with borrowings under our new revolving credit facility, will be used as partial consideration for the Quicksilver Contributions. Therefore, none of the proceeds of this offering will be used to maintain or grow our asset base, which will be necessary to help fund future distributions to our unitholders, and none of the proceeds will be reserved for future distributions to our unitholders.

Our acquisition and development operations require substantial capital expenditures, which will reduce our cash available for distribution and could materially affect our ability to make distributions to our unitholders.

The development and production of our proved reserves requires substantial capital expenditures, which will reduce the amount of cash otherwise available for distribution to our unitholders. If our cash flow from operations, or our earnings (before interest, taxes, depreciation, depletion and amortization) to cash interest expense ratio or the borrowing base under our new revolving credit facility, decrease as a result of lower commodity prices, operating difficulties, declines in proved reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at expected levels, whether through debt or equity financings. The failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our proved reserves, and could adversely affect our business, financial condition, results of operations and ability to generate the cash sufficient to make distributions to our unitholders.

If the prices we receive for our production decrease, our development efforts are unsuccessful or our costs increase substantially, we may be required to recognize non-cash impairment of our oil and gas properties, which could have a material adverse effect on our results of operations.

We employ the full cost method of accounting for our oil and gas properties which, among other things, imposes limits to the capitalized cost of our assets. The capitalized cost pool cannot exceed the net present value of the underlying oil and gas reserves. Our predecessor recognized impairment to the carrying value of our oil and gas properties in 2008 and 2009 of $299.4 million and $60.0 million, respectively, and could recognize future impairments if the commodity prices utilized in determining proved reserve value cause the value of our proved reserves to decrease. Increased operating and capitalized costs without incremental increases in proved reserve value could also trigger impairment based upon decreased value of our proved reserves. The impairment of our oil and gas properties will cause us to reduce their carrying value and recognize non-cash expense, which could have a material adverse effect on our results of operations.

Certain of our wells may be adversely affected by actions Quicksilver and other operators may take when operating wells that they own.

Our wells are in close proximity to wells operated by Quicksilver and other operators in the Barnett Shale. As a result, operations conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time for completion operations and other activities conducted on those properties, could result in increased lease operating expense and could adversely affect the production from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators, including Quicksilver.

 

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Our hedging policy may not effectively mitigate the impact of commodity price volatility on our cash flows, and our hedging activities could result in losses or limit our ability to benefit from price increases. In addition, the commodity derivatives covering our production expire in 2015, and we may not be able to enter into commodity derivatives covering our production in future periods on favorable terms or at all.

To reduce our exposure to hydrocarbon price fluctuations, we have entered and intend to continue to enter into commodity derivatives covering our future production, which may limit the benefit we would receive from increases in hydrocarbon prices. These arrangements also expose us to risk of financial losses in some circumstances, including the following:

 

 

our production could be materially less than expected; or

 

the counterparties to the contracts could fail to perform their contractual obligations.

If our actual production and sales for any period are less than the production covered by commodity derivatives (including reduced production due to operational delays) or if we are unable to perform our development activities as planned, we might be required to satisfy a portion of our obligations under those commodity derivatives without the benefit of the cash flow from the sale of that production, which may materially impact our liquidity. Additionally, if market prices for our production exceed dollar ceilings or swap prices, we would be required to make monthly cash payments, which could materially adversely affect our liquidity. The price for natural gas set by our derivatives is significantly higher than the forecasted natural gas price for the year ending December 31, 2012 and the closing natural gas price for the year ended December 31, 2011 and the three months ended March 31, 2012. Likewise, our forecasted production revenue for the twelve months ending June 30, 2013 of $143.9 million includes an increase of $37.0 million attributable to expected gains on derivatives. Please read “Our cash distribution policy and restrictions on distributions—Assumptions and considerations—Operations and revenue.”

Although we intend to maintain a portfolio of commodity derivatives covering approximately 60% to 85% of our estimated production over a three-to-five year period at any given point in time, the commodity derivatives covering our production expire in 2015, and we may not be able to enter into commodity derivatives covering our production in future periods on favorable terms or at all. If we cannot or choose not to enter into commodity derivatives in the future, we could be more affected by changes in commodity prices than our competitors who engage in hedging arrangements. Our inability to hedge the risk of low commodity prices in the future could have a material adverse impact on our business, financial condition and results of operations, which could cause us to reduce our distributions or cease paying distributions altogether.

A significant increase in the differential between the NYMEX price or other benchmark prices and the price we receive for our production could reduce our cash available for distribution and adversely affect our financial condition.

The prices that we receive for our production often reflect a regional discount, based on the location of production, to the relevant benchmark prices, such as NYMEX, that are used for calculating the fair value of our commodity derivatives. Although there has been a demonstrated and consistent basis spread between NYMEX and where we sell our production, any increase in these differentials, if significant, could reduce our cash available for distribution to our unitholders.

 

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Our business involves many hazards and operational risks.

Our operations are subject to many risks inherent in the oil and gas industry, including operating hazards such as well blowouts, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, treatment plant “downtime,” pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks, any of which could cause us to experience substantial losses. The occurrence of a significant accident or other event could curtail our operations and have a material adverse effect on our business, financial condition and results of operations, and as a result, our ability to pay distributions to our unitholders.

All of our producing properties and operations are located in the Barnett Shale, making us vulnerable to risks associated with operating in a limited geographic area.

Upon the closing of this offering, all of our proved reserves and all of our production will be located in the Barnett Shale. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our Partnership Properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our business, financial condition and results of operations and could reduce our ability to make distributions to our unitholders.

The operation of our properties is largely dependent on the ability of Quicksilver’s employees.

The continuing production from a property, and to some extent the marketing of production, is dependent upon the ability of the operators of our properties. Quicksilver will operate all of the Partnership Properties, either directly as operator or, where we are the operator of record, on our behalf. Upon the closing of this offering, Quicksilver will operate all of the wells and properties in which we have interests. As a result, the success and timing of drilling and development activities on such properties, depend upon a number of factors, including:

 

 

the nature and timing of drilling and operational activities;

 

the timing and amount of capital expenditures;

 

Quicksilver’s or the operators’ expertise and financial resources;

 

the approval of other participants in such properties; and

 

the selection and application of suitable technology.

After completion of this offering, Quicksilver will operate on our behalf all of the Partnership Properties, and we may in the future acquire properties operated by third parties. If Quicksilver or the applicable third-party operator is unable to conduct drilling and development activities on our properties on a timely basis, we may be unable to increase our production or offset production declines, or we will be required to write off the proved reserves attributable thereto, any of which may adversely affect our production, revenue and results of operations and our

 

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cash available for distribution. Any such write-offs of our proved reserves could reduce our ability to borrow money and could adversely impact our ability to pay distributions on the common units.

Delays in obtaining oil field equipment and increases in drilling and other service costs could adversely affect our ability to pursue our drilling program.

As commodity prices increase, demand and costs for drilling equipment, crews and associated supplies, equipment and services can increase significantly. We cannot be certain that in a higher petroleum price environment we would be able to obtain necessary drilling equipment and supplies in a timely manner, on satisfactory terms or at all, and we could experience difficulty in obtaining, or material increases in the cost of, drilling equipment, crews and associated supplies, equipment and services. In addition, drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, including urban drilling, and possible title issues. As a result of increased activity levels, we have seen increases and supply limitations for the services we procure. Any such shortages or delays and price increases could adversely affect our ability to execute our drilling program and reduce our cash available for distribution to our unitholders.

Competition in our industry is intense, and we are smaller and have a more limited operating history than many of our competitors.

We compete with major and independent oil and gas companies, including Quicksilver, for property acquisitions and for the equipment and labor required to develop and operate our properties. Many of our competitors have substantially greater financial and other resources than we do, and they may be better able to absorb the burden of drilling and infrastructure costs and any changes in federal, state and local laws and regulations than we can, which would adversely affect our competitive position. In addition, there is substantial competition for investment capital in the oil and gas industry. These competitors may be able to pay more for properties and may be able to define, evaluate, bid for and purchase a greater number of properties than we can. Our ability to acquire additional properties in the future will depend upon our ability to conduct operations, to evaluate and select suitable properties and to complete transactions in this highly competitive environment. Furthermore, the oil and gas industry competes with other industries in supplying the energy and fuel needs of industrial, commercial and other consumers. Our inability to compete effectively with other oil and gas companies could have a material adverse impact on our business activities, financial condition and results of operations and our ability to make distributions to our unitholders.

If we do not make acquisitions on economically acceptable terms, our future growth and ability to pay or increase distributions will be limited.

Our ability to grow and to increase distributions to our unitholders depends in part on our ability to make acquisitions that result in an increase in available cash per unit. We may be unable to make such acquisitions because we are:

 

 

unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with their owners;

 

 

unable to obtain financing for such acquisitions on economically acceptable terms; or

 

 

outbid by competitors.

 

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If we are unable to acquire properties containing proved reserves, our total level of proved reserves will decline as a result of our production, and we will be limited in our ability to increase or possibly even to maintain our level of cash distributions to our unitholders.

Any acquisitions we complete will be subject to substantial risks that could reduce our ability to make distributions to unitholders.

One of our growth strategies is to acquire oil and gas properties that fit our acquisition profile. Even if we do make acquisitions that we believe will increase available cash per unit, these acquisitions may nevertheless result in a decrease in available cash per unit. Any acquisition involves potential risks, including, among other things:

 

 

the validity of our assumptions about our proved reserves, future production, commodity prices, revenue, capital expenditures, operating expenses and costs;

 

 

an inability to successfully integrate the assets we acquire;

 

 

an inability to obtain satisfactory title to the assets we acquire;

 

 

a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

 

 

a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

 

 

the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;

 

 

the diversion of management’s attention from other business concerns;

 

 

mistaken assumptions about the overall cost of equity or debt;

 

 

an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and

 

 

the occurrence of other significant changes, such as impairment of oil and gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data and other information, the results of which are often inconclusive and subject to various interpretations.

In addition, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition, given time constraints imposed by sellers. 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 assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as latent contamination, are not necessarily observable even when an inspection is undertaken.

We may experience a financial loss if Quicksilver is unable to receive payment for a significant portion of our production.

Under our omnibus agreement, Quicksilver will sell our production on our behalf, and its ability to sell will depend upon the demand for natural gas, NGLs and oil from potential purchasers of

 

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our production. Quicksilver currently has only two active purchasers of our NGL production. To the extent that either reduces the volume of its NGL purchases from us, or if other purchasers of a material portion of our production fail to perform their payment obligations to us, we could experience a temporary interruption in sales of, or a lower price for, our NGL production and our revenue and cash available for distribution could decline, which could have a material adverse effect on our results of operation and could adversely affect our ability to make cash distributions to our unitholders. To the extent that purchasers of our production rely on access to the credit or equity markets to fund their operations, there could be an increased risk that those purchasers could default in their contractual obligations to us.

Parties with whom we do business may become unable or unwilling to timely perform their obligations to us.

We enter into contracts and transactions with various third parties, including contractors, suppliers, customers, lenders and counterparties to hedging arrangements, under which such third parties incur performance or payment obligations to us. Any delay or failure on the part of one or more of such third parties to perform their obligations to us could, depending upon the nature and magnitude of such failure or failures, have a material adverse effect on our business, financial condition, results of operations and our ability to make distributions to our unitholders.

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 regulations. 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 pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders. Please read “Business and properties—Environmental matters” and “Business and properties—Government regulation.”

We cannot control the operations of gas gathering, processing, liquids fractionation and transportation facilities we do not own or operate.

We deliver our production to market through gathering, fractionation and transportation systems that we do not own, including pipelines and easements to our properties that will continue to be held by Quicksilver after the completion of this offering. The marketability of our production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties. A portion of our production could be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, maintenance of third-party facilities or capital constraints that limit the ability of third parties to construct gathering systems, processing facilities or interstate pipelines to transport our production. Disruption of our production could negatively impact our ability to market, fractionate and deliver our production. Since we do not own or operate these assets, their continuing operation is not within our control. If any of these pipelines and other facilities becomes unavailable or capacity constrained, or if further planned development of such assets is delayed or abandoned, it could have a material adverse effect on our business, financial condition, results of operations and our ability to make distributions to our unitholders.

 

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Our prior and continuing relationship with Quicksilver exposes us to risks attributable to the businesses and retained liabilities of Quicksilver.

In connection with the closing of this offering, we intend to enter into an exchange agreement with Quicksilver pursuant to which Quicksilver will cause the transfer to us of all of the equity interests in Quicksilver Production Partners Operating Ltd. (which will own all of the Partnership Properties) and the novation of certain derivative contracts. The exchange agreement will also include certain contributed rights for us to use easements and pipelines that will continue to be owned by Quicksilver. In connection with such exchange, we will agree to indemnify Quicksilver for all liabilities and obligations of Quicksilver Production Partners Operating Ltd. (whether arising before or after the closing of this offering) except for certain limited liabilities for which Quicksilver will agree to provide limited indemnities to us. Please read “Certain relationships and related party transactions—Agreements governing the transactions—Exchange agreement.” Immediately following the closing of this offering, any claims made against us that are properly attributable to Quicksilver in accordance with these arrangements or any claims we have against Quicksilver to enforce our rights under the exchange agreement would require us to exercise our rights under the exchange agreement to obtain payment from Quicksilver. We are exposed to the risk that, in these circumstances, Quicksilver cannot, or will not, make the required payment.

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

We expect that our new revolving credit facility will restrict, among other things, our ability to incur debt and pay distributions in certain circumstances, and will require us to comply with customary financial covenants and specified financial ratios. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our new revolving credit facility that are not cured or waived within the specified time periods, a significant portion of our indebtedness may become immediately due and payable, and we will be prohibited from making distributions to our unitholders. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our new revolving credit facility will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our new revolving credit facility, the lenders could seek to foreclose on our assets. Please read “Management’s discussion and analysis of financial condition and results of operations—Liquidity and capital resources—Liquidity and borrowing capacity” for additional detail regarding the covenants and restrictive provisions to be included in our new revolving credit facility.

Our new revolving credit facility will allow us to borrow up to the borrowing base, which is primarily based on the estimated present value of the cash flows from our proved reserves, discounted at 9%, and our commodity derivatives as determined semi-annually by our lenders in their sole discretion and consistent with normal oil and gas lending criteria as it exists at the determination time. The borrowing base will be redetermined by our lenders twice each year based on a reserve report with respect to our proved reserves, based on lenders’ expected future commodity prices, as adjusted for the impact of our commodity derivatives. A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base. If 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.

 

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The risks associated with our debt could adversely affect our business, financial condition, results of operations, our ability to make distributions to our unitholders and could cause our unitholders to experience a partial or total loss of their investment in us.

Subject to the limits contained in our new revolving credit facility that we expect to enter into upon the closing of this offering, we may incur additional debt. Our ability to incur additional debt and to comply with the terms of our new revolving credit facility is affected by a variety of factors, including commodity prices and their effects on our proved reserves, financial condition, results of operations and cash flows. In addition, we expect our ability to borrow under our new revolving credit facility will depend on our borrowing base, which will be redetermined twice each year based on our reserve report and such other information deemed appropriate by the administrative agent and the lenders under our new revolving credit facility. If we incur additional debt or fail to increase the quantity and value of our proved reserves, the risks that we expect to face as a result of our indebtedness could intensify.

We have demands on our cash resources, including operating expenses, funding of our capital expenditures and the interest expense we expect to have on our outstanding debt. Our level of debt, the value of our oil and gas properties and other assets, the demands on our cash resources, and the provisions of our outstanding debt could have important effects on our business and our ability to make distributions to our unitholders. For example, the provisions of our outstanding debt could:

 

 

make it more difficult for us to satisfy our obligations with respect to our debt;

 

 

require us to dedicate a substantial portion of our cash flow from operations to payments on our debt, thereby reducing the amount of our cash flow available for working capital, capital expenditures, acquisitions, other general partnership purposes and distributions to our unitholders;

 

 

require us to make principal payments if the quantity and value of our proved reserves are insufficient to support our level of borrowings;

 

 

limit our flexibility in planning for, or reacting to, changes in the oil and gas industry;

 

 

place us at a competitive disadvantage compared to our competitors who may have lower debt service obligations and greater financing flexibility than we do;

 

 

limit our financial flexibility, including our ability to borrow additional funds;

 

 

increase our interest expense on our variable rate borrowings if interest rates increase;

 

 

limit our ability to make capital expenditures to develop our properties;

 

 

increase our vulnerability to general adverse economic and industry conditions; and

 

 

result in a default or event of default under our outstanding debt, which, if not cured or waived, could adversely affect our financial condition, results of operations and cash flows.

Our ability to pay principal and interest on our debt, to otherwise comply with the provisions of our outstanding debt and to refinance our debt may be affected by economic and capital

 

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markets conditions and other factors that may be beyond our control. If we are unable to service our debt and fund our other liquidity needs, we will be forced to adopt alternative strategies that may include:

 

 

reducing or delaying capital expenditures;

 

seeking additional debt financing or equity capital;

 

selling assets;

 

restructuring or refinancing debt; or

 

reorganizing our capital structure.

We cannot assure you that we would be able to implement any of these strategies on satisfactory terms, if at all, and our inability to do so could adversely affect our ability to make distributions to our unitholders, and could cause our unitholders to experience a partial or total loss of their investment in us.

We may incur additional debt to enable us to pay our quarterly distributions, which may negatively affect our ability to pay future distributions or execute our business strategy.

We may be unable to pay the minimum quarterly distribution or the then-current distribution rate without borrowing under our new revolving credit facility or otherwise. If we use borrowings to pay distributions to our unitholders for an extended period of time rather than to fund capital expenditures and other activities relating to our operations, we may be unable to maintain or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness incurred to pay these distributions, will reduce our cash available for distribution on our units and will have a material adverse effect on our business, financial condition and results of operations. If we borrow to pay distributions to our unitholders during periods of low commodity prices and commodity prices remain low, we may have to reduce our distribution to our unitholders to avoid excessive leverage.

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity and incur debt.

Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. We expect that borrowings under our new revolving credit facility will be subject to a variable interest rate, and as a result, increases in interest rates will increase the cost of borrowing under our new revolving credit facility. Also, as with other yield-oriented securities, our unit price is impacted by the level of our cash distributions to our unitholders and the implied distribution yield. The distribution yield is often used by investors to compare and rank similar yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue additional equity or incur debt, and the cost to us of any such issuance or incurrence.

Liabilities and expenses not covered by our insurance could have a material adverse effect on our business, financial condition, results of operations, and as a result, our ability to pay distributions to our unitholders.

As a result of operating hazards, regulatory risks and other uninsured risks, we could incur substantial liabilities to third parties or governmental entities. We maintain insurance against some, but not all, of such risks and losses in accordance with customary industry practice. We are

 

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not insured against all incidents, claims or damages that might occur, and pollution and environmental risks generally are not fully insurable. Any significant accident or event that is not adequately insured could adversely affect our business, financial condition and results of operations. In addition, we may be unable to economically obtain or maintain the insurance that we desire, or may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain of our insurance policies could escalate further. In some instances, certain insurance could become unavailable or available only at reduced coverage levels. Any type of catastrophic event that is not covered by insurance could have a material adverse effect on our business, financial condition and results of operations, and as a result, our ability to pay distributions to our unitholders.

Our activities are regulated by complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

Our operations are subject to various federal, state, and local government laws and regulations that could change in response to economic or political conditions. Matters that are typically regulated include:

 

 

discharge permits for drilling operations;

 

water obtained for drilling purposes;

 

drilling permits and bonds;

 

reports concerning operations;

 

spacing of wells;

 

disposal wells;

 

unitization and pooling of properties; and

 

taxation.

From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of natural gas and oil wells below actual production capacity to conserve supplies of natural gas and oil. We may incur substantial costs in order to maintain compliance with these existing laws and regulations.

In addition, laws, regulations and tax requirements frequently are changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.

We cannot assure you that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations, will not materially adversely affect our business, results of operations and financial condition.

We are subject to environmental laws, regulations and permits, including greenhouse gas requirements, that may expose us to significant costs, liabilities and obligations.

We are subject to stringent and complex federal, state and local environmental laws, regulations and permits relating to, among other things, the generation, storage, handling, use, disposal, gathering, transmission and remediation of natural gas, NGLs, oil and other hazardous materials; the emission and discharge of such materials to the ground, air and water; wildlife, habitat, water and wetlands protection; the storage, use, treatment and disposal of water, including process water; the placement, operation and reclamation of wells; and the health and safety of our employees. These requirements may impose operational restrictions and remediation obligations, including requirements to close pits. In particular, many of these requirements are

 

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intended to help preserve water resources and regulate those aspects of our operations that could potentially impact surface water or groundwater. Failure to comply with these laws, regulations and permits may result in our being subject to litigation, fines or other sanctions, including the revocation of permits and suspension of operations, and could otherwise delay or impede the issuance or renewal of permits. We expect to continue to incur significant capital and other compliance costs related to such requirements.

We could be subject to joint and several strict liability for any environmental contamination at our or our predecessors’ currently or formerly owned, leased or operated properties or third-party waste disposal sites. In addition to potentially significant investigation and remediation costs, such matters can give rise to claims from governmental authorities and other third parties for fines or penalties, natural resource damages, personal injury and property damage.

These laws, regulations and permits, and the enforcement and interpretation thereof, change frequently and generally have become more stringent over time. For example, federal and state regulators are becoming increasingly focused on air emissions from our industry, including volatile organic compound emissions, which increased scrutiny could lead to heightened enforcement of existing regulations as well as the imposition of new air emission measures. With respect to greenhouse gas (“GHG”) emissions, we are currently required to report annual GHG emissions from certain of our operations, and additional GHG emission related requirements have been implemented or are in various stages of development. Any current or future GHG or other air emission requirements could curtail our operations or otherwise result in operational delays, liabilities and increased compliance costs. In addition, to the extent climate change results in more severe weather, our or our customers’ operations may be disrupted, which could curtail our exploration and production activity, increase operating costs and reduce product demand.

Our costs, liabilities and obligations relating to environmental matters could have a material adverse effect on our business, reputation, results of operations and financial condition.

Our hydraulic fracturing operations are subject to laws and regulations that could expose us to increased costs and additional operating restrictions and delays, and adversely affect production.

We rely and expect to continue to rely upon hydraulic fracturing, a practice that involves the pressurized injection of water, chemicals and other substances into rock formations to stimulate hydrocarbon production. Various federal, state and local initiatives have been implemented or are under development to regulate or further investigate the environmental impacts of hydraulic fracturing. In particular, the U.S. Environmental Protection Agency (the “EPA”) has commenced a study to determine the environmental and health impacts of hydraulic fracturing and announced that it will propose standards for the treatment or disposal of wastewater from certain gas production operations. In April 2012, the EPA also issued new air standards that require measures to reduce volatile organic compound emissions at hydraulically fractured or re-fractured natural gas wells. In addition, certain states and municipalities have adopted, or are considering adopting, regulations that have imposed, or could impose, more stringent permitting, transparency, disposal and well construction requirements on hydraulic fracturing operations. For example, in December 2011, the Railroad Commission of Texas finalized regulations requiring public disclosure of chemicals in fluids used in the hydraulic fracturing process. Local ordinances or other regulations also may regulate or prohibit the performance of well drilling in general and hydraulic fracturing in particular. Such laws and regulations may result in increased scrutiny or third-party claims, or otherwise result in operational delays, liabilities and increased costs.

 

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Hydraulic fracturing requires significant quantities of water. Recently, Texas has been experiencing a drought. Any diminished access to water for use in hydraulic fracturing, whether due to usage restrictions or drought or other weather conditions, could curtail our operations or otherwise result in operations delays or increased costs.

Any current or future federal, state or local hydraulic fracturing requirements applicable to our operations, or diminished access to water for use in hydraulic fracturing, could have a material adverse effect on our business, results of operations and financial condition.

The recent adoption of the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, could have an adverse effect on our ability to use derivatives to reduce the effect of commodity price risk, interest rate and other risks associated with our business.

We use commodity derivatives to manage our commodity price risk. The U.S. Congress recently adopted comprehensive financial reform legislation that, among other things, establishes comprehensive federal oversight and regulation of over-the-counter derivatives and many of the entities that participate in that market. Although the Dodd-Frank Act was enacted on July 21, 2010, the Commodity Futures Trading Commission (the “CFTC”) and the SEC, along with certain other regulators, must promulgate final rules and regulations to implement many of its provisions relating to over-the-counter derivatives. While some of these rules have been finalized, many have not and, as a result, the final form and timing of the implementation of the new regulatory regime affecting commodity derivatives remains uncertain.

In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act establishing position limits for certain, energy commodity futures and options contracts and economically equivalent swaps, futures and options. The position limit levels set the maximum amount of covered contracts that a trader may own or control separately or in combination, net long or short. The final rules also contain limited exemptions from position limits which will be phased in over time for certain bona fide hedging transactions and positions that were established in good faith before the initial limits become effective. On December 2, 2011, the International Swaps and Derivatives Association, Inc. and the Securities Industry and Financial Markets Association filed a legal challenge to the final rules, claiming, among other things, that the rules may adversely impact commodities markets and market participants, including end-users, by reducing liquidity and increasing price volatility.

While the timing of implementation of the final rules on position limits, their applicability to, and impact on, us and the success of any legal challenge to their validity remain uncertain, there can be no assurance that they will not have a material adverse impact on us by affecting the prices of or market for commodities relevant to our operations and/or by reducing the availability to us of commodity derivatives.

The Dodd-Frank Act will also impose a number of other new requirements on certain over-the-counter derivatives and subject certain swap dealers and major swap participants to significant new regulatory requirements, which in certain cases may cause them to conduct their activities through new entities that may not be as creditworthy as our current counterparties, all of which may have a material adverse effect on us. The impact of this new regulatory regime on the availability, pricing and terms and conditions of commodity derivatives remains uncertain, but there can be no assurance that it will not have a materially adverse effect on our ability to hedge our exposure to commodity prices.

 

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In addition, under Dodd-Frank swap dealers and major swap participants will be required to collect initial and variation margin from certain end-users of over-the-counter derivatives. The rules implementing many of these requirements have not all been finalized and therefore the timing of their implementation and their applicability to us remains uncertain. Depending on the final rules and definitions ultimately adopted, we might in the future be required to post collateral for some or all of our derivative transactions, which could cause liquidity issues for us by reducing our ability to use our cash or other assets for capital expenditures or other partnership purposes and reduce our ability to execute strategic hedges to reduce commodity price uncertainty and protect cash flows.

If we reduce our use of derivatives as a result of the Dodd-Frank Act, the regulations promulgated under it and the changes to the nature of the derivatives markets, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and fund unitholder distributions. In addition, the Dodd-Frank Act was intended, in part, to reduce the volatility of commodity prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to natural gas, NGLs and oil. Our revenue could, therefore, be adversely affected if commodity prices were to decrease.

Lastly, the Dodd-Frank Act requires, no later than 270 days after the enactment of the Act, the SEC to promulgate rules requiring SEC reporting companies that engage in the commercial development of oil, natural gas or minerals, to include in their annual reports filed with the SEC disclosure about all payments (including taxes, royalties, fees and other amounts) made by the issuer or an entity controlled by the issuer to the United States or to any non-U.S. government for the purpose of commercial development of oil, natural gas or minerals. As these rules are not yet effective, we are unable to predict what form these rules may take and whether we will be able to comply with them without adversely impacting our business, or at all. Any of these consequences could have a material adverse effect on our business, financial condition and results of operations.

Risks inherent in an investment in us

Our general partner and its affiliates will own a controlling interest in us and will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of our unitholders.

Conflicts of interest exist and may arise in the future as a result of the relationship between our general partner and its affiliates (including Quicksilver), on the one hand, and us and our unitholders on the other hand. Quicksilver owns and controls our general partner, and our general partner will control us and all decisions related to our operations. Quicksilver may, in certain circumstances, have interests that are different from or inconsistent with the interests of the partnership and our unitholders, and, there is nothing in our partnership agreement or any other agreement that requires Quicksilver to act in our interests or prevents Quicksilver from competing with us. Moreover, our partnership agreement eliminates all fiduciary or other duties that Quicksilver might otherwise owe to us and our limited partners and limits or eliminates the fiduciary and other duties of our general partner.

While our general partner in most instances has a duty to act in good faith in managing the partnership (which is defined, without reference to a reasonableness standard, to mean the actual belief that it is acting in, or not opposed to, the best interest of the partnership), the

 

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directors and officers and other people who control our general partner may also have independent fiduciary duties to our general partner and its owner, Quicksilver, including fiduciary duties which require them to manage our general partner in the best interest of its owner. Certain of the directors and all of the officers of our general partner also serve in similar capacities with Quicksilver and may have fiduciary duties to Quicksilver and its stockholders. In addition, these officers and directors will be compensated by Quicksilver and may have interests and other economic incentives in Quicksilver, which may lead to additional conflicts of interest.

For further information concerning these conflicts of interest, see “Certain relationships and related party transactions” and “Fiduciary and other duties.”

Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors. Quicksilver, as the owner of our general partner, has the power to appoint and remove our general partner’s directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or its board of directors. The members of the board of directors of our general partner were appointed by Quicksilver. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Our general partner has control over all decisions related to our operations. Upon consummation of this offering, Quicksilver will own our general partner and approximately     % of our outstanding common units and all of our subordinated units. Our partnership agreement generally may not be amended and the partnership cannot consummate a merger or other similar transaction during the subordination period without the approval of our public common unitholders. However, after the subordination period, our partnership agreement can be amended and the partnership can consummate a merger or other similar transaction with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by Quicksilver and its affiliates). Assuming we do not issue any additional common units and Quicksilver does not transfer its common units, Quicksilver will, after the subordination period, have the ability to amend our partnership agreement (including our policy to distribute all of our available cash to our unitholders) and consummate a merger or other similar transaction without the approval of any other unitholder. Furthermore, Quicksilver’s goals and objectives for us may not be consistent with those of a majority of the other unitholders. Please read “—Our general partner and its affiliates will own a controlling interest in us and will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of our unitholders.”

Even if our unitholders are dissatisfied, they cannot remove our general partner without Quicksilver’s consent.

After the completion of this offering, the public unitholders will be unable to remove our general partner without Quicksilver’s consent. Our general partner may be removed only with the approval of the holders of at least 66 2/3% of all outstanding units (including units held by our general partner and its affiliates) voting together as a single class. Upon consummation of this

 

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offering, Quicksilver will own approximately     % of our outstanding common units (approximately     % if the underwriters exercise their option to purchase additional common units in full), and all of our subordinated units.

Also, if our general partner is removed without cause during the subordination period and units held by Quicksilver and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of poor business management.

Certain of the directors and all of the officers who have responsibility for our management have significant duties with, and will spend significant time serving, entities that compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

To maintain and increase our levels of production, we will need to acquire oil and gas properties. All of the officers and certain of the directors of our general partner who are responsible for managing our operations and acquisition activities hold similar positions with Quicksilver and its affiliates. The positions held by these directors and officers with Quicksilver and other entities may give rise to fiduciary or other duties that are in conflict with the fiduciary or other duties they owe to us. For example, the officers and directors of our general partner may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. They may decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present them to us or may present them to other entities prior to presenting them to us. We cannot assure you that any conflicts that arise between us and our unitholders, on the one hand, and Quicksilver, on the other hand, will be resolved in our favor. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our unitholders should be aware, please read “Business and properties—Our relationship with Quicksilver” and “Fiduciary and other duties.”

Neither we nor our general partner have any employees and we will rely solely on the employees of Quicksilver to manage our business. The employees of Quicksilver who will manage our business will also perform substantially similar services for Quicksilver, and thus will not be solely focused on our business.

Neither we nor our general partner have any employees and we will rely solely on Quicksilver to operate our assets. Upon consummation of this offering, we and our general partner will enter into an omnibus agreement with Quicksilver, pursuant to which, among other things, Quicksilver will agree to operate our assets and perform other general, administrative and operational services for us and our general partner.

Because Quicksilver will be providing services to us that are substantially similar to those it performs for itself, Quicksilver may not have sufficient human, technical and other resources to provide those services at a level that Quicksilver would be able to provide to us, if it were solely

 

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focused on our business and operations. Quicksilver may make internal decisions regarding the allocation of its available resources and expertise that may prioritize Quicksilver’s interests over ours and may not be in our best interest. There is no requirement that Quicksilver favor us over itself in providing its services. If the employees of Quicksilver and its affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

Quicksilver and its affiliates, other than our general partner, will not be limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to develop and grow our business.

Neither our partnership agreement nor our omnibus agreement will prohibit Quicksilver and its affiliates, other than our general partner, from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Quicksilver and its affiliates, other than our general partner, may acquire or develop additional oil and gas properties or other assets in the future, without any obligation to offer us the opportunity to acquire or develop any of those assets.

Quicksilver is an established participant in the oil and gas industry, and has resources greater than ours, which may make it more difficult for us to compete with it with respect to commercial activities and potential acquisitions. As a result, competition from Quicksilver could adversely impact our results of operations and cash available for distribution to our unitholders. Please read “Fiduciary and other duties.”

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our proved reserves and production.

Our partnership agreement provides that we will distribute all of our available cash each quarter. As a result, we may be dependent on the issuance of additional common units and other partnership securities and borrowings to finance our growth. A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:

 

 

general economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds;

 

 

conditions in the oil and gas industry;

 

 

the market price of, and demand for, our common units;

 

 

our results of operations and financial condition; and

 

 

commodity prices.

Cost reimbursements due to Quicksilver and our general partner for services provided to us or on our behalf will be substantial and will reduce our cash available for distribution to our unitholders.

Prior to making distributions on our common units, we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur on our behalf. These expenses include amounts paid to third parties and an allocation of expenses incurred by our general partner and its affiliates in providing services on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner may be reimbursed. The reimbursements to Quicksilver and our general partner will reduce the amount of cash otherwise available for distribution to our unitholders.

 

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At the closing of this offering, we will enter into agreements with Quicksilver and our general partner pursuant to which, among other things, we will make payments to Quicksilver. These payments will be substantial and will reduce the amount of cash available for distribution to unitholders. These include the following:

 

 

an omnibus agreement pursuant to which, among other things, Quicksilver will provide operational and general and administrative services for us and our general partner; and

 

 

a tax sharing agreement pursuant to which we will pay Quicksilver (or its affiliates) our share of state and local income and other taxes for which our results are included in a combined or consolidated tax return filed by Quicksilver or its affiliates. It is possible that Quicksilver or its affiliates may use its tax attributes to cause its combined or consolidated group, of which we may be a member for this purpose, to owe less or no tax. In this situation, we would nevertheless pay Quicksilver or its affiliates the tax we would have owed had we filed our own separate tax return, without the benefit of any tax attributes of Quicksilver or its affiliates, even if the actual cash tax expense of Quicksilver or its affiliates is less than the amount we pay to Quicksilver or its affiliates. Currently, the Texas franchise tax (which has a maximum effective tax rate of 0.7% of federal gross income apportioned to Texas) is the only tax that will be included in a combined or consolidated tax return with Quicksilver or its affiliates.

Our general partner will be required to deduct estimated maintenance capital expenditures from our operating surplus, which may result in less cash available for distribution to unitholders from operating surplus than if actual maintenance capital expenditures were deducted.

Maintenance capital expenditures are capital expenditures that are intended to maintain our asset base over the long term and may include expenditures to replace our reserves (including undeveloped leasehold acreage), whether through the development and production of an existing leasehold or the acquisition or development of a new oil or natural gas property. Our partnership agreement requires our general partner to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus in determining cash available for distribution from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and approval by our conflicts committee at least once a year. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders from operating surplus will be lower than if actual maintenance capital expenditures had been deducted from operating surplus. On the other hand, if our general partner underestimates the appropriate level of estimated maintenance capital expenditures, we will have more cash available for distribution from operating surplus in the short term but will have less cash available for distribution from operating surplus in future periods when we have to increase our estimated maintenance capital expenditures to account for the previous underestimation.

If we distribute cash from capital surplus, which is analogous to a return of capital, our minimum quarterly distribution and the distribution thresholds after which the incentive distribution rights entitle our general partner to an increased percentage of distributions will be proportionately decreased.

Our cash distributions will be characterized as coming from either operating surplus or capital surplus. Operating surplus as defined in our partnership agreement, which is included in this prospectus as Appendix A, generally means amounts we receive from operating sources, such as

 

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sales of our production, less operating expenditures, such as production costs, taxes and estimated maintenance capital expenditures. Capital surplus is also defined in our partnership agreement, and generally would result from cash received from non-operating sources such as sales of properties and issuances of debt and equity interests. Cash representing capital surplus that is distributed is therefore analogous to a return of capital. Distributions of capital surplus are made to our unitholders and our general partner in proportion to their percentage interests in us (or, 99.9% to our unitholders and 0.1% to our general partner) and will result in a decrease in our minimum quarterly distribution and the target distribution thresholds. For a more detailed description of operating surplus, capital surplus and the effect of distributions from capital surplus, please read “Provisions of our partnership agreement relating to cash distributions.”

Our partnership agreement allows us to add $             million to operating surplus. As a result, a portion of this amount, which is analogous to a return of capital, may be distributed to the general partner and its affiliates, as holders of incentive distribution rights, rather than to holders of common units as a return of capital.

We have the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions, and covenants in our new revolving credit facility may restrict our ability to make distributions.

Our partnership agreement allows us to borrow to make distributions. We may make short-term borrowings under our new revolving credit facility to make distributions. The primary purpose of these borrowings would be to mitigate the effects of short-term fluctuation in our working capital that would otherwise cause volatility in our quarter-to-quarter distributions.

The terms of our new revolving credit facility will restrict our ability to pay distributions if we do not satisfy the financial and other covenants in the facility.

We may not make cash distributions during periods when we record net income.

The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow, including cash from reserves established by our general partner, working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions to our unitholders during periods when we record net losses and may not make cash distributions to our unitholders during periods when we record net income.

Control of our general partner and its incentive distribution rights may be transferred to a third party without unitholder consent or approval from our general partner’s conflicts committee.

Our partnership agreement does not restrict Quicksilver’s ability to transfer all or a portion of its ownership interest in our general partner to a third party, including to an affiliate, without approval from our general partner’s conflicts committee. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and thereby influence the decisions made by the board of directors and officers in a manner that may not be aligned with the interests of our unitholders.

Our general partner may transfer its general partner interest to a third party in a merger, consolidation or sale of substantially all of its assets without the consent of the unitholders.

In addition, our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner

 

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may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units, which may limit the ability of significant unitholders to influence the manner or direction of management.

Our partnership agreement restricts unitholders’ limited voting rights by providing that any common units held by a person, entity or group that owns 20% or more of any class of partnership interests then outstanding (other than our general partner, its affiliates, their transferees and persons who acquired such common units with the prior approval of the board of directors of our general partner) cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.

Our partnership agreement limits our general partner’s fiduciary duties to 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 or eliminate the fiduciary and other duties that our general partner, its board of directors (and any committee thereof) and its directors and the other persons who control it might have otherwise owed to us and our unitholders. Except in certain circumstances where they will not be subject to any fiduciary or other duties our general partner, its board of directors (and any committee thereof) and its directors and the other persons who control it will not be subject to any fiduciary or other duty to us or our unitholders other than the obligation to act in good faith (which is defined in the partnership agreement, without reference to a reasonableness standard, to mean acting with the actual belief that it is in, or not opposed to, the best interest of the partnership). In taking any action or making any decision on behalf of the general partner or us such persons will be presumed to have acted in good faith and in any proceeding brought by or on behalf of any unitholder or us, the person bringing such proceeding will have the burden of overcoming such presumption.

Our partnership agreement also provides that any resolution or course of action with respect to a conflict of interest between our general partner or any of its affiliates (or any of their respective directors, officers, employees or other agents), on the one hand, and us or our unitholders, on the other hand, shall be conclusively deemed to be approved by and binding on all of our unitholders and not a breach of the partnership agreement or any other agreement contemplated to be entered into in connection with this offering or any fiduciary or other duty owed to us or our unitholders if it is:

 

   

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;

 

   

approved by a majority of the conflicts committee acting in good faith;

 

   

on terms no less favorable to us than those generally being provided to or available from unrelated third parties, as determined by a majority of the board of directors of our general partner acting in good faith; or

 

   

fair and reasonable to us, as determined by a majority of the board of directors of our general partner acting in good faith.

 

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If the conflicts committee grants approval pursuant to the second bullet point or the board of directors determines that the resolution or course of action taken with respect to a conflict of interest satisfies the third or fourth bullet points, then it shall be presumed that they acted in good faith.

Furthermore, under our partnership agreement, our general partner, its board of directors (and any committee thereof), its affiliates and the directors, officers and other persons who control our general partner or any of its affiliates will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such person acted in bad faith or engaged in fraud or willful misconduct, or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

By purchasing a common unit, a unitholder will become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Fiduciary and other duties” for more information on the fiduciary and other duties owed by our general partner and other persons under our partnership agreement.

Our right of first offer to acquire certain of Quicksilver’s producing properties and right to participate in acquisition opportunities with Quicksilver are subject to risks and uncertainty, and thus may not enhance our ability to grow our business.

Under the terms of our right of first offer in our omnibus agreement, Quicksilver will commit to offer us the first opportunity to acquire any properties in the Barnett Shale Counties that Quicksilver or any of its controlled subsidiaries may offer for sale.

The consummation and timing of any future transactions pursuant to such right will depend upon, among other things, our ability to negotiate definitive agreements with respect to such opportunities and our ability to obtain financing on acceptable terms. We can offer no assurance that we will be able to consummate any future transactions pursuant to this right. Additionally, Quicksilver is under no obligation to accept any offer made by us to acquire properties in the Barnett Shale Counties that it or its controlled subsidiaries may offer for sale. Furthermore, for a variety of reasons, we may decide not to exercise this right when it becomes available, and our decision will not be subject to unitholder approval. The initial term of our omnibus agreement will be five years, and our omnibus agreement will automatically renew for additional one-year terms thereafter, unless either party provides 180 days written notice of its intent not to renew. Please read “Certain relationships and related party transactions—Agreements governing the transactions—Omnibus agreement.”

We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval, which would dilute unitholders’ ownership interests.

Our partnership agreement does not limit the number of additional common units that we may issue at any time without the approval of our unitholders. These units may be senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:

 

 

our unitholders’ proportionate ownership interest in us will decrease;

 

 

the amount of cash available for distribution on each unit may decrease;

 

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because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

 

 

the ratio of taxable income to distributions may increase;

 

 

the relative voting strength of each previously outstanding unit may be diminished; and

 

 

the market price of our common units may decline.

Once our common units are publicly traded, Quicksilver may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered hereby, Quicksilver will own             % of our outstanding common units and all of our subordinated units, which convert into common units at the end of the subordination period. Once our common units are publicly traded, the sale of these units, including common units issued upon the conversion of the subordinated units, in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and target distribution levels related to our incentive distribution rights without the approval of the conflicts committee or our unitholders. This election would dilute unitholders’ ownership interest in us.

Our general partner has the right (but not the obligation), at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (25%) for each of the prior four consecutive fiscal quarters, to reset the minimum quarterly distribution to an amount equal to the average cash distribution per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels to correspondingly higher levels based on a percentage increase in the minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive additional common units and general partner units. The number of common units to be issued to our general partner will be equal to that number of common units which would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will be issued a number of general partner units necessary to maintain our general partner’s interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right (if at all) only to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. However, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units and general partner units to our general partner in connection with resetting the target distribution levels.

 

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Please read “Provisions of our partnership agreement relating to cash distributions—General partner’s right to reset incentive distribution levels.”

Units held by persons who our general partner determines are not eligible holders will be subject to redemption.

Our general partner may amend our partnership agreement to permit us to redeem the limited partner interests held by any limited partner in respect of which:

 

 

our 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 that limited partner, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rate that can be charged to customers by us or our subsidiaries, or

 

 

there is a substantial risk of cancellation or forfeiture of any property in which we or any of our subsidiaries have an interest because of the nationality, citizenship or other related status of that limited partner.

Please read “The partnership agreement—Non-citizen and non-taxpaying unitholders; redemption.”

Our general partner has a call right that may require common unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is the greater of (i) the highest cash price paid by our general partner or any of its affiliates for any common units purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those common units; and (ii) the average daily closing prices of our common units over the 20 days preceding the date three days before the date the notice is mailed. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders also may incur a tax liability upon a sale of their common units. Upon consummation of this offering, our general partner will own approximately     % of our outstanding common units and all of our subordinated units. For additional information about this call right, please read “The partnership agreement—Limited call right.”

Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

Under Delaware law, a limited partner in a Delaware limited partnership is not generally liable for the obligations of the partnership unless such limited partner participates in the control of the partnership’s business. Although we are organized under Delaware law, we will operate in other states where the limitations on the liability of a limited partner may be different or unclear. A unitholder could be liable for our obligations as if it was a general partner if:

 

 

a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership or limited partnership statute; or

 

 

a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

 

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Please read “The partnership agreement—Limited liability” for a discussion of the implications of the limitations of liability on a unitholder.

Our unitholders may have liability to repay distributions.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make distributions to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

Our unitholders may have limited liquidity for their common units, a trading market may not develop for the common units and our unitholders may be unable to resell their common units at the initial public offering price.

Prior to this offering, there has been no public market for the common units. After this offering, there will be publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Our unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, a lack of liquidity would likely result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units. All of the              common units that are issued to affiliates of our general partner, or     % of our outstanding common units, will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters. Each of the lock-up agreements with the underwriters may be waived in the discretion of certain of the underwriters. Sales by affiliates of our general partner of a substantial number of our common units in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to our general partner and its affiliates. Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations.

If our common unit price declines after the initial public offering, our unitholders could lose a significant part of their investment.

The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

 

 

changes in commodity prices;

 

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changes in securities analysts’ recommendations and their estimates of our financial performance;

 

 

public reaction to our press releases, announcements and filings with the SEC;

 

 

fluctuations in broader securities market prices and volumes, particularly among securities of oil and gas companies and securities of publicly traded limited partnerships and limited liability companies;

 

 

changes in market valuations of similar companies;

 

 

departures of key personnel;

 

 

commencement of or involvement in litigation;

 

 

variations in our quarterly results of operations or those of other oil and gas companies;

 

 

variations in the amount of our quarterly cash distributions to our unitholders;

 

 

future issuances and sales of our common units; and

 

 

changes in general conditions in the U.S. economy, financial markets or the oil and gas industry.

In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.

Our unitholders will experience immediate and substantial dilution of $             per unit.

The assumed initial offering price of $             per common unit (the midpoint of the price range set forth on the cover of this prospectus) exceeds our net tangible book value after this offering of $             per common unit. Based on the assumed initial offering price of $             per common unit, our unitholders will incur immediate and substantial dilution of $             per common unit. This dilution will occur primarily because the assets contributed by Quicksilver and its affiliates are recorded in accordance with GAAP at their historical cost and not at their fair value. The impact of such dilution would be magnified upon any conversion of the incentive distribution rights into common units. Please read “Dilution.”

Our independent registered public accounting firm identified a material weakness in connection with their audits of our predecessor’s historical carve out financial statements for years prior to 2011. If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal control over financial reporting is necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports, our reputation and operating results will be harmed.

Prior to the completion of this offering, the Partnership Properties and commodity derivatives that comprise our predecessor were owned by Quicksilver and were not held in a separate legal entity or operated independently. As a result, there were no dedicated accounting personnel to develop

 

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accounting processes and establish internal control over financial reporting for our predecessor. In connection with their audit of our predecessor’s historical carve out financial statements for years prior to 2011, our independent registered accounting firm identified a number of deficiencies in respect of internal control over financial reporting that in the aggregate constituted a material weakness. The internal control deficiencies related to the completeness and precision of the review procedures used in preparing certain information included in the historical carve out financial statements of our predecessor. A “material weakness” is a deficiency, or combination of deficiencies, in internal controls such that there is a reasonable possibility that a material misstatement of our predecessor’s financial statements will not be prevented or detected in a timely basis.

We believe we have remedied the material weakness by dedicating existing personnel and hiring new personnel who are charged with the responsibility of developing and maintaining an appropriate accounting process and system of internal controls over financial reporting, including an augmented review process. Although we believe we have addressed the internal control deficiencies that led to the material weakness, the measures we have taken and will take may not be effective. Consequently, if this or another material weakness or significant deficiencies occur in the future, it could affect the financial results that we report or create a perception that our reported financial condition or results of operations are not fairly presented. Either of those events could have an adverse effect on the value of our units.

We are not currently required to comply with the SEC’s rules regarding 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 traded partnership, 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 control 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 control over financial reporting pursuant to Section 404 while we maintain our status as an emerging growth company. See “Summary—Emerging growth company status.” To comply with the requirements of being a publicly traded partnership, we may need to implement or augment internal controls, reporting systems and procedures and hire additional accounting and finance staff.

Our independent registered public accounting firm is not required to formally attest to the effectiveness of our internal controls over financial reporting. Our independent registered public accounting firm may issue a report that has an adverse opinion if it is not satisfied with the level at which our controls are documented, designed or maintained. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future.

We cannot be certain that our efforts to develop and maintain our internal controls will be determined to be sufficient, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could be financially costly or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

 

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As an “emerging growth company” under the Jumpstart Our Business Startups Act, we are permitted to, and intend to, rely on exemptions from certain disclosure requirements.

As an “emerging growth company” under the Jumpstart Our Business Startups Act, we are permitted to, and intend to, rely on exemptions from certain disclosure requirements. In particular, we have not included all of the executive compensation-related information that would be required in this prospectus if we were not an emerging growth company. In addition, for so long as we are an emerging growth company, which may be up to five years, we will not be required to and may not:

 

 

provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal controls over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002;

 

 

comply with any new requirements that may be adopted by the 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 (auditor discussion and analysis);

 

 

comply with any new audit rules adopted by the PCAOB after April 5, 2012, unless the SEC determines otherwise;

 

 

submit certain executive compensation matters to unitholders in nonbinding, advisory votes, such as say on pay and frequency of say on pay; and

 

 

disclose certain executive compensation-related items such as the correlation between executive compensation and performance and comparisons of the CEO’s compensation to median employee compensation.

For more information, please read “Summary—Emerging growth company status.”

NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

We have applied to list our common units on the NYSE. Because we will be a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE’s corporate governance requirements. Please read “Management—Management of Quicksilver Production Partners LP.”

Tax risks to unitholders

In addition to reading the following risk factors, a prospective unitholder should read “Tax considerations” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of our common units.

Because a unitholder will be treated as a partner, a unitholder will be required to pay taxes on its share of our income even if it does not receive any cash distributions from us, and the tax liability the unitholder incurs on the disposition of our common units could be more or less than expected.

A unitholder will be treated as a partner, and a unitholder will be required to pay taxes on the income that we allocate to the unitholder for each year, which will likely be different in amount

 

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from, and may be greater than, the amount of cash the unitholder receives from us as distributions on the common units in such year. A unitholder will be required to pay any federal income taxes and, in some cases, state and local income taxes on the unitholder’s allocable share of our taxable income even if the cash distributions the unitholder receives from us on the common units are less than the unitholder’s share of such taxable income, or if the unitholder receives no cash distributions from us.

In addition, because a unitholder will be treated as a partner, when a unitholder sells common units, the tax liability that the unitholder incurs may be more or less than expected. On a sale of our common units, a unitholder will recognize for tax purposes a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our total net taxable income decrease the unitholder’s tax basis in the common units, the amount, if any, of such prior excess distributions with respect to the common units sold will, in effect, become taxable income to the unitholder if the common units are sold at a price greater than the unitholder’s tax basis in those common units, even if the price the unitholder receives is less than the original cost of those common units. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income because of potential recapture items, including depreciation, depletion and intangible drilling and development costs, or “IDCs,” recapture. In addition, because the amount realized for purposes of calculating taxable gain or loss upon a sale of common units may include a unitholder’s share of our nonrecourse liabilities, the unitholder may incur a tax liability that is in excess of the amount of cash the unitholder receives from a sale of the common units. Please read “Tax considerations—Disposition of common units—Recognition of gain or loss.”

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, or “IRS,” on this or any other tax matter affecting us. Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in current law, or a change in our business, could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to federal income taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. We would also likely pay state income tax at varying rates. Distributions to a unitholder would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to the unitholder. This obligation to pay federal and state income taxes, if it arose, would substantially reduce our cash available for distribution to our unitholders, and therefore would likely result in a substantial reduction in both the anticipated cash flow and after-tax return to our unitholders, and a substantial reduction in the value of our common units.

 

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The IRS may challenge our treatment of each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased, which could adversely affect the value of our common units.

Because, among other reasons, we cannot match transferors and transferees of our common units, we will adopt depreciation, depletion and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could both adversely affect the amount and timing of tax benefits available to a unitholder, as well as the amount of gain or loss from a sale of our common units, and have a negative impact on the value of our common units or result in audit adjustments to a unitholder’s tax returns. Please read “Tax considerations—Tax consequences of unit ownership—Section 754 election” for a further discussion of the effect of the depreciation, depletion and amortization positions we will adopt.

Because of the special and potentially adverse tax rules that apply to tax-exempt entities and non-U.S. persons that own our units, our units may not be an appropriate investment for these types of investors.

Special, and potentially adverse, tax consequences will apply to tax-exempt entities, such as employee benefit plans and individual retirement accounts, or “IRAs,” and non-U.S. persons that own our common units. For example, substantially 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. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. A prospective unitholder who or which is a tax-exempt entity or a non-U.S. person should consult a tax adviser before investing in our common units.

A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered to have disposed of those common units. If so, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units for federal income tax purposes. If the unitholder were treated as having disposed of the loaned common units, the unitholder may recognize gain or loss from such disposition, and may not be treated for federal income tax purposes as a partner with respect to those common units, with the result that any of our income, gain, loss or deduction with respect to those common units would not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. A unitholder may wish to consult its tax adviser to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit the unitholder’s broker from borrowing our common units.

The sale or exchange of 50% or more of our capital and profits interests during any 12-month period will result in the termination of our partnership for federal income tax purposes, which could result in adverse tax consequences for a unitholder and additional costs for us.

If there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period, we will be considered, solely for federal income tax purposes, to have technically terminated our existence as a partnership and to have been re-formed as a new

 

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partnership. For this purpose, multiple sales of the same unit will be counted only once. Our technical termination, among other things, could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In addition, our technical termination would result in the closing of our taxable year for all unitholders, which would require us to prepare and file two tax returns (and a unitholder could receive two Schedules K-1 if relief was not available from the IRS) for one fiscal year. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than 12 months of our taxable income or loss being includible in the unitholder’s taxable income for the year of the technical termination. In addition, as a new partnership, we would be required to make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. Please read “Tax considerations—Disposition of common units—Technical termination” for a discussion of the consequences of a technical termination for federal income tax purposes.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The current federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, the Obama Administration and members of Congress have recently considered substantive changes to the existing federal income tax laws that would adversely affect the tax treatment of certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. We are 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 our common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution and the target distribution levels may be adjusted to reflect the impact of that law on us.

The IRS may challenge certain tax accounting conventions that we will adopt, which could change the allocation of items of income, gain, loss and deduction to a unitholder and adversely affect the value of our common units.

For purposes of determining the amount and allocation of items of income, gain, loss and deduction for federal income tax purposes, we will adopt certain tax accounting conventions that, while consistent with the tax accounting conventions adopted by other similarly-situated publicly traded partnerships, may be challenged by the IRS.

We will prorate our items of income, gain, loss and deduction for federal income tax purposes between a transferor and a transferee of our common units each month based upon the ownership of our common units on the first day of each month, rather than on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among a transferor and a transferee of our common units. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our

 

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proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read “Tax considerations—Disposition of common units—Allocations between transferors and transferees.”

In addition, when we issue additional common units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our 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, as determined for federal income tax purposes, between certain unitholders and the general partner, which may be unfavorable to those unitholders. Moreover, under our current valuation methods, a subsequent purchaser of common units may have a greater portion of the special adjustment to the tax basis of our assets that we are permitted to make under the federal income tax laws with respect to that purchaser (which we refer to as the “Section 743(b) adjustment”) allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between the general partner and certain of our unitholders. A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss that is allocated to our unitholders. It also could affect the amount of taxable gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder’s tax return without the benefit of additional deductions. Please read “Tax considerations—Tax consequences of unit ownership—Section 754 election.”

Certain federal income tax deductions currently available with respect to oil and gas exploration and production may be eliminated as a result of future legislation.

President Obama’s Proposed Fiscal Year 2013 Budget and other recently introduced legislation include proposals that would, if enacted into law, eliminate certain significant U.S. federal income tax incentives currently available with respect to oil and gas exploration and production. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for IDCs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the 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 would 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 gas exploration and development, which could result in an increase in the taxable income allocable to our unitholders and negatively impact the value of an investment in our common units.

If we were subjected to a material amount of additional entity-level taxation by Texas, or entity-level taxation in any other state in which we may do business in the future, our cash available for distribution to our unitholders would be reduced.

Because we operate in Texas, we will be required to pay Texas franchise tax each year at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. If in the future Texas increases its franchise tax rate applicable to us, or we begin to operate in other states that impose income or franchise taxes on us, our cash flow available for distribution to our unitholders could be substantially reduced, and could result in a reduction in the value of our

 

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common units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation for state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.

As a result of investing in our common units, a unitholder may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.

In addition to federal income taxes, a unitholder may become subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if the unitholder does not live in any of those jurisdictions. A unitholder may be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions, and may be subject to penalties for failure to comply with those requirements. We initially will own property and conduct business in Texas, which imposes an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose income, margin or other taxes, along with a requirement to file tax returns, on a unitholder. It is a unitholder’s responsibility to file all U.S. federal, state and local tax returns.

 

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Use of proceeds

We intend to use the estimated net proceeds of approximately $         million from this offering, based upon the assumed initial public offering price of $         per common unit (the midpoint of the price range set forth on the cover of this prospectus), after deducting underwriting discounts and commissions, offering costs and a structuring fee, together with borrowings of approximately $150 million (based upon the assumed midpoint of the price range set forth on the cover of this prospectus) under our new revolving credit facility, as partial consideration (together with our issuance to Quicksilver of              common units and              subordinated units) for the contribution by Quicksilver of the Partnership Properties and the novation by Quicksilver of certain commodity derivatives to us, and to pay costs related to the formation transactions and our new revolving credit facility. Quicksilver has advised us that it intends to use the cash consideration received for the Partnership Properties to retire a portion of its existing debt.

The following table illustrates our use of the proceeds of this offering and our borrowings under our new revolving credit facility.

 

Sources of cash (in millions)     Uses of cash (in millions)  

 

 

Gross proceeds from this offering

  $              

Cash consideration paid to Quicksilver

  $            

Borrowings under new revolving credit facility

    150     

Underwriting discounts and commissions, offering costs, a structuring fee, costs related to the formation transactions and costs related to our new revolving credit facility

 
 

 

 

     

 

 

 

Total

  $       

Total

  $     

 

 

If the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from Quicksilver a number of common units equal to the number of common units issued upon such exercise, at a price per common unit equal to the initial public offering price per common unit in this offering before offering costs but after deducting underwriting discounts and commissions.

Our estimates assume an initial public offering price of $         per common unit (the midpoint of the price range set forth on the cover of this prospectus) and no exercise of the underwriters’ option to purchase additional common units. An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from this offering, after deducting underwriting discounts, offering costs and a structuring fee to increase or decrease by $         million, and would result in a corresponding decrease or increase, respectively, in the amount borrowed under our new revolving credit facility.

 

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Capitalization

The following table shows:

 

 

the historical capitalization of our predecessor as of March 31, 2012; and

 

 

our pro forma capitalization as of March 31, 2012, adjusted to reflect the formation transactions and the issuance and sale of common units in this offering and the application of the net proceeds from this offering as described under “Use of proceeds.”

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical carve out financial statements and the accompanying notes of our predecessor included elsewhere in this prospectus. You should also read this table in conjunction with “Summary—Our partnership structure and formation transactions,” “Use of proceeds” and “Management’s discussion and analysis of financial condition and results of operations.”

 

March 31, 2012

(in thousands)

   Our predecessor  
   Historical      Pro forma  

 

 

Long-term debt(1)

   $      

Partners’ capital/net equity:

     

Owner’s capital of our predecessor

     304,747      

Common units held by purchasers in this offering

          

Common units held by Quicksilver

          

Subordinated units held by Quicksilver

          

General partner interest

          
  

 

 

 

Total partners’ capital/net equity(2)

     304,747      
  

 

 

 

Total capitalization

   $ 304,747       $                

 

 

 

(1)   We intend to enter into a $         million revolving credit facility, approximately $         million of which will be available for borrowing upon the completion of the formation transactions described under “Summary—Our partnership structure and formation transactions.” After giving effect to the formation transactions described under “Summary—Our partnership structure and formation transactions,” including our expected borrowing of $150 million under our new revolving credit facility (based upon the assumed midpoint of the price range set forth on the cover of this prospectus), we will have approximately $         million of borrowing capacity. For additional information on our new revolving credit facility, please read “Management’s discussion and analysis of financial condition and results of operations—Liquidity and capital resources—Liquidity and borrowing capacity.”

 

(2)   A $1.00 increase or decrease in the assumed initial public offering price per common unit would increase or decrease, respectively, the net proceeds by approximately $         million, would result in a corresponding decrease or increase in the amount borrowed under our new revolving credit facility and would change our total partners’ capital by approximately $         million.

 

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Dilution

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the as adjusted net tangible book value per unit after this offering. Net tangible book value is our total tangible assets less total liabilities. Assuming an initial offering price of $         per common unit (the midpoint of the price range set forth on the cover of this prospectus), on an adjusted basis as of March 31, 2012, after giving effect to the formation transactions described under “Summary—Our partnership structure and formation transactions,” including this offering of common units and the application of the related net proceeds, our as adjusted net tangible book value was $         million, or $         per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for accounting purposes, as illustrated in the following table:

 

Assumed initial offering price per common unit

            $                

As adjusted net tangible book value per unit before this offering(1)

   $                   

Increase in net tangible book value per unit attributable to purchasers in this offering

     
  

 

 

    

Less: As adjusted net tangible book value per unit after this offering(2)

     
     

 

 

 

Immediate dilution in net tangible book value per unit to purchasers in this offering(3)

      $     

 

 

 

(1)   Determined by dividing the net tangible book value of our net assets immediately prior to the offering by the number of units (         common units and          subordinated units) to be issued to Quicksilver as partial consideration for the Quicksilver Contributions and the          general partner units to be issued to our general partner. See “Summary—Our partnership structure and formation transactions.”

 

(2)   Determined by dividing our as adjusted net tangible book value, after giving effect to the application of the expected net proceeds of this offering, by the total number of units to be outstanding after this offering (         common units,          subordinated units, and          general partner units).

 

(3)   If the assumed initial offering price were to increase or decrease by $1.00 per common unit, then dilution in as adjusted net tangible book value per unit would equal $         or $        , respectively. The information discussed above is illustrative only and will be adjusted based on the actual public offering price and other terms of this offering determined at pricing.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates (including Quicksilver) in respect of their units and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:

 

      Units acquired      Total
consideration
 
(in millions, except percentage amounts)    Number    Percent      Amount      Percent  

 

 

General partner and its affiliates(1)(2)

            %       $                          %   

Purchasers in the offering(3)

        %            %   
  

 

 

Total

        100.0%       $           100.0%   

 

 

 

(1)   Upon the consummation of the transactions contemplated by this prospectus, and assuming the underwriters do not exercise their option to purchase additional common units, our general partner and its affiliates (including Quicksilver) will own          common units,          subordinated units and          general partner units.

 

(2)   The assets contributed by our general partner were recorded at historical cost in accordance with GAAP. Total consideration provided by affiliates of our general partner is equal to the net tangible book value of such assets as of March 31, 2012.

 

(3)   Total consideration is after deducting underwriting discounts, a structuring fee and offering costs.

 

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Our cash distribution policy and restrictions on distributions

You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read “—Assumptions and considerations” below. In addition, you should read “Forward-looking statements” and “Risk factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our predecessor’s historical operating results, you should refer to the audited historical carve out financial statements of our predecessor as of December 31, 2011 and 2010 and for the years ended December 31, 2011, 2010 and 2009 and the unaudited historical carve out financial statements of our predecessor as of March 31, 2012 and for the three months ended March 31, 2012 and 2011, all included elsewhere in this prospectus.

General

Rationale for our cash distribution policy

Our partnership agreement requires us to distribute on a quarterly basis all of our available cash. Please read “Provisions of our partnership agreement relating to cash distributions—Distributions of available cash” for a definition of available cash. We generally intend to fund any acquisitions and growth capital expenditures with borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than our retaining it. Also, because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute to our unitholders than would be the case if we were subject to federal income tax.

Restrictions and limitations on cash distributions and our ability to change our cash distribution policy

There is no guarantee that unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or distributions at any other rate except as provided in our partnership agreement. Our cash distribution policy is subject to certain restrictions and may be changed at any time, including:

 

 

Our cash distribution policy may be subject to restrictions on distributions under our new revolving credit facility or other debt agreements that we may enter into in the future. Specifically, we anticipate that the agreement related to our new revolving credit facility will contain financial tests and covenants that we must satisfy. These financial and other covenants are described under the caption “Management’s discussion and analysis of financial condition and results of operations—Liquidity and capital resources—Liquidity and borrowing capacity.” Should we be unable to satisfy these restrictions, or if a default otherwise occurs under our new revolving credit facility, we would be unable to make cash distributions to our unitholders notwithstanding our stated cash distribution policy. Any future indebtedness may contain similar or more stringent restrictions.

 

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Our general partner will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in reduced cash distributions from the anticipated levels in our stated cash distribution policy. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish, other than with respect to reserves for future cash distributions. Any determination to establish or increase reserves made by our general partner in good faith will be binding on the unitholders. We intend to reserve a portion of our cash generated from operations to fund our estimated maintenance capital expenditures. Over a longer period of time, if our general partner does not set aside sufficient cash reserves or make sufficient cash expenditures to maintain our asset base, we will be unable to pay the minimum quarterly distribution from cash generated from operations and would likely reduce our distributions. We are unlikely to be able to sustain our current level of distributions without making capital expenditures to maintain the current production levels of our oil and natural gas properties. Decreases in commodity prices from current levels will adversely affect our ability to pay distributions. If our asset base decreases and we do not reduce our distributions, a portion of the distributions may be considered a return of part of our unitholders’ investment in us as opposed to a return on our unitholders’ investment.

 

 

Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur on our behalf. These expenses include amounts paid to third parties and an allocation of expenses incurred by our general partner and its affiliates in providing services on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us (taking into consideration the goods, services or other benefits provided to us in respect of such expenses). Under our omnibus agreement, Quicksilver will be entitled to be reimbursed for expenses incurred and payments made in connection with the services it provides to our general partner on our behalf. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available to pay cash distributions to our unitholders.

 

 

Our partnership agreement, including the provisions requiring us to make cash distributions, may be amended. In general, our partnership agreement may not be amended during the subordination period without the approval of a majority of our public common unitholders and subordinated unitholders (each voting as a separate class), other than in certain limited circumstances where no unitholder approval is required. After the subordination period has ended, our partnership agreement may generally be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units that are held by our general partner and its affiliates). See “The partnership agreement—Limited voting rights” for a description of matters requiring unitholder vote. Upon consummation of this offering, Quicksilver will own our general partner and will control the voting of an aggregate of approximately         % of our outstanding common units and all of our subordinated units. Assuming we do not issue any additional common units and Quicksilver does not transfer its common units, Quicksilver will have the ability to amend certain provisions of our partnership agreement without the approval of any other unitholder once the subordination period ends.

 

 

Although, we must distribute all available cash each quarter, under the terms of our partnership agreement, our general partner determines how much available cash we have.

 

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

 

 

We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including reductions in commodity prices, reductions in our production, increases in our general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and other cash needs. For a discussion of additional factors that may affect our ability to pay distributions, please read “Risk factors.”

 

 

If our cash available for distribution materially declines, we may reduce or eliminate our quarterly distribution in order to meet our operational and other cash requirements.

 

 

All available cash distributed by us will be treated as distributed from operating surplus until operating surplus is reduced to zero. Please read “Provisions of our partnership agreement relating to cash distributions—Operating surplus and capital surplus” for a definition of operating surplus. We anticipate that distributions from operating surplus will generally not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components that represent non-operating sources of cash, including a cash basket equal to $             million and working capital borrowings. Consequently, it is possible that distributions from operating surplus may represent a return of capital. For example, the $             million cash basket would allow us to distribute as operating surplus cash proceeds we receive in the future from non-operating sources such as asset sales, issuances of equity interests and long-term borrowings, which would ordinarily represent a return of capital. Distributions representing a return of capital could result in a corresponding decrease in our asset base. Additionally, any cash distributed by us in excess of operating surplus will be deemed to be made out of capital surplus. Our partnership agreement treats a distribution made out of capital surplus as the repayment of the initial unit public offering price from this offering, which is similar to a return of capital. Distributions from capital surplus could result in a corresponding decrease in our asset base. We do not anticipate that we will make any distributions from capital surplus. Please read “Provisions of our partnership agreement relating to cash distributions—Distributions from capital surplus—Effect of a distribution from capital surplus.”

 

 

Our ability to make distributions to our unitholders depends on the performance of our operating subsidiary and its ability to distribute cash to us. The ability of our operating subsidiary to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.

Our ability to grow depends on our ability to access external growth capital

Our partnership agreement requires us to distribute all of our available cash to unitholders on a quarterly basis. As a result, we expect to fund our growth capital expenditures and any acquisitions primarily using external financing sources, including commercial bank borrowings and the issuance of debt and equity interests, rather than cash reserves established by our general partner. To the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand their ongoing operations. To the extent we issue

 

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additional units in connection with any capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our quarterly per unit distribution level. There are no limitations in our partnership agreement, nor do we expect any limitations in our new revolving credit facility, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

Our minimum quarterly distribution

Upon completion of this offering, the board of directors of our general partner will establish a minimum quarterly distribution of $         per unit per whole quarter, or $         per unit per year on an annualized basis, to be paid no later than 45 days after the end of each fiscal quarter beginning with the quarter ending             . This equates to an aggregate cash distribution of approximately $         million per quarter or $         million per year, in each case based on the number of common, subordinated and general partner units outstanding immediately after completion of this offering, but excluding any common units that may be issued under our 2012 Equity Plan that our general partner is expected to adopt prior to the closing of this offering.

To the extent the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from Quicksilver a number of common units equal to the number of common units issued upon such exercise, at a price per common unit equal to the proceeds per common unit before offering costs but after deducting underwriting discounts and commissions. Accordingly, the exercise of the underwriters’ option will not affect the total number of common, subordinated and general partner units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read “Use of proceeds.”

Our ability to make cash distributions at the minimum quarterly distribution will be subject to the factors described above under the caption “—General—Restrictions and limitations on cash distributions and our ability to change our cash distribution policy.”

As of the date of this offering, our general partner will be entitled to 0.1% of all distributions of available cash that we make prior to our dissolution. Our general partner’s initial 0.1% interest in these distributions may be reduced if we issue additional units in the future (other than the issuance of common units in connection with a reset of the incentive distribution target levels relating to our general partner’s incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 0.1% general partner interest. Our general partner is not obligated to contribute a proportionate amount of capital to us to maintain its current general partner interest. Our general partner will also hold the incentive distribution rights, which entitle the holder to additional increasing percentages, up to a maximum of 24.9%, of the cash we distribute in excess of $         per common unit per quarter.

 

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The table below sets forth the assumed number of outstanding common (assuming no exercise and full exercise of the underwriters’ option to purchase additional common units), subordinated and general partner units upon the closing of this offering and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our minimum quarterly distribution of $         per unit per quarter, or $         per unit on an annualized basis.

 

      No exercise of the
underwriters’ option
     Full exercise of the
underwriters’ option
 
          Distributions           Distributions  
     Number
of units
   One
quarter
     Four
quarters
     Number
of units
   One
quarter
     Four
quarters
 

 

 

Common units held by purchasers in this offering(1)

      $                    $                       $                    $                

Common units held by Quicksilver(1)

                 

Subordinated units held by Quicksilver

                 

General partner units

                 
  

 

 

Total

      $         $            $         $     

 

 

 

(1)   Does not include any common units that may be issued under our 2012 Equity Plan that our general partner is expected to adopt prior to the closing of this offering.

If the minimum quarterly distribution on our common units is not paid with respect to any quarter, the common unitholders will not be entitled to receive such payments in the future except that, during the subordination period, to the extent we distribute cash in any future quarter in excess of the amount necessary to make cash distributions at the minimum quarterly distribution to holders of our common units, we will use this excess cash to pay any of these arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. Please read “Provisions of our partnership agreement relating to cash distributions—Subordination period.”

We do not have a legal obligation to pay the minimum quarterly distribution or distributions at any other rate except as provided in our partnership agreement. Our partnership agreement requires that we distribute all of our available cash quarterly. Please read “Provisions of our partnership agreement relating to cash distributions—Distributions of available cash—Definition of available cash.”

Our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by our partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or imposed at equity. Our partnership agreement provides that our general partner is entitled to make the determinations described above without regard to any standard, including a reasonableness standard, other than the requirement to act in good faith. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must have the actual belief that the determination is in, or not opposed to, our best interest. Please read “Fiduciary and other duties.”

Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash

 

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distributions for any quarter is subject to fluctuation based on the amount of cash we generate from our business after payment of cash obligations and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. During the subordination period, our partnership agreement may be amended by a vote of the holders of a majority of our common units (excluding those common units held by our general partner and its affiliates) and a majority of the subordinated units, each voting as a separate class. Upon consummation of this offering, Quicksilver will own approximately     % of our outstanding common units and all of our subordinated units. Assuming we do not issue any additional common units and Quicksilver does not transfer a controlling interest in our general partner or the common units it owns, Quicksilver will have the ability to amend our partnership agreement, including provisions contained therein requiring us to make cash distributions, without the approval of any other unitholders once the subordination period ends.

We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about the first day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. For our initial quarterly distribution, we will adjust the quarterly distribution for the period from the closing of this offering through                     , 2012 based on the actual length of the period. We expect to pay this initial quarterly cash distribution on or before                     , 2012.

In the sections that follow, we present in detail the basis for our belief that we expect to be able to fully fund our minimum quarterly distribution of $         per unit each quarter for the four quarters ending June 30, 2013. In those sections, we present two tables, consisting of:

 

 

“Unaudited pro forma available cash for the year ended December 31, 2011,” in which we present the amount of cash we would have had available for distribution to our unitholders and our general partner for the year ended December 31, 2011, based on our unaudited pro forma historical financial statements. Our calculation of unaudited pro forma available cash in this table should only be viewed as a general indication of the amount of available cash that we might have generated had the transactions contemplated in this prospectus occurred in an earlier period.

 

 

“Estimated Adjusted EBITDA for the twelve months and four-quarter period ending June 30, 2013,” in which we demonstrate our ability to generate the minimum Adjusted EBITDA necessary for us to have sufficient cash available for distribution to pay the full minimum quarterly distribution on all the outstanding units, including our general partner units, for the twelve months ending June 30, 2013.

Unaudited pro forma available cash for the year ended December 31, 2011

If we had completed the formation transactions and the offering contemplated in this prospectus (including the acquisition of the Partnership Properties) on January 1, 2011, our unaudited pro forma available cash generated during the year ended December 31, 2011 would have been approximately $         million. The amount of available cash we need to pay the minimum quarterly distribution for four quarters on our common, subordinated and general partner units that will be outstanding upon the closing of this offering is approximately $         million (or $         million per quarter). As a result, for the year ended December 31, 2011, we would have generated aggregate available cash sufficient to pay the aggregate minimum quarterly distribution on all of our common, subordinated and general partner units.

 

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The exercise by the underwriters of their option to purchase additional common units will not affect the number of units outstanding at the consummation of this offering. Please read “—Our minimum quarterly distribution.”

The number of outstanding common and subordinated units on which we have based such belief does not include any common units that may be issued under our 2012 Equity Plan that our general partner is expected to adopt prior to the closing of this offering. We have not calculated available cash on a pro forma quarter-by-quarter basis for the year ended December 31, 2011 to determine if we would have generated available cash sufficient to pay the minimum quarterly distribution for each quarter during that period.

Unaudited pro forma available cash also includes general and administrative expenses. These general and administrative expenses are expected to total $6.2 million for the twelve months ending June 30, 2013, including $3.9 million of direct expenses we expect to incur, for items such as annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; and registrar and transfer agent fees. These expenses are not reflected in the historical carve out financial statements of our predecessor. For the year ended December 31, 2011, Quicksilver allocated to the Partnership Properties $11.0 million of general and administrative expenses. Quicksilver is entitled to reimbursement of such expenses under our omnibus agreement. Please read “Certain relationships and related party transactions—Agreements governing the transactions—Omnibus agreement.”

We based the pro forma disclosures upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the formation transactions contemplated in this prospectus actually been completed as of January 1, 2011. In addition, cash available to pay distributions is primarily a cash accounting concept, while our pro forma available cash for the year ended December 31, 2011 has been prepared on an accrual basis. As a result, you should view the amount of unaudited pro forma available cash only as a general indication of the amount of cash available to pay distributions that we might have generated had we been formed in an earlier period.

 

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The following table illustrates, on an unaudited pro forma basis, for the year ended December 31, 2011, the amount of available cash that would have been available for distribution to our unitholders, assuming that the formation transactions and this offering had been consummated on January 1, 2011. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.

Quicksilver Production Partners LP

Unaudited pro forma cash available for distribution

 

Year ended December 31, 2011

(in thousands, except per unit data)

  

Pro forma

 

 

 

Net income(1)

   $ 54,660   

Interest expense(1)

     4,950   

Income tax expense

     1,038   

Depletion

     22,408   

Accretion of asset retirement obligations

     221   

Unrealized (gains) losses on derivative instruments

       
  

 

 

 

Adjusted EBITDA(2)

   $ 83,277   

Less:

  

Cash interest expense

     4,950   

Cash income taxes

     267   

Estimated maintenance capital expenditures(3)

     37,530   
  

 

 

 

Pro forma available cash(4)

   $ 40,530   
  

 

 

 

Pro forma annualized distributions per unit

   $     

Pro forma estimated annual cash distributions:

  

Distributions on common units held by purchasers in this offering(5)

   $     

Distributions on common units held by Quicksilver and its affiliates(5)

  

Distributions on subordinated units

  

Distributions on general partner units

  

Total estimated annual cash distributions

  
  

 

 

 

Excess (Shortfall)

   $     
  

 

 

 

Percent of minimum quarterly distributions payable to common unitholders

   $     
  

 

 

 

Percent of minimum quarterly distributions payable to subordinated unitholders

   $     

 

 

 

(1)   At the completion of this offering, we intend to enter into a new $         million revolving credit facility under which we intend to borrow approximately $150 million (based upon the assumed midpoint of the price range set forth on the cover of this prospectus) at that time and use the net proceeds from the borrowing as partial consideration for the Quicksilver Contributions, the balance of which will be paid by the net proceeds of this offering. See “Summary—Our partnership structure and formation transactions.” If the net proceeds of this offering increase or decrease, then our borrowing under our new revolving credit facility would correspondingly decrease or increase. Pro forma net income represents net income for the year ended December 31, 2011 of $59.6 million reduced by the expected impact of interest expense on $150 million in borrowings as if this offering and related borrowings had been completed on January 1, 2011. The pro forma interest expense is based on borrowings of $150 million at an assumed rate of 3.3%. If the interest rate used to calculate this interest were 1% higher or lower, our annual net income and interest expense would increase or decrease, respectively, by approximately $1.5 million. Likewise, a $1.00 increase or decrease in the assumed initial public offering price per common unit would result in a $         million decrease or increase in borrowings, respectively and a $         million decrease or increase, respectively, in net income and interest expense.

 

(2)   Adjusted EBITDA is defined in “Summary—Summary historical financial data—Non-GAAP financial measure.”

 

(3)   Historically, our predecessor did not make a distinction between maintenance and growth capital expenditures. For purposes of the presentation of “Unaudited pro forma cash available for distribution,” we have estimated that all of our predecessor’s capital expenditures during the year ended December 31, 2011 were maintenance capital expenditures.

 

(4)   Includes $11 million of general and administrative expenses that we do not expect to incur prospectively. Please read “—Assumptions and considerations—Capital expenditures and expenses.”

 

(5)  

The table above reflects the number of common, subordinated and general partner units outstanding immediately following the closing of this offering, but excluding any common units that may be issued under our 2012 Equity Plan that our general

 

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partner is expected to adopt prior to the closing of this offering. The exercise by the underwriters of their option to purchase additional common units will not affect the number of units outstanding at the consummation of this offering. Please read “—Our minimum quarterly distribution.”

Estimated Adjusted EBITDA for the twelve months and four-quarter period ending June 30, 2013

The forecast has been prepared by and is the responsibility of our management. Our forecast 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 ending June 30, 2013. While the assumptions disclosed in this prospectus are not all-inclusive, the assumptions listed below are those that we believe are material to our forecasted results of operations and any assumptions not discussed below were not deemed to be material. We believe we have a reasonable objective basis for these assumptions; however, there will likely be differences between our forecast and the actual results and those differences could be material. If the forecast is not achieved, we may not be able to pay cash distributions on our common units at the minimum quarterly distribution rate or at all.

The cumulative amount that we would distribute for the twelve months ending June 30, 2013, if we made distributions on all our common, subordinated and general partner units at the minimum quarterly distribution rate of $         per unit during that period, would be $         million. Based upon the assumptions and considerations set forth in “—Assumptions and considerations,” in order to fund distributions on all our common, subordinated and general partner units at the minimum quarterly distribution rate for the twelve months ending June 30, 2013, we estimate that our minimum Adjusted EBITDA for that period must be at least $         million. The number of outstanding common, subordinated and general partner units on which we have based such estimates does not include any common units that may be issued under our 2012 Equity Plan that our general partner is expected to adopt prior to the closing of this offering. The exercise by the underwriters of their option to purchase additional common units will not affect the number of units outstanding at the consummation of this offering. Please read “—Our minimum quarterly distribution.”

Based on the assumptions set forth in “—Assumptions and considerations,” and as set forth in the table below, we believe that we will be able to generate approximately $84.8 million in Adjusted EBITDA during the twelve months ending June 30, 2013, which amount we refer to as our “estimated Adjusted EBITDA.” We can give you no assurance, however, that we will generate this amount of Adjusted EBITDA during that period. There will likely be differences between our estimated Adjusted EBITDA and our actual results for the twelve months ending June 30, 2013 and those differences could be material. In addition, Adjusted EBITDA may not represent actual cash generated during an applicable period because of, among other things, timing differences between the incurrence and actual payment of accounts payable and accounts receivable. If the amount of Adjusted EBITDA that we actually generate during the twelve months ending June 30, 2013 is less than our estimated Adjusted EBITDA, we may not be able to pay the minimum quarterly distribution on all of our units.

Our management has prepared the prospective financial information that is the basis of our estimated Adjusted EBITDA below to substantiate our belief that we will have sufficient cash to pay the minimum quarterly distribution on all outstanding common, subordinated and general partner units for the twelve months ending June 30, 2013. This prospective financial information is a forward-looking statement and should be read together with the historical carve out financial statements and the accompanying notes included elsewhere in this prospectus and

 

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“Management’s discussion and analysis of financial condition and results of operations.” This prospective financial information was not prepared with a view toward complying with the published guidelines of the SEC or the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of our management’s knowledge and belief, the assumptions and considerations on which we base our belief that we can generate sufficient Adjusted EBITDA to pay the minimum quarterly distribution to all of our common and subordinated unitholders, as well as in respect of our general partner units, for the twelve months ending June 30, 2013. However, this prospective financial information is not fact and may not be necessarily indicative of our actual results of operations, and readers of this prospectus are cautioned not to place undue reliance on this prospective financial information. Please read “—Assumptions and considerations.”

The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Neither our independent auditors nor any other independent accountants have compiled, examined or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion on or any other form of assurance of such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information.

When considering this prospective financial information, you should keep in mind the risk factors and other cautionary statements described under “Risk factors” and “Forward-looking statements.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate the estimated Adjusted EBITDA sufficient to pay the minimum quarterly distribution to holders of our common, subordinated and general partner units for the twelve months ending June 30, 2013.

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

As a result of the factors described in “—Our estimated Adjusted EBITDA” and “—Assumptions and considerations,” we believe we will be able to pay cash distributions at the minimum quarterly distribution of $         per unit on all outstanding common, subordinated and general partner units for each full calendar quarter in the twelve months ending June 30, 2013. The number of outstanding common units on which we have based such belief does not include any common units that may be issued under our 2012 Equity Plan that our general partner is expected to adopt prior to the closing of this offering.

Our estimated Adjusted EBITDA

Adjusted EBITDA is a significant financial metric that will be 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. Specifically, we intend to use this financial measure to assist us in determining whether we are generating operating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDA is defined in “Summary—Summary historical financial data—Non-GAAP financial measure.”

 

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Quicksilver Production Partners LP

Estimated Adjusted EBITDA

 

     Forecasted  
    Twelve
months
ending
    Three Months Ending  
(in millions, except per unit amounts)  

June 30,

2013

   

June 30,

2013

   

March 31,

2013

   

December 31,

2012

    September 30,
2012
 

 

 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Production revenue including realized derivative gains and losses:(1)

  $ 143.9      $ 32.9      $ 35.0      $ 37.5      $ 38.5   

Less:

         

Lease operating expenses

    21.9        5.4        5.9        5.2        5.3   

Gathering, processing and transportation expense

    29.6        7.0        7.4        7.5        7.7   

Production and ad valorem taxes

    3.4        0.8        0.9        0.9        0.9   

General and administrative expenses

    6.2        1.6        1.6        1.6        1.6   

Depletion and accretion

    29.5        7.0        7.4        7.4        7.7   

Interest expense

    4.7        1.1        1.1        1.2        1.2   

Income tax expense

    0.2               0.1        0.1          
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

    48.4        10.0        10.6        13.7        14.1   

Adjustments to reconcile net income to estimated Adjusted EBITDA:

         

Add:

         

Depletion and accretion

  $ 29.5      $ 7.0      $ 7.4      $ 7.4      $ 7.7   

Equity compensation

    2.0        0.5        0.5        0.5        0.5   

Interest expense

    4.7        1.1        1.1        1.2        1.2   

Income tax expense(3)

    0.2               0.1        0.1          
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Estimated Adjusted EBITDA

    84.8        18.6        19.7        22.9        23.6   

Adjustments to reconcile estimated Adjusted EBITDA to cash available for distribution:

         

Less:

         

Cash interest expense(2)

    4.7        1.1        1.1        1.2        1.2   

Cash income taxes(3)

    0.2               0.1        0.1          

Estimated average maintenance capital expenditures(4)

    30.3        7.6        7.6        7.6        7.6   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Estimated cash available for distribution

  $ 49.6      $ 9.8      $ 10.9      $ 14.1      $ 14.7   

Annualized minimum quarterly distribution per unit:

         

Estimated annual cash distributions:

         

Distributions on common units held by purchasers in this offering(5)

         

Distributions on common units held by Quicksilver Production Partners GP and its affiliates(5)

         

Distributions on subordinated units

         

Distributions on general partner units

         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total estimated annual cash distributions

         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Excess cash available for distributions

         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Minimum estimated Adjusted EBITDA:

         

Estimated Adjusted EBITDA

  $ 84.8      $ 18.6      $ 19.7      $ 22.9      $ 23.6   

Less:

         

Excess cash available for distributions(6)

         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Minimum estimated Adjusted EBITDA

         

 

 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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(1)   Includes the forecasted effect of cash settlements of natural gas and NGL derivatives.

 

(2)   At the completion of this offering, we intend to enter into a new $         million revolving credit facility under which we intend to borrow approximately $150 million (based upon the assumed midpoint of the price range set forth on the cover of this prospectus) at that time and use the net proceeds from the borrowing as partial consideration for the Quicksilver Contributions, the balance of which will be paid by the net proceeds of this offering. If the net proceeds of this offering increase or decrease, then our borrowing under our new revolving credit facility would correspondingly decrease or increase, respectively. See “Summary—Our partnership structure and formation transactions.”

 

(3)   Income tax expense is solely comprised of taxes due under the Texas franchise tax.

 

(4)   In calculating the estimated cash available for distribution, we have included our estimated maintenance capital expenditures of $30.3 million for the twelve months ending June 30, 2013. We expect to incur approximately $12.2 million of capital expenditures for the twelve months ending June 30, 2013, but will reserve an additional $18.1 million to maintain the targeted net production rate of 58.8 Mmcfed from our assets from July 1, 2013 through December 31, 2016 (although our production may vary from period to period).

 

(5)   The table above reflects the number of common, subordinated and general partner units outstanding immediately following the closing of this offering. Common units that may be issued under our 2012 Equity Plan that our general partner will adopt prior to the closing of this offering are included in the applicable period in which such units are anticipated to vest. The exercise by the underwriters of their option to purchase additional common units will not affect the number of units outstanding at the consummation of this offering. Please read “—Our minimum quarterly distribution.”

 

(6)   We intend to retain any excess cash to repay indebtedness or for other general partnership purposes.

Assumptions and considerations

Based upon the specific assumptions outlined below with respect to the twelve months ending June 30, 2013, we expect to generate estimated Adjusted EBITDA sufficient to establish reserves for capital expenditures and to pay the minimum quarterly distribution on all common, subordinated and general partner units for the twelve months ending June 30, 2013.

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 minimum quarterly distribution (absent borrowings under our new revolving credit facility), or any amount, on all common, subordinated and general partner units, in which event the market price of our common units may decline substantially. We are unlikely to be able to sustain our minimum quarterly distribution without making capital expenditures that maintain our asset base. Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient cash expenditures to maintain our asset base, we will be unable to pay distributions at the then-current level from cash generated from operations and would therefore expect to reduce our distributions. We intend to pay for maintenance capital expenditures from operating cash flow, and we expect to primarily rely upon external financing sources, including commercial bank borrowings and the issuance of debt and equity interests, rather than cash reserves established by our general partner, to fund our growth capital expenditures and any acquisitions. In addition, decreases in commodity prices from current levels will adversely affect our ability to pay distributions. When reading this section, you should keep in mind the risk factors and other cautionary statements described under “Risk factors” and “Forward-looking statements.” Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.

 

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Operations and revenue

Production.    The following table sets forth information regarding our predecessor’s production on an actual basis for the year ended December 31, 2011 and the three months ended March 31, 2012, and our forecasted production for the twelve months ending June 30, 2013:

 

     

Forecasted
twelve months
ending

June 30, 2013

     Three months
ended
March 31,
2012
     Year ended
December 31,
2011
 

 

 

Annual production:

        

Natural Gas (Mmcf)

     12,026         2,925         12,440   

NGL (Mbbl)

     1,741         403         1,565   

Oil (Mbbl)

     41         13         53   

Total (Mmcfe)

     22,722         5,421         22,148   

Average daily production:

        

Natural gas (Mcfd)

     32,947         32,145         34,082   

NGL (Bbld)

     4,770         4,426         4,288   

Oil (Bbld)

     114         148         146   

Total (Mcfed)

     62,251         59,591         60,683   

 

 

The forecasted production for the twelve months ending June 30, 2013 reflects $12.2 million of capital expenditures to be made during that period. This increase in average daily production for the forecast period reflects the addition of production from new wells brought on line before the end of 2011 as well as the accelerated timing of the 2012 development program resulting in more contribution from new wells in the forecast period.

 

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Prices.    The table below illustrates our predecessor’s average realized sales prices on an actual basis for the year ended December 31, 2011 and the three months ended March 31, 2012, and our average realized sales prices on a forecasted basis for the twelve months ending June 30, 2013:

 

     

Forecasted
twelve months
ending

June 30, 2013

     Three months
ended
March 31,
2012
     Year ended
December 31,
2011
 

 

 

Average natural gas sales prices:

        

NYMEX-Henry Hub natural gas price (per Mmbtu)(1)

   $ 2.97       $ 2.43       $ 4.00   

Realized natural gas sales price per Mcf (excluding cash settlements of derivatives)(4)

   $ 2.95       $ 2.61       $ 3.96   

Realized natural gas sales price per Mcf (including cash settlements of derivatives)(3)(4)

   $ 5.70       $ 5.56       $ 5.69   

Average NGL sales prices:

        

NYMEX-WTI oil price (per Bbl)(1)(2)

   $ 105.73       $ 102.99       $ 95.05   

Realized NGL sales price per Bbl (excluding cash settlements of derivatives)(4)

   $ 38.61       $ 42.51       $ 48.45   

Realized NGL sales price per Bbl (including cash settlements of derivatives)(3)(4)

   $ 40.87       $ 43.67       $ 48.45   

Average oil sales prices:

        

NYMEX-WTI oil price (per Bbl)(1)

   $ 105.73       $ 102.99       $ 95.05   

Realized oil sales price per Bbl (excluding cash settlements of derivatives)(4)

   $ 100.66       $ 98.66       $ 91.79   

Realized oil sales price per Bbl (including cash settlements of derivatives)(3)(4)

   $ 100.66       $ 98.66       $ 91.79   

Total combined price (per Mcfe, excluding cash settlements of derivatives)

   $ 4.70       $ 4.81       $ 5.87   

Total combined price (per Mcfe, including cash settlements of derivatives)(3)

   $ 6.33       $ 6.49       $ 6.84   

 

 

 

(1)   Based on average NYMEX future prices for the twelve months ending June 30, 2013, as reported on May 2, 2012.

 

(2)   No NYMEX forward curve exists for NGLs. Therefore, the NGL price is based on average forward curve prices obtained from multiple financial institutions that make a forward market in NGLs. These financial institutions provided forward prices as of May 2, 2012 for each of the components of a barrel of NGLs produced from the Partnership Properties for the twelve months ending June 30, 2013. This equates to a price of $38.61 per barrel, which is approximately 37% of the NYMEX-WTI future price for the forecast period.

 

(3)   We have given effect to the commodity derivatives covering 30 Mmcfd of natural gas production for 2012 and 3 Mbbld of NGL production for 2012. No derivatives cover our oil production. For a description of the effect of lower spot prices on cash available for distribution, please read “—Sensitivity analysis—Commodity price changes.”

 

(4)   The difference between NYMEX prices and realized prices (excluding derivatives) is due to the basis and sales differentials at the different locations where the production is sold. With respect to realized NGL prices, the difference between such prices and NYMEX-WTI oil prices results primarily from the differences in oil and NGL prices.

 

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Operating revenue and realized derivative gains.    The following table illustrates the primary components of operating revenue and realized derivative gains on an actual basis for our predecessor for the year ended December 31, 2011 and the three months ended March 31, 2012, and our forecast for the twelve months ending June 30, 2013:

 

(in millions)    Forecasted
twelve
months
ending
June 30,
2013
     Three months
ended
March 31,
2012
     Year ended
December 31,
2011
 

 

 

Natural gas:

        

Natural gas revenue

   $ 35.5       $ 7.6       $ 49.3   

Realized gain on natural gas derivatives(1)

     33.1         8.6         21.5   
  

 

 

 

Total

   $ 68.6       $ 16.2       $ 70.8   

NGL:

        

NGL revenue

   $ 67.2       $ 17.1       $ 75.8   

Realized gain on NGL derivatives(1)

     3.9         0.5           
  

 

 

 

Total

   $ 71.1       $ 17.6       $ 75.8   

Oil:

        

Oil revenue

   $ 4.2       $ 1.3       $ 4.9   

Realized gain on oil derivatives(1)

                       
  

 

 

 

Total

   $ 4.2       $ 1.3       $ 4.9   

Total:

        

Total production (excluding effect of derivatives)

   $ 106.9       $ 26.1       $ 130.0   

Realized gain on derivatives(1)

     37.0         9.1         21.5   
  

 

 

 

Total production revenue and realized derivative effects

   $ 143.9       $ 35.2       $ 151.5   

 

 

 

(1)   We have given effect to the commodity derivatives covering 30 Mmcfd of natural gas production for 2012 and 2013 and 3 Mbbld of NGL production for 2012 that we will receive as part of the Quicksilver Contributions at the closing of this offering. No derivatives cover our oil production. Our predecessor did not have derivatives covering its natural gas production before 2011 or covering its NGL production before 2012.

Capital expenditures and expenses

Capital expenditures.    Our estimated maintenance capital expenditures of $30.3 million represents our estimate of average annual maintenance capital expenditures necessary to maintain our targeted average net production of 58.8 Mmcfed from July 1, 2012 through December 31, 2016. We anticipate replacing declining production and proved reserves through the drilling and completion of wells on our undeveloped properties and growing production and proved reserves through the acquisition of producing and non-producing oil and gas properties from Quicksilver and third parties. As part of our maintenance capital expenditures, we estimate that, during the twelve months ending June 30, 2013, we will drill 3 gross (3 net) wells and conduct other completion or recompletion activities.

Our forecast for the twelve months ending June 30, 2013 does not reflect any material growth capital expenditures or acquisitions. We anticipate growing production above our targeted production rate over the next five years by spending growth capital expenditures primarily on acquisition opportunities. While we anticipate making these growth capital expenditures over the next five years and believe we will be able to access external funding sources, we cannot forecast the timing of such expenditures. Although we may make acquisitions during the twelve

 

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months ending June 30, 2013, our forecast does not reflect any acquisitions, as we can provide no assurance that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase agreements and, as such, any acquisitions. Please read “Risk factors—Risks related to our business—If we do not make acquisitions on economically acceptable terms, our future growth and ability to pay or increase distributions will be limited.”

Lease operating expense.    The following table summarizes our predecessor’s lease operating expense on an aggregate basis and on a per Mcfe basis for the year ended December 31, 2011 and the three months ended March 31, 2012, and our forecasted lease operating expense on an aggregate basis and on a per Mcfe basis for the twelve months ending June 30, 2013:

 

      Forecasted
twelve months
ending June 30,
2013
     Three months
ended
March 31,

2012
     Year ended
December 31,
2011
 
(in millions, except per unit amounts)           Per Mcfe             Per Mcfe             Per Mcfe  

 

 

Lease operating expense

   $ 21.9       $ 0.96       $ 5.1       $ 0.94       $ 22.1       $ 1.00   

 

 

The decrease in forecasted lease operating expense as compared to 2011 is primarily a result of non-routine workover costs associated with production enhancements on our properties and differences between historical allocated expenses and forecasted amounts under our omnibus agreement. A majority of these workover costs were initiated in 2011 and are not expected to continue in future periods.

Gathering, processing and transportation expense.    The following table summarizes our predecessor’s gathering, processing and transportation expense on an aggregate basis and on a per Mcfe basis for the year ended December 31, 2011 and the three months ended March 31, 2012, and our forecasted gathering, processing and transportation expense on an aggregate basis and on a per Mcfe basis for the twelve months ending June 30, 2013:

 

      Forecasted
twelve months
ending June 30,
2013
     Three months
ended
March 31,

2012
     Year ended
December 31,
2011
 
(in millions, except per unit amounts)           Per Mcfe             Per Mcfe             Per Mcfe  

 

 

Gathering, processing and transportation expense

   $ 29.6       $ 1.30       $ 7.5       $ 1.39       $ 30.8       $ 1.39   

 

 

The decrease in forecasted gathering, processing and transportation expense is primarily a result of higher NGL production as a percent of total production in the forecasted period. Transportation expense for NGLs is not separable from sales price and therefore is recorded as a reduction to revenue.

 

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Production and other taxes.    The following table summarizes production taxes and ad valorem taxes for our predecessor for the year ended December 31, 2011 and the three months ended March 31, 2012, and our forecast for the twelve months ending June 30, 2013:

 

(in millions, except percentage amounts)    Forecasted
twelve
months
ending
June 30,
2013
     Three months
ended
March 31,
2012
     Year ended
December 31,
2011
 

 

 

Production revenue, excluding the effect of derivatives

   $ 106.9       $ 26.1       $ 130.0   

Production taxes

     2.0         0.4         1.8   

Production taxes as a percentage of revenue, excluding the effect of derivatives

     1.91%         1.37%         1.41%   

Ad valorem taxes

     1.4         0.6         2.4   

Ad valorem taxes as a percentage of revenue, excluding the effect of derivatives

     1.31%         2.30%         1.87%   

Production and ad valorem taxes

   $ 3.4       $ 1.0       $ 4.3   

 

 

Our production taxes are generally based on revenue, excluding the effects of commodity derivatives. In general, as prices and volumes increase, production taxes increase. As prices and volumes decrease, production taxes decrease. Ad valorem taxes are generally tied to the valuation of the oil and gas properties. However, these valuations are reasonably correlated to revenue, excluding the effects of our commodity derivatives. As a result, we are forecasting our ad valorem taxes as a percent of revenue, excluding the effects of our commodity derivatives.

General and administrative expenses.    We estimate that general and administrative expense for the twelve months ending June 30, 2013 will be $6.2 million as compared to $11.0 million and $3.1 million for the year ended December 31, 2011 and the three months ended March 31, 2012, respectively, as a result of differences between historical allocated expenses and forecasted amounts under our omnibus agreement. We expect that we will incur $3.9 million of direct expenses and $2.3 million of expenses that will be allocated to us by Quicksilver pursuant to our omnibus agreement. Quicksilver currently intends to allocate its expected general and administrative costs based on the time spent on managing the affairs of the partnership.

Depletion and accretion expense.    We estimate that our depletion and accretion expense for the twelve months ending June 30, 2013 will be approximately $29.5 million, as compared to $22.6 million and $6.2 million for the year ended December 31, 2011 and the three months ended March 31, 2012, respectively. The forecasted depletion of our oil and gas properties is based on the estimated proved reserves and future development costs in our reserve report. Our capitalized costs are calculated using the full cost accounting method. For a detailed description of the full cost method of accounting, please read “Management’s discussion and analysis of financial condition and results of operations—Our and our predecessor’s critical accounting policies.”

Interest expense.    We estimate that at the closing of this offering we will borrow approximately $150 million (based upon the assumed midpoint of the price range set forth on the cover of this prospectus) in revolving debt under our new revolving credit facility. We estimate that the borrowings will bear interest at an assumed rate of approximately 3.3%. Based on these assumptions, we estimate that our interest expense for the twelve months ending June 30, 2013 will be $4.7 million. If the net proceeds of this offering increase or decrease, then our borrowing under our new revolving credit facility would correspondingly decrease or increase, respectively. If the interest rate used to calculate this interest were 1% higher or lower, our annual interest

 

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expense would increase or decrease, respectively, by approximately $1.4 million. Likewise, a $1.00 increase or decrease in the assumed initial public offering price per common unit would result in a $             million decrease or increase in borrowings, respectively, and a $             million decrease or increase in interest expense, respectively. Our predecessor had no debt prior to 2012.

We expect that our new revolving credit facility will contain financial covenants that require us to maintain a minimum earnings (before interest, taxes, depreciation, depletion and amortization) to cash interest expense ratio of not less than 2.5 to 1.0 and a minimum current ratio of not less than 1.0 to 1.0. Please see “Management’s discussion and analysis of financial condition and results of operations—Liquidity and capital resources—Liquidity and borrowing capacity” for additional detail regarding the covenants and restrictive provisions to be included in our new revolving credit facility. We expect that our new revolving credit facility will not require any cash expenditures on our part other than interest expense that would affect our cash available for distribution. As a result, based on the assumptions used in preparing the estimates set forth above, our new revolving credit facility will not have any effect, other than interest expense, upon our ability to pay the estimated distributions to our unitholders during the forecast period.

Regulatory, industry and economic factors

Our forecast for the twelve months ending June 30, 2013 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 portions of the energy industry in which we operate, or an interpretation of existing regulation, that will be material to our business;

 

 

There will not be any major change in commodity prices or the energy industry in general;

 

 

Market, insurance and overall economic conditions will not change substantially; and

 

 

We will not undertake any extraordinary transactions that would materially affect our cash flow.

Forecasted distributions

We expect that aggregate quarterly distributions of available cash on our common, subordinated and general partner units for the twelve months ending June 30, 2013 will be approximately $         million. Quarterly distributions of available cash will be paid within 45 days after the close of each calendar quarter.

While we believe that the assumptions we have used in preparing the estimates set forth above are reasonable based upon management’s current expectations concerning future events, they are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties, including those described in “Risk factors,” that could cause actual results to differ materially from those we anticipate. If our assumptions are not realized, the actual available cash that we generate could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay the full minimum quarterly distribution or any amount on all our outstanding common, subordinated and general partner units in respect of the four calendar quarters ending June 30, 2013 or thereafter, in which event the market price of the common units may decline materially.

 

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Sensitivity analysis

Our ability to generate sufficient cash from operations to pay distributions to our unitholders is a function of two primary variables: (i) production volumes and (ii) commodity prices. In the paragraphs below, we discuss the impact that changes in either of these variables, while holding all other variables constant, would have on our ability to generate sufficient cash from our operations to pay the minimum quarterly distributions on our outstanding common, subordinated and general partner units for the twelve months ending June 30, 2013.

Production volume changes

The following table shows estimated Adjusted EBITDA under production levels of 90%, 100% and 110% of the production level we have forecasted for the twelve months ending June 30, 2013. The estimated Adjusted EBITDA amounts shown below are based on the assumptions used in our forecast.

 

      Percentage of forecasted net production  
     90%      100%      110%  

 

 

Forecasted net production:

        

Annual production:

        

Natural gas (Mmcf)

     10,823         12,026         13,228   

NGL (Mbbl)

     1,567         1,741         1,915   

Oil (Mbbl)

     37         41         46   

Total (Mmcfe)

     20,449         22,722         24,994   

Average daily production:

        

Natural gas (Mcfd)

     29,652         32,947         36,242   

NGL (Bbld)

     4,293         4,770         5,247   

Oil (Bbld)

     102         114         125   

Total (Mcfed)

     56,026         62,251         68,476   

 

 

 

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      Percentage of forecasted net production  
(in millions, except per unit amounts)        90%         100%     110%  

 

 

Forecasted prices:

      

Average natural gas prices:

      

NYMEX-Henry Hub natural gas price (per Mmbtu)(1)

   $ 2.97      $ 2.97      $ 2.97   

Realized natural gas price (per Mcf) (excluding derivatives)

   $ 2.95      $ 2.95      $ 2.95   

Realized natural gas price (per Mcf) (including derivatives)

   $ 6.01      $ 5.70      $ 5.45   

Average NGL prices:

      

NYMEX-WTI oil price (per Bbl)(1)(2)

   $ 105.73      $ 105.73      $ 105.73   

Realized NGL price (per Bbl) (excluding derivatives)(2)

   $ 38.61      $ 38.61      $ 38.61   

Realized NGL price (per Bbl) (including derivatives)(2)

   $ 41.12      $ 40.87      $ 40.66   

Average oil prices:

      

NYMEX-WTI oil price (per Bbl)(1)

   $ 105.73      $ 105.73      $ 105.73   

Realized oil price (per Bbl) (excluding derivatives)

   $ 100.66      $ 100.66      $ 100.66   

Realized oil price (per Bbl) (including derivatives)

   $ 100.66      $ 100.66      $ 100.66   

Forecasted Adjusted EBITDA projection:

      

Natural gas, NGL and oil revenue

   $ 96.2      $ 106.9      $ 117.6   

Realized gains (losses) on derivatives

     37.0        37.0        37.0   
  

 

 

 

Total production revenue

   $ 133.2      $ 143.9      $ 154.6   

Lease operating expense

     (19.7     (21.9     (24.1

Gathering, processing and transportation expense

     (26.6     (29.6     (32.6

Production and ad valorem taxes

     (3.1     (3.4     (3.8

General and administrative expenses

     (6.2     (6.2     (6.2

Equity-based compensation (included in general and administrative)

     2.0        2.0        2.0   
  

 

 

 

Estimated Adjusted EBITDA

   $ 79.6      $ 84.8      $ 89.9   

Minimum estimated Adjusted EBITDA

      

Excess cash available for distribution

      

 

 

 

(1)   Based on average NYMEX future prices for the twelve months ending June 30, 2013, as reported on May 2, 2012.

 

(2)   No NYMEX forward curve exists for NGLs. Therefore, the NGL price is based on average forward curve prices obtained from multiple financial institutions that make a forward market in NGLs. These financial institutions provided forward prices as of May 2, 2012 for each of the components of a barrel of NGLs produced from the Partnership Properties for the twelve months ending June 30, 2013. This equates to a price of $38.61 per barrel, which is approximately 37% of the NYMEX-WTI future price for the forecast period.

 

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Commodity price changes

For purposes of this presentation, we have assumed the consummation of the Quicksilver Contributions at the closing of this offering. In addition, the estimated Adjusted EBITDA amounts shown below are based on forecasted realized commodity prices that take into account our average NYMEX commodity price differential assumptions. We have assumed no changes in our production based on changes in prices. The following table shows estimated Adjusted EBITDA under various assumed NYMEX commodity prices for the twelve months ending June 30, 2013.

 

Twelve months ending June 30, 2013
(in millions, except per unit amounts)

       

 

 

NYMEX-Henry Hub natural gas price (per Mmbtu):

   $ 2.00      $ 2.50      $ 3.00      $ 3.50   

NYMEX-WTI oil price (per Bbl)(1):

   $ 85.00      $ 95.00      $ 105.00      $ 115.00   

Forecasted net production:

        

Annual production:

        

Natural gas (Mmcf)

     12,026        12,026        12,026        12,026   

NGL (Mbbl)

     1,741        1,741        1,741        1,741   

Oil (Mbbl)

     41        41        41        41   

Total (Mmcfe)

     22,722        22,722        22,722        22,722   

Average daily production:

        

Natural gas (Mcfd)

     32,947        32,947        32,947        32,947   

NGL (Bbld)

     4,770        4,770        4,770        4,770   

Oil (Bbld)

     114        114        114        114   

Total (Mcfed)

     62,251        62,251        62,251        62,251   

Forecasted prices:

        

Realized natural gas price (per Mcf) (excluding derivatives)

   $ 1.99      $ 2.49      $ 2.98      $ 3.48   

Realized natural gas price (per Mcf) (including derivatives)

   $ 5.63      $ 5.67      $ 5.72      $ 5.76   

Realized NGL price (per Bbl) (excluding derivatives)

   $ 31.04      $ 34.70      $ 38.35      $ 42.00   

Realized NGL price (per Bbl) (including derivatives)

   $ 35.84      $ 38.33      $ 40.82      $ 43.32   

Realized oil price (per Bbl) (excluding derivatives)

   $ 80.89      $ 90.40      $ 99.92      $ 109.43   

Realized oil price (per Bbl) (including derivatives)

   $ 80.89      $ 90.40      $ 99.92      $ 109.43   

Forecasted Adjusted EBITDA projection:

        

Operating revenue

   $ 81.3      $ 94.1      $ 106.8      $ 119.5   

Realized derivative gains (losses)

     52.1        44.7        37.2        29.7   
  

 

 

 

Total revenue and realized derivative gains (losses)

   $ 133.4      $ 138.8      $ 144.0      $ 149.2   

Lease operating expense

     (21.9     (21.9     (21.9     (21.9

Gathering, processing and transportation expense

     (29.3     (29.5     (29.6     (29.8

Production and ad valorem taxes

     (2.6     (3.0     (3.4     (3.9

General and administrative expenses

     (6.2     (6.2     (6.2     (6.2

Equity-based compensation (included in general and administrative)

     2.0        2.0        2.0        2.0   
  

 

 

 

Estimated Adjusted EBITDA

   $ 75.4      $ 80.2      $ 84.9      $ 89.4   

Minimum estimated Adjusted EBITDA

        

Excess cash available for distribution

        

 

 

 

(1)   No NYMEX forward curve exists for NGLs. Therefore, the NGL price is based on average forward curve prices obtained from multiple financial institutions that make a forward market in NGLs. These financial institutions provided forward prices as of May 2, 2012 for each of the components of a barrel of NGLs produced from the Partnership Properties for the twelve months ending June 30, 2013. This equates to a price of $38.61 per barrel, which is approximately 37% of the NYMEX-WTI future price for the forecast period.

 

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The following table shows estimated Adjusted EBITDA under various assumed NYMEX-Henry Hub natural gas prices and NYMEX-WTI oil prices for the twelve months ending June 30, 2013.

Estimated Adjusted EBITDA

 

      NYMEX-Henry Hub natural gas price (per  Mmbtu):  
NYMEX-WTI oil price (per Bbl)(1):    $1.50      $2.00      $2.50      $3.00      $3.50      $4.00  

 

 

$75.00

   $ 70.8       $ 70.9       $ 71.1       $ 71.3       $ 71.4       $ 71.6   

$85.00

     75.3         75.4         75.6         75.8         76.0         76.1   

$95.00

     79.8         80.0         80.2         80.3         80.5         80.6   

$105.00

     84.3         84.5         84.7         84.9         85.0         85.2   

$115.00

     88.8         89.0         89.2         89.3         89.4         89.7   

$125.00

     93.4         93.5         93.7         93.9         94.0         94.2   

 

 

 

(1)   No NYMEX forward curve exists for NGLs. Therefore, the NGL price is based on average forward curve prices obtained from multiple financial institutions that make a forward market in NGLs. These financial institutions provided forward prices as of May 2, 2012 for each of the components of a barrel of NGLs produced from the Partnership Properties for the twelve months ending June 30, 2013. This equates to a price of $38.61 per barrel, which is approximately 37% of the NYMEX-WTI future price for the forecast period.

The amount of available cash we need to pay the minimum quarterly distribution for four quarters on our common, subordinated and general partner units that will be outstanding after this offering is approximately $         million. The minimum estimated Adjusted EBITDA for the twelve months ending June 30, 2013 necessary to pay the aggregate annualized minimum quarterly distributions for such period is approximately $         million, resulting in an excess of cash available for distribution over the minimum quarterly cash distributions of $         million, based on an estimated Adjusted EBITDA of $         million for such period. Please see “—Estimated Adjusted EBITDA for the twelve months and four-quarter period ending June 30, 2013.”

Our estimated Adjusted EBITDA for the twelve months ending June 30, 2013 is based on a price of $2.97 per Mmbtu of natural gas and a price of $105.73 per barrel of oil for the twelve months ending June 30, 2013. The natural gas price is based on average NYMEX Henry Hub future prices for the twelve months ending June 30, 2013, as reported on May 2, 2012. The oil price is based on average NYMEX-WTI futures prices for the twelve months ending June 30, 2013, as reported on May 2, 2012. No NYMEX forward curve exists for NGLs. Therefore, the NGL price is based on average forward curve prices obtained from multiple financial institutions that make a forward market in NGLs. These financial institutions provided forward prices as of May 2, 2012 for each of the components of a barrel of NGLs produced from the Partnership Properties for the twelve months ending June 30, 2013. This equates to a price of $38.61 per barrel, which is approximately 37% of the NYMEX-WTI future price for the forecast period. Based on such prices, and assuming the effect of the commodity derivatives that will be novated to us at the closing of this offering, if either natural gas prices were to decline by         % to $         (assuming oil prices are held constant at $105.73 per Bbl), or if oil prices were to decline by         % to $         (assuming natural gas prices are held constant at $2.97 per Mmbtu), then we would not have any excess cash available for distribution. If oil and natural gas prices were to decline further, we would be unable to generate sufficient Adjusted EBITDA to pay the minimum quarterly distribution to all of our unitholders. Please see “—Assumptions and considerations—Operations and revenue—Prices.”

We expect to adopt a hedging policy designed to reduce the impact to our cash flows from commodity price volatility. Under this policy, we intend to enter into commodity derivatives covering approximately 60% to 85% of our estimated production over a three-to-five year period

 

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at any given point in time. We may, however, from time to time hedge more or less than this approximate range or change this range. As opposed to entering into commodity derivatives at predetermined times or on prescribed terms, we intend to enter into commodity derivatives in connection with material increases in our estimated proved reserves and at times when we believe market conditions or other circumstances suggest that it is prudent to do so. By removing a significant portion of price volatility associated with production, we believe we will mitigate, but not eliminate, the potential negative effects of reductions in commodity prices on our cash flow from operations for those periods. However, our commodity derivatives program may also reduce our ability to benefit from increases in commodity prices. Additionally, we intend to individually identify our commodity derivatives as “designated hedges” for U.S. federal income tax and accounting purposes as we enter into them.

As commodity prices decline, our estimated Adjusted EBITDA does not decline proportionately for two reasons: (1) the effects of our commodity derivatives and (2) the effects of our general and administrative expenses, which are not expected to correlate with commodity prices. Furthermore, we have assumed no changes in estimated production or operating costs during the twelve months ending June 30, 2013. However, over the long term, a sustained decline in commodity prices would likely lead to a decline in production and operating costs, as well as a reduction in our realized commodity prices. Therefore, the foregoing table is not illustrative of all of the potential effects of changes in commodity prices for periods subsequent to June 30, 2013.

 

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Provisions of our partnership agreement relating to cash distributions

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of available cash

General

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending                     , 2012, we distribute all of our available cash to unitholders of record on the applicable record date.

Definition of available cash

Available cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:

 

 

less, the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter:

 

   

to provide for the proper conduct of our business (which could include reserves for operating expenses, working capital and capital expenditures);

 

   

to comply with our debt instruments or other agreements and applicable law; or

 

   

to provide funds for distributions to our unitholders (including our general partner) for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for future distributions if it would prevent us from distributing the minimum quarterly distribution and any cumulative arrearages on all common units for such quarter);

 

 

plus, if our general partner so determines, all or a portion of working capital borrowings made or available to be made after the end of the quarter but on or before the date of the determination of available cash for the quarter.

Working capital borrowings are borrowings incurred under a credit facility, commercial paper facility or similar financing arrangement that are used solely for working capital purposes or to pay distributions to partners and were incurred with the intent of repaying such borrowings within 12 months from sources other than additional working capital borrowings.

Intent to distribute the minimum quarterly distribution

We intend to distribute to the holders of common, subordinated and general partner units on a quarterly basis at least the minimum quarterly distribution of $         per unit, or $         per unit on an annualized basis, to the extent we have sufficient available cash. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Our partnership agreement requires us to distribute all available cash each quarter, but, as described above in the definition of available cash, our general partner determines how much available cash we have. Please read “Management’s discussion and analysis of financial condition and results of operations—Liquidity and capital resources—Liquidity and borrowing capacity” for a discussion of the restrictions to be included in our credit facility that may restrict our ability to make distributions.

 

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We will adjust the minimum quarterly distribution payable in respect of the quarter ending                     , 2012 for the period from the closing of the offering through                     , 2012.

General partner interest and incentive distribution rights

Initially, our general partner will be entitled to 0.1% of all quarterly distributions that we make prior to our dissolution. At the consummation of this offering, our general partner’s 0.1% interest in us will be represented by                      general partner units. Our general partner has the right, but not the obligation, to maintain its 0.1% interest in us in connection with future issuances of limited partner interests. If we issue additional limited partner units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units in connection with the reset of the minimum quarterly distribution and target distributions in respect of the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us in exchange for additional general partner units, its 0.1% interest in our distributions will be reduced.

Our general partner also holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 24.9%, of the cash we distribute from operating surplus (as defined below) in excess of $         per unit per quarter. The maximum distribution of 24.9% does not include any distributions that our general partner may receive on its general partner units or affiliates of our general partner may receive on common units or subordinated units owned by them.

Operating surplus and capital surplus

General

All cash distributed to unitholders will be characterized under our partnership agreement as being paid from either “operating surplus” or “capital surplus.” Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

Operating surplus

Operating surplus is determined as of the end of a period and consists of:

(i) the sum of:

 

 

$             million;

 

 

all of our cash receipts after the closing of this offering;

 

   

excluding cash proceeds of interim capital transactions prior to dissolution, which includes borrowings (including sales of debt securities) other than working capital borrowings, sales of equity interests and sales or other dispositions of assets outside the ordinary course of business;

 

   

excluding cash realized on disposition of an investment capital expenditure other than the amount of any gains;

 

   

provided that cash receipts from an early termination of a commodity derivative or interest rate derivative shall be amortized in equal quarterly installments over the remaining original scheduled life of such derivative;

 

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including working capital borrowings made after the end of the period but on or before the date of the determination of available cash for the period and any available working capital borrowings that our general partner has determined shall be included in available cash with respect to such period;

 

 

including cash distributions paid on equity issued to finance all or a portion of maintenance or growth capital expenditures for the period from the date that we enter into a binding obligation with respect to such capital asset to the earlier to occur of the date such asset begins producing in paying quantities or is placed into service, as applicable, and the date that it is abandoned or disposed of; and

 

 

including cash distributions paid on equity issued to pay the construction period interest on debt incurred or to pay construction period distributions on equity issued to finance the capital expenditure referred to above;

(ii) less the sum of:

 

   

all of our operating expenditures (as described below) after the closing of this offering;

 

   

the amount of cash reserves established by our general partner to provide funds for future operating expenditures;

 

   

all working capital borrowings not repaid within 12 months after having been incurred, or repaid within such 12-month period with the proceeds of additional working capital borrowings; and

 

   

any cash loss realized on disposition of an investment capital expenditure.

Operating expenditures are defined in our partnership agreement generally to mean all of our cash expenditures, including taxes, reimbursement for expenses of our general partner and its affiliates (including expenses incurred under our omnibus agreement), payments made in the ordinary course of business under interest rate and commodity derivatives (provided that payments in connection with the initial purchase of a derivative will be amortized in equal quarterly installments over the life of the applicable derivative, and payments in connection with an early termination of a derivative will be amortized in equal quarterly installments over the remaining original scheduled life of such derivative), officer compensation, payments of interest on indebtedness (except as otherwise provided in our partnership agreement) and plugging and abandonment costs, provided that operating expenditures:

(i) will include estimated maintenance capital expenditures but not actual maintenance capital expenditures, growth capital expenditures or investment capital expenditures (as described in fuller detail below);

(ii) will include repayment of working capital borrowings but not other borrowings; and

(iii) will not include:

 

   

repayment of working capital borrowings previously deducted from operating surplus pursuant to the provision described in the penultimate bullet point of the description of operating surplus above when such repayment actually occurs;

 

   

payment of transaction expenses relating to interim capital transactions;

 

   

repurchases of equity interests except to satisfy obligations under employee benefit plans;

 

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distributions to our partners; or

 

   

any other payments made in connection with this offering described in “Use of proceeds.”

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by our operations. For example, it includes a basket of $             million that will enable us, if we choose, to distribute as operating surplus $             million of cash we receive in the future from non-operating sources such as asset sales, issuances of equity interests and long-term borrowings that would otherwise be distributed as capital surplus.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described above) and thus reduce operating surplus when repayments are made. However, if a working capital borrowing is not repaid during the 12-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 be excluded from operating expenditures because operating surplus will have been previously reduced by the deemed repayment.

Capital surplus

Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, capital surplus would generally be generated by:

 

 

borrowings (including sales of debt securities) other than working capital borrowings;

 

sales of our equity interests; and

 

sales or other dispositions of assets outside the ordinary course of business.

Characterization of cash distributions

Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital expenditures

All capital expenditures are either maintenance capital expenditures, growth capital expenditures or investment capital expenditures. Estimated maintenance capital expenditures reduce operating surplus, but actual maintenance capital expenditures, growth capital expenditures and investment capital expenditures do not.

Maintenance capital expenditures are capital expenditures that are intended to maintain our asset base 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 undeveloped leasehold acreage), whether through the development and production of an existing leasehold or the acquisition or development of a new oil or natural gas property. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

 

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Our maintenance capital expenditures can vary from period to period, which could cause similar fluctuations in the amounts of operating surplus and adjusted operating surplus 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 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 our general partner’s board of directors at least once a year, provided that any change is approved by the conflicts committee. 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 our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please read “Our cash distribution policy and restrictions on distributions.”

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 minimum quarterly distribution on outstanding units for such 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 reduce the amount available for distribution as operating surplus; conversely, in quarters in which actual maintenance capital expenditures exceed estimated maintenance capital expenditures, it will increase the amount available for distribution as operating surplus; and

 

 

it will reduce the likelihood that a large maintenance capital expenditure during a particular quarter will prevent our general partner’s affiliates from being able to convert some or all of their subordinated units to common units since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period.

Growth capital expenditures are capital expenditures that are intended to increase our asset base over the long term. Examples of growth capital expenditures include the acquisition of reserves or equipment, the acquisition of new leasehold interests, or the development and production of an existing leasehold interest, to the extent such expenditures are incurred to increase our asset base over the long term. Capital expenditures made solely for investment purposes will not be considered growth capital expenditures.

Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor growth capital expenditures. Investment capital expenditures will consist largely 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

 

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maintenance of our asset base, but which are not expected to expand our asset base for more than the short term. Cash gains or losses on disposition of an investment capital expenditure will increase or decrease operating surplus when realized.

Maintenance and growth capital expenditures will each include construction period interest paid on debt incurred to finance the related capital asset. In addition, maintenance capital expenditures will include construction period distributions paid on equity to finance the related capital asset.

As described above, neither growth capital expenditures nor investment capital expenditures will be included in operating expenditures, and thus will not reduce operating surplus. Because growth capital expenditures include construction period interest paid on debt incurred to finance all or a portion of the related capital asset, such interest payments also do not reduce operating surplus.

Capital expenditures that are made in part for maintenance capital purposes and in part for growth capital or investment capital purposes will be allocated as maintenance capital expenditures, growth capital expenditures or investment capital expenditures by our general partner’s board of directors, based upon its good faith determination, subject to approval by the conflicts committee.

Subordination period

General

During the subordination period (which we describe below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $         per common unit (which amount is defined in our partnership agreement as the minimum quarterly distribution) plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.

Expiration of the subordination period

The subordination period will extend from the closing of this offering until the earlier of:

(i) the first business day after the payment of the distribution to unitholders in respect of any quarter ending on or after                     , 2015 if each of the following tests are met:

 

 

aggregate distributions of available cash from operating surplus on all outstanding common, subordinated and general partner units (and any other partnership interests that are senior or equal in right of distribution to the subordinated units) for a period of 12 consecutive quarters ending on the last day of such quarter equaled or exceeded the aggregate minimum quarterly distributions on all such units outstanding during such period;

 

 

the “adjusted operating surplus” (as defined below) for such 12-quarter period equaled or exceeded the aggregate minimum quarterly distributions on all common, subordinated and

 

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general partner units (and any other partnership interests that are senior or equal in right of distribution to the subordinated units) outstanding during such period on a fully diluted weighted average basis; and

 

 

there are no arrearages in payment of the minimum quarterly distribution on the common units.

(ii) the first business day after the payment of the distribution to unitholders in respect of any quarter ending on or after                     , 2013, if each of the following tests are met:

 

 

distributions of available cash from operating surplus on each outstanding common, subordinated and general partner unit (and any other partnership interest that is senior or equal in right of distribution to the subordinated units) for each quarter in a four-quarter period ending on the last day of such quarter equaled or exceeded $         (125% of the minimum quarterly distribution) and the corresponding distribution on the incentive distribution rights were made;

 

 

the “adjusted operating surplus” for such four-quarter period equaled or exceeded the sum of (i) an aggregate amount equal to $         (125% of the minimum quarterly distribution) per quarter on each common, subordinated and general partner unit (and any other partnership interests that are senior or equal in right of distribution to the subordinated units) outstanding during such period on a fully diluted weighted average basis and (ii) the corresponding distributions that would be made on the incentive distribution rights; and

 

 

there are no arrearages in payment of the minimum quarterly distribution on the common units.

(iii) the date on which the unitholders remove our general partner without cause and without any votes cast by our general partner or its affiliates in favor of such removal.

In determining whether the requirements of (i) or (ii) above have been satisfied with respect to the first partial quarter after the closing of this offering, the prorated amount of the minimum quarterly distribution shall be used.

Effect of the expiration of the subordination period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. Common units will then no longer be entitled to arrearages.

Effect of the expiration of the subordination period following removal of our general partner

If the unitholders remove our general partner other than for cause and the units held by our general partner and its affiliates are not voted in favor of such removal:

 

 

the subordination period will end, and each subordinated unit will immediately convert into one common unit;

 

 

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

 

 

our general partner will have the right to convert its general partner units and incentive distribution rights into common units or to receive cash in exchange for such interests at the equivalent common unit fair market value.

 

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Adjusted operating surplus

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods.

Adjusted operating surplus for any period consists of operating surplus for such period (excluding the $             million basket otherwise included in operating surplus);

(i) 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;

(ii) plus

 

   

any net decrease in working capital borrowings 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 under (i) above.

Distributions of available cash from operating surplus during the subordination period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

 

 

first, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

 

 

second, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

 

 

third, 99.9% to the subordinated unitholders, pro rata, and 0.1% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

 

 

thereafter, in the manner described in “—General partner interest and incentive distribution rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 0.1% general partner interest and that we do not issue additional classes of equity securities.

 

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Distributions of available cash from operating surplus after the subordination period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

 

 

first, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

 

 

thereafter, in the manner described in “—General partner interest and incentive distribution rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 0.1% general partner interest and that we do not issue additional classes of equity securities.

General partner interest and incentive distribution rights

Our partnership agreement provides that our general partner initially will be entitled to 0.1% of all distributions that we make prior to our dissolution. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest if we issue additional units. Our general partner’s 0.1% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future (other than the issuance of common units in connection with the reset of the minimum quarterly distribution and the target distribution levels relating to the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 0.1% general partner interest in the form of cash or common units based on the current market value of the contributed common units.

Incentive distribution rights represent the right to receive an increasing percentage (14.9% and 24.9%, in each case not including distributions paid to the general partner on its 0.1% general partner interest) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest.

The following discussion assumes that our general partner maintains its 0.1% general partner interest and that our general partner continues to own the incentive distribution rights.

If for any quarter during the subordination period:

 

 

we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

 

 

we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

 

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then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:

 

 

first, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until each unitholder receives a total of $         per unit for that quarter (the “first target distribution”);

 

 

second, 85.0% to all unitholders, pro rata, and 0.1% in respect of its general partner interest and 14.9% in respect of its incentive distribution rights to our general partner, until each unitholder receives a total of $         per unit for that quarter (the “second target distribution”); and

 

 

thereafter, 75.0% to all unitholders, pro rata, and 0.1% in respect of its general partner interest and 24.9% in respect of its incentive distribution rights to our general partner.

Percentage allocations of available cash from operating surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal percentage interest in distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total quarterly distribution per unit.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 0.1% general partner interest and assume our general partner has contributed any additional capital to maintain its 0.1% general partner interest and has not transferred its incentive distribution rights and there are no arrearages on common units.

 

      Total quarterly
distribution per
unit
     Marginal percentage
interest in distributions
 
      Unitholders      General
partner
 

 

 

Minimum Quarterly Distribution

   up to $                     99.9%         0.1%   

First Target Distribution

   above $

up to $

            

            

  

 

     99.9%         0.1%   

Second Target Distribution

   above $

up to $

            

            

  

 

     85.0%         15.0%   

Thereafter

   above $                     75.0%         25.0%   

 

 

General partner’s right to reset incentive distribution levels

Our general partner, as the holder of the incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and 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 incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion

 

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assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made.

Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels may be exercised, without approval of our unitholders or the conflicts committee, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters and the amount of each such distribution did not exceed adjusted operating surplus. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right (if at all) only to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner 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 received in respect of the incentive distribution rights for the two quarters prior to the reset event as compared to the average cash distributions per common unit during such period. In addition, our general partner will be issued the number of general partner units necessary to maintain its general partner interest in us at the same level as existed immediately prior to the reset election.

The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels would be equal to the quotient determined by dividing (x) the average amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average amount of cash distributions per common unit during each of these two quarters.

Following any reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

 

 

first, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until each unitholder receives an amount equal to 115% of the reset minimum quarterly distribution for that quarter;

 

 

second, 85.0% to all unitholders, pro rata, and 0.1% in respect of its general partner interest and 14.9% in respect of its incentive distribution rights to our general partner, until each

 

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unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for the quarter; and

 

 

thereafter, 75.0% to all unitholders, pro rata, and 0.1% in respect of its general partner interest and 24.9% in respect of its incentive distribution rights to our general partner.

The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the closing of this offering, and (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $        .

 

     Quarterly
distribution per
unit prior to reset
    Marginal
percentage interest
in distribution
   

Quarterly distribution

per unit following
hypothetical reset

 
      Unitholders     General partner    

 

 

Minimum quarterly distribution

    up to $                   99.9%        0.1%        $              

First target distribution

   

 

above $            

up to $            

  

 

    99.9%        0.1%        up to $             (1) 

Second target distribution

   

 

above $            

up to $            

  

 

    85.0%        15.0%       

 

above $            

up to $            

(1) 

(2) 

Thereafter

    above $                   75.0%        25.0%        above $             (2) 

 

 

 

(1)   This amount is 115% of the hypothetical reset minimum quarterly distribution.

 

(2)   This amount is 125% of the hypothetical reset minimum quarterly distribution.

Cash distributions prior to reset

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights based on an average of the amounts distributed for a quarter for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be          common units outstanding, our general partner has maintained its 0.1% general partner interest, and the average distribution to each common unit would be $         for the two quarters prior to the reset.

 

     Quarterly
distributions
per unit
prior to reset
    Cash
distributions
to common
unitholders
prior to
reset
    Cash distributions to
general partner prior to  reset
    Total
distributions
 
      Common
units
    0.1%
General
partner
interest
    Incentive
distribution
rights
    Total    

 

 

Minimum quarterly distribution

    up to $                   $                    $—        $                    $                    $—        $               

First target distribution

    up to $                               

Second target distribution

   

 

above $            

up to $            

  

 

                

Thereafter

    above $                               
   

 

 

 
      $                    $—        $                    $                    $            $               

 

 

 

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Cash distributions after reset

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there would be          common units outstanding, our general partner’s 0.1% interest has been maintained, and the average distribution to each common unit would be $        . The number of common units to be issued to our general partner upon the reset was calculated by dividing (i) the average of the amounts received by our general partner in respect of its incentive distribution rights for the two quarters prior to the reset as shown in the table above, or $        , by (ii) the average available cash distributed on each common unit for the two quarters prior to the reset as shown in the table above, or $        .

 

     Quarterly
distributions
per unit after
reset
    Cash
distributions
to common
unitholders
after reset
    Cash distributions to
general partner after  reset
    Total
distributions
 
      Common
units
    0.1%
General
partner
interest
    Incentive
distribution
rights
    Total    

 

 

Minimum quarterly distribution

    up to $                   $                    $                    $                    $        —        $                    $               

First target distribution

    up to $                                                        

Second target distribution

   

 

above $            

up to $            

 

 

                                         

Thereafter

    above $                                                        
   

 

 

 
      $                    $                    $                    $                    $                    $               

 

 

Our general partner will be entitled to cause the minimum quarterly distribution amount and 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 and the amount of each such distribution did not exceed adjusted operating surplus.

Distributions from capital surplus

How distributions from capital surplus will be made

We will make distributions of available cash from capital surplus, if any, in the following manner:

 

 

first, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until the unrecovered initial unit price, as defined below, has been reduced to zero;

 

 

second, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each common unit an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units and, to the extent not duplicative, the minimum quarterly distribution for the quarter with respect to which a distribution pursuant to the first bullet reduced the unrecovered initial unit price to zero; and

 

 

thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

 

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The preceding discussion is based on the assumption that our general partner maintains its 0.1% general partner interest and that we do not issue additional classes of equity securities.

Effect of a distribution from capital surplus

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial public offering price per unit in this offering, which is similar to a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. When the unrecovered initial unit price has been reduced to zero, the minimum quarterly distribution and target distribution levels will also be zero. Because distributions of capital surplus will reduce the minimum quarterly distribution and the target distribution levels, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, until the unrecovered initial unit price is reduced to zero, distributions of capital surplus will be applied to reduce the unrecovered initial unit price and not to the payment of the minimum quarterly distribution or any arrearages.

After the unrecovered initial unit price has been reduced to zero and all arrearages on the common units and if not duplicative, the minimum quarterly distribution for the quarter have been paid, our partnership agreement specifies that we then make all future distributions as distributions from operating surplus, with 75.0% being paid to the holders of units and 25.0% to our general partner. The percentage interests shown for our general partner include its 0.1% general partner interest and assume our general partner has maintained its 0.1% general partner interest and has not transferred the incentive distribution rights.

Adjustment to the minimum quarterly distribution and target distribution levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, our partnership agreement specifies that the number of outstanding common, subordinated and general partner units will all be adjusted on the same basis and that the following items will be proportionately adjusted:

 

 

the minimum quarterly distribution;

 

 

target distribution levels;

 

 

the unrecovered initial unit price; and

 

 

the per unit amount of any outstanding arrearages in payment of the minimum quarterly distribution.

For example, if a two-for-one split of the common units should occur, the subordinated and general partner units will be similarly adjusted, and the minimum quarterly distribution, target distribution levels and unrecovered initial unit price would each be reduced to 50% of its initial level. Our partnership agreement provides that we do not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if as a result of a change in law or interpretation thereof, we or any of our subsidiaries is treated as an association taxable as a corporation or is otherwise subject to

 

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additional taxation as an entity for U.S. federal, state, local or non-U.S. income or withholding tax purposes, our general partner may reduce the minimum quarterly distribution and the target distribution levels by multiplying each by a fraction, the numerator of which is available cash for that quarter (after deducting our general partner’s estimate of our aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in laws or interpretation) and the denominator of which is the sum of available cash for that quarter (after deducting our general partner’s estimate of our aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in laws or interpretation) plus our general partner’s estimate of our aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in laws or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of cash upon dissolution

General

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the 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.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our dissolution, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

Manner of adjustments for gain

The manner of the adjustment for gain is set forth in the partnership agreement. If our dissolution occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:

 

 

first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

 

 

second, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our dissolution occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

 

 

third, 99.9% to the subordinated unitholders, pro rata, and 0.1% to our general partner, until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our dissolution occurs;

 

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fourth, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 99.9% to the unitholders, pro rata, and 0.1% to our general partner, for each quarter of our existence;

 

 

fifth, 85.0% to all unitholders, pro rata, and 0.1% in respect of its general partner interest and 14.9% in respect of its incentive distribution rights to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence; and

 

 

thereafter, 75.0% to all unitholders, pro rata, and 0.1% in respect of its general partner interest and 24.9% in respect of its incentive distribution rights to our general partner.

The percentage interests set forth above for our general partner include its 0.1% general partner interest and assume our general partner has not transferred the incentive distribution rights.

If the dissolution occurs after the end of the subordination period, the distinction between common and subordinated units will disappear so that the third bullet point above will no longer be applicable, and references to common unitholders and common units in the second bullet will be changed to unitholders and units.

We may make special allocations of gain among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

Manner of adjustments for losses

If our dissolution occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:

 

 

first, 99.9% to holders of subordinated units in proportion to the positive balances in their capital accounts and 0.1% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

 

 

second, 99.9% to the holders of common units in proportion to the positive balances in their capital accounts and 0.1% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and

 

 

thereafter, 100.0% to our general partner.

If the dissolution occurs after the end of the subordination period, the distinction between common and subordinated units will disappear, so that the first bullet point above will no longer be applicable, and references to common unitholders and common units in the second bullet will be changed to unitholders and units.

 

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Adjustments to capital accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for U.S. federal income tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners’ capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made. By contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. In the event we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

 

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Selected historical financial data

We were formed in November 2011 and do not have historical financial operating results. Therefore, the selected historical financial data below and presented elsewhere in this prospectus is that of our predecessor, which is derived, as of December 31, 2011 and 2010 and for the years ended December 31, 2011, 2010 and 2009, from the audited historical carve out financial statements of our predecessor included elsewhere in this prospectus. The selected historical financial data of our predecessor as of December 31, 2009, 2008 and 2007 and for the years ended December 31, 2008 and 2007 are derived from the historical carve out financial statements of our predecessor not included in this prospectus. The selected historical financial data of our predecessor, as of March 31, 2012 and for the three months ended March 31, 2012 and 2011, are derived from the unaudited condensed historical carve out financial statements of our predecessor included elsewhere in this prospectus. Due to the factors described in “Management’s discussion and analysis of financial condition and results of operations—Overview,” our future results of operations will not be comparable to the historical results of our predecessor.

You should read the following table in conjunction with “Summary—Our partnership structure and formation transactions,” “Use of proceeds,” “Management’s discussion and analysis of financial condition and results of operations” and the historical carve out financial statements of our predecessor included elsewhere in this prospectus. Among other things, those historical carve out financial statements include more detailed information regarding the basis of presentation for the following information.

 

    

Our predecessor

 
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    Three months
ended March 31,
    Year ended December 31,  
(in thousands, except per unit
amounts)
  2012     2011     2011     2010     2009     2008     2007  

 

 

Income statement data:

             

Production revenue:

             

Natural gas(1)

  $ 16,259      $ 16,321      $ 70,765      $ 54,995      $ 68,664      $ 150,148      $ 54,453   

NGL(2)

    17,588        16,593        75,827        67,117        65,218        95,532        48,321   

Oil

    1,332        1,252        4,876        5,803        8,142        18,463        5,379   
 

 

 

   

 

 

   

 

 

 

Total production revenue

    35,179        34,166        151,468        127,915        142,024        264,143        108,153   

Total revenue

    41,867        34,166        151,468        127,915        142,024        264,143        108,153   

Operating expense:

             

Lease operating

    5,079        5,308        22,125        20,257        19,023        17,401        12,113   

Gathering, processing and transportation

    7,543        7,651        30,841        32,705        41,891        38,460        16,168   

Production and ad valorem taxes

    957        1,025        4,266        5,565        6,673        6,204        1,397   

Depletion and accretion

    6,217        5,077        22,629        21,050        37,978        41,428        20,595   

Impairment

                                60,045        299,422          

Net income (loss)

  $ 18,789      $ 12,252      $ 59,610      $ 35,111      $ (39,804   $ (157,291   $ 57,880   

Cash dividends declared per unit

                                                

Pro forma general partner’s interest in net income (loss)

  $ 19      $ 12      $ 60      $ 35      $ (40   $ (157   $ 58   

Pro forma limited partners’ interest in net income (loss)

  $ 18,770      $ 12,240      $ 59,550      $ 35,076      $ (39,764   $ (157,134   $ 57,822   

 

 

 

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Our predecessor

 
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    Three months
ended March 31,
    Year ended December 31,  
(in thousands, except per unit
amounts)
  2012     2011     2011     2010     2009     2008     2007  

 

 

Pro forma earnings per unit:

             

Pro forma net income (loss) per limited partner units:

             

Common units (basic)

  $      $      $      $      $      $      $   

Subordinated units

  $      $      $      $      $      $      $   

Common units (diluted)

  $      $      $      $      $      $      $   

Weighted average limited partner units outstanding:

             

Common units (basic)

             

Subordinated units

             

Common units (diluted)

             

 

 

 

(1)   For the three months ended March 31, 2012 and 2011 and the twelve months ended December 31, 2011, natural gas revenue included increases of $8.6 million, $5.1 million and $21.5 million, respectively, attributable to realized effects from derivatives.
(2)   For the three months ended March 31, 2012, NGL revenue included an increase of $0.5 million attributable to realized effects from derivatives.

 

              Our predecessor  
  

 

 

    

 

 

 
     As of
March 31,
     As of December 31,  
  

 

 

    

 

 

 
(in thousands)    2012      2011      2010      2009      2008      2007  

 

 

Balance sheet data:

                 

Total assets

   $ 416,089       $ 395,649       $ 336,088       $ 275,677       $ 360,032       $ 433,586   

Long-term debt

   $       $       $       $       $       $   

 

 

 

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Management’s discussion and analysis of financial condition and results of operations

The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors, including, without limitation, those set forth in “Risk factors,” “Forward-looking statements” and the other matters set forth in this prospectus. Except to the extent required by law, we undertake no obligation to publicly update any forward-looking statements for any reason, even if new information becomes available or other events occur in the future.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited interim financial statements of our predecessor and the notes thereto for the three months ended March 31, 2012 and 2011 and the audited financial statements of our predecessor and notes thereto for the years ended December 31, 2011, 2010 and 2009 contained elsewhere in this prospectus.

Overview

We are a Delaware limited partnership formed in November 2011 by Quicksilver to own and acquire oil and gas properties in North America that fit our acquisition criteria, which are mature onshore properties with long-lived reserves, predictable production profiles and modest capital requirements. Our primary business objective is to generate stable cash flows, allowing us to make quarterly cash distributions to our unitholders and, over time, to increase those quarterly cash distributions. We believe our properties are well-suited for our partnership because they consist of mature onshore oil and gas properties that fit our acquisition criteria.

Our properties

Following the contribution of the Partnership Properties to us, we will own oil and gas properties located in the Barnett Shale. As of December 31, 2011, our total proved reserves were 368.3 Bcfe, of which approximately 85% were classified as proved developed reserves, including 18.0 Bcfe classified as proved developed non-producing. Excluding the effect of commodity derivatives, 29.2%, 65.7% and 5.1% of our revenue for the three months ended March 31, 2012 was from natural gas, NGLs and oil, respectively, while 53.2%, 46.6% and 0.2% of our total proved reserves as of December 31, 2011 were from natural gas, NGLs and oil by volume, respectively. Based on our average net production for the three months ended March 31, 2012 of 59.6 Mmcfed, our total proved reserves had an annualized reserve-to-production ratio of 16.9 years. Based on our anticipated average net production for the twelve months ending June 30, 2013 of 62.3 Mmcfed, our reserve-to-production ratio would be 16.2 years. We operate all of the properties in which we have interests, and we own an average working interest of 98.8% in the wells and properties included in the Partnership Properties, with a weighted average net revenue interest of 78.9%, based on our proved reserves as of December 31, 2011. All of our oil and gas reserves are in the Barnett Shale.

How we conduct our business and evaluate our operations

We use a variety of financial and operational metrics to assess the performance of our oil and gas operations, including:

 

 

production volumes;

 

 

wellhead and realized prices on our production, including the effect of our commodity derivatives;

 

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lease operating expense;

 

 

production and ad valorem taxes; and

 

 

Adjusted EBITDA.

Production volumes

Production volumes directly impact our results of operations. For more information about our predecessor’s production volumes, please read “—Results of operations—years ended December 31, 2011, 2010 and 2009.”

Wellhead and realized prices on the sale of our production

Factors affecting the sales price of our production.    Quicksilver sells our production to a variety of purchasers based on regional pricing. The relative prices we receive are determined by the factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, relative prices are heavily influenced by product quality and location relative to consuming and refining markets.

Natural gas.    The NYMEX-Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The dry natural gas residue from our properties is transported and generally sold on index prices in the region. Location differentials to NYMEX-Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered and individual supply and demand dynamics at each location. We sell our natural gas production into major market points, which minimizes the discount from NYMEX-Henry Hub that would exist if we sold our production at the wellhead. However, since we sell our natural gas production into major market points, we are required to pay the transportation expense for our natural gas to reach those sales points.

Natural gas with a high energy content is referred to as “wet gas.” Certain of our properties produce wet gas, which has a higher value at the wellhead than natural gas with a lower energy content. When comparing prices received from production among producers in a region, it is important to compare wellhead prices as all producers have unique natural gas streams as well as unique contracts that take their natural gas to the sales markets. Because of our high energy content natural gas and Quicksilver’s downstream contracts from which we expect to benefit under our omnibus agreement, we believe that our wellhead prices compare favorably with other natural gas producers with a lower energy content. Although we do not sell our production at the wellhead, wellhead prices on a per Mcfe basis can be calculated by dividing the revenue we receive for our natural gas and NGL production by the volume of natural gas produced at the wellhead.

NGLs.    Wet gas can be sold at the wellhead or, as is the case with our production, transported to a gas processing plant where the NGLs are separated from the wet gas leaving an NGL product called Y-Grade and dry gas residue. After processing, both the Y-Grade and dry gas residue are transported from or sold at a gas processing plant’s “tailgate.” The Y-Grade recovered from the processing of our wet gas is transported to Mont Belvieu where it is fractionated into its five primary NGL components and sold based on posted prices.

The wellhead Btu for our natural gas from Hood and Somervell Counties has an average energy content of approximately 1,225 Btu, minimal sulfur and CO2 content and generally receives a

 

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premium valuation. For all of the properties that we operate that produce wet gas, Quicksilver has agreements in place with third parties to process this natural gas in order to receive the revenue benefit of the NGLs that are generated from processing.

Oil.    The NYMEX-WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX-WTI price as a result of quality and location differentials.

Oil makes up a minor amount of our production (approximately 2% for the three months ended March 31, 2012). The oil produced from our properties generally has a low sulfur content. We sell our oil at the NYMEX-WTI price, adjusted by a quality and transportation differential that varies by location and purchaser. Our oil normally sells at a discount to the NYMEX-WTI price.

Commodity derivatives.    Our hedging philosophy is to stabilize a significant portion of our incoming cash flow by reducing our exposure to commodity price volatility. We intend to enter into commodity derivatives covering approximately 60% to 85% of our estimated production over a three-to-five year period. We may, however, from time to time hedge more or less than this approximate range or change this range. Additionally, we intend to treat the commodity derivatives as hedges for accounting purposes, which will require us to have elevated documentation and regression measurement efforts, but which we believe will eliminate volatility in our earnings arising from changes in the value of our commodity derivatives attributable to future production periods.

At the closing of this offering, Quicksilver will novate to us commodity derivatives covering 30 Mmcfd of natural gas production with a weighted average floor of $6.00 for 2012, 2013, 2014 and 2015 and 3 Mbbld of NGL production with a weighted average floor of $46.16 for 2012.

Lease operating expense.    Lease operating expense is the cost incurred in the operation of producing properties, including workover costs, as appropriate. Expenses for utilities, direct labor, water disposal and materials and supplies comprise the most significant portion of our lease operating expense. Lease operating expense does not include general and administrative expenses, production and other taxes or midstream expenses. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased lease operating expense in periods during which they are performed.

The most significant variable lease operating expense that we incur is for the handling and disposal of produced water. Over the life of our production, the amount of water produced relative to the net production sold generally increases. Thus, when combined with allocated fixed costs, the production of a given volume of natural gas gets more expensive each year throughout the life of a well until, at some point, continued production becomes uneconomic. We believe that Quicksilver, which will operate our properties pursuant to our omnibus agreement, has a demonstrated track record of containing lease operating expense, which we believe will help extend the economic life of our fields and improve the cash margin of producing our natural gas.

We monitor our production expenses and operating costs to determine if any wells or properties should be shut in, recompleted or potentially sold. We typically evaluate our lease operating expense on a per Mcfe basis, which allows us to monitor our lease operating expense against other producers.

 

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Production and ad valorem taxes.    Texas regulates the development, production, gathering and sale of natural gas, NGLs and oil, including imposing production taxes and requirements for obtaining drilling permits. Specifically, Texas currently imposes a production tax at 4.6% of the market value of the oil produced, 3/16 of one cent per Bbl of oil produced and a production tax of 7.5% of the market value of the natural gas produced. However, a significant portion of our wells are either currently exempt from production tax due to high cost natural gas abatement or given a reduced rate for post-production cost recoupment. Ad valorem taxes are generally tied to the valuation of the oil and gas properties; however, these valuations are reasonably correlated to revenue, excluding the effects of any commodity derivatives.

Adjusted EBITDA

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements to assess our operating performance as compared to that of other companies and partnerships in our industry, without regard to financing methods, capital structure or historical cost basis. Adjusted EBITDA will also be used by our management as a factor to evaluate actual cash flow available to pay distributions to our unitholders. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. Adjusted EBITDA is defined in “Summary—Summary historical financial data—Non-GAAP financial measure.”

Outlook

Beginning in the second half of 2008, the United States and other industrialized countries experienced a significant economic slowdown, which led to a substantial decline in worldwide energy demand. During this same period, the North American natural gas supply was increasing as a result of the rise in domestic unconventional natural gas production. The combination of lower energy demand due to the economic slowdown and higher North American natural gas supply resulted in significant declines in commodity prices. While oil and NGL prices have increased since the second quarter of 2009, natural gas prices remained volatile throughout 2010 and 2011 due to a continued increase in natural gas supply despite weaker offsetting demand growth. The outlook for a worldwide economic recovery remains uncertain for the foreseeable future, and the timing of a recovery in worldwide demand for energy is difficult to predict. As a result, it is likely that commodity prices will continue to be volatile in 2012. For example, natural gas prices fell during the latter half of 2011 and continued to fall during the first quarter of 2012, returning to the low levels realized in 2009 after the economic slowdown. Sustained periods of low commodity prices could materially and adversely affect our financial position, our results of operations, the quantities of oil and gas that we can economically produce and our access to capital.

Significant factors that may impact future commodity prices include the political and economic developments currently impacting North Africa and the Middle East in general; the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas; and the overall North American oil and natural gas supply and demand fundamentals. Although we cannot predict the occurrence of events that will affect future commodity prices or the degree to which these prices

 

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will be affected, the prices we receive for our production will generally approximate market prices in the geographic region of the production.

We also face the challenge of natural production declines. As reservoir pressures decline, production from a given well or formation decreases. Our future growth will depend on our ability to continue to add proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through acquisitions, including from properties we may acquire from Quicksilver, development projects and improving the economics of our properties. We expect that acquisition opportunities may come from Quicksilver and its affiliates, as well as from unrelated third parties. Our ability to add reserves through acquisitions and development projects is dependent on many factors, including our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions. Please read “Risk factors—Risks related to our business” for a discussion of these and other risks affecting our proved reserves and production.

Quantitative and qualitative disclosure about market risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below.

Commodity price risk

Quicksilver Production Partners

Our major market risk exposure is the price that we receive for our production. Realized pricing is primarily driven by the spot market prices applicable to where we sell our production. The prices we receive for our production depend on many factors outside of our control, such as the strength of the global economy.

In order to reduce the impact of fluctuations in commodity prices on our revenue, or to protect the economics of property acquisitions, we intend to maintain a commodity derivative position covering a significant portion of our estimated production through various transactions that reduce the volatility of the future prices received. These transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into fixed price physical sales, commodity derivatives, such as collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or we pay the excess, if any, of the floating rate over the fixed ceiling price, or put options, whereby we receive the excess, if any, of the contract floor price over the reference price based on NYMEX quoted prices. These hedging activities are intended to manage our exposure to commodity price fluctuations. We do not expect to enter into commodity derivatives for speculative trading purposes.

Predecessor

Our predecessor’s major market risk exposure was the price that it received for its production. Realized pricing was primarily driven by the spot market prices applicable to where it sold its production. The prices our predecessor received for its production depended on many factors outside of its control, such as the strength of the global economy.

 

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In order to reduce the impact of fluctuations in commodity prices on our predecessor’s revenue, our predecessor periodically entered into commodity derivatives covering a significant portion of its estimated production that fixed the future prices received. Under the price swaps entered into by our predecessor, it received a fixed price for its production and paid a variable market price to the contract counterparty. These activities were intended to manage our predecessor’s exposure to commodity price fluctuations. Our predecessor did not enter into commodity derivatives for speculative trading purposes.

The following table summarizes our predecessor’s open commodity derivative positions as of March 31, 2012, which positions we will receive as part of the Quicksilver Contributions at the closing of this offering:

 

Product

  Type     Remaining contract
period
  Volume     Weighted
average
price
    Fair value  
                          Total     2012     2013     2014     2015  

 

 
                          (in thousands, except per unit amounts)  

Gas

    Swap      Apr. 2012 – Dec. 2015     10 Mmcfd      $ 6.00/Mcf      $ 32,439      $ 9,610      $ 9,184      $ 7,382      $ 6,263   

Gas

    Swap      Apr. 2012 – Dec. 2015     20 Mmcfd        6.00/Mcf        64,615        19,201        18,310        14,681        12,423   

NGL

    Swap      Apr. 2012 – Dec. 2012     1,000 Bbld        46.55/Bbl        1,091        1,091                        

NGL

    Swap      Apr. 2012 – Dec. 2012     1,000 Bbld        47.99/Bbl        1,486        1,486                        

NGL

    Swap      Apr. 2012 – Dec. 2012     1,000 Bbld        43.94/Bbl        373        373                        

 

 

The commodity derivative program resulted in our predecessor receiving different prices for its production than prevailing market prices. As a result of settlements of commodity derivatives, our predecessor’s production revenue was greater by $9.1 million and $5.1 million for the three months ended March 31, 2012 and 2011, respectively, and $21.5 million for the year ended December 31, 2011, but production revenue for 2010 and 2009 was not impacted.

At December 31, 2011, anticipated production from proved reserves subsequent to 2013 was less than the notional volume covered by derivatives for natural gas for such periods. However, we intend to address the shortfall through successful execution of our long-term drilling program on identified unproved drilling locations.

Interest rate risk

Quicksilver Production Partners

At the closing of this offering, we expect to borrow $150 million under our new revolving credit facility (based upon the assumed midpoint of the price range set forth on the cover of this prospectus), which we believe will have an assumed interest rate of LIBOR plus     %. Assuming no change in the amount outstanding, the impact on interest expense of a 10% increase or decrease in the average interest rate would be approximately $         million. In the future, we may enter into interest rate derivative contracts on a portion of our outstanding debt to mitigate the risk of fluctuations in LIBOR.

Predecessor

Our predecessor had no indebtedness and, as a result, had no interest rate risk.

 

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Counterparty and customer credit risk

Quicksilver Production Partners

Joint interest risk arises in circumstances where other entities own partial interests in the wells we operate. We expect risk related to our joint interest partners to be minimal because we have few instances where third parties own working interests in wells we operate or will drill.

We are also subject to credit risk due to the concentration of the receivables for our production with several significant customers. For further information about our significant customers, please read “Business and properties—Partnership Properties—Marketing, delivery commitments and purchasers of our production” and “Risk factors—Risks related to our business—We may experience a financial loss if Quicksilver is unable to receive payment for a significant portion of our production.” The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our commodity derivatives expose us to credit risk in the event of nonperformance by counterparties.

While we have the ability to require the counterparties to our commodity derivatives to post collateral, in certain circumstances, we may not require that such collateral be posted. We intend to have a formal process in place to evaluate and assess the credit standing of the counterparties to our commodity derivatives or our significant customers. We will evaluate the credit standing of such counterparties and our customers as we deem appropriate under the circumstances. This evaluation may include reviewing a counterparty’s credit rating and latest financial information or, in the case of a customer with which we have receivables, reviewing their historical payment record, the financial ability of the customer’s parent company to make payment if the customer cannot and performing the due diligence to set credit terms and credit limits. The counterparties to the commodity derivatives that will be novated to us at the closing of this offering carried investment grade ratings and were lenders under Quicksilver’s credit facility at the time our predecessor entered into such commodity derivatives. We are likely to enter into future commodity derivatives with these or other counterparties that also carry investment grade ratings and lenders under our new revolving credit facility. Several of our significant customers have a below investment grade credit rating or do not have rated debt securities. In these circumstances, we will consider the lack of investment grade credit rating in addition to the other factors described above to set credit terms and credit limits.

After the closing of this offering, we will be dependent on Quicksilver to operate our assets and to perform other general, administrative and operational services for us and our general partner and are consequently subject to the risk of non-performance of such services under our omnibus agreement with Quicksilver. Quicksilver’s credit ratings are below investment grade, and we expect its credit ratings to remain below investment grade for the foreseeable future. Accordingly, the risk of non-performance under our omnibus agreement will be higher than it would be with a more creditworthy contract counterparty or with a more diversified group of operators or service providers. We expect to continue to be subject to significant and non-diversified risk of non-performance of such services.

Predecessor

Joint interest risk arose in circumstances where other entities owned partial interests in the wells our predecessor operated. Risk related to our predecessor’s joint interest partners was minimal because our predecessor had few instances where third parties owned working interests in wells our predecessor operated or drilled.

 

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Our predecessor was also subject to credit risk due to the concentration of the receivables for its production with several significant customers. Please read “Business and properties—Partnership Properties—Marketing, delivery commitments and purchasers of our production” for further detail about our predecessor’s significant customers. Our predecessor’s commodity derivatives exposed our predecessor to credit risk in the event of nonperformance by counterparties.

While Quicksilver had the ability to require the counterparties to our predecessor’s commodity derivatives to post collateral, in certain circumstances, it did not require that such collateral be posted. Quicksilver had a formal process in place to evaluate and assess the credit standing of the counterparties to our predecessor’s commodity derivatives or its significant customers. Quicksilver evaluated the credit standing of such counterparties and its customers as it deemed appropriate under the circumstances. This evaluation included reviewing a counterparty’s credit rating and latest financial information or, in the case of a customer with which our predecessor had receivables, reviewing their historical payment record, the financial ability of the customer’s parent company to make payment if the customer could not and undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties to our predecessor’s commodity derivatives carried investment grade ratings and were lenders under Quicksilver’s credit facility at the time our predecessor entered into such commodity derivatives. Several of our predecessor’s significant customers had a below investment grade credit rating or did not have rated debt securities. In these circumstances, our predecessor considered the lack of investment grade credit rating in addition to the other factors described above.

Results of operations—three months ended March 31, 2012 and 2011

The following discussion compares the results of our predecessor’s operations for the three months ended March 31, 2012 and 2011, which we refer to as the 2012 period and the 2011 period, respectively.

Revenue

Production revenue:

 

Three months ended March 31,

(in thousands)

  Natural gas     NGL     Oil     Total  
  2012     2011     2012     2011     2012     2011     2012     2011  

 

 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total before derivatives

  $ 7,621      $ 11,195      $ 17,123      $ 16,593      $ 1,332      $ 1,252      $ 26,076      $ 29,040   

Realized gain on derivatives

    8,638        5,126        465                             9,103        5,126   
 

 

 

 

Total including realized gain on derivatives

  $ 16,259      $ 16,321      $ 17,588      $ 16,593      $ 1,332      $ 1,252      $ 35,179      $ 34,166   

 

 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Average daily production volume:

 

Three months ended March 31,   Natural
gas
    NGL     Oil     Total  
  2012     2011     2012     2011     2012     2011     2012     2011  

 

 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    (Mmcfd)     (Mbbld)     (Mbbld)     (Mmcfed)  

Total

    32.1        31.0        4.4        4.2        0.1        0.2        59.6        57.1   

 

 

 

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Average realized price:

 

Three months ended March 31,

   Natural gas      NGL      Oil      Total  
   2012      2011      2012      2011      2012      2011      2012      2011  

 

 
     (per Mcf)      (per Bbl)      (per Bbl)      (per Mcfe)  

Total before derivatives

   $ 2.61       $ 4.02       $ 42.51       $ 43.88       $ 98.66       $ 91.31       $ 4.81       $ 5.65   

Realized gain on derivatives

     2.95         1.84         1.15                                 1.68         1.00   
  

 

 

 

Total including realized gain on derivatives

   $ 5.56       $ 5.86       $ 43.66       $ 43.88       $ 98.66       $ 91.31       $ 6.49       $ 6.65   

 

 

The following table summarizes the changes in our predecessor’s production revenue:

 

(in thousands)    Natural
gas
    NGL     Oil     Total  

 

 

Total for the 2011 period

   $ 16,321      $ 16,593      $ 1,252      $ 34,166   

Volume variances

     555        1,080        (19     1,616   

Hedge settlement variances

     3,512        465               3,977   

Price variances

     (4,129     (550     99        (4,580
  

 

 

 

Total for the 2012 period

   $ 16,259      $ 17,588      $ 1,332      $ 35,179   

 

 

The increase in our predecessor’s production revenue during the 2012 period compared with the 2011 period is primarily the result of wells tied into sales since the 2011 period, offset by lower realized prices. The commodity price decrease was offset by hedge settlements.

Other revenue:

Other revenue for the three months ended March 31, 2012 and 2011 was $6.7 million and $0, respectively. At the end of December 31, 2011, a derivative no longer qualified as a cash flow hedge, which resulted in the incremental fair value being recorded to the income statement in other revenue. The $6.7 million gain was comprised of $0.3 million of realized gains and $6.4 million of unrealized gains due to lower future natural gas prices.

Operating expense

Lease operating

 

Three months ended March 31,

(in thousands, except per unit amounts)

   2012      Per Mcfe      2011      Per Mcfe  

 

  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 5,079       $ 0.94       $ 5,308       $ 1.03   

 

 

Lease operating expense decreased for the 2012 period primarily due to decreased salt water disposal cost, and the per Mcfe decrease was due to fixed costs being spread across higher production.

Gathering, processing and transportation

 

Three months ended March 31,

(in thousands, except per unit amounts)

   2012      Per Mcfe      2011      Per Mcfe  

 

  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 7,543       $ 1.39       $ 7,651       $ 1.49   

 

 

Gathering, processing and transportation expense per Mcfe decreased in the 2012 period due to lower electricity cost and the production mix between areas within the Barnett Shale.

 

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Production and ad valorem taxes

 

Three months ended March 31,

(in thousands, except per unit amounts)

   2012      Per Mcfe      2011      Per Mcfe  

 

  

 

 

    

 

 

    

 

 

    

 

 

 

Production taxes

   $ 357       $ 0.07       $ 425       $ 0.08   

Ad valorem taxes

     600         0.11         600         0.12   
  

 

 

       

 

 

    

Total

   $ 957       $ 0.18       $ 1,025       $ 0.20   

 

 

Depletion and accretion

 

Three months ended March 31,

(in thousands, except per unit amounts)

   2012      Per Mcfe      2011      Per Mcfe  

 

 

Depletion

   $ 6,087       $ 1.12       $ 5,024       $ 0.98   

Accretion

     130         0.02         53         0.01   
  

 

 

       

 

 

    

Total

   $ 6,217       $ 1.15       $ 5,077       $ 0.99   

 

 

Depletion expense increased in the 2012 period from the 2011 period due to a higher depletion base associated with our capital program, higher future development costs and a decrease in reserves.

General and administrative

 

Three months ended March 31,

(in thousands, except per unit amounts)

   2012      Per Mcfe      2011      Per Mcfe  

 

 

Total

   $ 3,072       $ 0.57       $ 2,675       $ 0.52   

 

 

General and administrative expense increased due to higher professional fees primarily related to the audit of our sponsor, Quicksilver, during the 2012 period.

Income taxes

 

Three months ended March 31,

(in thousands, except percentage amounts)

   2012      2011  

 

 

Income tax expense

   $ 210       $ 178   

Effective tax rate

     1.1%         1.4%   

 

 

Income tax expense was solely comprised of taxes due under the Texas franchise tax.

Results of operations—years ended December 31, 2011, 2010 and 2009

The following discussion compares the results of operations for our predecessor for 2011, 2010 and 2009.

Revenue

Production revenue:

 

Year ended December 31,

(in millions)

  Natural gas     NGL     Oil     Total  
  2011     2010     2009     2011     2010     2009     2011     2010     2009     2011     2010     2009  

 

 

Total before derivatives

  $ 49.3      $ 55.0      $ 68.7      $ 75.8      $ 67.1      $ 65.2      $ 4.9      $ 5.8      $ 8.1      $ 130.0      $ 127.9      $ 142.0   

Realized gain on derivatives

    21.5                                                                21.5                 
 

 

 

 

Total including realized gain on derivatives

  $ 70.8      $ 55.0      $ 68.7      $ 75.8      $ 67.1      $ 65.2      $ 4.9      $ 5.8      $ 8.1      $ 151.5      $ 127.9      $ 142.0   

 

 

 

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Average daily production volume:

 

Year ended December 31,   Natural gas     NGL     Oil     Total  
  2011     2010     2009     2011     2010     2009     2011     2010     2009     2011     2010     2009  

 

 
    (Mmcfd)        (Mbbld)       
(Mbbld)
  
    (Mmcfed)   

Total

    34.1        34.9        48.4        4.3        5.0        6.6        0.1        0.2        0.4        60.7        66.0        90.4   

 

 

Average realized price:

 

Year ended December 31,   Natural gas     NGL     Oil     Total  
  2011     2010     2009     2011     2010     2009     2011     2010     2009     2011     2010     2009  

 

 
    (per Mcf)     (per Bbl)    

(per Bbl)

    (per Mcfe)  

Total before derivatives

  $ 3.96      $ 4.32      $ 3.89      $ 48.45      $ 37.00      $ 27.13      $ 91.79      $ 74.42      $ 52.23      $ 5.87      $ 5.31      $ 4.30   

Realized gain on derivatives

    1.73                                                                0.97                 
 

 

 

 

Total including realized gain on derivatives

  $ 5.69      $ 4.32      $ 3.89      $ 48.45      $ 37.00      $ 27.13      $ 91.79      $ 74.42      $ 52.23      $ 6.84      $ 5.31      $ 4.30   

 

 

The following table summarizes the changes in our predecessor’s production revenue:

 

(in thousands)    Natural gas     NGL     Oil     Total  

 

 

Total for 2009

   $ 68,664      $ 65,218      $ 8,142      $ 142,024   

Volume variances

     (19,157     (16,008     (4,069     (39,234

Price variances

     5,488        17,907        1,730        25,125   
  

 

 

 

Total for 2010

     54,995        67,117        5,803        127,915   

Volume variances

     (1,239     (9,208     (1,850     (12,297

Hedge settlement variances

     21,463                      21,463   

Price variances

     (4,454     17,918        923        14,387   
  

 

 

 

Total for 2011

   $ 70,765      $ 75,827      $ 4,876      $ 151,468   

 

 

Production revenue for 2011 increased from 2010 due to natural gas hedge settlements and higher prevailing prices for NGLs and oil during the year. This was partially offset by production decreases for all our predecessor’s products as properties continued to age and lower prevailing natural gas prices.

The decrease in our predecessor’s production revenue during 2010 compared with 2009 was due principally to a decrease in our predecessor’s production as its properties aged and operational curtailments due to completion operations on adjacent wells. This was partially offset by higher prevailing prices for all of our predecessor’s products.

Operating expense

Lease operating

 

Year ended December 31,        
(in thousands, except per unit amounts)    2011      Per Mcfe      2010      Per Mcfe      2009      Per Mcfe  

 

 

Total

   $ 22,125       $ 1.00       $ 20,257       $ 0.84       $ 19,023       $ 0.58   

 

 

Lease operating expense increased during 2011 due to increases in workover activity associated with our predecessor’s aging wells and an increase in gas lift expense.

 

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Lease operating expense increased during 2010 due almost entirely to increases in workover activity associated with our predecessor’s aging wells. On a per Mcfe basis, the effect of these increases were amplified by the lower production levels previously discussed.

Gathering, processing and transportation

 

Year ended December 31,

(in thousands, except per unit amounts)

   2011      Per Mcfe      2010      Per Mcfe      2009      Per Mcfe  

 

 

Total

   $ 30,841       $ 1.39       $ 32,705       $ 1.36       $ 41,891       $ 1.27   

 

 

Gathering, processing and transportation expense decreased in 2011 due to lower production, while gathering, processing and transportation expense per Mcfe increased in 2011 from 2010 due to the production mix between areas within the Barnett Shale.

Gathering, processing and transportation expense decreased in 2010 due to decreased production, while gathering, processing and transportation expense per Mcfe increased in 2010 from 2009 due to increased compression rates resulting from lower line pressures on the gathering system and the impact of annual inflation rate adjustments under Quicksilver’s gathering, processing and transportation agreements.

Production and ad valorem taxes

 

Year ended December 31,

(in thousands, except per unit amounts)

   2011      Per Mcfe      2010      Per Mcfe      2009      Per Mcfe  

 

 

Production taxes

   $ 1,839       $ 0.08       $ 1,778       $ 0.07       $ 1,970       $ 0.06   

Ad valorem taxes

     2,427         0.11         3,787         0.16         4,703         0.14   
  

 

 

       

 

 

       

 

 

    

Total

   $ 4,266       $ 0.19       $ 5,565       $ 0.23       $ 6,673       $ 0.20   

 

 

Production taxes increased in total in 2011 from 2010 and on a per Mcfe basis due to a higher average realized price per Mcfe before derivatives.

Ad valorem taxes and per Mcfe amounts decreased in 2011 from 2010 due to a decline in assessed value on mature wells.

Production taxes decreased in 2010 from 2009 due to lower production. On a per Mcfe basis, production taxes increased due to an increase in our predecessor’s realized prices.

Ad valorem taxes and per unit amounts decreased in 2010 from 2009 due to a decline in assessed value on mature wells, which caused a $1.0 million decrease in ad valorem expense.

Depletion and accretion

 

Year ended December 31,

(in thousands, except per unit amounts)

   2011      Per Mcfe      2010      Per Mcfe      2009      Per Mcfe  

 

 

Depletion

   $ 22,408       $ 1.01       $ 20,876       $ 0.86       $ 37,816       $ 1.15   

Accretion

     221         0.01         174         0.01         162           
  

 

 

       

 

 

       

 

 

    

Total

   $ 22,629       $ 1.02       $ 21,050       $ 0.87       $ 37,978       $ 1.15   

 

 

Depletion expense increased in 2011 from 2010 due to a higher depletion base associated with our 2011 capital program, higher future development costs and a decrease in reserves.

 

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Depletion expense decreased in 2010 from 2009 due primarily to both lower production and to the impact of the impairment recorded in 2009, which reduced the depletable base and the depletion rate.

Impairment

Our predecessor performed annual ceiling tests to assess impairment of its oil and gas properties. Information detailing the calculation of any impairment is more fully described in “—Our and our predecessor’s critical accounting policies” below and in our predecessor’s financial statements found elsewhere in this prospectus.

There were no impairment charges for 2010 or 2011. Our predecessor recognized non-cash charges of $60.0 million for impairment of its oil and gas properties during 2009. All of our predecessor’s impairments have resulted from the decrease in prevailing prices of natural gas since 2007.

General and administrative

 

Year ended December 31,

(in thousands, except per unit amounts)

   2011      Per Mcfe      2010      Per Mcfe      2009      Per Mcfe  

 

 

Total

   $ 10,959       $ 0.49       $ 12,389       $ 0.51       $ 16,132       $ 0.49   

 

 

General and administrative expense decreased in 2011 from 2010 due to lower general and administrative expense allocated to our predecessor from Quicksilver. This decrease was a result of our predecessor’s production decreasing as a percentage of the total U.S. Quicksilver production. The decrease was offset by higher professional fees and increased office rent, which were allocated to our predecessor by Quicksilver.

General and administrative expense decreased in 2010 from 2009 due to lower general and administrative expense allocated to our predecessor from Quicksilver. This resulted from a decrease in our predecessor’s production and the increase in production for other Quicksilver properties. The amount of the general and administrative allocation base increased 14% in 2010 from 2009, primarily related to higher costs associated with office rent and relocation plus an increase in information technology costs, which caused the increase in per Mcfe costs.

General and administrative expense allocated to our predecessor included a portion of equity compensation at Quicksilver.

Income taxes

 

Year ended December 31,

(in thousands, except percentage amounts)

   2011      2010      2009  

 

 

Income tax expense

   $ 1,038       $ 838       $ 86   

Effective tax rate

     1.7%         2.3%         (0.2)%   

 

 

Income tax expense is solely comprised of taxes due under the Texas franchise tax.

 

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Liquidity and capital resources

Cash flows

Quicksilver Production Partners

Changes to our cash flow from operations are primarily driven by realized commodity prices, including realized commodity derivative settlements, and production volumes. Prices for natural gas, NGLs and oil are driven primarily by supply and demand, which are impacted by national and international economic and political environments and seasonal influences of weather. Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices could decrease our development expenditures.

Predecessor

Changes to our predecessor’s cash flow from operations were primarily driven by realized commodity prices, including realized commodity derivative settlements, and production volumes. Prices our predecessor received for its production were driven primarily by supply and demand, which was impacted by national and international economic and political environments and seasonal influences of weather. Our predecessor’s working capital was significantly influenced by changes in commodity prices. Our predecessor’s cash flow from operations increased in 2011 from 2010 due principally to the increase in realized derivative settlements and higher prevailing prices for NGLs. Our predecessor’s cash flows from operations were flat between 2010 and 2009 due to the decreased production revenue of $14 million and decreased cash operating costs of $13 million.

Our predecessor decreased capital expenditures in 2011 from 2010 as a result of decreased commodity prices. Costs incurred during 2011 were primarily attributable to drilling activities. Our predecessor’s capital expenditures decreased from 2009 to 2010 due to decreased capital expenditures in response to decreased commodity prices offset by the acquisition of proved developed resources.

The following table summarizes our predecessor’s sources and uses of funds for the periods noted:

 

      Three months ended
March 31,
    Year ended December 31,  
(in thousands)    2012     2011     2011     2010     2009  

 

 

Net cash provided by operating activities

   $ 16,722      $ 13,205      $ 83,011      $ 57,391      $ 62,345   

Net cash used by investing activities

     (10,535     (8,392     (37,530     (39,814     (41,882

Net cash used by financing activities

   $ (6,187   $ (4,813   $ (45,481   $ (17,577   $ (20,463

 

 

Liquidity and borrowing capacity

Quicksilver Production Partners

We expect that our primary sources of liquidity and capital resources after the consummation of the offering will be cash flows generated by operating activities and borrowings under the new revolving credit facility that we intend to enter into concurrently with the closing of this offering. We may also have the ability to issue additional equity and debt as needed.

 

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We plan to enter into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Under this strategy, we intend to enter into commodity derivatives at times and on terms desired to maintain a portfolio of commodity derivatives covering approximately 60% to 85% of our estimated production over a three-to-five year period at a given point in time, although we may from time to time hedge more or less than this approximate range or change the range.

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders, including our general partner. In making cash distributions, our general partner will attempt to avoid large variations in the amount we distribute from quarter to quarter. In order to facilitate this, our partnership agreement will permit our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows our general partner to borrow funds to make distributions.

We may borrow to make distributions to our unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to sustain our level of distributions. In addition, we plan to hedge a significant portion of our production. We generally will be required to settle our commodity derivatives within five days of the end of the month. As is typical in the oil and gas industry, we do not generally receive the proceeds from the sale of our hedged production until 45 to 60 days following the end of the month. As a result, when commodity prices increase above the fixed price in the commodity derivative contract, we will be required to pay the derivative counterparty the difference between the fixed price in the commodity derivative contract and the market price before we receive the proceeds from the sale of the hedged production. If this occurs, we may make working capital borrowings to fund our distributions. Because we will distribute all of our available cash, we will not have those amounts available to reinvest in our business to increase our proved reserves and production and as a result, we may not grow as quickly as other oil and gas entities or at all.

We plan to reinvest a sufficient amount of our cash flow to fund our maintenance capital expenditures, and we plan to primarily use external financing sources, including commercial bank borrowings and the issuance of debt and equity interests, rather than cash reserves established by our general partner, to fund our growth capital expenditures and any acquisitions. Because our proved reserves and production continually decline over time and because we own a limited amount of undeveloped properties, we expect that we will need to make acquisitions to sustain our level of distributions to unitholders over time.

If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures, reduce distributions to unitholders, and/or fund a portion of our capital expenditures using borrowings under our new revolving credit facility, issuances of debt and equity securities or from other sources, such as asset sales. We cannot assure you that needed capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by the covenants in our new revolving credit facility. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves.

 

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Concurrently with the closing of this offering, we expect that we, as parent guarantor, our wholly-owned subsidiary, Quicksilver Production Partners Operating Ltd., as initial borrower (and, following the initial borrower’s redomiciliation as a Delaware limited liability company promptly following the closing of this offering, Quicksilver Production Partners Operating LLC, as borrower (the use of the term “borrower” in this description of the revolving credit facility is intended to refer to the initial borrower, prior to such redomiciliation and thereafter, the borrower)) and JPMorgan Chase Bank, N.A., as administrative agent will enter into a new secured borrowing base revolving credit facility. We expect this new facility will be a five-year, $750 million revolving credit facility with an initial borrowing base of $275 million.

The new revolving credit facility will be a borrowing base facility, and, as such, revolving credit loans and letters of credit may be provided to the borrower from time to time in an aggregate amount up to the borrowing base. Borrowings will bear interest at a variable annual rate based on adjusted LIBOR or the alternate base rate plus, in each case, an applicable margin. The applicable margin will increase as the utilization of the borrowing base increases and is expected to range, for LIBOR loans, from 1.75% up to 2.75%. The amount of the borrowing base will be determined by the administrative agent based on the estimated value of the borrower’s proved (included proved producing, non-producing and undeveloped) reserves. The borrowing base is scheduled to be re-determined semi-annually based upon reserve reports and such other information deemed appropriate by the administrative agent, in a manner consistent with its normal oil and gas lending criteria as it exists at the time of such redetermination. All of the lenders must approve any increase to the borrowing base and lenders having 66 2/3% of the aggregate revolving loans outstanding under the revolving credit facility at such time must approve any decrease to the borrowing base or the maintenance of the then-existing borrowing base.

Borrowings under the revolving credit facility will be guaranteed by us and substantially all future restricted, domestic subsidiaries of the borrower and will be secured by 100% of the equity interests of the borrower and liens on substantially all of the oil and gas properties and related assets of the borrower, but in any event, not less than 80% of the total value of the oil and gas properties evaluated in the most recently delivered reserve report of the borrower.

The revolving credit facility includes certain financial covenants, which require the maintenance of a minimum current ratio of not less than 1.0 to 1.0 and a minimum earnings (before interest, taxes, depreciation, depletion and amortization) to cash interest expense ratio of not less than 2.5 to 1.0. Our ability to make distributions to our unitholders is contingent on our compliance with these financial covenants and there being no default or borrowing base deficiency under our new revolving credit facility. The calculation of earnings (before interest, taxes, depreciation, depletion and amortization) under our new revolving credit facility will be different than the calculation of Adjusted EBITDA used in this prospectus.

The revolving credit facility also contains certain restrictive covenants, which include, among other things, limitations on: debt; liens; restricted payments; repayment of debt; investments; merger and consolidation; sale of properties; amendments to organizational documents adverse to lenders; affiliate transactions; change in business; negative pledge agreements; swap agreements and amendments to the borrower’s tax status.

In addition, the revolving credit facility will contain customary events of default, including, but not limited to: (1) failure to make payments when due; (2) proven material inaccuracy of any representation or warranty; (3) failure to comply with certain restrictive or affirmative covenants;

 

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(4) default under other material debt; (5) specified events of bankruptcy, insolvency or reorganization involving us, the borrower or any restricted subsidiary; (6) one or more final, non-appealable judgments in excess of a certain aggregate amount; (7) a change of control and (8) loss of lien, perfection or priority or unenforceability of any collateral document.

If an event of default resulting from specified events involving our, the borrower’s or a restricted subsidiary’s bankruptcy, insolvency or reorganization occurs and is continuing, or we, the borrower or any restricted subsidiary admit in writing the inability or failure generally to pay debts when due, the commitments under the revolving credit facility will terminate and any principal and accrued interest owed thereunder will become immediately due and payable without any declaration or other act on the part of the lenders or the administrative agent. If any other event of default occurs and is continuing, the administrative agent may, and at the request of a majority of the lenders shall, terminate the commitments and/or declare any principal and accrued interest thereunder due and payable immediately.

Our ability to remain in compliance with any of the financial covenants may be affected by events beyond our control, including market prices for our products. Any future inability to comply with these covenants, unless waived by the requisite lenders, could adversely affect our liquidity by rendering us unable to borrow further under our new revolving credit facility and by accelerating the maturity of our indebtedness thereunder.

Predecessor

Historically, our predecessor’s primary source of liquidity and capital resources was cash flow from operations and funding provided by Quicksilver. Our predecessor had no indebtedness outstanding. For a discussion of our predecessor’s commodity derivatives, please read “—Quantitative and qualitative disclosure about market risk—Commodity price risk—Predecessor.”

Capital expenditures

Quicksilver Production Partners

Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our asset base (including our undeveloped leasehold acreage). The primary purpose of maintenance capital expenditures is to maintain our asset base at a steady level over the long term to maintain our distributions per unit. For the twelve months ending June 30, 2013, we have estimated our capital expenditures to be $12.2 million. Our average estimated annual maintenance capital expenditures from July 1, 2012 through December 31, 2016 are $30.3 million. We intend to fund these capital expenditures from operating cash flow. In 2012, we currently do not expect to have growth capital expenditures.

Growth capital expenditures are capital expenditures that are intended to increase the size of our asset base. The primary purpose of growth capital expenditures is to acquire producing assets that will increase our distributions per unit and secondarily increase the rate of development and production of our existing properties in a manner that is expected to be accretive to our unitholders. Growth capital expenditures may include projects on our existing asset base, such as additional infill drilling that increases the rate of production or provides new areas of future reserve growth. We expect to primarily rely upon external financing sources, including

 

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commercial bank borrowings and the issuance of debt and equity interests, rather than cash reserves established by our general partner, to fund growth capital expenditures and any acquisitions. Although we may make acquisitions during the 12-month forecast period ending June 30, 2013, including potential acquisitions of producing properties from Quicksilver, we have not estimated any growth capital expenditures related to potential opportunistic acquisitions because we cannot be certain that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase contracts. For more information regarding our acquisition strategy, please read “Business and properties—Our business strategies” and “Business and properties—Our relationship with Quicksilver.”

The amount and timing of our capital expenditures is largely discretionary and within our general partner’s control, with the exception of certain future projects that may be managed by other operators. If commodity prices decline below levels we deem acceptable, our general partner may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in commodity prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside of our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and labor crews.

Based on our current commodity price expectations, we anticipate that our cash flow from operations and available borrowing capacity under our new credit facility will exceed our planned capital expenditures and other cash requirements for the twelve months ending June 30, 2013. However, future cash flows are subject to a number of variables, including the level of our production and the prices we receive for our production. There can be no assurance that our operations and other capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures. Please read “Risk factors—Risks related to our business—Our acquisition and development operations require substantial capital expenditures, which will reduce our cash available for distribution and could materially affect our ability to make distributions to our unitholders” for more information.

Predecessor

Our predecessor did not distinguish between maintenance and growth capital expenditures. Its capital expenditures were funded from a combination of cash flow generated from operations and funding from its parent.

 

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Contractual obligations and commercial commitments

Contractual obligations of the Partnership Properties

The following table summarizes, by period, the payments due for the Partnership Properties’ contractual and scheduled interest obligations as of March 31, 2012:

 

      Payments due by year  
     Total      Less than
1 year
     1–3
years
     4–5
years
     More than
5 years
 

 

 
     (in thousands)  

Debt

   $       $       $       $       $   

Scheduled interest obligations

                                       

Asset retirement obligations

     10,782                                 10,782   
  

 

 

 

Total obligations

   $ 10,782       $       $       $       $ 10,782   

 

 

Debt.    As of March 31, 2012, there were no outstanding borrowings.

We expect that for borrowings under our new revolving credit facility, each additional $10 million in borrowings would result in additional annual interest payments of $         million.

Scheduled interest obligations.    As of March 31, 2012, the Partnership Properties had no borrowings and consequently no scheduled annual interest payments.

Gathering, processing and transportation contracts.    Under contracts with various third parties, Quicksilver has obligations to provide minimum daily natural gas volume for gathering, treating or transportation, as determined on a monthly basis, or pay for any volume deficiencies at a specified reservation fee rate. However, we will not have an obligation for any such minimum payments or volume deficiencies. We will be obligated to deliver dedicated gas under the applicable transportation and gathering contracts, but only in the amounts we produce. For a discussion of our gathering, treating and transportation contracts, see “Business and properties—Partnership Properties—Marketing, delivery commitments and purchasers of our production.”

Asset retirement obligations.    The Partnership Properties’ obligations result from the acquisition, construction or development and the normal operation of long-lived assets.

Commercial commitments

We have no standby letters of credit outstanding. Please read “—Off-balance sheet arrangements” below.

Commercial arrangements

Transactions with Quicksilver

Our historical results include allocations by Quicksilver for general and administrative expenses and salary, travel costs and other invoices paid by Quicksilver. During the three months ended March 31, 2012, and the years ended December 31, 2011, 2010 and 2009, we were allocated by Quicksilver $3.1 million, $11.0 million, $12.4 million and $16.1 million, respectively, for general and administrative expenses. Quicksilver also has contracts that dedicate its production to midstream companies and, in certain cases, such contracts require minimum monthly volumes. Although our properties are burdened by this dedication, we are not subject to the minimum volume requirements within those contracts; rather, we are only obligated to deliver what we produce.

 

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Off-balance sheet arrangements

We have no off-balance sheet arrangements. We had no surety bonds outstanding as of March 31, 2012. At the closing of this offering, we will cause surety bonds to be issued in an aggregate of $3.7 million with respect to the Partnership Properties, their wells and associated pipelines.

Our and our predecessor’s critical accounting policies

Critical accounting policies discussed in this section apply to both Quicksilver Production Partners and our predecessor. References to “our” in this section refer to Quicksilver Production Partners or our predecessor, as the context requires.

This discussion and analysis of our financial condition and results of operations is based upon our financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make assumptions and estimates about future events, and apply judgments that affect the reported amounts of assets, liabilities, revenue, expense and the related disclosures. We base our assumptions, estimates and judgments on historical experience, current trends and other factors that management believes to be relevant at the time we prepare our financial statements. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. On a regular basis, management reviews the accounting policies, assumptions, estimates and judgments to ensure that our financial statements are presented fairly and in accordance with GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ materially from our assumptions and estimates.

Described below are our critical accounting policies applied in preparing our financial statements. Our management believes that the following accounting estimates are the most critical in fully understanding and evaluating our reported financial results, and they require management’s most difficult, subjective or complex judgments, resulting from the need to make estimates about the effect of matters that are inherently uncertain. See notes to our financial statements under the heading “Note 2. Summary of significant accounting policies” for additional accounting policies and estimates by management.

Our proved reserves

Policy description

Proved reserves are the estimated quantities of natural gas, NGLs and oil that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. We utilized the current rule adopted by the SEC in December 2008 to estimate proved reserves for 2011, 2010 and 2009.

We use operating costs at period end, held constant into future periods, to determine proved reserve estimates. Our estimates of proved reserves are determined and reassessed at least annually using available geological and reservoir data as well as production performance data. Revisions may result from changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Our proved reserve estimates and related disclosures for 2011, 2010 and 2009 are presented in compliance with the current SEC rule.

 

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The current SEC rule allows proved undeveloped reserves to be booked beyond one offset location where reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

Judgments and assumptions

All of the proved reserve data in this prospectus are based on estimates. Estimates of our proved reserves are prepared in accordance with guidelines established by the SEC. Reservoir engineering is a subjective process of estimating recoverable underground accumulations of natural gas, NGLs and oil. In estimating recoverable quantities of proved natural gas, NGLs and oil, there are numerous uncertainties including the projection of future production rates and the expected timing of development expenditures. The accuracy of any proved reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, proved reserve estimates may be different from the quantities of natural gas, NGLs and oil that are ultimately recovered.

The passage of time provides more qualitative information regarding estimates of proved reserves, and revisions are made to prior estimates to reflect updated information. The average annual revision to our proved reserve estimates over the last three years have been less than 5% of the average of the previous year’s estimate (excluding revisions due to price changes). However, there can be no assurance that more significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated proved reserve quantities, it could result in a ceiling test-related impairment. In addition to the impact of the estimates of proved reserves on the calculation of the ceiling limitation, estimation of proved reserves is also a significant component of the calculation of depletion expense. For example, if estimates of proved reserves decline, the depletion rate will increase, resulting in a decrease in net income.

Oil and gas properties

Policy description

We use the full cost method to account for our oil and gas properties. Under the full cost method, all costs associated with our acquisition, development and production of our properties are capitalized and accumulated in a single cost center. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of proved reserves, in which case a gain or loss is calculated and recognized. The application of the full cost method generally results in higher capitalized costs and higher depletion rates compared to its alternative, the successful efforts method. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production basis using proved natural gas, NGL and oil reserves. Excluded from amounts subject to depletion are costs associated with unevaluated properties.

Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations or the cost center ceiling. The cost center ceiling is defined as the sum of (1) estimated future net revenue, discounted at 10% per annum, from proved reserves, based on the unweighted average of the

 

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preceding 12-month first day-of the-month prices adjusted to reflect local differentials and contract provisions, unescalated year-end costs and commodity derivatives that hedge our production revenue, (2) the cost of properties not being amortized and (3) the lower of cost or market value of unproved properties included in the cost being amortized, less (4) income tax effects related to differences between the book and tax bases of the natural gas, NGL and oil properties. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required.

Judgments and assumptions

The discounted present value of future net cash flows from our proved reserves is the major component of the cost center ceiling calculation and is determined in connection with the estimation of our proved reserves. Estimates of proved reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of proved reserve estimation requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of proved reserve quantities based on the same data.

While the quantities of proved reserves require substantial judgment, the associated prices of our proved reserves and the applicable discount rate that are used to calculate the discounted present value of the proved reserves do not require judgment. The current SEC rule requires the use of the future net cash flows from proved reserves discounted at 10%. Therefore, the future net cash flows associated with the proved reserves is not based on our assessment of future prices or costs. In calculating the ceiling, we adjust the future net cash flows by the discounted value of commodity derivatives in place that hedge future prices. This valuation is determined by calculating the difference between proved reserve pricing and the contract prices for such hedges also discounted at 10%.

Because the cost center ceiling calculation dictates that our historical experience be held constant indefinitely and requires a 10% discount factor, the resulting value is not necessarily indicative of the fair value of the proved reserves or our properties. Commodity prices have historically been volatile. At any time that we conduct a cost center ceiling test, forecasted prices can be either substantially higher or lower than our historical experience. Also, marginal borrowing rates may be well below the required 10% used in the calculation. Rates below 10%, if they could be utilized, would have the effect of increasing the otherwise calculated ceiling amount. Therefore, natural gas, NGL and oil property ceiling test-related impairments that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of proved reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related proved reserves.

Derivative instruments

Policy description

We enter into financial derivative instruments to mitigate risk associated with the prices received from our production. We may also utilize financial derivative instruments to hedge the risk associated with interest rates on our outstanding debt. We account for our derivative instruments by recognizing qualifying derivative instruments on our balance sheet as either

 

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assets or liabilities measured at their fair value determined by reference to published future market prices and interest rates.

For derivative instruments that qualify as cash flow hedges, the effective portions of gains or losses are deferred in accumulated other comprehensive income and recognized in earnings during the period in which the hedged transactions are realized. Gains or losses on qualified derivative instruments terminated prior to their original expiration date are deferred and recognized as income or expense in the period in which the hedged transaction is recognized. If the hedged transaction becomes probable of not occurring, the deferred gain or loss is immediately recorded to earnings. The ineffective portion of the hedge relationship is recognized currently as a component of other revenue.

The fair values of our commodity derivatives are estimated using published market prices of natural gas, NGLs and oil for the periods covered by the contracts. Estimates are determined by applying the net differential between the prices in each derivative and market prices for future periods to the volume stipulated in each contract, to arrive at an estimated value of future cash flow streams. These estimated future cash flow values are then discounted for each contract at rates commensurate with federal treasury instruments with similar contractual lives to arrive at estimated fair value.

Judgments and assumptions

The estimates of the fair values of our derivative instruments require substantial judgment. Valuations are based upon multiple factors such as futures prices, volatility data from major commodity trading points, length of time to maturity and interest rates. We compare our estimates of fair value for these instruments with valuations obtained from independent third parties and counterparty valuation confirmations. The values we report in our financial statements change as these estimates are revised to reflect actual results. Future changes to forecasted or realized commodity prices could result in significantly different values and realized cash flows for such instruments.

Equity-based compensation

Policy description

An estimate of fair value is determined for all equity-based payment awards that may be settled in units. Recognition of compensation expense for all equity-based payment awards is recognized over the vesting period for each award.

Judgments and assumptions

Estimating the grant date fair value of our equity-based compensation that settles in units requires management to make assumptions and to apply judgment to determine the grant date fair value of our awards. These assumptions and judgments include estimating the future volatility of the underlying unit’s price, expected dividend yield, future employee turnover rates and future employee unit option exercise behaviors. Changes in these assumptions can materially affect the estimated fair value.

 

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We do not believe there is a reasonable likelihood that there will be a material change in the future estimates or assumptions that we use to determine equity-based compensation expense. However, if actual results are not consistent with our estimates or assumptions, we may be exposed to changes in equity-based compensation expense that could be material. If actual results are not consistent with the assumptions used, the equity-based compensation expense reported in our financial statements may not be representative of the actual economic cost of the equity-based compensation.

Internal controls and procedures

Prior to the completion of this offering, the Partnership Properties and commodity derivatives that comprise our predecessor were owned by Quicksilver and were not held in a separate legal entity or operated independently. As a result, there were no dedicated accounting personnel to develop accounting processes and establish internal control over financial reporting for our predecessor. In connection with their audit of our predecessor’s historical carve out financial statements for years prior to 2011, our independent registered public accounting firm identified a number of deficiencies in respect of internal control over financial reporting that in the aggregate constituted a material weakness. The internal control deficiencies related to the completeness and precision of the review procedures used in preparing certain information included in the historical carve out financial statements of our predecessor. A “material weakness” is a deficiency, or combination of deficiencies, in internal controls such that there is a reasonable possibility that a material misstatement of our predecessor’s financial statements will not be prevented or detected in a timely basis.

We believe we have remedied the material weakness by dedicating existing personnel and hiring new personnel who are charged with the responsibility of developing and maintaining an appropriate accounting process and system of internal controls over financial reporting, including an augmented review process. Although we believe we have addressed the internal control deficiencies that led to the material weakness, the measures we have taken and will take may not be effective. Consequently, if this or another material weakness or significant deficiencies occur in the future, it could affect the financial results that we report or create a perception that our reported financial condition or results of operations are not fairly presented. Either of those events could have an adverse effect on the value of our units.

We are not currently required to comply with the SEC’s rules regarding 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 traded partnership, 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 control 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 control over financial reporting pursuant to Section 404, while we maintain our status as an emerging growth company. See “Summary — Emerging growth company status.” To comply with the requirements of being a publicly traded partnership, we may need to implement or augment internal controls, reporting systems and procedures and hire additional accounting and finance staff.

 

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Our independent registered public accounting firm is not required to formally attest to the effectiveness of our internal controls over financial reporting. Our independent registered public accounting firm may issue a report that has an adverse opinion if it is not satisfied with the level at which our controls are documented, designed or maintained. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future.

As a public company with listed equity securities, 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 and the requirements of the NYSE. Complying with these statutes, regulations and requirements will require a significant amount of time from our general partner’s board of directors and management and such compliance will be time-consuming and costly. We will need to:

 

 

institute a 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;

 

comply with rules promulgated by the NYSE;

 

prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

 

establish internal policies, such as those relating to disclosure controls and procedures and insider trading;

 

involve and retain outside counsel and accountants in the above activities; and

 

establish an investor relations function.

Recently issued accounting standards

No pronouncements materially affecting our financial statements were issued during 2009, 2010, or 2011. In 2012 the following pronouncements impact our financial statements.

In June 2011, the FASB issued an amendment to accounting guidance to update the presentation of comprehensive income in consolidated financial statements. Under the amended guidance, the presentation of total comprehensive income, the components of net income, and the components of other comprehensive income may be made either in a single continuous statement of comprehensive income or in two separate but consecutive statements. This guidance became effective for us beginning with the quarter ended March 31, 2012 and did not have an effect on our financial statements.

In May 2011, the FASB issued an amendment to the accounting guidance for fair value measurement and disclosure. Among other things, the guidance expands the disclosure requirements around fair value measurements categorized in Level 3 of the fair value hierarchy and requires disclosure of the level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position but whose fair value must be disclosed. It also clarifies and expands upon existing requirements for measurement of the fair value of financial assets and liabilities as well as instruments classified in shareholders’ equity. This guidance became effective for us beginning with the quarter ended March 31, 2012. The adoption of this accounting pronouncement did not have an effect on our financial statements.

 

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In December 2011, the FASB issued an amendment to the accounting guidance for the disclosure of arrangements that permit offsetting assets and liabilities. The amendment expands the disclosure requirements to require both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The amendment is effective for fiscal years, and interim periods within those years, beginning on or after January 1, 2013 and shall be applied retrospectively. We do not expect the adoption of this accounting pronouncement to have a material impact on our financial statements when implemented.

No other pronouncements materially affecting our financial statements have been issued.

 

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Business and properties

The following Business and Properties discussion should be read in conjunction with the “Selected historical financial data” and the accompanying financial statements and related notes included elsewhere in this prospectus. Unless otherwise indicated, all references to our properties and operations on a historical basis are to the properties and operations that will be contributed to us by Quicksilver in the transactions described under “Summary—Our partnership structure and formation transactions.”

Overview

We are a Delaware limited partnership formed in November 2011 by Quicksilver to own and acquire oil and gas properties in North America that fit our acquisition criteria, which are mature onshore properties with long-lived reserves, predictable production profiles and modest capital requirements. Our primary business objective is to generate stable cash flows, allowing us to make quarterly cash distributions to our unitholders and, over time, to increase those quarterly cash distributions. We believe our properties are well-suited for our partnership because they consist of mature onshore oil and gas properties that fit our acquisition criteria. As of December 31, 2011, our total proved reserves were 368.3 Bcfe, of which approximately 85% were classified as proved developed reserves, including 18.0 Bcfe classified as proved developed non-producing. Excluding the effect of commodity derivatives, 29.2%, 65.7% and 5.1% of our revenue for the three months ended March 31, 2012 were from natural gas, NGLs and oil, respectively, while 53.2%, 46.6% and 0.2% of our total proved reserves as of December 31, 2011 were from natural gas, NGLs and oil by volume, respectively. Based on our average net production for the three months ended March 31, 2012 of 59.6 Mmcfed, our total proved reserves as of December 31, 2011 had an annualized reserve-to-production ratio of 16.9 years. Based on our anticipated average net production for the twelve months ending June 30, 2013 of 62.3 Mmcfed, our reserve-to-production ratio would be 16.2 years. We operate all of the properties in which we have interests, and we own an average working interest of 98.8% in the wells and properties included in the Partnership Properties, with a weighted average net revenue interest of 78.9%, based on our proved reserves as of December 31, 2011. All of our oil and gas reserves are in the Barnett Shale.

We believe our business relationship with Quicksilver, which owns our general partner and, indirectly, will own approximately     % of our outstanding common units and all of our subordinated units, general partner units and incentive distribution rights, will enhance our ability to maintain or grow our production and expand our proved reserve base over time. Following the contribution of the Partnership Properties to us, Quicksilver will retain over 2.1 Tcfe of its proved reserves in the United States as of December 31, 2011, almost all of which is in the Barnett Shale that may be suitable for us to acquire in the future.

Quicksilver is a Fort Worth-based independent oil and gas company engaged primarily in the acquisition, exploration, development and production of onshore oil and gas in North America. Quicksilver was organized as a Delaware corporation in 1997 and has been a public company since 1999. Quicksilver focuses primarily on unconventional reservoirs where hydrocarbons may be found in challenging geological conditions, such as fractured shales, coalbeds and tight sands. Quicksilver’s producing oil and gas properties in the United States are principally located in Texas, Colorado, Wyoming and Montana.

Quicksilver has been producing from unconventional shale plays since 1999 and established its initial acreage position in the Barnett Shale in 2003. Since then, Quicksilver has grown its

 

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leasehold to approximately 140,000 net acres in the Fort Worth Basin as of December 31, 2011. Quicksilver currently has 1,008 gross (823.7 net) producing wells in the Fort Worth Basin and has produced over 440 Bcfe. Since 2003, Quicksilver has grown its Barnett Shale average net production from no production to over 335 Mmcfed for 2011.

At the closing of this offering and the completion of the formation transactions, we will consummate the Quicksilver Contributions. Please read “Summary—Our partnership structure and formation transactions” for more information.

Our business strategies

Our primary business objective is to generate stable cash flows through cost-effective growth in production and proved reserves and enhanced operating results, allowing us to make quarterly cash distributions to our unitholders after servicing our debt and, over time, to increase those quarterly cash distributions. We currently focus our strategy in the Barnett Shale. To achieve our objective, we intend to execute the following business strategies:

 

 

Maintain and grow a stable production profile through low-risk development.    We intend to pursue low-risk development of our undeveloped inventory of drilling locations and any additional locations that we may acquire in the future. As of December 31, 2011, we had identified 44 drilling locations. We believe that our existing inventory of drilling locations will allow us to maintain our targeted average net production rate of 58.8 Mmcfed from July 1, 2012 through December 31, 2016 without reliance on any acquisitions. As a result, we expect that any acquisitions either from Quicksilver or third parties will have a direct and favorable impact on our production growth.

 

 

Acquire assets from Quicksilver through negotiated transactions.    We expect to have the opportunity to make acquisitions of oil and gas properties that fit our acquisition criteria from Quicksilver from time to time in the future. After the contribution of the Partnership Properties to us, Quicksilver will retain proved reserves as of December 31, 2011 in the United States of more than 2.1 Tcfe, of which 62.6% were proved developed reserves. Quicksilver has indicated that it intends in the future to offer us the opportunity to acquire additional properties in negotiated transactions. While Quicksilver is not obligated to offer or sell any properties to us, except with respect to properties in the Barnett Shale Counties over which we have a right of first offer as provided in our omnibus agreement, we believe that Quicksilver will find engaging in transactions with us to be beneficial given its significant retained ownership interests in us and our general partner, including the incentive distribution rights.

 

 

Acquire assets from third parties either independently or jointly with Quicksilver.    We plan to implement a growth strategy of pursuing accretive acquisitions of oil and gas assets that fit our acquisition criteria. Through the services that Quicksilver will provide under our omnibus agreement, we expect that we will have access to Quicksilver’s experienced management team and industry relationships, which we believe will provide us a competitive advantage in pursuing potential third-party acquisition opportunities. We expect to have the opportunity to work jointly with Quicksilver to pursue certain acquisitions of oil and gas properties that may not otherwise be attractive acquisition candidates for either of us individually. For example, we may jointly pursue an acquisition where we would acquire the proved developed portion of the acquired properties and Quicksilver would acquire the undeveloped portion.

 

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Leverage Quicksilver’s size and technical understanding of the Barnett Shale to manage our costs and achieve optimum recovery.    Quicksilver has been operating in the Barnett Shale since 2003, during which time Quicksilver has grown its Barnett Shale average net production from no production to over 335 Mmcfed for 2011. As of December 31, 2011, Quicksilver operated over 1,000 gross producing wells and two drilling rigs in the area. Pursuant to our omnibus agreement, Quicksilver will operate the Partnership Properties on our behalf, while continuing to operate its own properties, which we believe will enable us to realize significant cost efficiencies through size and scale and proven technical and operating talent.

 

 

Reduce exposure to commodity price risk and stabilize cash flows through a disciplined hedging policy.    We intend to maintain a portfolio of commodity derivatives covering approximately 60% to 85% of our estimated production over a three-to-five year period at any given point in time, although we may from time to time hedge more or less than the approximate range or change the range. At the closing of this offering, the derivatives covering our natural gas production will set a NYMEX price of $6.00 per Mmbtu through 2015 and the derivatives covering our NGL production will set a weighted average price of $46.16 per Bbl for 2012. The natural gas derivatives represent an average of approximately 96% of our anticipated gas production through 2015. For additional information about our commodity derivatives, please read “Summary—Our partnership structure and formation transactions” and “Management’s discussion and analysis of financial condition and results of operations—Overview—Commodity derivatives.” We believe these commodity derivatives and others entered into pursuant to our hedging policy will allow us to mitigate the impact of commodity price volatility, thereby increasing the predictability of our cash flow.

 

 

Maintain a prudent capital structure to ensure financial flexibility for acquisitions and development.    Concurrently with the closing of this offering, we anticipate that we will enter into a new revolving credit facility. We intend to maintain modest levels of indebtedness in relation to our cash flows from operations. We believe our internally generated cash flows and our borrowing capacity under our new revolving credit facility will provide us with the financial flexibility to pursue our acquisition and development strategy in an effective and competitive manner.

Our competitive strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our objective of generating and growing cash available for distribution:

 

 

Our Relationship with Quicksilver

 

   

Quicksilver will have a significant retained interest in the Barnett Shale, which we anticipate will give us access to multi-year inventory of drop-down acquisitions from Quicksilver comprised of existing producing properties and drilling opportunities in the Barnett Shale, though there is no assurance we would be able to complete any such acquisitions.    After the contribution of the Partnership Properties to us, Quicksilver will retain over 2.1 Tcfe of proved reserves in the United States, almost all of which is in the Barnett Shale, as of December 31, 2011 and 275.9 Mmcfed of average net production for 2011. In addition, Quicksilver has identified a significant number of proved and unproved drilling opportunities in the Barnett Shale on its approximately 140,000 net acre leasehold, which, with time and through additional drilling, we believe would become attractive

 

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acquisition prospects for us. Throughout Quicksilver’s aggregate position in the Barnett Shale, we have identified a multi-year inventory of drop-down acquisitions that we believe would contribute to a stable, predictable and systematic growth in our business. Under the terms of our right of first offer in our omnibus agreement, Quicksilver will commit to offer us the first opportunity to acquire any of its or its controlled subsidiaries’ properties, if any, in the Barnett Shale Counties that it may offer for sale. We expect that, given Quicksilver’s significant retained ownership interest in us, including the incentive distribution rights, Quicksilver will have a strong economic incentive to facilitate these acquisitions in the future.

 

   

Quicksilver has extensive technical experience and familiarity with developing and operating Barnett Shale properties and other unconventional resources.    Quicksilver is one of the five largest producers in the Barnett Shale. The development of the Barnett Shale helped pioneer unconventional shale development, and the Barnett Shale currently produces over 5.0 Bcf of natural gas per day with over 15,000 wells drilled since 2003, according to the Railroad Commission of Texas. Through our omnibus agreement with Quicksilver, we will have the operational support of Quicksilver’s staff of petroleum professionals, many of whom have significant engineering, geologic and other expertise in the Barnett Shale and elsewhere. We believe that this technical expertise differentiates us from, and provides us with a competitive advantage over, many of our competitors. We intend to utilize these resources to optimize our production and ultimate proved reserve recovery to enhance the value of our assets.

 

   

Quicksilver increases our competitiveness for third-party acquisitions.    Quicksilver has completed multiple acquisitions in the Barnett Shale and elsewhere in recent years. We believe that our ability to leverage Quicksilver’s industry relationships and broad expertise in evaluating oil and gas assets will expand our access to accretive acquisition opportunities and differentiate us from many of our competitors. Additionally, although Quicksilver is not obligated to pursue acquisitions with us, we expect to have opportunities to work jointly with Quicksilver to pursue acquisitions of 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.

 

   

The executive management team of our general partner includes some of the most senior officers of Quicksilver, each of whom has extensive industry experience, including experience managing a master limited partnership.    Our general partner’s executive management team includes some of the most senior officers of Quicksilver, each of whom has extensive experience in the acquisition, exploration, development and production of oil and gas properties and the integration and management of energy assets in a reliable and cost-effective manner. In addition, members of our general partner’s management team have significant experience in forming and managing a master limited partnership, having established, taken public and participated in the management of Quicksilver Gas Services LP (now known as Crestwood Midstream Partners LP, or Crestwood), a master limited partnership that provided Barnett Shale natural gas gathering and processing services to Quicksilver and other third parties. From the time of Crestwood’s formation in 2007 through its sale in 2010, members of our general partner’s management team were instrumental in developing and expanding Crestwood’s operations, and therefore, are familiar with the management, complex accounting, asset drop-down and distribution management issues that are unique to master limited partnerships.

 

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Our asset base is characterized by low-declining, predictable and long-lived production with a significant NGL component.    Our properties have well-understood geologic features, predictable production profiles and modest maintenance capital requirements. Based on our average net production for the three months ended March 31, 2012 of 59.6 Mmcfed, our total proved reserves as of December 31, 2011 had an annualized reserve-to-production ratio of 16.9 years. Based on our anticipated average net production for the twelve months ending June 30, 2013 of 62.3 Mmcfed, our reserve-to-production ratio would be 16.2 years. Based on our December 31, 2011 reserve report, our existing proved developed producing reserves have an estimated compounded average decline rate from July 1, 2012 through December 31, 2016 of 11.0% and less than 6% per year thereafter. In addition, our natural gas properties generate significant NGL production, enhancing our profit margins, with NGLs accounting for 65.7% of our revenue (excluding the effect of commodity derivatives) for the three months ended March 31, 2012.

 

 

Our competitive cost of capital and financial flexibility.    Unlike some of our competitors, we do not expect to be subject to federal income taxation at the entity level. We believe that this attribute will provide us with a lower cost of capital compared to many of those competitors, thereby enhancing our ability to compete for future acquisitions. We also expect to be able to enhance our financial flexibility through the issuance of additional common units and other partnership interests in the capital markets or directly to Quicksilver in connection with acquisitions. We also intend to utilize a modest amount of debt through our new revolving credit facility and the capital markets to provide flexibility in our capital structure.

Our relationship with Quicksilver

We view our relationship with Quicksilver as a significant competitive strength. We believe this relationship will provide us with potential acquisition opportunities from a portfolio of oil and gas properties that meet our acquisition criteria, as well as access to personnel with extensive technical expertise and industry relationships.

Following the completion of this offering, Quicksilver will indirectly be our largest unitholder, holding common units (approximately     % of all outstanding common units) and all of our subordinated units. Through its ownership of our general partner, Quicksilver will also hold all of the incentive distribution rights.

After the contribution of the Partnership Properties to us, Quicksilver will retain total proved reserves of 2.1 Tcfe in the United States as of December 31, 2011, of which 78.1% were natural gas, 21.0% were NGLs and 0.9% were oil. We believe that all of Quicksilver’s reserves in the United States are (or after additional capital is invested will become) suitable for us, based on our acquisition criteria. We also believe the largely contiguous and overlapping nature of Quicksilver’s and our Partnership Properties acreage will provide key operational, logistical and technical benefits, as well as cost savings, derived from our aligned interests.

 

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The following table summarizes information about Quicksilver’s U.S. proved reserves as of the year ended December 31, 2011, excluding the Partnership Properties.

 

     Estimated  proved
reserves
    Average net
production
   

Average

Reserve-to-

production
ratio(1)

    Producing
wells
 
    Bcfe     % Natural
gas
    % Proved
developed
    % Total
proved
    Mmcfed     % Total
production
      Gross     Net  

 

 

Barnett Shale

    2,053.5        78.7%        62.3%        99.2%        244.4        98.5%        20.9        758        577.4   

Other U.S.

    16.7        7.7%        100.0%        0.8%        3.8        1.5%        10.9        281        275.9   
 

 

 

       

 

 

     

 

 

 

Total U.S.

    2,070.2        78.1%        62.6%        100.0%        248.2        100.0%        20.7        1,039        853.3   

 

 

 

(1)   The annualized average reserve-to-production ratio is calculated by dividing proved reserves as of December 31, 2011 by the average net production for the three months ended March 31, 2012.

As a result of its significant ownership interests in us and our general partner, we believe Quicksilver will be motivated to support the successful execution of our primary business objective and will provide us with opportunities to pursue acquisitions that we believe will be accretive to our unitholders. Quicksilver has informed us that it views our relationship as part of its growth strategy, and we believe that Quicksilver has an incentive to sell additional assets to us and to pursue acquisitions jointly with us in the future. However, except with respect to its properties in the Barnett Shale Counties over which we have a right of first offer as provided under an omnibus agreement that Quicksilver will enter into with us and our general partner at the completion of this offering, or our omnibus agreement, Quicksilver will have no obligation following the consummation of this offering to offer us additional properties. In addition, Quicksilver will have no obligation to participate with us in joint acquisitions of property from third parties. Moreover, after the closing of this offering, Quicksilver may act in a manner that is beneficial to its interests without regard to ours, which may include electing not to present us with future acquisition opportunities. If Quicksilver fails to present us with, or successfully competes against us for, acquisition opportunities, then our ability to replace or increase our proved reserves may be impaired, which could adversely affect our cash flow from operations and our ability to make cash distributions to our unitholders. Please read “Fiduciary and other duties.”

Under the terms of our right of first offer in our omnibus agreement, Quicksilver will commit to offer us the first opportunity to acquire any properties in the Barnett Shale Counties that Quicksilver or any of its controlled subsidiaries may offer for sale. It is difficult to predict whether Quicksilver will seek to sell any of such properties, and, if so, which ones.

Under our omnibus agreement, Quicksilver will also provide general, administrative and operational services to us and our general partner. Under this agreement, we will utilize Quicksilver’s management and staff of engineers, geologists and administrative personnel. Please read “Management” for more information about the management of our partnership and our use of Quicksilver personnel and “Certain relationships and related party transactions—Agreements governing the transactions—Omnibus agreement” for more information about our omnibus agreement.

Partnership Properties

General summary of our Partnership Properties and the Barnett Shale

At the closing of this offering, our assets will be comprised entirely of the Partnership Properties which are located in Hood, Somervell, Johnson, Tarrant and Hill Counties, Texas, and certain

 

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commodity derivatives that Quicksilver will novate to us. The proved reserves attributable to the Partnership Properties are all located in the Barnett Shale. The Partnership Properties consist of leases, mineral interests, producing wells drilled between 2004 and 2012 (including certain wells for which we will receive wellbore assignments), undeveloped locations (both proved and unproved), associated well equipment and surface rights.

The Barnett Shale is a marine basinal shale deposit of middle-to-late Mississippian age that has varying characteristics across the Fort Worth Basin. There has been production in the Barnett Shale since the early 1980s when Mitchell Energy drilled the first vertical well in 1981. Significant production growth began in 2003 as horizontal drilling became the preferred method of development.

Well performance in the Barnett Shale has been studied extensively, allowing us to have a greater understanding of the production and reservoir characteristics thus making future performance more predictable. Further, many of the wells in the Partnership Properties have sufficient production history to provide a defined production trend that allows us to forecast production with a greater degree of certainty. We use words such as “mature” or “low-risk” to describe properties that we believe have established operating, reservoir and production characteristics.

All of the Partnership Property production comes from horizontal gas wells. Our wells produce from depths ranging from an average of approximately 5,750 feet in Hood and Somervell Counties to approximately 7,400 feet in Tarrant County. The majority of our wells are in Hood and Somervell Counties and produce wet gas with an energy content greater than 1,200 Btu per cubic foot. This wet gas affords us the opportunity to use a third-party processing plant to extract approximately 125 Bbl of NGLs for each Mmcf of natural gas that we produce. In the current pricing environment, we market the NGLs separately from the gas to enhance the revenue we receive for our production.

The horizontal portion of the well, or lateral, has a large bearing on the cost and time to drill the well, as well as production and proved reserves associated with the well. Our laterals have increased in length as technology has advanced and are generally oriented within our acreage to maximize resource recovery and optimize surface use. Our average lateral is approximately 3,000 feet; however, some of our more recently drilled laterals exceed 6,500 feet. Our wells are spaced at approximately 500 feet in Hood and Somervell Counties, approximately 250 feet in Tarrant County and 1,000 feet in Hill County. A typical well in the Partnership Properties costs between $1.0 million and $1.5 million to drill and between $1.5 million and $2.5 million to complete and tie-in to sales.

The development and production of oil and gas has a number of uncertainties that pose substantial risk, even for mature properties. However, we view our properties as having less risk because many of the operational risks associated with oil and gas development and production (for example, in drilling a well, whether one will encounter hydrocarbons capable of production in paying quantities and initial production decline rates) occurred earlier in the horizontal development of the Barnett Shale. For a discussion of the risks inherent in our production, please read “Risk factors—Risks related to our business.”

As of December 31, 2011, the Partnership Properties contained 32 proved infill drilling, recompletion and development opportunities on 21,167 gross (20,747 net) acres, more than 95% of which were developed properties. Our working interests represent all of the working interest

 

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per location that Quicksilver held prior to the contribution of the Partnership Properties to us. As of December 31, 2011, our total proved reserves were 368.3 Bcfe, of which approximately 85% were classified as proved developed reserves, including 18.0 Bcfe classified as proved developed non-producing.

Based on our December 31, 2011 reserve report, our existing proved developed producing reserves have an estimated compounded average decline rate from 2012 through 2016 of 11.0% and less than 6% per year thereafter, and we estimate that a typical well within our properties will have an economic productive life of 20 to 50 years, with a median life of 40 years. We believe that through 2016, we will have a low-risk development inventory that will provide us with the opportunity to maintain our targeted average net production rate of 58.8 Mmcfed without acquiring incremental proved reserves.

The following table presents summary data for the Partnership Properties as of December 31, 2011.

 

Property type    Proved
reserves
(Bcfe)
     % Natural
gas
     % NGL      % Oil      Number of
locations(1)
     Average
working
interest
     Net
revenue
interest
 

 

 

Proved developed

     316.7         53.5%         46.3%         0.2%         258         98.6%         78.7%   

Proved undeveloped

     51.6         51.0%         48.4%         0.6%         32         100.0%         79.8%   
  

 

 

             

 

 

       

Total Proved

     368.3         53.2%         46.6%         0.2%         290         98.8%         78.9%   

 

 

 

(1)  

In addition to the proved locations, we also have identified 12 unproved locations to drill on acreage that we have under lease within the Partnership Properties.

Oil and gas data and operations—Partnership Properties

Our and Quicksilver’s proved reserve estimates and related disclosures for 2011, 2010 and 2009 are presented in compliance with the SEC rule. The information with respect to our and Quicksilver’s proved reserves and related disclosures have been prepared by Schlumberger Data & Consulting Services (“Schlumberger”), our and Quicksilver’s independent reserve engineers.

The process of estimating our and Quicksilver’s proved reserves is complex. In order to prepare these estimates, Quicksilver has developed, maintained and monitored internal processes and controls for estimating and recording proved reserves in compliance with the rules and regulations of the SEC. Compliance with the SEC reserve guidelines is the primary responsibility of Quicksilver’s reservoir engineering team. Quicksilver and we require that proved reserve estimates be made by qualified reserve estimators, as defined by the Society of Petroleum Engineers’ standards. Quicksilver’s reservoir engineering team, which is responsible for our proved reserve estimates, participates in continuing education to maintain a current understanding of SEC reserve reporting requirements.

Quicksilver’s reservoir engineering team, led by Chris Mundy, Vice President—Engineering, is responsible for the preparation and maintenance of our and Quicksilver’s engineering data and review of our and Quicksilver’s proved reserve estimates with Schlumberger. Mr. Mundy has over 15 years of experience in the oil and gas industry. The engineering team reports directly to him. Throughout the year, the reservoir engineering team analyzes the performance of producing properties for each operating area, identifies proved reserve additions and revisions and prepares internal proved reserve estimates. In addition, the team is responsible for maintaining all reserve engineering data. Integrity of reserve engineering data is enhanced by restricting full access to only the members of our and Quicksilver’s reservoir engineering team. Limited other personnel have read-only access with no ability to modify reserve engineering data.

 

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Our and Quicksilver’s proved reserves and future net cash flows have been prepared by Schlumberger. The technical person at Schlumberger responsible for overseeing the preparation of our estimates of proved reserves is Charles M. Boyer II, PG, CPG. Mr. Boyer is licensed in the Commonwealth of Pennsylvania and has over 30 years of geologic and engineering experience in the oil and gas industry. Mr. Boyer earned a Bachelor of Science degree in geological sciences from The Pennsylvania State University in University Park and completed graduate studies in mining and petroleum engineering at the University of Pittsburgh and The Pennsylvania State University. The Schlumberger technical team responsible for calculating our proved reserves has extensive experience in reservoir evaluation and reserve analysis for tight gas sand, shale gas and coalbed methane projects. Prior to finalizing its proved reserve estimates, Schlumberger’s results are reviewed in detail by Quicksilver’s reservoir engineering team. Reports of our and Quicksilver’s proved reserves prepared by Schlumberger have been reviewed with Mr. Mundy and the other members of our executive management team.

The audit committee of Quicksilver’s board of directors has met with our and Quicksilver’s executive management team, including Mr. Mundy, and Schlumberger to discuss the process and results of proved reserve estimation. The analytical review of proved reserve estimates includes comparisons of ending proved undeveloped estimates to our average ending ultimate recoverable proved reserves for each of our operating areas. Additional reviews of drilling results and proved undeveloped estimates have been conducted by our executive management team and the audit committee of Quicksilver’s board of directors.

Pursuant to the rules and regulations of the SEC, proved reserves are the estimated quantities of natural gas, NGLs and oil which, through analysis of geological and engineering data, demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” connotes a high degree of confidence that the quantities of natural gas, NGLs and oil actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the technologies used in the estimation process must have been demonstrated to yield results with consistency and repeatability. Proved developed reserves are expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are expected to be recovered from new wells on undrilled acreage. Proved reserves for undrilled wells are estimated only where it can be demonstrated that there is continuity of production from the existing productive formation. To achieve reasonable certainty of our proved reserve estimates, our reservoir engineering team assumes continued use of technologies with demonstrated success of yielding expected results, including the use of drilling results, well performance, well logs, seismic data, geologic maps, well stimulation techniques, well test data, and reservoir simulation modeling.

The proved reserve data we disclose are estimates and are subject to inherent uncertainties. The determination of our proved reserves is based on estimates that are highly complex and interpretive. Reserve engineering is a subjective process that depends upon the quality of available data and on engineering and geological interpretation and judgment. Although we believe the proved reserve estimates contained in this prospectus are reasonable, reserve estimates are imprecise and are expected to change as additional information becomes available. For additional information regarding risks associated with estimating our proved reserves, please read “Risk factors—Risks related to our business.”

 

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Proved reserves

The following table presents the estimated net proved reserves attributable to the Partnership Properties based on our December 31, 2011 reserve report.

 

Year ended December 31, 2011    Proved developed
reserves
     Proved undeveloped
reserves
     Total proved
reserves(1)
 

 

 

Natural gas (Mmcf)

     169,458         26,313         195,771   

NGL (Mbbl)

     24,439         4,160         28,599   

Oil (Mbbl)

     93         56         149   

Total (Mmcfe)

     316,649         51,610         368,259   

 

 

 

(1)   Total proved reserves are presented on a gas equivalent basis using a conversion of six Mcf “equivalent” per barrel of NGL or oil. This conversion is based on energy equivalence and not on price equivalence.

Proved undeveloped reserves

During 2011, we rig released 7 gross (7 net) proved undeveloped wells, of which we completed and installed equipment on 3 gross (3 net) wells.

We incurred $17.4 million in 2011 for drilling and completion activities on our proved undeveloped locations as of December 31, 2010.

A typical well on the Partnership Properties costs between $1.0 million and $1.5 million to drill and between $1.5 million and $2.5 million to complete and tie-in to sales. The amount of time to complete operational activities is largely dependent on the lateral length of the wells and the number of wells on the surface site. A single well will typically take approximately 11 days to drill. The completion activities include a number of separate operations which, combined, typically take less than two months to finish for a single well. When multiple wells are on a pad, operational efficiencies are often gained, but typically all wells will be put on production at the same time, thereby resulting in a longer period of time from the beginning of the completion activities on the first well until the start of production.

Our expectation is to fund our drilling and development programs primarily from our cash flow from operations. Based on our current expectations of our cash flows and drilling and development programs, which includes drilling of proved undeveloped locations, we believe that we can fund the drilling of our current inventory of proved undeveloped locations in the next five years from our cash flow from operations and, if needed, our new revolving credit facility. For a more detailed discussion of our pro forma liquidity position, please read “Management’s discussion and analysis of financial condition and results of operations—Liquidity and capital resources.”

The following table summarizes our proved undeveloped reserves activity during the year ended December 31, 2011 (in Mmcfe):

 

Beginning proved undeveloped reserves

     84,846   

Extensions and discoveries

     4,849   

Transfers to proved developed

     (19,939

Revisions of previous estimates

     (18,146
  

 

 

 

Ending proved undeveloped reserves

     51,610   

 

 

Transfers to proved developed reserves during 2011 consisted of 7.7 Bcfe that were drilled, completed and tied into sales and 12.2 Bcfe that were drilled and awaiting completion or tie-in to sales.

 

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Revisions of previous estimates is comprised of 6.6 Bcfe of negative price revisions associated with proved reserves that became uneconomic to drill as of December 31, 2011 based on utilized prices, 13.3 Bcfe of reserves which were not developed within five years of their initial recognition and 1.7 Bcfe of positive technical revisions.

As of December 31, 2011, we had total proved undeveloped reserves of 51.6 Bcfe on 32 locations, all of which are scheduled for development before the end of 2016. As of December 31, 2011, none of our proved undeveloped locations had been recognized as proved for longer than five years. The following summarizes our anticipated development of our December 31, 2011 proved undeveloped locations.

 

(in thousands)    Number of wells      Estimated cost  

 

 

2012

     5       $ 17,372.0   

2013

     3         8,377.7   

2014

     9         25,270.6   

2015

     7         17,585.1   

2016

     8         22,341.7   
  

 

 

 

Total

     32       $ 90,947.1   

 

 

Exploratory and development activities

The following table summarizes our capital expenditures.

 

(in thousands)    2011      2010      2009  

 

 

Proved acreage

   $       $ 9,179       $   

Development costs

     37,530         30,635         41,882   
  

 

 

    

 

 

 

Total

   $ 37,530       $ 39,814       $ 41,882   

 

 

Drilling activities

During the periods indicated, we drilled, completed and installed permanent equipment on the following wells:

 

Year ended December 31,    2011      2010      2009  
     Gross      Net      Gross      Net      Gross      Net  

 

 

Development:

                 

Productive

     5.0         5.0         4.0         4.0         4.0         4.0   

Non-productive

                                               
  

 

 

 

Total

     5.0         5.0         4.0         4.0         4.0         4.0   

Exploration:

                 

Productive

                                               

Non-productive

                                               
  

 

 

 

Total:

                 

Productive

     5.0         5.0         4.0         4.0         4.0         4.0   

Non-productive

                                               
  

 

 

 

Total

     5.0         5.0         4.0         4.0         4.0         4.0   

 

 

 

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Development and exploration activities

Quicksilver has discretion over where to utilize its drilling rigs and at December 31, 2011, Quicksilver was operating two drilling rigs on locations not included in the Partnership Properties. At March 31, 2012, our predecessor had 4 gross (4 net) wells that were awaiting completion or tie-in to sales lines and 2 gross (2 net) wells undergoing completion operations.

Volumes, prices and production expense

For information about volume, sales prices and production expense, please read “Management’s discussion and analysis of financial condition and results of operations—Overview.”

Marketing, delivery commitments and purchasers of our production

Our production is generally sold on a month-to-month or seasonal basis and priced in reference to published indices.

Quicksilver has gathering, treating, transporting and fractionation contracts with third parties, including Crestwood Midstream Partners, and production from the Partnership Properties is subject to those contracts. Although certain of the gathering and transportation contracts and all of the fractionation contracts require Quicksilver to provide minimum daily natural gas and NGL volumes for gathering, transportation and fractionation (as determined on a monthly basis) or pay for any deficiencies at a specified rate, we will not have an obligation for any such minimum payments or volume deficiencies. We will be obligated to deliver dedicated gas under the applicable transportation and gathering contracts, but only in the amounts we produce.

Quicksilver sells our production to a variety of customers, including utilities, major oil and gas companies or their affiliates, industrial companies and trading and energy marketing companies. We believe that because our products are commodity products sold primarily on the basis of price and availability, we are not dependent upon one purchaser or a small group of purchasers in the intermediate term, as an individual purchaser could be replaced by another purchaser, absent a broad market disruption. During 2011, Lone Star NGL Development LP and Targa Liquids Marketing and Trade individually accounted for 17% and 17%, respectively, of receipts for our production revenue. During 2010, Louis Dreyfus Energy Services LP and Targa Liquids Marketing and Trade individually accounted for 19% and 14%, respectively, of receipts for our production revenue. During 2009, Louis Dreyfus Energy Services LP, BG Energy Merchants LLC and Dynergy Liquids Marketing and Trade individually accounted for 19%, 11% and 16%, respectively, of receipts for our production revenue.

Productive wells

As of December 31, 2011, we had 250 gross (246.4 net) producing wells, all of which were natural gas wells.

Acreage

Our acreage consists of non-producing and producing oil and gas leases and mineral acreage. Developed acreage is allocated to wells that are producing or capable of producing. Undeveloped

 

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acreage represents areas where wells are not to a point of being capable of producing commercial reserves, regardless of whether such acreage will ultimately be capable of such commercial production. The following tables summarize our acreage as of December 31, 2011.

 

December 31, 2011            Gross              Net  

 

 

Developed acreage

     17,647         17,443   

Undeveloped acreage

     3,520         3,304   
  

 

 

 

Total

     21,167         20,747   

 

 

All of the undeveloped acreage can be held through drilling and producing operations. We believe that we have the ability to retain substantially all of the expiring acreage that we feel will provide economic production through drilling activities.

Drilling rig commitments

Quicksilver has entered into fixed-rate drilling contracts. As of December 31, 2011, there were two such rigs under contract by Quicksilver, and while none represented direct obligations to us, Quicksilver could utilize these rigs for drilling of wells on our acreage.

Title to property

We develop and produce our reserves pursuant to interests that we hold based on leases and other agreements with private owners or governmental entities. These agreements could limit our ability to explore or produce to a specific area, specific depths or specific times of the year. In certain instances, we will receive wellbore assignments from Quicksilver.

Our properties are generally subject to royalties and other interests common in the oil and gas industry. Under our new revolving credit facility, we expect to grant the lenders a lien on substantially all of our properties. Also, our properties may be subject to liens incident to operating agreements, as well as other customary encumbrances, easements, restrictions and tax liens.

We conduct a title examination prior to drilling a well and perform necessary curative work. We believe our title efforts are sufficient to ensure that our production is saleable for our account.

Insurance

As a result of operating hazards, regulatory risks and other uninsured risks, we could incur substantial liabilities to third parties or governmental entities. Quicksilver maintains insurance, which provides coverage to us for some, but not all, of such risks and losses in accordance with customary industry practice. Not all environmental incidents, claims or damages that might occur are insured. Any significant accident or event that is not adequately insured could adversely affect our business, results of operations, financial condition and our ability to make distributions to our unitholders.

Seasonality

Although there is some historical seasonality to the prices that we receive for our production, such factors have not been material. Seasonality does not play a significant role in our ability to conduct our operations, including drilling and completion activities.

 

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Competition

We operate in a highly competitive environment for acquiring properties and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the area in which we operate. As a result, our competitors may be able to pay more for productive oil and gas properties and exploratory prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop proved reserves will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and gas industry.

We are also affected by competition for drilling rigs, completion rigs and the availability of related equipment. In recent years, the United States onshore oil and gas industry has experienced shortages of drilling and completion rigs, equipment, pipe and personnel, which have delayed development drilling and other development activities and caused significant increases in the prices for this equipment and personnel. We are unable to predict when, or if, such shortages may occur or how they would affect our development programs.

In addition, Quicksilver and its affiliates, other than our general partner, are not restricted from competing with us and such entities could be competing producers in our operating area, as well as competitors for acquisition opportunities. Please read “Certain relationships and related party transactions,” and “Risk factors—Risks inherent in an investment in us—Quicksilver and its affiliates, other than our general partner, will not be limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to develop and grow our business.”

Environmental matters

We are subject to stringent and complex federal, state and local environmental laws, regulations and permits, including those relating to the generation, storage, handling, use, disposal, gathering, transmission and remediation of natural gas, NGLs, oil and other hazardous materials; the emission and discharge of such materials to the ground, air and water; wildlife, habitat, water and wetlands protection; the storage, use, treatment and disposal of water, including process water; and the placement, operation and reclamation of wells. In particular, many of these requirements are intended to help preserve water resources and regulate those aspects of our operations that could potentially impact surface water or groundwater. If we violate these requirements, or fail to obtain and maintain the necessary permits, we could be subject to sanctions, including the imposition of fines and penalties, as well as potential orders enjoining future operations or delays or other impediments in obtaining or renewing permits. Pursuant to such laws, regulations and permits, we may be subject to operational restrictions and have made and expect to continue to make capital and other compliance expenditures, including to remediate and close pits and to develop spill prevention, control and countermeasure plans.

We could be liable for any environmental contamination at our or our predecessors’ currently or formerly owned, leased or operated properties or third-party waste disposal sites. Certain environmental laws, including CERCLA, more commonly known as Superfund, impose joint and several strict liability for releases of hazardous substances at such properties or sites, without regard to fault or the legality of the original conduct. In addition to potentially significant investigation and remediation costs, environmental contamination can give rise to claims from

 

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governmental authorities and other third parties for fines or penalties, natural resource damages, personal injury and property damage.

Environmental laws, regulations and permits, and the enforcement and interpretation thereof, change frequently and generally have become more stringent over time. For example, various federal, state and local initiatives have been implemented or are under development to regulate or further investigate the environmental impacts of hydraulic fracturing. In particular, the EPA has commenced a study to determine the environmental and health impacts of hydraulic fracturing and announced that it will propose standards for the treatment or disposal of wastewater from certain gas production operations. In addition, certain states have adopted, or are considering adopting, regulations that have imposed, or could impose, more stringent permitting, transparency, disposal and well construction requirements on hydraulic fracturing operations. In particular, in December 2011, the Railroad Commission of Texas finalized regulations requiring public disclosure of chemicals in fluids used in the hydraulic fracturing process. Local ordinances or other regulations also may regulate or prohibit the performance of well drilling in general and hydraulic fracturing in particular, and may require baseline water well sampling. Such laws and regulations may result in increased scrutiny or third-party claims, or otherwise result in operational delays, liabilities and increased costs.

Federal and Texas regulators are also becoming increasingly focused on air emissions from our industry, including volatile organic compound emissions, which increased scrutiny could lead to heightened enforcement of existing regulations as well as the imposition of new air emission measures. In April 2012, the EPA issued requirements for sulfur dioxide, volatile organic compound and hazardous air pollutant air emissions from oil and gas operations, including standards for natural gas wells that are hydraulically fractured or re-fractured. In addition, from time to time, initiatives are proposed that could further regulate certain exploration and production by-products as hazardous wastes and subject them to more stringent requirements. Any current or future air emission, hazardous waste or other environmental requirements applicable to our operations could curtail our operations or otherwise result in operational delays, liabilities and increased costs.

GHG emission regulation is also becoming more stringent. We are currently required to implement a GHG recordkeeping and reporting program due to issuance of the EPA’s subpart W regulation which will require significant effort to quantify sources at all of our production sites, and beginning in 2012, we will be required to report our GHG emissions from operations. In addition, the EPA has begun regulating GHG emissions from stationary sources pursuant to the Prevention of Significant Deterioration and Title V provisions of the federal Clean Air Act, as a result of which we might be required to obtain permits to construct, modify or operate facilities on account of, and implement emission control measures for, our GHG emissions. Also, regulatory authorities are considering, or have developed, energy or emission measures to reduce GHG emissions. Any limitation or further regulation of GHG emissions could restrict our operations and subject us to significant costs, including those relating to emission credits, pollution control equipment, monitoring and reporting. Although there is still significant uncertainty surrounding the scope, timing and effect of GHG regulation, any such regulation could have a material adverse impact on our business, financial condition, reputation and operating performance.

In addition, to the extent climate change results in more severe weather, our operations may be disrupted. For example, storms in the Gulf of Mexico could damage downstream pipeline infrastructure causing a decrease in takeaway capacity and potentially requiring us to curtail production.

 

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Government regulation

Drilling and production regulation

Our operations are affected from time to time in varying degrees by political developments and U.S. federal, state and local laws and regulations. In particular, our production and related operations are, or have been, subject to taxes and other laws and regulations relating to the industry. Failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on the industry increases our cost of doing business and affects our profitability. We do not anticipate any significant challenges in complying with laws and regulations applicable to our operations.

Safety regulation

We are subject to a number of federal and state laws and regulations, whose purpose is to protect the health and safety of workers, both generally and within our industry. Regulations overseen by the Occupational Safety and Health Administration, the EPA and other agencies require, among other matters, that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We are also subject to safety regulations which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals.

Employees

As of March 31, 2012, we had no employees. At the closing of this offering, we and our general partner will enter into an omnibus agreement with Quicksilver pursuant to which, among other things, Quicksilver will provide general, administrative and operational services for us and our general partner. Please read “Certain relationships and related party transactions—Agreements governing the transactions—Omnibus agreement.”

Offices

Our principal executive office is in Fort Worth, Texas.

Legal proceedings

We are not at this time subject to any legal proceedings or claims. However, we anticipate that we will be involved in various legal proceedings arising from our normal course of business activities. Depending on the amount and timing, an unfavorable resolution of a matter could materially affect our financial condition or our future results of operations in a particular period. Regardless of the outcome, litigation can have an adverse impact on us because of defense costs, diversion of management resources and other factors.

 

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Management

Management of Quicksilver Production Partners LP

Our general partner, Quicksilver Production Partners GP, manages our operations and activities. Our general partner is an indirect wholly-owned subsidiary of Quicksilver. All of our general partner’s executive management personnel are employees of Quicksilver.

The executive officers of our general partner will allocate their time between managing our business and affairs and the business and affairs of Quicksilver. The executive officers of our general partner may face a conflict regarding the allocation of their time between our business and the other business interests of Quicksilver. We expect that the officers of our general partner will initially devote a significant amount of their time to our business, although we expect the amount of time that they devote may increase or decrease in future periods as our business develops. These officers of our general partner and other Quicksilver employees will operate our business and provide us with general, administrative and operational services pursuant to our omnibus agreement described in “Certain relationships and related party transactions—Agreements governing the transactions—Omnibus agreement.” We will reimburse Quicksilver for expenses incurred on our behalf, including an allocation of the expenses incurred by Quicksilver for its personnel who perform services for our benefit. For purposes of our estimated Adjusted EBITDA for the twelve months ending June 30, 2013, we assume that each of the executive officers of our general partner will devote approximately 10% of his time to our business. However, the amount of time that Quicksilver employees devote to our business will be subject to change depending on our and Quicksilver’s activities in any period.

Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders will not be entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our partnership agreement contains provisions that reduce or eliminate the fiduciary or other duties that our general partner, its board of directors (or any committee thereof), and its directors and other persons who control our general partner owe to us and our unitholders. Please read “Fiduciary and other duties—Fiduciary duties.” Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, our general partner intends to cause us to incur indebtedness or other obligations that are nonrecourse to it. Except as described in “The partnership agreement—Limited voting rights,” our general partner will have exclusive management power over our business and affairs.

The directors of our general partner oversee our operations and activities. The board of directors of our general partner has seven members, including three independent directors. Because we are a limited partnership, we are not required to have a majority of independent members on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee.

The board of directors of our general partner will have a conflicts committee composed of one or more members of the board of directors that will review matters that may involve conflicts of interest that are submitted to it by the board of directors. The members of the conflicts committee may not be officers or employees of our general partner or its affiliates or directors of any affiliates of our general partner (including Quicksilver), must otherwise be independent of our general partner and its affiliates (including Quicksilver) and must otherwise meet the independence

 

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standards required to serve on an audit committee of a board of directors of a company listed on the NYSE. Because our partnership agreement only requires that the conflicts committee have at least one member, during any time that the committee only has one member, that single member of the conflicts committee will be able to approve resolutions or the course of action taken in respect of conflicts of interest. It is possible that a single-member committee may not function as effectively as a multiple-member committee and, if we pursue a transaction with an affiliate while the conflicts committee has only one member, our limited partners will be deemed to have approved that transaction through the approval of that single-member committee.

Under our partnership agreement, our conflicts committee has responsibility for (i) approving the amount of estimated maintenance capital expenditures deducted from operating surplus; and (ii) the approval of the allocation of capital expenditures between maintenance capital expenditures, growth capital expenditures and investment capital expenditures. Other than these enumerated responsibilities, our general partner may, but is not required to, seek approval from the conflicts committee regarding the resolution or course of action taken in respect of a conflict of interest with our general partner or its affiliates (including Quicksilver, and any of their respective directors, officers, employees or agents), on the one hand, and us or our unitholders, on the other. If a matter is submitted to it, the conflicts committee will, in good faith (defined in the partnership agreement, without reference to a reasonableness standard, to mean acting with the actual belief that it is in, or not opposed to, the best interest of the partnership) determine the resolution or the course of action taken in respect of the conflict of interest. Any matters resolved or approved by a majority of the members of the conflicts committee will be presumed to have been resolved or approved by the conflicts committee in good faith and will be conclusively deemed to be approved by all of our partners and not a breach by our general partner, its board of directors (or any committee thereof including the conflicts committee), its affiliates or any of their respective directors or other persons who control them of any fiduciary or other duties it owed us or our unitholders. Please read “Fiduciary and other duties—Conflicts of interest.”

As of the date of this prospectus, the audit committee of the board of directors of our general partner consists of three directors, all of whom meet the independence and experience standards established by the NYSE rules and the Securities Exchange Act of 1934. The members of the audit committee are                 ,                  and                 . The board of directors has determined that (i) each of                 ,                  and                  meets the additional audit committee independence criteria specified in SEC rules and the NYSE’s listing standards; (ii) each of                 ,                  and                  has a basic understanding of finance and accounting and is able to read and understand fundamental financial statements; (iii)                  has accounting or related financial management expertise; and (iv)                 , the Chair of the audit committee, is an “audit committee financial expert” within the meaning of Item 407(d)(5) of Regulation S-K. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee.

 

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Directors and executive officers

The following table sets forth certain information regarding the current directors and executive officers of our general partner.

 

Name    Age        Position with our general partner

 

Thomas F. Darden

     58         Director, Chairman of the Board of Directors

Glenn Darden

     56         Director, President and Chief Executive Officer

Anne Darden Self

     54         Director

Robert S. Boswell

     62        

Director

Paul Coulter

     42        

Director

Walker C. Friedman

     59         Director

M. Garrett Smith

     51         Director

John C. Regan

     42         Senior Vice President, Chief Financial Officer and Chief Accounting Officer

John C. Cirone

     62         Executive Vice President—General Counsel and Secretary

Chris M. Mundy

     39         Vice President—Engineering

 

Our general partner’s directors are elected for one-year terms, and such directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. In selecting and appointing directors to the board of directors, Quicksilver does not intend to apply a formal diversity policy or set of guidelines. However, when appointing new directors, Quicksilver will consider each individual director’s qualifications, skills, business experience and capacity to serve as a director, as described below for each director, and the diversity of these attributes for the board of directors as a whole. Thomas F. Darden, Glenn Darden and Anne Darden Self are siblings.

Biographical information

Thomas F. Darden has served as Chairman of the Board of Directors of our general partner since December 2011. Mr. Darden has also served on the board of directors of Quicksilver since December 1997 and became Chairman of the Board of Directors of Quicksilver in March 1999. Prior to joining Quicksilver, Mr. Darden was employed by Mercury Exploration Company for 22 years in various executive level positions. He served as President and Chief Executive Officer of Crestwood Gas Services GP LLC (formerly known as Quicksilver Gas Services GP LLC) from January 2007 to October 2010 and as a director from July 2007 to September 2011. We believe Mr. Darden’s qualifications to serve on the board of directors include his strategic, operating and marketing expertise from 35 years of experience in the oil and gas industry, his depth of knowledge of our business, his position with Quicksilver and his previous positions with Crestwood Gas Services GP LLC.

Glenn Darden has served as Director, President and Chief Executive Officer of our general partner since December 2011. Mr. Darden has also served on the board of directors of Quicksilver since December 1997 and became Quicksilver’s Chief Executive Officer in December 1999. He served as Quicksilver’s Vice President until he was elected President and Chief Operating Officer of Quicksilver in March 1999. Prior to that time, he served with Mercury Exploration Company for 18 years, the last five as Executive Vice President. Mr. Darden previously worked as a geologist

 

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for Mitchell Energy Company LP (subsequently merged with Devon Energy). He served as a director of Crestwood Gas Services GP LLC (formerly known as Quicksilver Gas Services GP LLC) from March 2007 to October 2010. We believe Mr. Darden’s qualifications to serve on the board of directors include his depth of knowledge of our business, including our strategies, operations and markets, his 31 years of experience in the oil and gas industry, his position with Quicksilver and his previous position with Crestwood Gas Services GP LLC.

Anne Darden Self has served as Director of our general partner since June 2012. Ms. Self has served as a director of Quicksilver since August 1999 and became Quicksilver’s Vice President—Human Resources in July 2000. She is also currently President of Mercury Exploration Company, an oil and gas exploration company located in Fort Worth, Texas, where she has worked since 1992. From 1988 to 1991, she was employed by Banc PLUS Savings Association in Houston, Texas, initially as Marketing Director and for three years thereafter as Vice President of Human Resources. She also worked from 1987 to 1988 as an Account Executive for NW Ayer Advertising Agency. Prior to 1987, she spent three years in real estate management. We believe Ms. Self’s qualifications to serve on the board of directors include her executive leadership and management experience and 12 years of experience as a director of Quicksilver.

Robert S. Boswell has served as Director of our general partner since April 2012. Mr. Boswell served as a director of Complete Production Services, Inc., a provider of specialized oil and gas services and equipment in North America, from September 2005 until February 2012, at which time Complete was acquired by Superior Energy Services, Inc. Mr. Boswell has also served as the Chairman and Chief Executive Officer of Laramie Energy II, LLC, a private oil and gas company located in Denver, Colorado since June 2007. Prior to co-founding Laramie I in early 2004, Mr. Boswell was Chairman and Chief Executive Officer of Forest Oil Corporation, a large independent oil and gas exploration and production company headquartered in Denver, Colorado. He joined Forest Oil’s Board of Directors in 1987 and in 1989 was recruited to be its Chief Financial Officer. Mr. Boswell became President of Forest Oil in 1993 and its Chief Executive Officer in 1995. We believe Mr. Boswell’s qualifications to serve on the board of directors include his depth of knowledge of the oil and gas industry and his extensive experience in public accounting and corporate finance.

Paul Coulter has served as Director of our general partner since June 2012. Mr. Coulter has served as the Treasurer of Mercury Exploration Company, an oil and gas exploration company located in Fort Worth, Texas, since 2004. He has served as a director of projekt202 LLC (and its predecessors), a user experience design, application development and digital marketing firm in Dallas, Texas, since 2006. From 2001 to 2004, Mr. Coulter served in positions of increasing responsibility within the Southwest Region Finance group of Cardinal Health, a pharmaceutical distribution company, in Fort Worth, Texas. Previously, he served as controller of National Diversified Co., an investment company with holdings in multiple industries, in Waco, Texas, from 1997 to 2001. Mr. Coulter, a certified public accountant and member of the American Institute of Certified Public Accountants, also performed and supervised financial audits as an employee of different public accounting firms, including Deloitte & Touche, LLP, from 1991 to 1997. We believe Mr. Coulter’s qualifications to serve on the board of directors include his extensive management, accounting and corporate finance experience.

Walker C. Friedman has served as Director of our general partner since April 2012. He has also served as an officer and manager of WRB Trucking Company, LLC, a Fort Worth based private trucking company since 2011 and as a trustee of the Mary Potishman Lard Trust since 1987 and the Amon Carter Museum since 1996. Mr. Friedman is a shareholder at Friedman, Suder & Cooke, P.C., a law firm located in Fort Worth, Texas that he co-founded in 1993. He specializes in business litigation with an emphasis on oil and gas litigation. Prior to 1993, Mr. Friedman practiced law at

 

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the Fort Worth firm of Law, Snakard & Gambill. From April 2010 to December 2011, Mr. Friedman served as a director of the general partner of BreitBurn Energy Partners LP, a publicly traded upstream master limited partnership. He was the Chairman of the Fort Worth Mobility and Air Quality Advisory Committee from 2005 to 2008 and the Chairman and an executive committee member of the Fort Worth Transportation Authority from 1993 to 1999. We believe Mr. Friedman’s qualifications to serve on the board of directors include his previous directorship with an oil and gas master limited partnership and his extensive legal experience.

M. Garrett Smith has served as Director of our general partner since April 2012. He founded Spinnerhawk Companies, a private investment group focusing on the energy, real estate and health care industries, in 2005. He has also served as a general partner and the Chief Financial Officer of Tritex Energy A, LP, an owner of oil producing properties since January 2010. He has also served as a director of Cano Petroleum, an oil and gas company, since December 2008 and as director on the boards of Fund America Investors Corp and Fund America Investors Corp II since the 1980s. Mr. Smith served as a director of The Hallwood Group Incorporated, an integrated textile company with oil and gas investments, from November 2004 to April 2012, as a director of Energy Coal Resources, Inc., a coal mining company, from November 2009 to February 2012, and as a director of Pacific Energy Resources Ltd., an oil and gas company, from November 2008 to February 2010. In addition, from December 2000 to February 2005, Mr. Smith served as a member of the Investment Committee at BP Capital, LLC, an investment firm specializing in the oil and gas industry, and as a general partner and portfolio manager of BP Capital Energy Equity Fund, an energy hedge fund. Previously, Mr. Smith was Chief Financial Officer and Executive Vice President of Pioneer Natural Resources where he served in positions of increasing responsibility from 1989 to 2000. We believe Mr. Smith’s qualifications to serve on the board of directors include his extensive experience in the oil and gas industry and his knowledge of accounting and corporate finance.

John C. Regan has served as Senior Vice President, Chief Financial Officer and Chief Accounting Officer of our general partner since April 2012 and previously served as Vice President—Chief Accounting Officer of our general partner from December 2011 to April 2012. Mr. Regan has served as Quicksilver’s Senior Vice President, Chief Financial Officer, Controller and Chief Accounting Officer since April 2012 and previously served as Quicksilver’s Vice President, Controller and Chief Accounting Officer from September 2007 to April 2012. He also served as Vice President—Chief Accounting Officer of Crestwood Gas Services GP LLC (formerly known as Quicksilver Gas Services GP LLC) from September 2007 to October 2010. He is a Certified Public Accountant with 20 years of combined public accounting, corporate finance and financial reporting experience. Mr. Regan joined Quicksilver from Flowserve Corporation where he held various management positions of increasing responsibility from 2002 to 2007, including Vice President of Finance for the Flow Control Division and Director of Financial Reporting. He was also a senior manager specializing in the energy industry in the audit practice of PricewaterhouseCoopers LLP, where he was employed from 1994 to 2002.

John C. Cirone has served as Executive Vice President—General Counsel of our general partner since January 2012, adding the title of Secretary in June 2012, and previously served as Senior Vice President—General Counsel of our general partner from December 2011 to January 2012. Mr. Cirone has served as Quicksilver’s Executive Vice President—General Counsel since January 2012 and as its Secretary since June 2012. Mr. Cirone previously served as Quicksilver’s Senior Vice President—General Counsel from January 2006 to January 2012, after serving as Quicksilver’s Vice President and General Counsel since July 2002. Mr. Cirone served as Quicksilver’s Secretary from July 2002 to November 2010. Mr. Cirone also served as Senior Vice President, General Counsel and

 

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Secretary of Crestwood Gas Services GP LLC (formerly known as Quicksilver Gas Services GP LLC) from January 2007 to October 2010. Mr. Cirone was employed by Union Pacific Resources (subsequently merged with Anadarko Petroleum Corporation) from 1978 to 2000. During that time, he served in various positions in the Law Department, and from 1997 to 2000 he was the Manager of Land and Negotiations. In 2000, he became Assistant General Counsel of Union Pacific Resources. After leaving Union Pacific Resources in August 2000, Mr. Cirone was engaged in the private practice of law prior to joining Quicksilver in July 2002.

Chris M. Mundy has served as Vice President—Engineering of our general partner since December 2011. Mr. Mundy became Quicksilver’s Vice President—Engineering responsible for corporate reserves in August 2010 after serving as Senior Director—Engineering from January 2010 to August 2010, Director—Engineering from May 2009 to January 2010 and Manager, Engineering from October 2008 to May 2009. Mr. Mundy previously served as Manager, Corporate Projects for Quicksilver Resources Canada Inc. where he led the Horseshoe Canyon development program and was responsible for project planning and budgeting from September 2004 to September 2006. Prior to re-joining Quicksilver in 2008, Mr. Mundy served as Manager, Engineering at Twin Butte Energy where he was responsible for corporate reserves and numerous acquisition and divestiture evaluations from September 2006 to October 2008.

Reimbursement of expenses of our general partner

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. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates, including Quicksilver, may be reimbursed.

Upon the closing of this offering, we will enter into an omnibus agreement with Quicksilver pursuant to which general, administrative and operational services will be provided to our general partner and us to manage and operate our business. Our general partner will reimburse Quicksilver, on at least a quarterly basis, for the allocable expenses it incurs in its performance under our omnibus agreement, and we will reimburse our general partner for such payments it makes to Quicksilver. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated to our general partner. We expect the expenses to be no more than those we would be required to pay if we received services from an unaffiliated third party. Quicksilver will have substantial discretion to determine in good faith which expenses to incur on our behalf and what portion of its expenses to allocate to us (taking into consideration the goods, services or other benefits provided to us in respect of such expenses). Please read “Certain relationships and related party transactions—Agreements governing the transactions—Omnibus agreement.”

Executive compensation

We and our general partner were formed in November 2011. Neither we nor our general partner operated in 2011. As such, our general partner did not pay or accrue any obligations with respect to executive compensation for its directors and executive officers for 2011 or for any prior periods. In addition, we have not paid or accrued any amounts for executive compensation for 2011 or for any prior periods. Accordingly, we are not presenting any compensation for historical periods.

 

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The executive officers of our general partner are employed by Quicksilver and will manage the day-to-day affairs of our business. The executive officers intend to devote as much time to the management of our business as is necessary for the proper conduct of our business and affairs. Because the executive officers of our general partner are employees of Quicksilver, their compensation, other than the long-term incentive plan benefits pursuant to our 2012 Equity Plan described below, will be determined and paid by Quicksilver, and reimbursed by us to the extent determined by our general partner. The executive officers of our general partner, as well as the employees of Quicksilver who provide services to us, may participate in employee benefit plans and arrangements sponsored by Quicksilver, including plans that may be established in the future. Currently, Quicksilver provides a basic benefits package generally to all employees, including the executive officers of our general partner, which includes a 401(k) plan and health, disability and life insurance. In addition, Quicksilver provides change-in-control protections for each of the executive officers of our general partner.

We anticipate that, in connection with the closing of this offering, the board of directors of our general partner will grant equity awards in the form of phantom units to Quicksilver employees (including the executive officers of our general partner) that are key to our operations, as well as to each of Messrs. Boswell, Coulter, Friedman and Smith in their capacity as directors of our general partner, pursuant to our 2012 Equity Plan described below. We expect that the total amount of these awards will be no more than             units (approximately     % of all outstanding common units). With respect to the executive officers of our general partner, we expect that awards of phantom units under our 2012 Equity Plan will be in the following amounts:             phantom units to Thomas F. Darden,             phantom units to Glenn Darden,             phantom units to John C. Regan,             phantom units to John C. Cirone and             phantom units to Chris M. Mundy. We anticipate that the vesting of these awards will be tied to time-based service conditions. For details regarding equity awards to our directors, please read “—Director compensation.”

Compensation committee interlocks and insider participation

As a limited partnership, we are not required by NYSE rules to establish a compensation committee. Although the board of directors of our general partner does not currently intend to establish a compensation committee, it may do so in the future. The board of directors of our general partner did not hold any deliberations during 2011 concerning executive officer compensation. During 2011, Messrs. Glenn Darden and Thomas Darden both served as directors and executive officers of our general partner and Quicksilver. During 2011, Ms. Self served as a director of Quicksilver. Messrs. Glenn Darden and Thomas Darden and Ms. Self did not serve on the compensation committee of Quicksilver.

2012 Equity Plan

In connection with this offering, the board of directors of our general partner will adopt a long-term incentive plan for employees, officers, consultants and directors of our general partner and its affiliates, including Quicksilver (our “2012 Equity Plan”). The material terms of our 2012 Equity Plan are described below. This summary is qualified in its entirety by the detailed provisions of our 2012 Equity Plan, a copy of which is filed as an exhibit to our registration statement of which this prospectus is a part.

The purpose of our 2012 Equity Plan is to provide to employees, officers, consultants and directors of our general partner and its affiliates incentive compensation awards based on

 

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common units. Our 2012 Equity Plan is also intended to supplement the compensation that these individuals may receive from our general partner and its affiliates (including Quicksilver) and to provide them incentives to promote our interests and the interests of our affiliates. Our 2012 Equity Plan will permit the granting of awards in the form of options to purchase common units, common unit appreciation rights, restricted common units, phantom units, performance units, performance bonuses, distribution equivalent rights and other unit-based awards.

Subject to certain adjustments that may be required from time to time to prevent dilution or enlargement of the rights of participants in our 2012 Equity Plan, a maximum of             common units will be available for grants of all awards under our 2012 Equity Plan.

There will not be any limit on the number of awards that may be granted and paid in cash, and any common units allocated to an award payable in cash or common units will, to the extent paid in cash, be available for awards under our 2012 Equity Plan.

Common units that expire or are forfeited or withheld to satisfy exercise price or tax withholding obligations will be available for delivery pursuant to other awards. Our 2012 Equity Plan will be administered by the board of directors of our general partner or a committee thereof (which we refer to herein as the board of directors). The board of directors may also delegate its duties as appropriate, including to a designated committee, which may be created and authorized to make grants to new hires.

Subject to the terms of our 2012 Equity Plan, the board of directors of our general partner has the full authority to select participants to receive awards, determine the types of awards and terms and conditions of awards, and interpret provisions of our 2012 Equity Plan.

While the board of directors may amend our 2012 Equity Plan at any time, any amendment generally may not adversely impair the rights of plan participants with respect to outstanding awards. In addition, an amendment will be contingent on approval by holders of our common units if the amendment would result in our 2012 Equity Plan no longer satisfying any requirements of the principal securities exchange on which the common units are traded. Unless terminated earlier, our 2012 Equity Plan will terminate on the 10th anniversary of the date on which it is approved by the board of directors, after which no further awards may be made under our 2012 Equity Plan, but our 2012 Equity Plan will continue to govern unexpired awards.

Awards may be made under our 2012 Equity Plan to employees, officers, consultants and directors of our general partner or its affiliates who perform services for us or our affiliates or our general partner or its affiliates.

Change in control; termination of service.    The board of directors may provide for accelerated vesting of awards or for awards to become exercisable, as applicable, upon a “change in control” (as defined in our 2012 Equity Plan) or upon certain terminations of employment in applicable award agreements. Except as provided in the applicable award agreement, upon an eligible director’s ceasing to be a director for any reason prior to such director’s phantom units vesting, that director will immediately forfeit all nonvested phantom units, unless the board of directors, in its discretion, accelerates the vesting.

Source of common units.    The common units to be issued under our 2012 Equity Plan may consist, in whole or in part, of common units acquired in the open market or from any affiliate of ours or any other person, newly issued common units or any combination of the foregoing, as determined by the board of directors in its discretion.

 

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Our 2012 Equity Plan will permit the grant of the following awards:

Unit options.    A unit option is an award that, upon exercise, entitles the participant to purchase a common unit. The board of directors may make grants of unit options containing such terms as the board of directors shall determine. Unit options will typically have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit options granted will become exercisable over a period determined by the board of directors.

Common unit appreciation rights.    A common unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a common unit on the exercise date over the exercise price established for the common unit appreciation right. Such excess will be paid in cash or common units. The board of directors may make grants of common unit appreciation rights containing such terms as the board of directors shall determine. Common unit appreciation rights will typically have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, common unit appreciation rights granted will become exercisable over a period determined by the board of directors.

Restricted common units.    A restricted common unit is a common unit that vests over a period of time, and during that time, is subject to forfeiture. The board of directors may make grants of restricted common units containing such terms as the board of directors shall determine, including the period over which restricted common units will vest and whether those restricted common units will participate in distributions during the restricted period. The board of directors, in its discretion, may base its determination upon the achievement of specified performance objectives.

Phantom units.    A phantom unit is a contractual right that entitles the grantee to receive a common unit or cash equivalent to the value of a common unit upon the settlement of the phantom unit. Phantom units, when granted, will identify whether they will be settled in common units or cash. The board of directors may make grants of phantom units containing such terms as the board of directors shall determine, including the period over which phantom units granted will vest and whether phantom units will settle in common units or cash. The board of directors, in its discretion, may base its determination upon the achievement of specified performance objectives.

Performance units and performance bonuses.    A performance unit and a performance bonus are each awards that will become payable in cash or units or any combination of the two upon achievement of specified performance objectives. The board of directors may make grants of performance units or performance bonuses containing such terms as the board of directors shall determine.

Distribution equivalent rights.    The board of directors may, in its discretion, grant distribution equivalent rights, or DERs, in tandem with phantom unit awards or performance unit awards. DERs entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period that the right is outstanding.

Other unit-based awards.    Other unit-based awards are awards that are based, in whole or in part, on the value or performance of a common unit. Upon vesting, the award may be paid in common units, cash or a combination thereof, as provided in the applicable award agreement.

Awards to eligible directors.    Our 2012 Equity Plan sets forth the terms of the equity compensation arrangements of our eligible directors, and such arrangements will be in effect

 

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unless and until otherwise determined by the board of directors. For a description of the equity compensation arrangements that we intend to provide to our directors, see “—Director compensation.”

Withholding taxes.    To the extent that the general partner or any of its affiliates is required to withhold federal, state, local or foreign taxes in connection with any payment made or benefit realized by a participant or other person under our 2012 Equity Plan, and the amounts available for such withholding are insufficient, it will be a condition to the receipt of such payment or the realization of such benefit that the participant or such other person make arrangements satisfactory to our general partner for payment of the balance of such taxes required to be withheld. If a participant fails to make arrangements for the payment of the taxes required to be withheld, our general partner or its affiliates may withhold common units from an award equal to the amount of taxes required to be withheld. In addition, if permitted by the board of directors, the participant or such other person may elect to have any withholding obligation satisfied with units that would otherwise be transferred to the participant or such other person in payment of the participant’s award. However, without the consent of the board of directors, units will not be withheld in excess of the minimum number of units required to satisfy the withholding obligation.

Transferability.    No award may be sold, pledged, assigned or transferred in any manner other than by will or the laws of descent and distribution; provided, however, that a participant who is an officer of the general partner or an affiliate may, with the prior approval of the board of directors, transfer an award to family members of the participant, including to trusts in which family members of the participant own more than 50% of the beneficial interests, to foundations in which family members of the participant or the participant controls the management of assets and to other entities in which more than 50% of the voting interests are owned by family members of the participant or the participant. No unit option or common unit appreciation right granted to a participant will be exercisable during the participant’s lifetime by any person other than the participant or the participant’s guardian or legal representative or permitted transferee under our 2012 Equity Plan.

No repricing.    No repricing of a unit option or common unit appreciation right is permitted under our 2012 Equity Plan without the further approval of our unitholders.

Director compensation

Each of Messrs. Boswell, Coulter, Friedman and Smith will receive compensation for their services as directors of our general partner. In connection with the closing of this offering, each of these directors will receive an initial grant of             phantom units under our 2012 Equity Plan, which will vest in one-third increments on the first business day of each of the first three calendar years beginning after the grant date. In addition, these directors may receive an additional grant of phantom units in lieu of all or a portion of the director’s cash retainer for 2012 pursuant to deferral elections that have been made or will be made prior to the consummation of this offering.

Under our 2012 Equity Plan, each eligible director will receive an annual cash retainer in the amount determined by the board of directors and an annual grant of phantom units in the amount determined by the board of directors. For 2012, the board of directors has determined that each eligible director will receive an annual cash retainer of $43,750 and an annual grant of phantom units in the amount of $43,750. Each eligible director may elect to receive an additional

 

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grant of phantom units in lieu of all or a portion of the director’s cash retainer. Eligible directors will be reimbursed for all out-of-pocket expenses in connection with attending meetings of the board of directors or committees thereof. The position of Chairman of the Board of Directors of our general partner is considered an executive officer position.

Relation of compensation policies and practices to risk management

We anticipate that our compensation policies and practices will reflect the same philosophy and approach as those of Quicksilver. Because the executive officers of our general partner are employees of Quicksilver, compensation other than the long-term incentive plan awards granted pursuant to our 2012 Equity Plan will be determined and paid by Quicksilver and reimbursed by us to the extent determined by our general partner. We expect the equity awards granted pursuant to our 2012 Equity Plan to contain design elements that will serve to minimize the incentive for taking unwarranted risk to achieve short-term, unsustainable results. We will routinely monitor the design of our 2012 Equity Plan to ensure ongoing compliance. Therefore, we do not believe that risk arising from our compensation policies and practices is reasonably likely to have a material adverse effect on us.

 

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Security ownership of certain beneficial owners and management

Quicksilver Production Partners LP

The following table sets forth the beneficial ownership of our common and subordinated units that, upon the consummation of this offering and the related transactions and assuming the underwriters do not exercise their option to purchase additional common units, will be owned by:

 

 

each person who then will beneficially own more than 5% of the then outstanding common units;

 

 

each director and director nominee of our general partner;

 

 

each of the executive officers of our general partner; and

 

 

all directors, director nominees and executive officers of our general partner as a group.

 

Name of beneficial owners(1)   Common
units to be
beneficially
owned
  Percentage
of common
units to be
beneficially
owned
    Subordinated
units to be
beneficially
owned
  Percentage of
subordinated
units to be
beneficially
owned
    Percentage
of total
common and
subordinated
units to be
beneficially
owned
 

 

 

Quicksilver Resources Inc.(2)

          %              %            %   

Thomas F. Darden

          %              %            %   

Glenn Darden

          %              %            %   

Anne Darden Self

          %              %            %   

Robert S. Boswell

          %              %            %   

Paul Coulter

          %              %            %   

Walker C. Friedman

          %              %            %   

M. Garrett Smith

          %              %            %   

John C. Regan

          %              %            %   

John C. Cirone

          %              %            %   

Chris M. Mundy

          %              %            %   

All executive officers, directors and director nominees as a group (8 persons)

          %              %            %   

 

 

 

(1)   Unless otherwise indicated, the address for all beneficial owners in this table is: c/o Quicksilver Production Partners LP, 801 Cherry Street, Suite 3700, Unit 19, Fort Worth, Texas 76102. There are no options, warrants or other rights or obligations outstanding that are currently exercisable or exercisable within 60 days into common or subordinated units.

 

(2)   All of our common units and subordinated units beneficially owned by Quicksilver are held by QPP Holdings LLC. Quicksilver owns 100% of the interest in QPP Holdings LLC and will beneficially own 100% of any distributions made to QPP Holdings LLC with respect to common units and subordinated unit held by QPP Holdings LLC. Quicksilver Production Partners GP, our general partner, owns all of the incentive distribution rights and a 0.1% general partner interest in us. Quicksilver, through QPP Holdings LLC, beneficially owns 100% of the voting member interest in our general partner and will beneficially own 100% of any cash distributions made to our general partner with respect to its 0.1% general partner interest in us and its incentive distribution rights and 100% of any common units issued to our general partner with respect to its incentive distribution rights.

Quicksilver Resources Inc.

The following table sets forth the beneficial ownership of shares of common stock of Quicksilver held by each director and director nominee of our general partner, each of the executive officers

 

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of our general partner and all directors, director nominees and executive officers of our general partner as a group, as of April 1, 2012. The percentage of beneficial ownership is calculated on the basis of 172,936,914 shares of Quicksilver common stock outstanding as of April 1, 2012. Except as otherwise noted, the individual director or executive officer had sole voting and investment power with respect to the shares of common stock of Quicksilver. Unless otherwise indicated, the address for each director and named executive officer listed is: c/o Quicksilver Resources Inc., 801 Cherry Street, Suite 3700, Unit 19, Fort Worth, Texas 76102.

 

Name of beneficial owner    Shares of Quicksilver
common stock
beneficially owned
     Percent of class
outstanding
 

 

 

Thomas F. Darden(1)(2)(3)(4)(5)

     46,041,543         26.5%   

Glenn Darden(1)(2)(3)(4)(5)

     45,924,127         26.5%   

Anne Darden Self(1)(2)(3)(4)(5)

     44,024,017         25.4%   

Robert S. Boswell

               

Paul Coulter(2)

     2,064         *   

Walker C. Friedman

               

M. Garrett Smith

               

John C. Regan(3)(4)(5)

     61,588         *   

John C. Cirone(3)(5)(6)(7)

     611,092         *   

Chris M. Mundy(3)(5)

     73,585         *   

All directors and executive officers as a group (10 people)(1)(2)(3)(4)(5)(6)(7)

     53,383,440         30.6%   

 

 

 

*   Less than 1%.

 

(1)   Includes as to each of Messrs. Thomas F. Darden and Glenn Darden and Ms. Self: 41,677,288 shares beneficially owned by Quicksilver Energy L.P., for which he or she has shared voting and investment power as a member of Pennsylvania Management, LLC, the sole general partner of Quicksilver Energy L.P. Each of Messrs. Thomas F. Darden and Glenn Darden and Ms. Self disclaims beneficial ownership of all shares owned by Quicksilver Energy L.P., except to the extent of his or her pecuniary interest therein.

 

(2)   Includes with respect to each of the following individuals and all directors and executive officers as a group, the following approximate numbers of shares represented by units in a Unitized Stock Fund held through Quicksilver’s 401(k) Plan: Mr. Thomas F. Darden—111,138; Mr. Glenn Darden—41,152; Ms. Self—61,087; Mr. Coulter—2,064; and all directors and executive officers as a group—215,441.

 

(3)   Includes with respect to each of the following individuals and all directors and executive officers as a group, the following numbers of shares subject to options that are or could become exercisable on or before May 31, 2012: Thomas F. Darden—548,728; Mr. Glenn Darden—548,728; Ms. Self—70,594; Mr. Regan—2,530; Mr. Cirone—338,503; Mr. Mundy—14,172; and all directors and executive officers as a group—1,523,255.

 

(4)   Includes with respect to each of the following individuals and all directors and executive officers as a group, the following numbers of shares pledged as collateral security for loans or loan commitments or in accordance with customary terms and conditions of standard margin account arrangements: Mr. Thomas F. Darden—9,273,542 (including 6,113,849 shares beneficially owned by Quicksilver Energy L.P.); Mr. Glenn Darden—6,113,849 (including 6,113,849 shares beneficially owned by Quicksilver Energy L.P.); Ms. Self—6,113,849 (including 6,113,849 shares beneficially owned by Quicksilver Energy L.P.); Mr. Regan—18,081; and all directors and executive officers as a group—9,291,623 (including 6,113,849 shares beneficially owned by Quicksilver Energy L.P.).

 

(5)   Includes with respect to each of the following individuals and all directors and executive officers as a group, the following numbers of shares of restricted stock for which the indicated beneficial owners have no investment power: Mr. Thomas F. Darden—350,511; Mr. Glenn Darden—350,511; Ms. Self—40,977; Mr. Regan—40,977; Mr. Mundy—38,700; and all directors and officers as a group—780,699.

 

(6)   Includes 122,953 shares subject to restricted stock units that could vest on or before May 31, 2012 and for which Mr. Cirone has no voting or investment power.

 

(7)   Includes shares subject to options that would become exercisable, and restricted stock units that would vest, upon Mr. Cirone’s retirement. Mr. Cirone satisfied the retirement eligibility criteria under the Quicksilver Resources Inc. 2006 Equity Plan on January 22, 2012.

The information regarding beneficial ownership is based on information furnished by each director or executive officer or information contained in filings made with the SEC.

 

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Certain relationships and related party transactions

Upon the consummation of this offering, assuming the underwriters do not exercise their option to purchase additional common units, Quicksilver will own approximately     % of our outstanding common units, all of our subordinated units and all of the membership interests in and control our general partner. Our general partner will own a 0.1% general partner interest in us, evidenced by              general partner units, and all of the incentive distribution rights. These percentages do not reflect any common units that may be issued under our 2012 Equity Plan that our general partner expects to adopt prior to the closing of this offering.

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 dissolution. These distributions and payments were determined by and among affiliated entities and, consequently, were not the result of arm’s-length negotiations.

Formation Stage

 

Consideration received by Quicksilver in exchange for (i) the Partnership Properties, which were transferred from Quicksilver to Quicksilver Production Partners Operating Ltd., which will be transferred (pursuant to our exchange agreement described below) to us; and (ii) certain commodity derivatives   

•              common units;

 

•              subordinated units; and

 

• approximately $         million in cash.

Interests received by our general partner   

•              general partner units; and

 

• all of the incentive distribution rights.

In the event that the over-allotment option is exercised, Quicksilver will receive fewer common units and more cash in exchange for the Partnership Properties. If the over-allotment option is exercised, we will use the net proceeds from that exercise to redeem from Quicksilver a number of common units equal to the number of common units issued upon such exercise, at a price per common unit equal to the proceeds per common unit before offering costs but after deducting underwriting discounts and commissions. If the over-allotment option is exercised in full, we will redeem              common units from Quicksilver and pay Quicksilver $         million in cash, after which Quicksilver will end up with              common units and $             million in cash.

Operational Stage

 

Distributions of available cash to our general partner and its affiliates    We will generally make cash distributions 99.9% to our unitholders (including Quicksilver as the holder of approximately     % of our limited partner interests), pro rata

 

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and 0.1% to our general partner (assuming it maintains its 0.1% general partner interest in us). In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to a maximum of 25.0% of the distributions above the highest target distribution level (including the general partner’s 0.1% general partner interest).

 

Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive annual distributions of approximately $         million on its general partner units and Quicksilver would receive annual distributions of approximately $         million on its common units and subordinated units.

Payments to our general partner and its affiliates    Our general partner will not receive a management fee or other compensation for its management of our partnership, but we will reimburse our general partner for all expenses it incurs or payments it makes on our behalf, including expenses incurred or payments made under our omnibus agreement as well as other expenses or payments allocable to us and our subsidiaries, as determined, in good faith, by our general partner (taking into consideration the goods, services or other benefits provided to us in respect of such expenses). Our partnership agreement does not set a limit on the amount of expenses for which our general partner may be reimbursed.
Withdrawal or removal of our general partner    If our general partner is removed for cause or withdraws in breach of our partnership agreement, a successor general partner will have the option to purchase the departing general partner’s general partner interest and the incentive distribution rights 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 by the limited partners, the

 

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   departing general partner will have the option to require the successor general partner to purchase the departing general partner’s general partner interest and its incentive distribution rights for their fair market value. If the departing general partner or the successor general partner, as the case may be, does not exercise its option, the departing general partner’s general partner interests and incentive distribution rights will convert into common units.
Dissolution Stage   

Dissolution

   Upon our dissolution, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Second Amended and Restated Limited Liability Company Agreement of Quicksilver Production Partners GP

Upon the closing of this offering, Quicksilver will indirectly own all of the membership interests in our general partner. The membership interests will be the sole voting interests in our general partner and will entitle Quicksilver to all distributions we make to our general partner (including distributions with respect to our general partner’s 0.1% general partner interest in us and its incentive distribution rights).

A member may transfer, pledge or assign all or any portion of its membership interest in our general partner at any time.

Agreements governing the transactions

In connection with the closing of this offering, we, our general partner and its affiliates will enter into the various documents and agreements that will effect the transactions described in “Summary—Our partnership structure and formation transactions,” including the contribution of assets to, and the assumption of liabilities by, us and the application of the proceeds of this offering. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets to us, will be paid from the proceeds of this offering or from amounts borrowed under our new revolving credit facility.

Exchange agreement

In connection with the closing of this offering, we intend to enter into an exchange agreement with Quicksilver and a number of its affiliates pursuant to which Quicksilver will transfer to us all of the equity in Quicksilver Production Partners Operating Ltd. (which will own all of the Partnership Properties) and certain derivative contracts in exchange for a combination of common and subordinated units and cash.

 

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In connection with such exchange, we will agree to indemnify Quicksilver for all liabilities and obligations of Quicksilver Production Partners Operating Ltd. (whether arising before or after the closing), and Quicksilver will agree to indemnify us for certain limited types of liabilities as described below.

Quicksilver will indemnify us and our subsidiaries against (1) certain environmental losses relating to the Partnership Properties and arising from events occurring prior to the closing, (2) title defects in the oil and gas properties contributed to us, (3) losses arising from the failure to obtain any consent, waiver or permit necessary for us to own or operate the Partnership Properties in a manner consistent with our business, (4) income taxes attributable to pre-closing ownership or operation of the Partnership Properties, including any income tax liabilities related to the formation transactions occurring on or prior to the closing and (5) losses associated with breach of certain representations and warranties made by Quicksilver which relate to the valid formation and existence of Quicksilver Production Partners Operating Ltd. Quicksilver’s indemnification obligations will survive (1) for one year after the closing of this offering with respect to environmental losses, (2) for three years with respect to loses arising from title defects and failures to obtain consents, (3) until after expiration of the applicable statute of limitations with respect to income taxes and (4) indefinitely with respect to valid formation and existence of Quicksilver Production Partners Operating Ltd. All indemnity claims (other than income tax related claims) are subject to a $50,000 per claim de minimis exception; environmental claims are subject to an aggregate $500,000 deductible and $10,000,000 cap; and claims relating to title defects or missing consents are subject to an aggregate $500,000 deductible.

The exchange agreement will provide that if the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem a number of common units from Quicksilver equal to the number of common units issued upon such exercise, at a price per common unit equal to the proceeds per common unit before offering costs but after deducting underwriting discounts and fees.

Omnibus agreement

In connection with the closing of this offering, we and our general partner will enter into an omnibus agreement with Quicksilver pursuant to which:

 

 

Quicksilver will provide general, administrative and operational services to allow us to carry on our business in a manner similar to that in which such business was carried on by our predecessor. These services will include drilling, engineering, marketing and environmental services;

 

 

We will reimburse Quicksilver for all expenses Quicksilver incurs (or payments Quicksilver makes on our behalf) in conjunction with its provision of such services, including our public company expenses, an allocated portion of the compensation and benefits of the executive officers and eligible directors of our general partner and other employees of Quicksilver who perform services for us or on our behalf, expenses related to drilling, engineering, marketing and compliance with environmental laws and the cost of insurance coverage with respect to our business, operations and the officers and directors of our general partner;

 

 

Quicksilver will have no liability to us, our subsidiaries or our representatives under the omnibus agreement except if a court of competent jurisdiction finds that Quicksilver is liable for bad faith, fraud, gross negligence or willful misconduct;

 

 

We will indemnify Quicksilver and its respective officers, managers, directors, employees and agents for any liabilities they incur attributable to the services provided to us under the

 

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agreement, other than liabilities resulting from Quicksilver’s bad faith, fraud, gross negligence or willful misconduct. In addition, Quicksilver must indemnify us for any liability we incur as a result of Quicksilver’s bad faith, fraud, gross negligence or willful misconduct in providing the services under our omnibus agreement; and

 

 

Neither Quicksilver nor its affiliates (other than our general partner) will be restricted from competing with us. Pursuant to our omnibus and partnership agreements, Quicksilver and its affiliates (other than our general partner) will be permitted to compete with us and may acquire additional oil and gas properties or other assets in the future without any obligation to offer us the opportunity to acquire those assets.

Under our omnibus agreement, Quicksilver will offer us the first opportunity to acquire any oil and gas properties in the Barnett Shale Counties that Quicksilver or any of its controlled subsidiaries may offer for sale.

The initial term of our omnibus agreement will be five years, and our omnibus agreement will automatically renew for additional one-year terms thereafter, unless either party provides 180 days’ written notice of its intent not to renew. Quicksilver may terminate our omnibus agreement on 60 days’ written notice in the event that it ceases to be our affiliate and on 30 days’ written notice if we fail to pay material amounts due under that agreement in accordance with its terms. Our omnibus agreement may only be assigned by either party with the other party’s consent.

Tax sharing agreement

In connection with the closing of this offering, we intend to enter into a tax sharing agreement pursuant to which we will pay Quicksilver an amount equal to the state and local income and other taxes that we would pay on a separate basis where we are included in a combined or consolidated tax return filed by Quicksilver or its affiliates with respect to periods after the closing of this offering. Quicksilver may use its tax attributes to reduce the taxes of its combined or consolidated group, of which we may be a member for this purpose. However, we would nevertheless pay Quicksilver for the tax we would have owed had we filed a separate tax return, without the benefit of any tax attributes of Quicksilver, even if the actual cash tax expense of Quicksilver is less than the amount we pay to Quicksilver.

Trademark license agreement

In connection with the closing of this offering, we will enter into a trademark license agreement with Quicksilver and our general partner, pursuant to which Quicksilver will license to us and our general partner Quicksilver’s rights in the trademark “QUICKSILVER” for use in our and our general partner’s respective names, logos and domain names. The license agreement will require us and our general partner to comply with certain customary quality control measures prescribed by Quicksilver with respect to the use of the “QUICKSILVER” trademark and will permit Quicksilver to terminate the trademark license agreement upon the occurrence of certain termination events, including our or our general partner’s material breach of the trademark license agreement and certain change of control events. Neither we nor our general partner will be permitted to assign the trademark license agreement without Quicksilver’s consent.

Review, approval or ratification of transactions with related persons

Our general partner’s board of directors will adopt a written policy that will set forth procedures covering transactions with related parties. The policy will cover transactions to which we or any

 

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of our subsidiaries is a party and in which any director or executive officer of our general partner or any person that beneficially owns more than 5% of our common units, any immediate family member of such director, officer or owner, or any related entity of such related party, had, has or will have a direct or indirect interest, other than a transaction involving (a) compensation by us or (b) less than $120,000. The policy will instruct directors and executive officers to bring any possible related party transaction to the attention of our general partner’s general counsel or compliance officer, who, unless he or she determines that the transaction is not a related party transaction, will notify the board of directors of our general partner. The board of directors of our general partner may, but is not required to, seek the approval of the conflicts committee in connection with its review of a possible related party transaction. Under the policy, the conflicts committee may approve or ratify a related party transaction for which its approval has been sought by the board of directors if a majority of the conflicts committee determines that the transaction is in, or not opposed to, our best interest. Under the policy, in making this determination, the conflicts committee will consider (i) the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest, (ii) the totality of the relationships among the parties involved (including other transactions that may be particularly favorable or advantageous to us), (iii) any customary or accepted industry practices and any customary or historical dealings with a particular person, (iv) any applicable generally accepted accounting practices or principles and (v) such additional factors as the conflicts committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.

The board of directors of our general partner will have a standing conflicts committee comprised of at least one independent director. Additional independent directors may be added by the board of directors of our general partners to address conflicts of interest on a case by case basis. Our general partner may, but is not required to, seek the approval of the conflicts committee in connection with future acquisitions from (or other transactions with) Quicksilver or any of its affiliates. In the case of any sale of equity or debt by us to Quicksilver or any of its affiliates, we anticipate that our practice will be to obtain the approval of the conflicts committee for the transaction.

Quicksilver and its affiliates will be free to offer properties to us on terms Quicksilver and its affiliates deem acceptable. In such cases, an offer can be approved under our partnership agreement by (i) a majority of the conflicts committee, (ii) a majority of the board of directors of our general partner, if it determines in good faith either that the terms of the transaction are no less favorable to us than those provided to or available from unrelated third parties or that the transaction is fair and reasonable to us taking into account the totality of the relationships between the parties involved, or (iii) a majority of the holders of the outstanding common units (excluding common units owned by our general partner and its affiliates). We expect the board of directors of our general partner (or the conflicts committee) will consider a number of factors in its determination of value, including, without limitation, production and proved reserve data, operating cost structure, current and projected cash flows, financing costs, the anticipated impact on distributions to our unitholders, production decline profile, commodity price outlook, proved reserve life, future drilling inventory and the weighting of the expected production between oil and natural gas.

We expect that Quicksilver and its affiliates will consider a number of the same factors considered by the board of directors of our general partner to determine the proposed price for any assets it or they may offer to us in future periods. In addition to these factors, given that

 

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Quicksilver will indirectly be our largest unitholder following the consummation of this offering, Quicksilver may consider the potential positive impact on its underlying investment in us by offering properties to us at attractive purchase prices. Likewise, it may consider the potential negative impact on its underlying investment in us if we are unable to acquire additional assets on favorable terms.

 

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Fiduciary and other duties

Delaware law provides that a Delaware limited partnership may, in its partnership agreement, expand, restrict or eliminate any fiduciary or other duties that might otherwise be applicable (except for the implied contractual covenant of good faith and fair dealing) and limit or eliminate any liability for breach of contract or breach of fiduciary or other duties (except for liability for a bad faith violation of the implied contractual covenant of good faith and fair dealing).

Limitations on duties and liabilities

Our partnership agreement restricts, and in many instances eliminates, the fiduciary and other duties that our general partner, its board of directors (including any committee thereof), its affiliates and the directors and other persons who control our general partner or any of its affiliates might otherwise owe to us and our unitholders. Our partnership agreement also limits, or in many instances eliminates, the liability of our general partner, its board of directors (including any committee thereof), its affiliates and the directors and other persons who control our general partner or any of its affiliates, and the remedies available for a breach of contract or breach of any fiduciary or other duties that might exist.

For example, our partnership agreement:

 

 

provides that except as otherwise expressly provided in any other agreement entered into by Quicksilver (which is used in this prospectus to mean Quicksilver and its subsidiaries other than our general partner, us and our subsidiaries) and our general partner or us, Quicksilver and its directors, officers, employees and other agents (in their capacities as such) will have no fiduciary or other duties to us or our unitholders and may consider any interests or factors that they desire, including their own interests, to the exclusion of all others. As a result, for example, Quicksilver will have no fiduciary or other duty to us or our unitholders in exercising its rights to vote or transfer its units and may exercise such rights in its sole discretion.

 

 

provides that except as described in the fifth bullet point, our general partner, its board of directors (and any committee thereof) and its directors and other persons who control it when acting on behalf of our general partner or us, will not be subject to any fiduciary or other duty to us or our unitholders other than the obligation to act in good faith (which is defined in the partnership agreement, without reference to a reasonableness standard, to mean acting with the actual belief that it is in, or not opposed to, the best interest of the partnership).

 

 

provides that in taking any action or making any decision on behalf of the general partner or us, our general partner, its board of directors (and any committee thereof) and its directors and other persons who control it will be presumed to have acted in good faith (as defined in the partnership agreement) and not to have breached the partnership agreement or any other agreement contemplated to be entered into in connection with this offering or any fiduciary or other duty owed to us or our unitholders, and that in any proceeding brought by or on behalf of any unitholder or us, the person bringing such proceeding will have the burden of overcoming such presumption.

 

 

provides that in taking any action or making any decision on behalf of the general partner or us, our general partner, its board of directors (and any committee thereof) and its directors and other persons who control it are not required under the partnership agreement or otherwise to consider the interests of any person other than the partnership and in no event

 

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are they under any duty to consider the separate interests of our unitholders (including, without limitation, the tax consequences to unitholders) or of any particular unitholder in granting (or not granting) any approvals or making any decisions, including deciding whether to cause the partnership to take (or decline to take) any actions.

 

 

provides that in making certain decisions, our general partner, its board of directors (and any committee thereof) and its directors and other persons who control it will not be subject to any fiduciary or other duty (including any duty to act in good faith) and may consider any interests or factors that it desires, including its own interests, to the exclusion of all others. Examples of such decisions include our general partner’s exercise of its right to vote or transfer its general partner or other units or the incentive distribution rights, its registration rights, its call right, its right to reset the minimum quarterly distribution and target distribution levels and thereby receive common units or its determination whether or not to consent to a merger, consolidation or sale of substantially all of our assets or any amendment to the partnership agreement.

 

 

provides that any resolution or course of action with respect to a conflict of interest between our general partner or any of its affiliates (or any of their respective directors, officers, employees or other agents), on the one hand, and us or our unitholders, on the other hand shall be conclusively deemed approved by and binding on all of our unitholders and not a breach of the partnership agreement or any other agreement contemplated to be entered into in connection with this offering or any fiduciary or other duty owed to us or our unitholders if it is:

 

   

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;

 

   

approved by a majority of the conflicts committee acting in good faith;

 

   

on terms no less favorable to us than those generally being provided to or available from unrelated third parties, as determined by a majority of the board of directors of our general partner acting in good faith; or

 

   

fair and reasonable to us, as determined by a majority of the board of directors of our general partner acting in good faith.

Please read “—Conflicts of interest” for a discussion of further details concerning the partnership agreement provisions with respect to the procedures for resolving potential conflicts of interest.

 

 

provides that our general partner, its board of directors (and any committee thereof), its affiliates and the officers, directors and other persons who control our general partner or any of its affiliates will not be liable for monetary damages to us or our unitholders (and will be indemnified by us) for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such person acted in bad faith or engaged in fraud or willful misconduct, or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

By purchasing a common unit, a unitholder will become bound by the provisions in the partnership agreement, including the provisions discussed above.

 

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We have adopted these restrictions to allow our general partner and its affiliates (including Quicksilver) to engage in transactions with us that would otherwise raise concerns under state-law fiduciary duty 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 of the benefits we expect to get from our relationship with Quicksilver and the conflicting duties our general partner’s board of directors and others would otherwise have to Quicksilver and to us. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. With them, our general partner may consider the interests of all parties involved in a related party transaction when acting pursuant to the second or fourth sub-bullet points above. We believe that these modifications also enable our general partner to attract and retain experienced and capable directors. These modifications are detrimental to our common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty.

Conflicts of interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Quicksilver) on the one hand, and us and our limited partners, on the other hand. For example, the interests of Quicksilver may, in certain circumstances, be different or inconsistent with the interests of the partnership, and there is nothing in the partnership or other agreement that requires Quicksilver to act in our interests or prevents Quicksilver from competing with us. While our general partner in most instances has a duty to act in good faith in managing the partnership (which is defined, without reference to a reasonableness standard, to mean the actual belief that it is acting in, or not opposed to, the best interest of the partnership), the directors and officers and other persons who control our general partner may also have independent fiduciary duties to our general partner and its owner, Quicksilver, including fiduciary duties which require them to manage our general partner in the best interest of its owner, Quicksilver. Certain of the directors and all of the officers of our general partner also serve in similar capacities with Quicksilver and may have fiduciary duties to Quicksilver and its stockholders. In addition, these directors and officers will be compensated by Quicksilver and may have interests and other economic incentives in Quicksilver, which may lead to additional conflicts of interest.

If a conflict arises between our general partner or any of its affiliates (or any of their respective directors, officers, employees or agents) on the one hand, and us or our limited partners, on the other hand, the resolution or course of action taken in respect of the conflict of interest shall be conclusively deemed to be approved and binding on all of our unitholders and not a breach of the partnership agreement or any other agreement contemplated to be entered into in connection with this offering or any fiduciary or other duty owed to us or our unitholders if it is:

 

 

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;

 

 

approved by a majority of the conflicts committee acting in good faith;

 

 

on terms no less favorable to us than those generally being provided to or available from unrelated third parties, as determined by a majority of the board of directors of our general partner acting in good faith; or

 

 

fair and reasonable to us, as determined by a majority of the board of directors of our general partner acting in good faith.

 

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As provided by our partnership agreement, the board of directors of our general partner will have a conflicts committee composed of one or more members of the board of directors that will review matters that may involve conflicts of interest that are submitted to it by the board of directors. In addition, the conflicts committee will be requested to review and approve the amount of estimated maintenance capital expenditures deducted from operating surplus and the allocation of capital expenditures between maintenance capital expenditures, growth capital expenditures and investment capital expenditures. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of Quicksilver or other affiliates of our general partner, cannot be holders of ownership interests in Quicksilver, our general partner or any of its affiliates (other than common units and awards granted under our 2012 Equity Plan or successor equity compensation plan) and must otherwise meet the independence standards required to serve on an audit committee of a board of directors of a company listed on the NYSE. Because our partnership agreement only requires that the conflicts committee have at least one member, during any time that the conflicts committee only has one member, that single member of the conflicts committee will be able to approve resolutions or courses of action taken in respect of conflicts of interest. It is possible that a single-member committee may not function as effectively as a multiple-member committee, but if we pursue a transaction with an affiliate while the conflicts committee has only one member, our limited partners will be deemed to have approved that transaction through the approval of that single-member committee. Our general partner may, but is not required to, seek approval from the conflicts committee of a resolution or course of action taken in respect of a conflict of interest.

The conflicts committee (in granting approval under the second bullet point above) and the board of directors (in determining the “fair and reasonable” nature to us under the fourth bullet point) shall each be authorized to consider (i) the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest, (ii) the totality of the relationships among the parties involved (including other transactions that may be particularly favorable or advantageous to us), (iii) any customary or accepted industry practices and any customary or historical dealings with a particular person, (iv) any applicable generally accepted accounting practices or principles and (v) such additional factors as the conflicts committee or the board of directors determines to be relevant, reasonable or appropriate under the circumstances.

If the conflicts committee grants approval pursuant to the second bullet point or the board of directors determines that the resolution or course of action taken with respect to a conflict of interest satisfies the third or fourth bullet points, then it shall be presumed that they acted in good faith, and in any proceeding brought by or on behalf of any unitholder or us challenging such decision, the person bringing such proceeding will have the burden of overcoming such presumption.

Conflicts of interest could arise in the situations described below, among others:

Quicksilver owns and controls our general partner, which controls us and our operations.

Quicksilver owns and controls our general partner, which controls us and manages all of our operations. As owner of our general partner, Quicksilver has the power to appoint and remove all of the directors of our general partner. Our unitholders will have limited voting rights and will not be able to appoint or remove our general partner or any of its directors.

 

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Quicksilver may have interests that are different from or inconsistent with our interests or the interests of our unitholders, and there is nothing in the partnership or any other agreement that requires Quicksilver to act in our best interest or prevents Quicksilver from competing with us.

There is nothing in the partnership agreement or any other agreement with Quicksilver that requires it to act in our best interest or prevents Quicksilver from competing with us. Indeed the partnership agreement specifically eliminates any fiduciary or other duties that Quicksilver might otherwise owe to us under Delaware law. In making any determination or in taking or declining to take any action, Quicksilver and its officers, directors, employees, agents and other controlling persons (in their capacities as such) may act in their sole discretion and consider any interests or factors that they may desire, to the exclusion of all others

There is nothing in the partnership or any other agreement that limits the ability of Quicksilver and its affiliates (other than our general partner) to compete with us, which could cause conflicts of interest and limit our ability to develop and grow our business.

Our partnership agreement provides that Quicksilver and its affiliates (other than our general partner) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Quicksilver and its affiliates (other than our general partner) may acquire or develop additional oil and gas properties or other assets in the future, without any obligation to offer us the opportunity to acquire or develop any of those assets. Quicksilver could choose to acquire properties and pursue opportunities that would have been suitable for our partnership. In such a case, Quicksilver would have the benefit of any such opportunity instead of us.

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

The doctrine of corporate opportunity will not apply to Quicksilver or its affiliates, which could cause conflicts of interest and limit our ability to develop and grow our business.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to Quicksilver, any of its affiliates, any of the officers, directors or other persons who control any such entities or to any of our subsidiaries. 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 or other duty if it takes the opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us, provided that (i) our general partner will not be permitted to keep any such opportunity for itself and (ii) such person does not use confidential information provided by us or on our behalf to such person.

 

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Certain of the directors and all of the officers who have responsibility for our management have significant duties with, and will spend significant time serving, entities that compete with us and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

All of the officers of our general partner hold similar positions with Quicksilver, and certain of the directors of our general partner are directors or officers of Quicksilver. Thomas F. Darden, the chairman of the board of directors of our general partner, is the chairman of Quicksilver’s board of directors. Glenn Darden, the President and Chief Executive Officer of our general partner and a member of its board of directors, is the President and Chief Executive Officer of Quicksilver and serves on Quicksilver’s board of directors. After the closing of this offering, officers of our general partner will continue to devote significant time to the business of Quicksilver. We cannot assure you that any conflicts that may arise between us or our unitholders, on the one hand, and Quicksilver or its affiliates, on the other hand, will be resolved in our favor. Because the officers and certain of the directors of our general partner are also officers and/or directors of Quicksilver, such officers and directors may have fiduciary duties to Quicksilver that conflict with their duties to us and cause them to pursue business strategies that are more beneficial to Quicksilver than to us or are otherwise not in our best interest. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our unitholders should be aware, please read “Business and properties—Our relationship with Quicksilver.”

Neither we nor our general partner have any employees, and we will rely solely on the employees of Quicksilver to manage our business. The employees of Quicksilver who will manage our business will also perform substantially similar services for Quicksilver , and thus will not be solely focused on our business.

Neither we nor our general partner have any employees, and we will rely solely on Quicksilver to operate our assets. Upon consummation of this offering, our general partner will enter into an omnibus agreement with Quicksilver, pursuant to which, among other things, Quicksilver will agree to make available to our general partner Quicksilver’s personnel to allow us to carry on our business in a manner similar to that in which it was carried on by our predecessor.

Because Quicksilver will provide services to us that are substantially similar to those it provides with respect to its own assets and operations, Quicksilver may not have sufficient human, technical and other resources to provide those services at a level that Quicksilver would be able to provide to us if it were solely focused on our business and operations. Quicksilver may make internal decisions regarding the allocation of its available resources and expertise that may prioritize Quicksilver’s interests over ours. There is no requirement that Quicksilver favor us over itself in providing its services. If the employees of Quicksilver and its affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

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

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our

 

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general partner seeks approval of the conflicts committee, on such terms as it determines to be necessary or appropriate to conduct our business, including, but not limited to, the following:

 

 

the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

 

 

the purchase, sale or other acquisition or disposition of our securities, or the issuance of options, rights, warrants and unit appreciation rights relating to our securities;

 

 

the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;

 

 

the negotiation, execution and performance of any contracts, conveyances or other instruments;

 

 

the distribution of our cash;

 

 

the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

 

 

the maintenance of insurance for our benefit and the benefit of our indemnitees;

 

 

the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other entities;

 

 

the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

 

 

the indemnification of any person against liabilities and contingencies to the extent permitted by law;

 

 

the making of tax, regulatory and other filings or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

 

 

the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Our partnership agreement provides that in most instances (and unless the partnership agreement specifically provides otherwise) our general partner must act in “good faith” when making decisions on our behalf, and our partnership agreement defines “good faith,” without reference to a reasonableness standard, as the actual belief that the determination is in, or not opposed to, our best interest. Please read “The partnership agreement—Limited voting rights” for information regarding matters that require unitholder approval.

 

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Our general partner determines the amount and timing of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuance of additional partnership interests and cash reserves, each of which can affect the amount of cash that is distributed to our unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

 

 

the manner in which our business is operated;

 

the amount, nature and timing of asset purchases and sales;

 

the amount, nature and timing of our capital expenditures;

 

the amount, nature and timing of borrowings;

 

the issuance of additional units; and

 

the creation, reduction or increase in cash reserves.

Our general partner determines the amount and timing of any capital expenditures and, with the concurrence of the conflicts committee, whether a capital expenditure is classified as a maintenance capital expenditure, the estimate of which reduces operating surplus, or a growth or investment capital expenditure, which does not. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert into common units.

In addition, our general partner may use an amount, initially equal to $             million, which would not otherwise constitute operating surplus, in order to permit the payment of cash distributions. This may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “Provisions of our partnership agreement relating to cash distributions.”

Borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of enabling our general partner or its affiliates to receive distributions on the incentive distribution rights or any subordinated units held by them or enabling the expiration of the subordination period. For example, if we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on outstanding units.

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us or our operating subsidiaries.

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

We will reimburse our general partner and its affiliates for costs incurred in managing and operating our business, including costs incurred in rendering staff and support services to us. These costs will include all direct and indirect costs and expenses incurred in providing such services (including a share of general, administrative, overhead and other indirect costs allocable to the provision of such services).

 

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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 contractual arrangements with any of these entities on our behalf.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to reimburse itself for direct and indirect expenses incurred by it on our behalf (taking into consideration the goods, services or other benefits provided to us in respect of such expenses). Our general partner may also enter into contractual or other arrangements with Quicksilver or its affiliates on our behalf (such as our omnibus agreement) on such terms as it shall determine in good faith. Such arrangements will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may refer one or more of these types of situations to the conflicts committee.

Our general partner and its affiliates will have no obligation to permit us to use their facilities or assets, except as may be provided in our omnibus agreement and other contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm’s-length negotiations.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to reimburse itself for direct and indirect expenses incurred by it on our behalf (taking into consideration the goods, services or other benefits provided to us in respect of such expenses) and pay Quicksilver or their respective affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with Quicksilver and its affiliates on our behalf. Neither the partnership agreement nor any of the other agreements, contracts and arrangements between us, on the one hand, and our general partner, Quicksilver and their respective affiliates, on the other, are or will be the result of arm’s-length negotiations.

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner, Quicksilver or their respective affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner, Quicksilver or their respective affiliates in our favor.

Our general partner and Quicksilver may be able to amend our partnership agreement without the approval of any other unitholder after the subordination period.

Our general partner has the discretion to propose amendments to our partnership agreement, certain of which may be made by our general partner without unitholder approval. During the subordination period, certain amendments of our partnership agreement require the consent of our general partner and the approval of a majority of our public common unitholders and a majority of the outstanding subordinated units, each voting as a separate class. After the subordination period, our partnership agreement can be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by Quicksilver and its affiliates). Upon the consummation of this

 

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offering, Quicksilver will own an aggregate of approximately     % of our outstanding common units and all of our subordinated units. Assuming that Quicksilver retains a sufficient number of its common units and that we do not issue additional common units, our general partner and Quicksilver will have the ability to amend our partnership agreement without the approval of any other unitholder after the subordination period. Please read “The partnership agreement—Amendment of the partnership agreement.”

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

Our general partner will enter into contractual arrangements on our behalf and intends to limit its liability under such contractual arrangements so that the other party has recourse only to our assets and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability in this manner is not a breach of our general partner’s fiduciary or other duties, even if we could have obtained more favorable terms without the limitation on liability.

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by Quicksilver. The attorneys, independent accountants and others who will perform services for us in the future will be selected by our general partner or the conflicts committee and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units 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. We do not intend to do so in most cases.

Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.

Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner will not be subject to any fiduciary or other duty in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “The partnership agreement—Limited call right.”

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and target distribution levels related to its incentive distribution rights without the approval of the conflicts committee or our unitholders. This election would dilute unitholders’ ownership interest in us.

Our general partner has the right (but not the obligation), in certain circumstances, to reset the initial target distribution levels at higher levels and receive common units in exchange therefor. In exercising this right, our general partner is not subject to any fiduciary or other duty to us or our unitholders.

Although we anticipate that our general partner would exercise this right only to facilitate certain acquisitions or internal growth projects, it is possible that our general partner could exercise this right at a time when we are experiencing, or may in the future experience, declines

 

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in our aggregate cash distributions. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives on its incentive distribution rights and may therefore desire to be issued our common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels. Please read “Provisions of our partnership agreement relating to cash distributions—General partner interest and incentive distribution rights.”

Fiduciary duties

The following is a summary of the material restrictions on the fiduciary and other duties owed by our general partner to us and our limited partners:

 

 

          Default State Law        Our Partnership Agreement

 

Fiduciary Duties   

• Under Delaware law, the fiduciary and other duties owed to the partnership and its limited partners (except for the implied contractual covenant of good faith and fair dealing) may, by provision in the partnership agreement, be restricted or eliminated. In the absence of such a provision in a partnership agreement, a general partner owes a limited partnership and its limited partners a fiduciary duty of care and loyalty. A majority limited partner and persons who control the general partner may owe fiduciary or other duties to the limited partners.

 

• Under the duty of care, the general partner must inform itself of all material information reasonably available and relevant to a decision.

 

• Under the duty of loyalty, the general partner must act in good faith and in the best interest of the partnership and its limited partners and cannot act based on its own interests or the interests of persons other than the partnership and its limited partners.

  

• Our partnership agreement restricts and, in many instances, eliminates the fiduciary and other duties owed to us and our limited partners.

 

• In most instances, when our general partner or a person who controls our general partner is acting in its capacity as such, it will not be subject to any fiduciary or other duty to us or our unitholders (including the duties of care and loyalty), except the obligation to act in “good faith” (as defined in our partnership agreement).

 

• In certain circumstances, our general partner may act free of any fiduciary or other duty (including the obligation to act in good faith) to us or our limited partners.

 

• Quicksilver and its directors, officers, employees and other agents (in their capacities as such) will have no fiduciary or other duties to us or our unitholders.

 

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      Default State Law    Our Partnership Agreement

 

Claims in the Absence of a Conflict of Interest    The general partner is presumed to have acted in accordance with its duties, and the plaintiff must prove that the general partner acted with gross negligence.    The general partner is presumed to have acted in accordance with its duties, and the plaintiff must prove that the general partner did not act in good faith (defined, without reference to a reasonableness standard, as the actual belief that it was acting in, or not opposed to, the best interest of the partnership).
Claims Relating to Conflicted Transactions    In the case of a conflict of interest that has not been approved by disinterested limited partners or directors, the general partner has the burden of satisfying the entire fairness standard which requires both a fair price and fair process.   

In the case of a conflict of interest that has not been approved by disinterested unitholders or the conflicts committee of the board of directors of our general partner, the plaintiff will have the burden of proving that the general partner did not act in good faith if its board of directors has determined that the transaction is:

 

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

 

• fair and reasonable to us.

Limitations on Liability    Under Delaware law, the liabilities for breach of contract or breach of fiduciary or other duties (except for liabilities for a bad faith violation of the contractual covenant of good faith and fair dealing) may, by a provision in the partnership agreement, be limited or eliminated.    Our partnership agreement limits and, in many instances, eliminates liabilities for breach of contract or breach of fiduciary or other duties. Our general partner, its affiliates and their directors, officers, and certain other specified persons will not be liable for monetary damages to us or our limited partners unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that any such person acted in bad faith or engaged in fraud or willful misconduct, or in the case of a criminal matter, acted with the knowledge that such conduct was unlawful.

 

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      Default State Law    Our Partnership Agreement

 

Indemnification    A limited partnership may indemnify any partner or other person against all claims and demands.    We must indemnify our general partner, its affiliates and their directors, officers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by such persons, in their capacities as such, unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith, or engaged in fraud or willful misconduct, or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. Please read “The partnership agreement—Indemnification.”
Limitation on Venue    Any legal proceeding with respect to the partnership agreement may be brought in the Court of Chancery of the State of Delaware.    Any legal proceedings with respect to the partnership agreement must be brought in the Court of Chancery of the State of Delaware (or, if for any reason the Court of Chancery of the State of Delaware does not have subject matter jurisdiction, such other appropriate state or federal court in the State of Delaware).

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our 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 to sign a partnership agreement does not render our partnership agreement unenforceable against that person.

 

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Description of the common units

The units

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “Our cash distribution policy and restrictions on distributions.” For a description of other rights and privileges of limited partners under our partnership agreement, including limited voting rights, please read “The partnership agreement.”

Transfer agent and registrar

Duties

Computershare Trust Company, N.A. will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units, except the following, which must be paid by our unitholders:

 

 

surety bond premiums to replace lost or stolen certificates or to cover taxes and other governmental charges;

 

 

special charges for services requested by a common unitholder; and

 

 

other similar fees or charges.

There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of their actions for their activities in that capacity, except for any liability due to any gross negligence or willful misconduct of the indemnitee.

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 is appointed, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of common units

By transfer of common units in accordance with our partnership agreement, each transferee of common units will be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

 

 

represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

 

 

automatically agrees to be bound by the terms and conditions of our partnership agreement; and

 

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gives the consents, waivers, powers-of-attorney and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

Our general partner may in certain circumstances require certifications from our limited partners as to their nationality, citizenship and related status and as to their U.S. federal income tax status and in certain cases redeem the common units of our limited partners that cannot provide the required certifications. Please see “The partnership agreement—Non-citizen and non-taxpaying unitholders; redemption.”

In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units. A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

We may, at 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 any transfers are subject to the laws governing transfers of securities.

 

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The partnership agreement

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

 

 

with regard to distributions of available cash, please read “Our cash distribution policy and restrictions on distributions” and “Provisions of our partnership agreement relating to cash distributions”;

 

 

with regard to the fiduciary duties of our general partner, please read “Fiduciary and other duties”;

 

 

with regard to the transfer of common units, please read “Description of the common units—Transfer of common units”; and

 

 

with regard to allocations of taxable income, taxable loss and other matters, please read “Tax considerations.”

Organization and duration

Our partnership was organized in Delaware in November 2011 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose under our partnership agreement is to acquire, own and operate oil and natural gas properties in North America and to engage in any other business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law. However, our general partner may 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 federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the ownership, acquisition and development of oil and gas properties and the ownership, acquisition and operation of related assets, our general partner has no current plans to do so 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 in the best interest of us or our limited partners. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Cash distributions

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its general partner interest and incentive distribution rights. For a description of these cash distribution provisions, please read “Provisions of our partnership agreement relating to cash distributions.”

 

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Capital contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited liability.” Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest in us if we issue additional units. Our general partner will be entitled to make such contribution in the form of cash or common units based on their then-current market value. Our general partner’s 0.1% interest in us, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest.

Limited voting rights

The following is a summary of the unitholder vote required for each of the matters specified below.

Various matters require the approval of a “unit majority,” which means:

 

 

during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, each voting as a separate class; and

 

 

after the subordination period, the approval of a majority of the outstanding common units.

During the subordination period, our general partner and its affiliates do not have the ability to ensure passage of, but do have the ability to ensure defeat of, any amendment that requires a unit majority.

In voting their common units and subordinated units, our general partner and its affiliates will have no fiduciary duty or other obligation to us or our limited partners.

 

 

Event    Unitholder Approval

 

Issuance of additional units

   No approval required. Please read “—Issuance of additional partnership interests.”

Amendment of the partnership agreement

   Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of the partnership agreement.”

Merger of our partnership or the sale of all or substantially all of our assets

   Unit majority, in certain circumstances. Please read “—Merger, consolidation, conversion, sale or other disposition of assets.”

Dissolution of our partnership

   Unit majority. Please read “—Termination and dissolution.”

Continuation of our business upon dissolution

   Unit majority. Please read “—Termination and dissolution.”

 

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Event    Unitholder Approval

 

Withdrawal of our general partner

   Prior to                     , 2022, 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. Please read “—Withdrawal or removal of our general partner.”

Removal of our general partner

   Not less than 66 2/3% of the outstanding units, including units held by our general partner and its affiliates. Please read “—Withdrawal or removal of our general partner.”
Transfer of our general partner interest    Prior to                     , 2022, our general partner may transfer without a vote of our unitholders all, but not less than all, of its general partner interest in us to an affiliate or to 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 the general partner interest to a third party (prior to                     , 2022). Please read “—Transfer of general partner units.”

Transfer of incentive distribution rights

   No approval required. Please read “—Transfer of incentive distribution rights, common or subordinated units by our general partner.”

Transfer of ownership interests in our general partner

   No approval required. Please read “—Transfer of ownership interests in our general partner.”

 

Applicable law; forum, venue and jurisdiction

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

 

 

arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the 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);

 

 

brought in a derivative manner on our behalf;

 

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asserting a claim of breach of a fiduciary 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;

 

 

asserting a claim arising pursuant to any provision of the Delaware Act; or

 

 

asserting a claim governed by the internal affairs doctrine,

shall be exclusively brought in the Court of Chancery of the State of Delaware (or, to the extent (and only to the extent) that the Court of Chancery of the State of Delaware does not have subject matter jurisdiction, such other appropriate state court in the State of Delaware or the Federal Courts located in the State of Delaware (collectively, the “Other Delaware Courts”), and not in any other State or Federal court in the United States of America or any court in any other country or other jurisdiction), 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. By 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 (or the Other Delaware Courts, as applicable) in connection with any such claims, suits, actions or proceedings.

Limited liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us 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 our limited partners as a group:

 

 

to remove or replace our general partner;

 

 

to approve some amendments to the partnership agreement; or

 

 

to take other action under the partnership agreement,

constituted “participation in the control” of our business for the purposes of the Delaware Act, then our limited partners could be held personally liable for our obligations under Delaware law, to the same extent as our general partner. This liability would extend to persons who transact business with us 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 may not 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

 

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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 shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that 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 the partnership agreement.

On the closing of this offering, our operating subsidiary will conduct business in Texas, and we may have operating subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a member of each of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which our operating subsidiaries conduct business, including qualifying our operating subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership in the operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company 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 partnership interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests and rights to acquire such interests for the consideration and on the terms and conditions determined by our general partner without the approval of our unitholders.

It is possible that we will fund acquisitions through the issuance of additional partnership interests and rights to acquire such interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests and rights to acquire such interests 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 or rights to acquire such securities, which may effectively rank senior to our common units.

 

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If we issue additional partnership interests or rights to acquire such interests in the future, our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 0.1% general partner interest in us. Our general partner’s 0.1% general partner interest in us will be reduced if we issue additional partnership interests in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest in us.

In addition, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other partnership interests and rights whenever, and on the same terms that, we issue those interests and rights to persons other than our general partner and its affiliates, to the extent necessary to maintain the aggregate percentage interest in us of our general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance on a fully diluted basis. Other holders of partnership interests will not have preemptive rights to acquire additional common units or other partnership interests.

Amendment of the partnership agreement

General

Amendments to our partnership agreement may be proposed only by or with the consent of 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 fiduciary duty or other obligation to us or our limited partners. To adopt a proposed amendment, other than the amendments discussed below under “—No unitholder approval,” our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of our limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited amendments

No amendment may be made that would:

 

 

enlarge the obligations of any limited partner without its 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 in its sole discretion free of any fiduciary duty or other obligation to us or our limited partners.

The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon completion of this offering, Quicksilver will own approximately     % of our outstanding common units and all of our subordinated units, representing an aggregate     % limited partner interest in us.

 

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No unitholder approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner or assignee to reflect:

 

 

a change in our name, the location of our principal place of business, our registered agent or our 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 to continue our qualification as a limited partnership or other entity in which the limited partners have limited liability under the laws of any state or to ensure that neither we, nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for 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 the directors, officers, agents or trustees of our general partner from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or 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 rights to acquire partnership securities;

 

 

any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

 

 

an amendment effected, necessitated or contemplated by a merger agreement 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 us of, or our 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 their tax status or their nationality, citizenship or related status and that would provide for the ability of our general partner to redeem the units of 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; or

 

 

any amendment our general partner determines, in its sole discretion, to be necessary or appropriate in connection with the adjustments to the minimum quarterly distribution and target distribution made upon the reset of the incentive distribution rights;

 

 

any other amendments substantially similar to any of the matters described in the clauses above.

 

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In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

 

 

do not adversely affect our limited partners (including any particular class of limited partner as compared to any other class of limited partner) 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 our limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which our 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 units under the provisions of our partnership agreement; or

 

 

are required to effect the intent expressed in this prospectus or the intent of the provisions of the partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of counsel and unitholder approval

For amendments of the type not requiring unitholder approval, or in connection with certain mergers or conversions of us, our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to our limited partners or result in our being treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Any amendment that would increase the percentage of units required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased.

Merger, consolidation, conversion, sale or other disposition of assets

A merger, consolidation or conversion of us 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 other obligation to us or our limited partners.

In addition, the partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to sell, exchange or otherwise dispose

 

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of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or sale, exchange or other disposition of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without the approval of a unit majority.

Our general partner may consummate any merger, consolidation or conversion without the prior approval of our unitholders if we are 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 a material amendment to our partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our units will be an identical unit of our partnership following the transaction, and the partnership securities to be issued do not exceed 20% of our outstanding partnership securities (other than incentive distribution rights) immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere 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 the governing instruments of the new entity provide our limited partners and our general partner with the same rights and obligations as contained in our partnership agreement.

The unitholders are not entitled to dissenters’ rights of appraisal under our 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 terminated under our partnership agreement. We will dissolve upon:

 

 

the election of our general partner to dissolve us, if approved by the holders of a unit majority;

 

 

there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

 

 

the entry of a decree of judicial dissolution of our partnership; 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 our partnership agreement, unless a successor is elected by holders of a unit majority and admitted as described in our partnership agreement and an opinion of counsel about tax and liability matters is received by us.

Dissolution and distribution of proceeds

Upon our dissolution, unless we are 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

 

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described in “Provisions of our partnership agreement relating to cash distributions—Distributions of cash upon dissolution.” The liquidator will dispose of our assets and otherwise wind up our affairs in such manner and over such period as it determines and it may distribute assets to partners in kind.

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                     , 2022 without obtaining the approval of the holders of at least a majority of our outstanding common units, excluding common units held by our general partner and its affiliates. On or after                     , 2022, our general partner may withdraw as our general partner without first obtaining approval of any unitholder. In each case, our general partner must give 90 days’ written notice and deliver an opinion of counsel regarding limited liability and tax matters, and that withdrawal will not constitute a violation of our partnership agreement in order to withdraw. In addition, prior to                     , 2022 our general partner may withdraw as our general partner without unitholder approval upon 90 days’ notice to our limited partners and delivery of an opinion of counsel regarding limited liability and tax matters if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates. 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 unitholders. Please read “—Transfer of general partner units.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a majority of our outstanding units may select a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters is not obtained, we will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority elect to continue the business and appoint a successor general partner, provided that an opinion of counsel about limited liability and tax matters is received by us first. Please read “—Termination and dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2/3% of our outstanding units, including 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 our outstanding common and subordinated units (each voting as a separate class), including common units held by our general partner and its affiliates. The ownership of more than 33 1/3% of our outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. At the closing of this offering, Quicksilver will own approximately     % of our outstanding common units and all of our subordinated units representing an aggregate     % limited partner interest in us.

Our partnership agreement also provides that if our general partner is removed as our general partner without cause and no units held by our general partner and its affiliates are voted in favor of that removal:

 

 

the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

 

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any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

 

 

our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of the interests at the time.

If our general partner is removed for cause or withdraws in breach of our partnership agreement, a successor general partner will have the option to purchase the departing general partner’s general partner interest in us and, if any, in our subsidiaries and incentive distribution rights for a cash payment equal to the fair market value of that interest. Under all other circumstances where our general partner is removed by the limited partners or withdraws, the departing general partner will have the option to require the successor general partner to purchase the departing general partner’s general partner interest and incentive distribution rights for its fair market value in cash.

In each case, the fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other 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 upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and incentive distribution rights will automatically convert into common units equal to the fair market value of that interest as determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an investment banking firm or other independent expert selected in the manner described in the preceding paragraph will make such determination.

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.

Transfer of general partner units

Prior to                     , 2022, except for the transfer by our general partner of all, but not less than all, of its general partner 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 such other 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 units to another person, without the approval of the holders of at least a majority of our outstanding common units, excluding common units held by our general partner and its affiliates.

After                     , 2022, the general partner may transfer all or any of the general partner units without unitholder approval.

 

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No transfer by the general partner of all or any of its general partner units (before or after                     , 2022) is permitted under the partnership agreement unless the transferee assumes, among other things, the rights and duties of our general partner, agrees to be bound by the provisions of our partnership agreement, and furnishes an opinion of counsel regarding limited liability and tax matters and agrees to purchase all (or the appropriate portion thereof) of the partnership or membership interests of our general partner as the general partner or managing member of each of our subsidiaries.

Transfer of incentive distribution rights, common or subordinated units by our general partner

Our general partner and its affiliates may at any time transfer all or part of their common units or subordinated units to one or more persons without unitholder approval, except that they may not transfer subordinated units to us during the subordination period.

Our general partner or any other holder of incentive distribution rights may transfer all or part of its incentive distribution rights to an affiliate or third party without unitholder approval.

Transfer of ownership interests in our general partner

At any time, the owner of our general partner may sell or transfer all or part of its membership interest in our general partner to an affiliate or third party without unitholder approval.

Change of management provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove 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% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

Limited call right

If at any time our general partner and its affiliates own more than 80% of the outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of such class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of:

 

 

the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class 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 current market price as of the date three days before the date the notice is mailed.

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

 

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that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The 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.

Meetings; voting

Except as described above regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the 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 unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting by written consent signed by holders of the number of units necessary to authorize or take that action at a meeting at which all of the unitholders were present and voted. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding voting units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of additional partnership interests.” However, if at any time any person or group, other than our general partner and its affiliates or a direct or subsequently approved transferee of our general partner or its affiliates or a person or group who acquires units with the prior approval of the board of directors of our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. 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 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 a limited partner under our partnership agreement will be delivered to the record holder of the partnership securities held by such limited partner at his street address shown in our records.

Status as limited partner

By transfer of any common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Except as described above under “—Limited liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

 

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Non-citizen and non-taxpaying unitholders; redemption

If our general partner determines that:

 

 

we are or have become subject to federal, state or local laws or regulations that create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner (This could occur, for example, if in the future we own interests in oil and gas leases on U.S. federal lands.), or

 

 

our 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, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rate that can be charged to customers by us or our subsidiaries,

then, our general partner may adopt amendments to our partnership agreement requiring any limited partner or transferee to furnish information about its nationality, citizenship or related status or its U.S. federal income tax status, as applicable. If a limited partner fails to furnish such information within a reasonable period or our general partner determines after receipt of the information that the limited partner would create the risk or cause the effect described above, such limited partner will not have the right to direct the voting of its units (the general partner will distribute these votes in the same ratios as the votes of other limited partners) and may not receive distributions in-kind upon our dissolution although it may receive the cash equivalent of its interests in exchange for an assignment of its share of any distribution in kind.

In addition, in such circumstance, we will have the right to acquire all (but not less than all) of the units held by such limited partner. The purchase price for such 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 either in cash or by delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5% annually and will be payable in three equal annual installments of principal and accrued interest, commencing one year after the purchase date. Any such promissory note will also be unsecured and will be subordinated to the extent required by the terms of our other indebtedness.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

 

 

our general partner;

 

 

any departing general partner;

 

 

any person who is or was an affiliate of a general partner or any departing general partner;

 

 

any person who is or was a manager, managing member, officer, director, employee, agent, fiduciary, trustee or other controlling person of any entity set forth in the preceding three bullet points;

 

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any person who is or was serving at the request of our general partner, a departing general partner or their affiliates as a manager, managing member, officer, director, fiduciary, trustee or other person who controls another person owing a fiduciary duty to our limited partners or our subsidiaries; and

 

 

any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance covering liabilities asserted against and expenses incurred by persons in connection with our business, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of expenses

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, including expenses incurred or payments made under our omnibus agreement as well as other expenses or payments allocable to us and our subsidiaries, as determined by our general partner. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed.

At the closing of this offering, our general partner will enter into an omnibus agreement pursuant to which, among other things, Quicksilver will agree to provide the general, administrative and operational services necessary to allow our general partner to manage and operate in the same manner in which it was carried on by our predecessor.

Books and reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For financial reporting and tax purposes, our fiscal year end is December 31.

We will furnish or make available to record holders of common units, within 90 days after the close of each fiscal year, an annual report containing audited financial statements. Except for our fourth quarter, we will also furnish or make available summary financial information within 45 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 make the report available on a publicly available website which we maintain.

We will furnish each record holder of a 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 our unitholders will depend on the cooperation of our unitholders in supplying us with specific information. Every unitholder 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.

 

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Right to inspect our books and records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his 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 partner became a partner;

 

 

copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

 

 

information regarding the status of our business and financial condition; and

 

 

any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interest, could damage our business or subsidiaries, or that we are required by law or by agreements with third parties to keep confidential.

Registration rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. In addition, our general partner and its affiliates have the right to include such securities in a registration by us, subject to customary exceptions. These registration rights continue for two years following any withdrawal or removal of our general partner. In addition, we are restricted from granting any superior piggyback registration rights. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts. In connection with any registration of this kind, we will indemnify our general partner and its affiliates participating in the registration and their officers, directors and controlling persons from and against specified liabilities, including under the Securities Act or any applicable state securities laws. Please read “Units eligible for future sale.”

 

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Units eligible for future sale

This is our initial public offering and prior to this offering, there has been no public market for our common units. After the sale of the common units offered hereby, Quicksilver will indirectly hold an aggregate of              common units and              subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

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:

 

 

1.0% 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. Please read “The partnership agreement—Issuance of additional partnership interests.”

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any common units or other partnership interests that they hold, which we refer to as registerable securities. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any registerable securities to require registration of such registerable securities and to include any such registerable securities in a registration by us of common units or other partnership interests, including common units or other partnership interests offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following the withdrawal or removal of our general partner. In connection with any registration of units held by our general partner or its affiliates, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from

 

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the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts. Except as described below, our general partner and its affiliates may sell their common units or other partnership interests in private transactions at any time, subject to compliance with certain conditions and applicable laws.

We, our general partner and certain of its affiliates and the directors and executive officers of our general partner have agreed, subject to certain exceptions, not to sell any common units for a period of 180 days from the date of this prospectus. For a description of these lock-up provisions, please read “Underwriting.”

 

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Tax considerations

This section is a summary of the material tax considerations that may be relevant to prospective holders of our common units who are individual citizens or residents of the United States and, unless otherwise noted, is the opinion of Davis Polk & Wardwell LLP, counsel to our general partner and us (“Tax Counsel”), insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended, (the “Code”), existing and proposed Treasury regulations promulgated under the Code (“Treasury Regulations”), and current administrative rulings and court decisions, all of which are subject to change, possibly with retroactive effect. Changes in these authorities may cause the tax consequences to any unitholder of an investment in the common units to vary substantially from the tax consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Quicksilver Production Partners LP and its subsidiaries.

This section does not describe all of the U.S. federal income or other tax considerations that may be relevant to us or our unitholders (including, for example, alternative minimum tax considerations). In addition, except as otherwise noted below, this section describes only those U.S. federal income or other tax considerations that may be relevant to unitholders who are individual citizens or residents of the United States, and therefore has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders that are not individual citizens or residents of the United States, including tax-exempt institutions, foreign persons, individual retirement accounts, real estate investment trusts or mutual funds. Moreover, this section includes only a limited discussion of the state or local tax consequences, and does not include any discussion of any foreign tax consequences, of an investment in our common units. Accordingly, we encourage each prospective unitholder to consult the unitholder’s own tax adviser in determining the U.S. federal, state, local and foreign tax consequences that will apply to the unitholder’s ownership or disposition of our common units.

No ruling has been or will be requested from the Internal Revenue Service (the “IRS”) regarding any of the matters discussed in this section. Instead, we will rely on opinions of our Tax Counsel with respect to those matters on which our Tax Counsel is able to opine. 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 with the IRS may materially and adversely impact the market for our common units and the prices at which our common units trade. In addition, the costs of any contest with the IRS will result in a reduction in available cash for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, our tax treatment, or the tax treatment of an investment in our common units, may change significantly as a result of future changes in law, any of which may apply retroactively.

Unless otherwise noted, all statements as to matters of U.S. federal income tax law, but not as to factual or other matters, contained in this section are the opinion of our Tax Counsel, and are based in part on the accuracy of the representations made by us. For the reasons described below, Tax Counsel has not rendered an opinion with respect to the following specific U.S. federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “—Tax consequences of unit ownership—Treatment of loans of common units”); (ii) whether our monthly convention for

 

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allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of common units—Allocations between transferors and transferees”); and (iii) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “—Tax consequences of unit ownership—Section 754 election”).

Partnership status

We will be treated as a partnership for U.S. federal income tax purposes and, therefore, generally will not be liable for U.S. federal income taxes. Instead, each of our unitholders will be required to take into account the unitholder’s respective share of our items of income, gain, loss and deduction in computing the unitholder’s U.S. federal income tax liability, regardless of whether we make cash distributions to our unitholders. Cash distributions that we make to a unitholder will generally not be taxable to the unitholder unless the amount of a cash distribution exceeds the unitholder’s adjusted tax basis in the unitholder’s common units at the time of the distribution.

Section 7704 of the Code provides that, subject to certain exceptions, publicly traded partnerships are taxed as corporations rather than as partnerships. One of these exceptions, referred to as the “Qualifying Income Exception,” applies to a publicly traded partnership for any year in which 90% or more of the gross income of the partnership consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, production, transportation, storage and processing of crude oil, natural 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. We estimate that less than 5% of our gross income for our current taxable year and future years will not be qualifying income. Based upon and subject to this estimate and the factual representations made by us and our general partner to Tax Counsel, Tax Counsel is of the opinion that at least 90% of the gross income we expect to earn in our current taxable year and in future taxable years will constitute qualifying income. However, the portion of our income that is qualifying income may change from time to time, and there can be no assurance that at least 90% of our gross income in any year will constitute qualifying income.

No ruling has been or will be sought from the IRS, and the IRS has made no determination, as to our status for U.S. federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Code. Instead, we will rely on the opinion of Tax Counsel on such matters. Tax Counsel is of the opinion that, based upon the Code, Treasury Regulations, published revenue rulings and court decisions, and the factual representations described below, we will be classified as a partnership for U.S. federal income tax purposes.

In rendering its opinion, Tax Counsel has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Tax Counsel has relied include the following:

 

 

Neither we nor our operating company has elected or will elect to be treated as a corporation;

 

 

For each of our taxable years, more than 90% of our gross income will be income that Tax Counsel has opined or will opine is qualifying income for purposes of Section 7704(d) of the Code; and

 

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Each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with our production and sale of oil, natural gas, or products thereof in transactions that Tax Counsel has opined or will opine result in qualifying income.

We believe that these representations are true and will be true in the future.

If we fail to meet the Qualifying Income Exception for any taxable year, 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 us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly-formed corporation (even though we will continue to operate as a limited partnership under Delaware law) on the first day of the taxable year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then made a liquidating distribution of that stock to our unitholders. This deemed contribution and liquidation should be tax-free to our unitholders and to us if, at that time, we do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for U.S. federal income tax purposes.

If we were treated as a corporation for U.S. federal income tax purposes in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and we would be subject to tax, at corporate rates, on our net income. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, first as a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, and thereafter as taxable capital gain. Accordingly, if we were treated as a corporation, there would be a material reduction in a unitholder’s cash flow and after-tax return, which would also likely result in a substantial reduction of the value of our common units.

The remainder of this section is based on Tax Counsel’s opinion that we will be classified as a partnership for U.S. federal income tax purposes.

Limited partner status

Beneficial owners of our common units, including beneficial owners whose 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 common units, will be treated as partners of Quicksilver Production Partners LP for U.S. federal income tax purposes. The references to “unitholders” in this section are to persons who are treated as partners in Quicksilver Production Partners LP for U.S. federal income tax purposes. However, if a unitholder transfers our common units to a short seller to complete a short sale, the unitholder will likely lose its status as a partner of Quicksilver Production Partners LP with respect to those common units for U.S. federal income tax purposes. Please read “—Tax consequences of unit ownership—Treatment of loans of common units.”

 

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Tax consequences of unit ownership

Flow-through of tax items

Subject to the discussion below under “—Entity-level collection of unitholder taxes,” we will not pay any U.S. federal income tax. Instead, each of our unitholders will be required to take into account, for each of our taxable years that ends with or within the unitholder’s taxable year, the unitholder’s respective share of our items of income, gain, loss and deduction in computing the unitholder’s U.S. federal income tax liability, regardless of whether we make cash distributions to our unitholders. As a result, a unitholder may have a tax liability with respect to the unitholder’s share of our items of income, gain, loss and deduction even if we do not make cash distributions to our unitholders. Except for any year in which we experience a technical termination for U.S. federal income tax purposes, our taxable year will end on December 31. Please read “—Disposition of common units—Technical termination.”

Treatment of distributions

Cash distributions we make to a unitholder generally will not be taxable to the unitholder for U.S. federal income tax purposes, except to the extent the amount of any cash distribution we make exceeds the unitholder’s tax basis in our common units immediately before the distribution. If the amount of any cash distribution that a unitholder receives exceeds the unitholder’s tax basis in our common units immediately before the distribution, the excess 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 common units” below.

Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss (“nonrecourse liabilities”) will be treated for U.S. federal income tax purposes as giving rise to a deemed distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, the unitholder must recapture any of our net losses that were allocated to the unitholder and deducted by the unitholder in prior years. Please read “—Limitations on deductibility of losses.”

A decrease in a unitholder’s percentage interest in us resulting from the issuance of additional common units will decrease the unitholder’s share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash to the unitholder. This deemed distribution of cash may constitute, in whole or in part, a non-pro rata distribution to our unitholders who are treated as receiving these deemed distributions of cash, which may result in the recognition of ordinary income by each of these unitholders (regardless of the unitholder’s tax basis in our common units), if the non-pro rata distribution reduces the unitholder’s share of our “unrealized receivables.” Unrealized receivables include depreciation and depletion recapture, and/or substantially appreciated “inventory items” (both as defined in the Code, and collectively, “Section 751 Assets”). If any portion of a deemed distribution of cash is treated as a non-pro rata distribution, and the non-pro rata distribution reduces the unitholder’s share of our Section 751 Assets, the unitholder will be treated as having received the unitholder’s proportionate share of our Section 751 Assets and then having exchanged those assets with us for the non-pro rata portion of the deemed distribution of cash. This deemed exchange will generally result in the realization of ordinary income by the unitholder in an amount equal to the excess of (i) the non-pro rata portion of the deemed distribution of cash over (ii) the unitholder’s tax basis (generally zero) in the share of Section 751 Assets deemed relinquished in the exchange.

 

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Ratio of taxable income to distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending             , will be allocated, on a cumulative basis, an amount of U.S. federal taxable income for that period that will be     % or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that earnings from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, these estimates are based on current U.S. federal income tax law and U.S. federal income tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual ratio of allocable taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be higher, and perhaps substantially higher, than our estimate with respect to the period described above if, during this period:

 

 

our gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, but we distribute only the minimum quarterly distributions on all units;

 

 

we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for U.S. federal income tax purposes or that generates a smaller amount of depreciation or amortization deductions, relative to the income generated by such property, than the amount of depreciation or amortization deductions generated by our assets at the time of this offering; or

 

 

legislation is passed, in response to President Obama’s Budget Proposal for Fiscal Year 2012 or otherwise, that would limit or repeal certain U.S. federal income tax preferences currently available to oil and gas exploration and production companies. Please read “—Tax treatment of our operations—Recent legislative developments.”

Basis of common units

A unitholder’s initial tax basis for our common units will be the amount paid for the common units plus the unitholder’s share of our nonrecourse liabilities. That basis will be increased by the unitholder’s allocable share of our net income and by any increases in the unitholder’s share of our nonrecourse liabilities (which share will generally be based on the unitholder’s allocable share of our net income). That basis will be decreased, but not below zero, by distributions received from us on the common units, by the unitholder’s allocable share of our net losses, by any decreases in the unitholder’s share of our nonrecourse liabilities, and by the unitholder’s share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. We expect that all of our debt will constitute nonrecourse liabilities for U.S. federal income tax purposes. Please read “—Disposition of common units—Recognition of gain or loss.”

 

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Limitations on deductibility of losses

The deduction by a unitholder of the unitholder’s share of our losses will be limited to the unitholder’s tax basis in our common units or, in the case of a unitholder that is an individual, an estate, a trust, or a corporation more than 50% of the value of the stock of which is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations, the lower of the unitholder’s tax basis in our common units or the amount for which the unitholder is considered to be “at-risk” with respect to our activities. A unitholder subject to these “at-risk” limitations must recapture any of our losses that were allocated to the unitholder and deducted by the unitholder in prior years to the extent that any distributions received from us cause the unitholder’s at-risk amount to be less than zero at the end of any taxable year. Any losses that are suspended or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that a unitholder’s at-risk amount subsequently increases, provided such losses do not exceed the unitholder’s tax basis in our common units at that time. Any gain recognized by a unitholder on the taxable disposition of a common unit can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the tax basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would be permanently disallowed.

In general, a unitholder will be “at-risk” to the extent of the unitholder’s tax basis in our common units, excluding any portion of that basis that is attributable to the unitholder’s share of our nonrecourse liabilities and 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 the unitholder borrows to acquire or hold our common units, if the lender of those borrowed funds either (x) owns an interest in us (y) is related to the unitholder or (z) can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the unitholder’s tax basis in our common units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in the unitholder’s share of our nonrecourse liabilities.

The at-risk limitation applies on an activity-by-activity basis, and, in the case of oil and natural gas properties, each property is treated as a separate activity. As a result, a taxpayer’s interest in each oil or natural gas property is generally required to be treated separately so that the deduction of any loss from any property would be limited to the at-risk amount for that property, and not the at-risk amount for all the taxpayer’s oil and natural gas properties. It is uncertain how this rule applies in the case of multiple oil and natural gas properties owned by a single entity treated as a partnership for U.S. federal income tax purposes. However, for taxable years ending on or before the date on which further guidance is published, the IRS will permit aggregation of oil or natural gas properties that we own in computing a unitholder’s at-risk limitation with respect to us. If a unitholder were required to compute his at-risk amount separately with respect to each oil or natural gas property that we own, the unitholder might not be allowed to utilize the unitholder’s allocable share of losses or deductions attributable to a particular property even though the unitholder has a positive at-risk amount with respect to our common units as a whole.

In addition to the tax basis and at-risk limitations on the deductibility of losses, the passive loss limitation rules 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

 

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limitation rules are applied separately with respect to each publicly traded partnership. As a result, any losses from passive activities that we generate will be available to offset only income that we generate from those passive activities in the future, and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when the unitholder disposes of the unitholder’s entire investment in our common units in a fully taxable transaction with an unrelated party. The passive activity loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the tax basis limitation. We expect that substantially all of our losses, if any, from our operations will generally constitute losses from passive activities with respect to public holders of our common units.

A unitholder’s share of our net income from passive activities may be offset by any suspended losses from our passive activities, but it may not be offset by any current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

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;

 

 

interest expense attributed to portfolio income; and

 

 

the portion of any 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 include interest on any margin account borrowing or other loan incurred to purchase or carry a common 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. The IRS has indicated that a unitholder’s allocable share of the net passive income earned by a publicly traded partnership will be treated as investment income for purposes of the limitation on the deduction of investment interest expense. In addition, a unitholder’s allocable share of our portfolio income will be treated as investment income for such purposes.

Entity-level collection of unitholder taxes

If we are required, or elect under applicable law, to pay any U.S. federal, state, local or foreign tax on behalf of any unitholder or former unitholder, we are authorized under our partnership agreement to pay those taxes from our 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, we are authorized under our partnership agreement to treat the payment as a distribution to all current unitholders. We are also authorized to amend our partnership agreement in any manner necessary to maintain uniformity of intrinsic tax characteristics of our common units and to adjust later distributions, so

 

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that, after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Any payment that we make as described above could give rise to an overpayment of tax on behalf of an individual unitholder, in which event the unitholder could be required to file a tax return or a claim for refund in order to obtain a credit or refund of that tax.

Allocation of income, gain, loss and deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and our unitholders in accordance with their percentage interests in us. At any time that distributions are made on the common units in excess of distributions on the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these excess distributions. If we have a net loss, that loss will be allocated, first, to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts, and, second, to our general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for (i) any difference between the tax basis and fair market value of our assets at the time of this offering and (ii) any difference between the tax basis and fair market value of any property contributed to us by the general partner and its affiliates that exists at the time of such contribution (these assets and property are together referred to in this discussion as “contributed property”). The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units in this offering will be to produce overall allocations of income, gain, loss and deduction that are essentially the same as would have been made if the tax bases of our assets were equal to their fair market values at the time of this offering. If we issue additional common units or engage 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 the general partner and our other unitholders immediately prior to such issuance or other transaction to account for the difference between our “book” basis in our assets, for purposes of maintaining capital accounts, and the fair market value of those assets at the time of such issuance or other transaction. In addition, items of gain that are treated as 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.

Except as described below with respect to allocations required by the Code and Treasury Regulations to eliminate a “book-tax disparity” (generally, the difference, if any, between a partner’s “book” capital account, which is based on the fair market value of contributed property, and the partner’s “tax” capital account, which is based on the tax basis of contributed property), an allocation of an item of our income, gain, loss or deduction under our partnership agreement will generally be given effect in determining a unitholder’s or the general partner’s allocable share of an item of income, gain, loss or deduction for U.S. federal income tax purposes only if the allocation has substantial economic effect. In any other case, a unitholder’s or the general partner’s share of an item of income, gain, loss or deduction will be determined on the basis of the unitholder’s or the general partner’s interest in us, which will be determined by taking into account all facts and circumstances, including:

 

 

the unitholder’s or the general partner’s relative contributions to us;

 

 

the interests of all of our unitholders and the general partner in our profits and losses;

 

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the interest of all of our unitholders and our general partner in our cash flow; and

 

 

the rights of all of our unitholders and the general partner to distributions of capital upon liquidation.

Tax Counsel is of the opinion that, with the exception of the issues described in “—Section 754 election” and “—Disposition of common units—Allocations between transferors and transferees,” allocations under our partnership agreement will be given effect for U.S. federal income tax purposes in determining a unitholder’s and the general partner’s share of an item of income, gain, loss or deduction.

Treatment of loans of common units

The U.S. federal income tax consequences to a holder of a partnership interest who loans all or a portion of its partnership interest in connection with a “short sale” of that partnership interest are uncertain. The IRS has announced that it is studying the issues relating to the U.S. federal income tax treatment of “short sales” of partnership interests. If a unitholder loans our common units to a “short seller” to cover a short sale of our common units, the unitholder may be considered, for U.S. federal income tax purposes, to have disposed of the common units that are loaned. If a unitholder is treated as having disposed of any common units that are so loaned, the unitholder would no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units while the loan is outstanding and may be required to recognize gain or loss from the disposition. As a result, while the loan is outstanding:

 

 

none of our income, gain, loss or deduction with respect to the common units so loaned would be reportable by the unitholder;

 

 

any “substitute” cash distributions received by the unitholder with respect to the common units so loaned would be fully taxable; and

 

 

these “substitute” cash distributions could be subject to ordinary income tax.

Tax Counsel has not rendered an opinion regarding the U.S. federal income tax treatment of a unitholder who loans common units to a short seller to cover a short sale of common units. A unitholder may wish to consult a tax adviser to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit the unitholder’s brokers from borrowing our common units. Please also read “—Disposition of common units—Recognition of gain or loss.”

Section 754 election

We will make an election, which is permitted by Section 754 of the Code and is generally irrevocable, to adjust, under Section 743(b) of the Code, the tax basis in our assets (“inside basis”) of a unitholder who purchases a common unit to reflect the purchase price for the common unit. This election does not apply to a unitholder who purchases common units directly from us. The Section 743(b) adjustment belongs solely to the purchasing unitholder and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (i) the unitholder’s share of our tax basis in our assets (“common basis”) and (ii) the unitholder’s Section 743(b) adjustment to that basis. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a

 

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transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or a basis reduction is substantial if it exceeds $250,000.

We will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Code require a portion of the Section 743(b) adjustment that is attributable to recovery property that is (i) subject to depreciation under Section 168 of the Code and (ii) the book basis of which is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized book-tax disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read “—Uniformity of units.”

Although Tax Counsel is unable to opine as to the validity of this approach because there is no controlling authority on this issue, we intend either (i) to depreciate 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 (ii) treat that portion as non-amortizable, to the extent attributable to property which is not amortizable. We believe that this method is consistent with the methods employed by other publicly traded partnerships, but it is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6) (which is not expected to directly apply to a material portion of our assets). To the extent this Section 743(b) adjustment is attributable to appreciation in the value of any contributed property in excess of the unamortized book-tax disparity with respect to that property, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring common units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This “aggregate” approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “—Uniformity of units.” A unitholder’s tax basis for our common units is reduced by the unitholder’s allocable share of our deductions (whether or not such deductions were claimed on an individual’s income tax return), so that any position we take that understates deductions will overstate the common unitholder’s basis in our common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of common units—Recognition of gain or loss.” The IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the uniformity of units might be affected, and a unitholder’s gain from the sale of our common units could be increased without the benefit of any corresponding additional deductions.

A Section 754 election is advantageous if a transferee’s tax basis in our common units is higher than the share of the aggregate tax basis of our assets attributable to those common units immediately prior to the transfer. In that case, as a result of the election, the transferee would

 

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have a larger amount of depreciation deductions, and the unitholder would have a smaller share of any gain or loss on a sale of any of our assets. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in our common units is lower than the share of the aggregate tax basis of our assets attributable to those common units immediately prior to the transfer. As a result, the effect of the Section 754 election on the fair market value of our common units may be either favorable or unfavorable. The calculations required under the Section 754 election are complex and require us to make various determinations as to the fair market value of our assets and other matters. For example, the IRS could challenge our determination of the relative values of our tangible assets and intangible assets, such as goodwill, and seek to reallocate some or all of any Section 743(b) adjustment that we allocate to our tangible assets to goodwill. Goodwill, as an intangible asset, is generally either nonamortizable or amortizable over a longer period of time (or under a less accelerated method) than our tangible assets. We cannot assure you that the determinations we make 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 should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a unitholder who purchases our common units after the Section 754 election is revoked may be allocated more income than the unitholder would have been allocated had the election not been revoked, which could adversely affect the value of our common units.

Tax treatment of our operations

Accounting method and taxable year

We will use the year ending December 31 as our taxable year and we will use the accrual method of accounting for U.S. federal income tax purposes. Each unitholder will be required to include in income the unitholder’s allocable share of our income, gain, loss and deduction for each of our taxable years ending within or with the unitholder’s 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 our common units following the close of our taxable year, but before the close of the unitholder’s taxable year, must include the unitholder’s allocable share of our income, gain, loss and deduction in income for our taxable year, with the result that the unitholder will be required to include in income in the taxable year of the disposition the unitholder’s allocable share of more than 12 months of our income, gain, loss and deduction. Please read “—Disposition of common units—Allocations between transferors and transferees.”

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 our oil and gas interests. Although the Code requires each unitholder to compute the unitholder’s own depletion allowance, and to maintain records of the unitholder’s share of the adjusted tax basis, with respect to our oil and gas interests for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for U.S. federal income tax purposes. Each unitholder, however, remains responsible for calculating the unitholder’s own depletion allowance. and for maintaining records of the unitholder’s share of the adjusted tax basis, with respect to our oil and gas interests 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 for a unitholder is calculated as an amount generally equal to 15% (and, in the case of marginal production, a potentially higher percentage) of the unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any depletable property is limited to 100% of the taxable income of the unitholder from that 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% 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% limitation may be carried forward indefinitely, and may be deducted in any subsequent taxable year in which the percentage depletion deduction for that year plus the deduction carryover does not exceed 65% of the unitholder’s total taxable income for that year.

Unitholders that do not qualify for the “independent producer” exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) 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 then (ii) multiplying the result by the number of mineral units sold in that 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 underlying mineral property.

All or a portion of any gain recognized by a unitholder as a result of either (i) our disposition of some or all of our oil and gas interests or (ii) the disposition by the unitholder of some or all of our 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 subject to recapture as ordinary income 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 Code provisions, Treasury Regulations and other authority relating to the availability and calculation of depletion deductions by unitholders. In addition, because depletion is required to be computed separately by each unitholder and not at the partnership level, no assurance can be given, and Tax Counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to any unitholder for any taxable year. The availability of percentage depletion may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of recent legislative proposals, please read

 

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“—Recent legislative developments.” We encourage each prospective unitholder to consult a tax adviser to determine whether percentage depletion would be available to the prospective unitholder with respect to our common units.

Deductions for intangible drilling and development costs

We will elect to currently deduct intangible drilling and development costs, which we refer to as “IDCs.” IDCs generally include our 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 or natural gas. The election to currently deduct IDCs applies only to those items that do not have a salvage value.

Although we will elect to currently deduct our IDCs, each unitholder will generally have the ability to elect either to currently deduct our IDCs or to capitalize all or part of our IDCs and amortize them on a straight-line basis over a 60-month period, beginning with the taxable month in which the IDC is incurred. A unitholder who is directly or indirectly, through certain related parties, involved in substantial oil and natural gas refining or retail marketing activities should consult the unitholder’s own tax adviser regarding special rules that may apply to the unitholder with respect to our IDCs.

Previously deducted IDCs that are allocable to any of our oil or natural gas interests and that would have been included in the adjusted tax basis of that interest had those IDCs not been previously deducted are recaptured and give rise to ordinary income to the extent of any gain realized upon the disposition of that interest or upon the disposition by a unitholder of any of our common units. Recapture is generally determined at the unitholder level. Where only a portion of an oil or natural gas interest subject to IDC recapture is sold, all IDCs related to the entire interest are recaptured to the extent of the gain realized on the portion of the interest that is sold. If a unitholder sells less than all of the common units owned by that unitholder, a proportionate amount of the IDCs previously deducted with respect to each of our oil and natural gas interests is treated as allocable to the transferred common units and is subject to recapture to the extent of any gain recognized. Please read “—Disposition of common 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.”

Deduction for U.S. production activities

Subject to the limitations on the deductibility of losses discussed above (please read “—Tax consequences of unit ownership—Limitations on deductibility of losses”), and the limitation discussed below, a unitholder will generally be entitled to a deduction (the “Section 199 deduction”) equal to 6% of our “qualified production activities income” that is allocated to that unitholder, but only to the extent that such amount does not exceed 50% of the unitholder’s allocable share of the IRS Form W-2 wages paid by us for the taxable year that are allocable to our domestic production gross receipts.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that

 

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are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

A unitholder’s Section 199 deduction with respect to our activities will be determined at the unitholder level. To determine the Section 199 deduction, each unitholder must aggregate the unitholder’s allocable share of our qualified production activities income with the unitholder’s qualified production activities income from other sources. Each unitholder must take into account the unitholder’s distributive share of our expenses from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing a unitholder’s Section 199 deduction are taken into account only if and to the extent the unitholder’s share of losses and deductions from all of our activities is not disallowed by the tax basis rules, the at-risk rules or the passive activity loss rules. Please read “—Tax consequences of unit ownership—Limitations on deductibility of losses.”

The amount of a unitholder’s Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder’s allocable share of our wages that are deducted in arriving at our qualified production activities income for that taxable year. Because we do not anticipate that we or our subsidiaries will pay material wages that will be allocated to our unitholders, a unitholder’s ability to claim the Section 199 deduction with respect to our qualified production activities income may be substantially limited.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex Code provisions, Treasury Regulations and other authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 wages, or how we allocate such items to unitholders. In addition, because the Section 199 deduction is required to be computed separately by each unitholder and not at the partnership level, no assurance can be given, and Tax Counsel is unable to express any opinion, as to the availability or extent of the Section 199 deduction to any unitholder for any taxable year. The availability of Section 199 deductions may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of recent legislative proposals, please read “—Recent legislative developments.” We encourage each prospective unitholder to consult a tax adviser to determine whether the Section 199 deduction would be available to the prospective unitholder with respect to our common units.

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 “—Depletion deductions” above.

Geophysical exploration 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

 

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24-month period beginning on the date that such cost is paid or incurred. The amortization period for certain geological and geophysical expenditures may be extended if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “—Recent legislative developments.”

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

President Obama’s budget proposal for the Fiscal Year 2013 (the “Budget Proposal”) and other similar proposals would, if enacted, eliminate certain important U.S. federal income tax preferences relating to oil and natural gas exploration and development. Changes in the Budget Proposal include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for IDCs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Each of these changes is proposed to be effective for taxable years beginning, or, in the case of costs described in (ii) and (iv), costs paid or incurred, after December 31, 2012. It is unclear whether these or similar changes will be enacted and, if enacted, when any such changes would become effective. The enactment 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 reduce the value of an investment in our units.

Initial tax basis, depreciation and amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and gain or loss on the disposition of these assets. The U.S. federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our general partner and its affiliates, and (ii) any other offering will be borne by our general partner and other unitholders as of that time. Please read “—Tax consequences of unit ownership—Allocation of income, gain, loss and deduction.”

To the extent allowable, we 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 earliest years after assets subject to these allowances are placed in service. Please read “—Uniformity of units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Code.

If we dispose 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 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 we own will likely be required to recapture some or all of those

 

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deductions as ordinary income, to the extent of any gain, upon a sale of our common units. Please read “—Tax consequences of unit ownership—Allocation of income, gain, loss and deduction” and “—Disposition of common units—Recognition of gain or loss.”

The costs we incur in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which we are permitted to amortize, and as syndication expenses, which we are not permitted to amortize. The underwriting discounts and commissions we incur in selling our units will be treated as syndication expenses.

Valuation and tax basis of our properties

The U.S. federal income tax consequences of the ownership and disposition of our common units will depend in part on our estimates of the relative fair market values from time to time, and the initial tax bases, of our assets. Although we may consult with professional appraisers regarding valuation matters, we expect to make many of the relative fair market value estimates ourselves. These estimates, and our determinations with respect to the tax basis, are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or our determinations with respect to tax basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction 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 common units

Recognition of gain or loss

A unitholder will recognize gain or loss on a sale of our common units equal to the difference between the amount realized and the unitholder’s tax basis in the units sold. A unitholder’s amount realized will be equal to the sum of the cash or the fair market value of any property received by the unitholder plus the unitholder’s share of our nonrecourse liabilities of which the unitholder is treated as having been relieved by reason of each sale or exchange of our common units. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities the unitholder is treated as having been relieved by reason of each sale or exchange of our common units, a unitholder could incur a tax liability with respect to the sale of our common units that exceeds the amount of any cash received from the sale.

Because a unitholder’s tax basis in our common units will decrease if a unitholder receives distributions with respect to our common units that exceed the cumulative amount of net taxable income allocated to the unitholder with respect our common units, a unitholder may recognize gain on a sale of our common units, based on the unitholder’s reduced tax basis in our common units, even if the unitholder sells our common units for less than the original cost of those common units.

Except as described below, gain or loss recognized by a unitholder, other than a “dealer” in our common units, on the sale or exchange of our common units will generally be taxable as capital gain or loss. However, a portion of this gain or loss, which we expect may be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to Section 751 Assets. Ordinary income attributable to Section 751 Assets may exceed the net taxable gain realized upon the sale of our common units, and may be recognized

 

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even if a unitholder realizes a net taxable loss on the sale of our common units. As a result, it is possible for a unitholder to recognize both ordinary income and a capital loss upon a sale of our common units. 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. Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a unitholder will be unable to select high or low basis common units to sell (as would be the case with respect to corporate stock), but, according to the Treasury Regulations, the unitholder may designate specific common units sold for purposes of determining the holding period of the units sold. A unitholder electing to use the actual holding period of specific common units sold must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult the unitholder’s tax adviser as to the effects of the ruling and Treasury Regulations discussed above.

Allocations between transferors and transferees

In general, we will determine our taxable income and loss annually, and for purposes of allocating our taxable income and loss to our unitholders we will prorate our taxable income and loss on a monthly basis and apportion the resulting amounts allocable to our unitholders among our unitholders in proportion to the number of common units owned by each unitholder as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, in the discretion of our general partner, gain or loss realized on a sale or other disposition of our assets, or any other extraordinary items of income, gain, loss or deduction, may be allocated to those unitholders who own our common units (in proportion to the number of common units owned by each unitholder) on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although there is no controlling authority with respect to this proration method, we intend to use this proration method because simplifying conventions are contemplated by the Code. We believe that most publicly traded partnerships use similar simplifying conventions. Recently, the Department of the Treasury and the IRS 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. Nonetheless, the safe harbor in the proposed regulations differs from the proration method we intend to adopt because the safe harbor would allocate tax items among the months based upon the relative number of days in each month, and could require certain tax items which our general partner may not consider extraordinary to be allocated to the month in which such items actually arise. 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

 

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Regulations are issued. Accordingly, Tax Counsel is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders. If this method is not allowed under the Treasury Regulations, or applies only to transfers of less than all of the common units owned by a unitholder, our taxable income or losses might be reallocated among the unitholders. We are authorized under our partnership agreement to revise our method of allocation between transferor and transferee unitholders, as well as to unitholders whose ownership of our common units varies during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who owns common units at any time during a quarter and who disposes of any of those common units prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution with respect to the disposed common units.

Notification requirements

A unitholder who sells any of our common units is generally required to notify us 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 units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy these reporting requirements.

Technical termination

If there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period, we will be considered, solely for U.S. federal income tax purposes, to have “technically terminated” our existence as a partnership and to have been reformed as a new partnership. For this purpose, multiple sales of the same interest will be counted only once. Our technical termination, among other things, could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In addition, our technical termination would result in the closing of our taxable year for all unitholders, which would require us to prepare and file two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available from the IRS) for one fiscal year. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than 12 months of our taxable income or loss being includible in the unitholder’s taxable income for the year of the technical termination. In addition, as a new partnership, we would be required to make new tax elections. We could be subject to penalties if we are unable to determine that a technical termination occurred. Our technical termination might also either accelerate the application of, or subject us to, tax legislation enacted before the date of our termination to which we would not otherwise be subject had we not experienced a technical termination. The IRS has recently announced a relief procedure under which, if a publicly traded partnership that has technically terminated requests, and the IRS grants, special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the two short tax years resulting from the technical termination.

 

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Uniformity of units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of our common units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of U.S. federal income tax requirements, both statutory and regulatory. For example, a lack of uniformity could result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of our common the units. Please read “—Tax consequences of unit ownership—Section 754 election.”

Tax-exempt organizations and other investors

As described below, special, and potentially adverse, U.S. federal income tax consequences will apply to tax-exempt entities, such as employee benefit plans and individual retirement accounts, or IRAs, and non-U.S. persons that own our common units. A tax-exempt entity or non-U.S. person should consult a tax adviser before investing in our common units.

Employee benefit plans and most other organizations exempt from U.S. federal income tax, including individual retirement accounts and other retirement plans, are subject to U.S. federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to the unitholder.

A non-resident alien, foreign corporation, foreign trust or foreign estate that owns our common units (a “foreign unitholder”) will be considered to be engaged in business in the United States by reason of the ownership of our common units. As a result, a foreign unitholder will be required to file a U.S. federal tax return to report the foreign unitholder’s allocable share of our income, gain, loss or deduction and to pay U.S. federal income tax at regular rates on the foreign unitholder’s allocable share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, distributions to a foreign unitholder will be subject to withholding at the highest applicable statutory tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN, or applicable substitute form, in order to obtain credit for any amounts withheld.

In addition, a foreign corporation that owns our common units may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular U.S. federal income tax, on its allocable share of our net income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity” which is effectively connected with the conduct of a U.S. trade or business. This branch profits tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, a foreign corporate unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A foreign unitholder who sells or otherwise disposes of our common units will be subject to U.S. federal income tax on gain realized from the sale or disposition of those common units to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS that interprets the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the United States by virtue of our activities in the United States, and part or all of that unitholder’s gain realized on a sale or disposition of our common units would be effectively connected with that

 

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trade or business. In addition, a foreign unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of our common units if (i) the foreign unitholder owned (directly or constructively, applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of the sale or disposition, and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which the foreign unitholder held our common units or the five-year period ending on the date of the sale or disposition. We expect that, after this offering and for the foreseeable future, more than 50% of our assets will consist of U.S. real property interests.

Administrative matters

Information returns and audit procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which will report the unitholder’s allocable share of our income, gain, loss and deduction for the preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will produce a result that conforms to the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Tax Counsel can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could reduce the value of our common units.

The IRS may audit our U.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 a unitholder’s own tax return. Any audit of a unitholder’s tax return could result in adjustments that are unrelated to the unitholder’s investment in our common units.

Partnerships generally are treated as separate entities for purposes of U.S. federal income tax audits, judicial review of administrative adjustments proposed by the IRS, and any settlement of those adjustments with the IRS. The U.S. federal income 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. Our partnership agreement names Quicksilver Production Partners GP LLC, our general partner, as our Tax Matters Partner.

The Tax Matters Partner has made and will make various tax elections on our behalf and on behalf of our unitholders with respect to us. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us 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. If the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% profits interest in us or by any group of unitholders having in the aggregate at least a 5% profits interest in us. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

 

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A unitholder must file a statement with the IRS identifying the treatment of any item on the unitholder’s U.S. federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

 

 

the name, address and taxpayer identification number of each of the beneficial owner and the nominee;

 

 

a statement regarding whether the beneficial owner is:

 

   

a person that is not a U.S. person;

 

   

a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

 

   

a tax-exempt entity;

 

 

the amount and description of our common units held, acquired or transferred for the beneficial owner; and

 

 

specific information, including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on common units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per calendar year, is imposed by the Code for failure to report that information to us. The nominee is also required to supply the beneficial owner of the units with the information furnished to us.

State, local and other tax considerations

In addition to U.S. federal income taxes, you likely will be subject to other taxes, such as state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider the potential impact of these taxes on an investment in our common units. Initially, we will own property or do business in Texas. In the future, we may own property or do business in additional jurisdictions. In many of these jurisdictions, a unitholder would be required to file income tax returns and to pay income taxes if we were to do business or own property in these jurisdictions, and could 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 us, or we may elect, to withhold a percentage of any amounts 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

 

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return. Any amounts withheld would be treated as if distributed to the relevant unitholders for purposes of determining the amounts distributed by us. Please read “—Tax consequences of unit ownership—Entity-level collection of unitholder taxes.” Based on current law and our estimate of our future operations, we anticipate that any amounts required to be withheld will not be material.

The personal tax consequences of an investment in our common units may vary among unitholders under the laws of the relevant jurisdictions. Therefore, each prospective unitholder is urged to consult a tax adviser with regard to these matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal, tax returns that the unitholder may be required to file. Tax Counsel has not rendered an opinion on the state, local or foreign tax consequences of an investment in our common units.

 

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Investment in Quicksilver Production Partners LP by employee benefit plans

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA (collectively, “Similar Laws”). For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or individual retirement accounts or annuities (“IRAs”) established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements. Among other things, consideration should be given to:

 

 

whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

 

 

whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

 

 

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Tax considerations—Tax-exempt organizations and other investors”; and

 

 

whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that, with respect to the plan, are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.

 

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The Department of Labor regulations and the statutory provisions of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets.” Under these rules, an entity’s assets would not be considered to be “plan assets” if, among other things:

 

 

the equity interests acquired by the employee benefit plan are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;

 

 

the entity is an “operating company,”—i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

 

 

there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interests, disregarding interests held by our general partner, its affiliates and certain other persons, is held by the employee benefit plans referred to above that are subject to ERISA and IRAs and other similar vehicles that are subject to Section 4975 of the Internal Revenue Code.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in the first two bullet points above.

In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

 

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Underwriting

We are offering the common units described in this prospectus through a number of underwriters. J.P. Morgan Securities LLC, Credit Suisse Securities (USA) LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., RBC Capital Markets, LLC and Wells Fargo Securities, LLC are acting as joint book-running managers of the offering and as representatives of the underwriters. We, our general partner and Quicksilver have entered into an underwriting agreement with the underwriters. Subject to the terms and conditions of the underwriting agreement, we have agreed to sell to the underwriters, and each underwriter has severally agreed to purchase, at the public offering price less the underwriting discounts and commissions set forth on the cover page of this prospectus, the number of common units listed next to its name in the following table:

 

Name    Number of common units

 

J.P. Morgan Securities LLC

  

Credit Suisse Securities (USA) LLC

  

Merrill Lynch, Pierce, Fenner & Smith

  

Incorporated

  

Citigroup Global Markets Inc.

  

Deutsche Bank Securities Inc.

  

RBC Capital Markets, LLC

  

Wells Fargo Securities, LLC

  

Goldman, Sachs & Co.

  

UBS Securities LLC

  

Robert W. Baird & Co. Incorporated

  

BB&T Capital Markets, a division of Scott and Stringfellow, LLC

  

Comerica Securities, Inc.

  
  

 

Total

  

 

The underwriters are committed to purchase all of the common units offered by us if they purchase any common units. The underwriting agreement also provides that if an underwriter defaults, the purchase commitments of non-defaulting underwriters may also be increased or the offering may be terminated.

The underwriters propose to offer the common units directly to the public at the initial public offering price set forth on the cover page of this prospectus and to certain dealers at that price less a concession not in excess of $             per common unit. Any such dealers may resell common units to certain other brokers or dealers at a discount of up to $             per common unit from the initial public offering price. After the initial public offering of the common units, the offering price and other selling terms may be changed by the underwriters. Sales of common units made outside of the United States may be made by affiliates of the underwriters. J.P. Morgan Securities LLC has advised us that the underwriters do not intend to confirm discretionary sales in excess of five percent of the common units offered in this offering. The offering of common units by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

The underwriters have an option to buy up to              additional common units from us to cover sales of common units by the underwriters that exceed the number of common units specified in the table above. The underwriters have 30 days from the date of this prospectus to exercise this option to acquire additional common units. If any common units are purchased with the

 

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underwriters’ option to purchase additional common units, the underwriters will purchase common units in approximately the same proportion as shown in the table above. If any additional common units are purchased, the underwriters will offer the additional common units on the same terms and conditions as those on which the common units are being offered pursuant to this prospectus.

At our request, the underwriters have reserved for sale, at the initial public offering price, up to              common units offered by this prospectus for sale to some of our directors, officers, employees and other parties related to us and Quicksilver. If these persons purchase reserved common units, it will reduce the number of shares available for sale to the general public. Any reserved shares that are not so purchased will be offered by the underwriters to the general public on the same terms as the other common units offered by this prospectus.

The underwriting fee is equal to the public offering price per common unit less the amount paid by the underwriters to us per common unit. The underwriting fee is $             per common unit. The following table shows the per common unit and total underwriting discounts and commissions to be paid to the underwriters assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units.

 

      Without over-allotment
exercise
   With full over-allotment
exercise

 

Per common unit

     

Total

     

 

We estimate that the total costs of this offering to us, including registration, filing and listing fees, printing fees, a structuring fee and legal and accounting costs, but excluding underwriting discounts and commissions, will be approximately $            . We will pay J.P. Morgan Securities LLC a structuring fee equal to     % of the gross proceeds of this offering for the evaluation, analysis and structuring of our partnership.

A prospectus in electronic format may be made available on the websites maintained by one or more underwriters participating in the offering. The underwriters may agree to allocate a number of common units to underwriters for sale to their online brokerage account holders. Internet distributions will be allocated by the representatives to underwriters that may make Internet distributions on the same basis as other allocations.

We have agreed that we will not (1) offer, pledge, announce the intention to sell, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, or otherwise transfer or dispose of, directly or indirectly, or file with the SEC a registration statement under the Securities Act relating to, any of our common units or securities convertible into or exchangeable or exercisable for any of our common units, or publicly disclose the intention to make any offer, sale, pledge, disposition, or filing, or (2) enter into any swap or other arrangement that transfers, in whole or in part, any of the economic consequences of the ownership of any common units or any such other securities (regardless of whether any of these transactions are to be settled by the delivery of common units or such other securities, in cash or otherwise), in each case without the prior written consent of J.P. Morgan Securities LLC for a period of 180 days after the date of this prospectus, other than (i) the common units to be sold to the underwriters in this offering, (ii) any of our common units or securities convertible into or exchangeable or exercisable for any of our common units (x) granted or to be granted under our 2012 Equity Plan or (y) issued or issuable upon the exercise, conversion or settlement of awards granted or to be granted under our 2012

 

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Equity Plan, (iii) the filing of one or more registration statements on Form S-8 or any amendments or supplements thereto, (iv) transfers to our affiliates, or (v) in connection with accretive acquisitions of assets or businesses (whether by means of merger, stock purchase, asset purchase or otherwise) in which common units or securities convertible into common units are issued as consideration; provided the aggregate number of common units or securities convertible into common units issued or issuable pursuant to clause (v) hereof does not exceed 15% of the number of common units outstanding immediately after the issuance and sale of common units offered hereby. Notwithstanding the foregoing, any such recipient of common units pursuant to clause (iv) or (v) above will agree to be bound by lock-up agreements for the remainder of the 180-day restricted period.

Notwithstanding the foregoing, if (A) during the last 17 days of the 180-day restricted period, we issue an earnings release or material news or a material event relating to the Partnership occurs; or (B) prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period, the restrictions described above shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event.

Certain affiliates of Quicksilver and each of our general partner’s directors and executive officers have entered into lock-up agreements with the underwriters prior to the commencement of this offering pursuant to which each of these persons or entities for a period of 180 days after the date of this prospectus, may not, without the prior written consent of J.P. Morgan Securities LLC (1) offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, or otherwise transfer or dispose of, directly or indirectly, any of our common units or any securities convertible into or exercisable or exchangeable for our common units (including, without limitation, common units or such other securities that may be deemed to be beneficially owned by such directors, executive officers or affiliates in accordance with the rules and regulations of the SEC and securities that may be issued upon exercise of options or warrants), (2) enter into any swap or other agreement that transfers, in whole or in part, any of the economic consequences of ownership of our common units or such other securities, whether any such transaction described in clause (1) or (2) above is to be settled by delivery of common units or such other securities, in cash or otherwise, or (3) announce the intention to do any of the foregoing or make any demand for or exercise any right with respect to the registration of any of our common units or any security convertible into or exercisable or exchangeable for our common units other than (i) transactions relating to common units or other securities acquired in open market transactions after the completion of this offering of common units, (ii) transfers of common units or any security convertible into or exchangeable or exercisable for any of our common units as a bona fide gift or gifts, (iii) if such holder is a corporation, partnership, limited liability company or other entity, distributions of common units or any security convertible into or exchangeable or exercisable for any of our common units to any trust or other entity for the direct or indirect benefit of such holder or any affiliate, wholly-owned subsidiary, limited partner, member or stockholder of the holder, (iv) if such holder is a corporation, partnership, limited liability company or other entity, distributions of common units or any security convertible into or exchangeable or exercisable for any of our common units to a corporation, partnership, limited liability company or other entity of which the holder and any affiliate, subsidiary, limited partner, general partner, member or stockholder of the holder are the direct or indirect legal and beneficial owners of all the outstanding equity securities or similar interests of such corporation, partnership, limited liability

 

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company or other entity, (v) distributions to any affiliate, wholly-owned subsidiary, limited partner, member or stockholder of the holder, (vi) transfers by will or the laws of intestacy, (vii) transfers of common units or any security convertible into or exchangeable or exercisable for any of our common units to any immediate family member of the holder or to a trust or other entity for the direct or indirect benefit of such immediate family member of the holder, (viii) exercises of options, warrants or other rights to purchase common units or conversion or settlements of awards or other rights into common units, and, in each case, the receipt from us of common units thereunder, (ix) dispositions of common units to us in transactions exempt from Section 16(b) of the Exchange Act solely in connection with the payment of taxes due or any applicable exercise prices, (x) dispositions of common units solely in connection with the payment of taxes due or any applicable exercise prices, provided that such disposition occurs on or following the date of termination of the holders’ employment or service to us or our affiliates, and (xi) the establishment of a trading plan pursuant to Rule 10b5-1 under the Exchange Act for the transfer of common units, provided that such plan does not provide for the transfer of common units during the 180-day restricted period; provided that, in the case of any transfer or distribution pursuant to clauses, (ii), (iii), (iv), (v), (vi) and (vii) hereof, so long as, subject to certain exceptions, the donee, distributee or transferee agrees to be bound by the restrictions in the lock-up agreements.

Notwithstanding the foregoing, if (A) during the last 17 days of the 180-day restricted period, we issue an earnings release or material news or a material event relating to our company occurs; or (B) prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period, the restrictions described above shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event.

There are no agreements or other intentions, either tacit or explicit, regarding the possible early release of any common units subject to the lock-up provisions described above.

We and our general partner have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act.

We have applied to have our common units listed on the New York Stock Exchange under the symbol “QPP.”

In connection with this offering, the underwriters may engage in stabilizing transactions, which involves making bids for, purchasing and selling common units in the open market for the purpose of preventing or retarding a decline in the market price of the common units while this offering is in progress. These stabilizing transactions may include making short sales of the common units, which involves the sale by the underwriters of a greater number of common units than they are required to purchase in this offering, and purchasing common units on the open market to cover positions created by short sales. Short sales may be “covered” shorts, which are short positions in an amount not greater than the underwriters’ option to acquire additional common units referred to above, or may be “naked” shorts, which are short positions in excess of that amount. The underwriters may close out any covered short position either by exercising their option to acquire additional common units, in whole or in part, or by purchasing common units in the open market. In making this determination, the underwriters will consider, among other things, the price of common units available for purchase in the open market compared to the price at which the underwriters may purchase common units through the option to acquire

 

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additional common units. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market that could adversely affect investors who purchase in this offering. To the extent that the underwriters create a naked short position, they will purchase common units in the open market to cover the position.

The underwriters have advised us that, pursuant to Regulation M of the Securities Act, they may also engage in other activities that stabilize, maintain or otherwise affect the price of the common units, including the imposition of penalty bids. This means that if the representatives of the underwriters purchase common units in the open market in stabilizing transactions or to cover short sales, the representatives can require the underwriters that sold those common units as part of this offering to repay the underwriting discount received by them.

These activities may have the effect of raising or maintaining the market price of the common units or preventing or retarding a decline in the market price of the common units and, as a result, the price of the common units may be higher than the price that otherwise might exist in the open market. If the underwriters commence these activities, they may discontinue them at any time. The underwriters may carry out these transactions on the NYSE, in the over-the-counter market or otherwise.

Prior to this offering, there has been no public market for our common units. The initial public offering price will be determined by negotiations between us and the representatives of the underwriters. In determining the initial public offering price, we and the representatives of the underwriters expect to consider a number of factors including:

 

 

the information set forth in this prospectus and otherwise available to the representatives;

 

 

our prospects and the history and prospects for the industry in which we compete;

 

 

an assessment of our management;

 

 

our prospects for future earnings;

 

 

the general condition of the securities markets at the time of this offering;

 

 

the recent market prices of, and demand for, publicly traded common units of generally comparable companies; and

 

 

other factors deemed relevant by the underwriters and us.

Neither we nor the underwriters can assure investors that an active trading market will develop for our common units or that the common units will trade in the public market at or above the initial public offering price.

Because the Financial Industry Regulatory Authority, or the “FINRA,” is expected to view the common units offered hereby as interests in a direct participation program, this offering is made in compliance with Rule 2310 of the FINRA rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Other than in the United States, no action has been taken by us or the underwriters that would permit a public offering of the securities offered by this prospectus in any jurisdiction where action for that purpose is required. The securities offered by this prospectus may not be offered

 

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or sold, directly or indirectly, nor may this prospectus or any other offering material or advertisements in connection with the offer and sale of any such securities be distributed or published in any jurisdiction, except under circumstances that will result in compliance with the applicable rules and regulations of that jurisdiction. Persons into whose possession this prospectus comes are advised to inform themselves about and to observe any restrictions relating to the offering and the distribution of this prospectus. This prospectus does not constitute an offer to sell or a solicitation of an offer to buy any securities offered by this prospectus in any jurisdiction in which such an offer or a solicitation is unlawful.

In relation to each member state of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”), other than Germany, from and including the date on which the European Union Prospectus Directive (the “EU Prospectus Directive”) is implemented in that Relevant Member State (the “Relevant Implementation Date”), an offer of securities described in this prospectus may not be made to the public in that Relevant Member State other than:

 

 

to any legal entity which is a qualified investor as defined in the EU Prospectus Directive;

 

 

to fewer than 100 or, if the Relevant Member State has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the EU Prospectus Directive), as permitted under the EU Prospectus Directive, subject to obtaining the prior consent of the relevant Dealer or Dealers nominated by the Issuer for any such offer; or

 

 

in any other circumstances falling within Article 3(2) of the EU Prospectus Directive,

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the EU Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the EU Prospectus Directive in that member state, and the expression “EU Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member State), and includes any relevant implementing measure in the Relevant Member State, and includes any relevant implementing measure in each relevant member state. The expression 2010 PD Amending Directive means Directive 2010/73/EU.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

We may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000 (“FSMA”) that is not a “recognized collective investment scheme” for the purposes of FSMA (“CIS”) and that has not been authorized or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except

 

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in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at:

(i) if we are a CIS and is marketed by a person who is an authorized person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) Order 2001, as amended (the “CIS Promotion Order”) or (b) high net worth companies and other persons falling with Article 22(2)(a) to (d) of the CIS Promotion Order; or

(ii) otherwise, if marketed by a person who is not an authorized person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the “Financial Promotion Order”) or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

(iii) in both cases (i) and (ii) to any other person to whom it may otherwise lawfully be made, (all such persons together being referred to as “relevant persons”). Our common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this document or any of its contents.

An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to us.

This prospectus has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Sales Prospectus Act (Verkaufsprospektgesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this prospectus and any other document relating to this offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of the common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This prospectus is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

This offering of our common units does not constitute an offer to buy or the solicitation or an offer to sell the common units in any circumstances in which such offer or solicitation is unlawful.

Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be

 

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copied, reproduced, distributed or passed on to third parties. Our common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be distributed in connection with any such public offering.

We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006 (“CISA”). Accordingly, our common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be made available through a public offering in or from Switzerland. Our common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

Certain of the underwriters and their affiliates have performed investment banking, commercial banking and advisory services for our affiliates from time to time, for which they have received customary fees and expenses. Affiliates of J.P. Morgan Securities LLC, Credit Suisse Securities (USA) LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., RBC Capital Markets, LLC, Wells Fargo Securities, LLC, Goldman, Sachs & Co., UBS Securities LLC, BB&T Capital Markets, a division of Scott and Stringfellow, LLC and Comerica Securities, Inc. will be lenders under our new credit facility. Certain of the underwriters and their affiliates may provide in the future investment banking, financial advisory or other financial services for us and our affiliates, for which they may receive advisory or transaction fees, as applicable, plus out-of-pocket expenses, of the nature and in amounts customary in the industry for these financial services. In addition, from time to time, certain of the underwriters and their affiliates may effect transactions for their own account or the account of customers, and hold on behalf of themselves or their customers, long or short positions in our or our affiliates’ debt or equity securities or loans, and may do so in the future. The underwriters and their respective affiliates may also communicate independent investment recommendations, market color or trading ideas and/or publish or express independent research views in respect of such assets, securities or instruments and may at any time hold, or recommend to clients that they should acquire, long and/or short positions in such assets, securities and instruments.

 

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Validity of the common units

The validity of the common units will be passed upon for us by Potter Anderson & Corroon LLP, Wilmington, Delaware, and certain legal matters in connection with the common units offered by us will be passed upon for us by Davis Polk & Wardwell LLP, New York, New York. Certain legal matters in connection with the common units offered by us will be passed upon for the underwriters by Andrews Kurth LLP, Houston, Texas.

Experts

The financial statements included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in its report (which report expresses an unqualified opinion on the financial statements and includes explanatory paragraphs relating to 1) financial statements that were prepared from the separate records maintained by Quicksilver Resources Inc. and may not necessarily be indicative of the conditions that would have existed or the results of operations if Quicksilver Production Partners LP Predecessor had been operated as an unaffiliated entity, and 2) Quicksilver Production Partners LP Predecessor’s adoption of Accounting Standards Update No. 2010-3, “Oil and Gas Reserve Estimation and Disclosures,” effective December 31, 2009). Such financial statements have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The information included in this prospectus regarding quantities of proved reserves, the future net revenue from those proved reserves and their present value is based on estimates of the proved reserves and present values of proved reserves as of December 31, 2011. Our proved reserve estimates at December 31, 2011, December 31, 2010, December 31, 2009 and December 31, 2008, and Quicksilver’s proved reserve estimates at December 31, 2011, are based on reports prepared by Data & Consulting Services Division of Schlumberger Technology Corporation, independent reserve engineers. These estimates are included in this prospectus in reliance upon the authority of such firm as experts in these matters.

Where you can find more information

We have filed with the SEC a registration statement on Form S-1 regarding our common units. This prospectus, which constitutes part of the registration statement, does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a website on the Internet at http://www.sec.gov. The registration statement, of which this prospectus forms a part, can be downloaded from the SEC’s website.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited

 

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interim financial information for the first three fiscal quarters of each of our fiscal years. Additionally, we intend to file periodic reports with the SEC, as required by the Securities Exchange Act of 1934.

 

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Forward-looking statements

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

 

 

business strategies;

 

ability to replace the proved reserves we produce through development and acquisition activities;

 

drilling locations;

 

our proved reserves;

 

realized commodity prices;

 

production volumes;

 

operating costs;

 

future operating results;

 

commodity derivatives and hedging activities;

 

cash flows, liquidity and ability to make distributions to unitholders;

 

availability and cost of oil field equipment and labor;

 

capital expenditures;

 

availability and terms of capital;

 

new revolving credit facility;

 

marketing of our production;

 

general economic conditions;

 

competition in the oil and gas industry;

 

effectiveness of risk management activities;

 

environmental regulation and liabilities;

 

counterparty risk;

 

relationships with our general partner, other related parties and third parties;

 

governmental regulation and taxation;

 

developments in oil and natural gas producing regions; and

 

plans, objectives, expectations and intentions.

These types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in “Summary,” “Risk factors,” “Our cash distribution policy and restrictions on distributions,” “Management’s discussion and analysis of financial condition and results of operations,” “Business and properties” and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking

 

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statements due to factors described in “Risk factors” and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

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Quicksilver Production Partners LP Predecessor

Index to financial statements

 

Unaudited carve out financial statements as of March 31, 2012 and for the three months ended March 31, 2012 and 2011

  

Carve out statements of income and comprehensive income for the three months ended March 31, 2012 and 2011

     F-2   

Carve out balance sheets as of March 31, 2012 and December 31, 2011

     F-3   

Carve out statements of cash flows for the three months ended March 31, 2012 and 2011

     F-4   

Carve out statement of owner’s equity for the three months ended March 31, 2012

     F-5   

Unaudited notes to carve out financial statements

     F-6   

Report of independent registered public accounting firm

     F-16   

Audited carve out financial statements as of December 31, 2011 and 2010 and for the years ended December 31, 2011, 2010 and 2009

  

Carve out statements of income and comprehensive income for the years ended December 31, 2011, 2010, and 2009

     F-17   

Carve out balance sheets as of December 31, 2011 and 2010

     F-18   

Carve out statements of cash flows for the years ended December 31, 2011, 2010, and 2009

     F-19   

Carve out statements of owner’s equity for the years ended December 31, 2011, 2010, and 2009

     F-20   

Notes to carve out financial statements

     F-21   

 

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Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Carve out statements of income and comprehensive income

(in thousands–unaudited)

 

      For the Three Months
Ended March 31,
 
     2012     2011  

 

  

 

 

   

 

 

 

Production revenue

    

Natural gas

   $ 16,259      $ 16,321   

NGL

     17,588        16,593   

Oil

     1,332        1,252   
  

 

 

 

Total production revenue

     35,179        34,166   

Other revenue

     6,688          
  

 

 

 

Total revenue

     41,867        34,166   
  

 

 

 

Operating expense

    

Lease operating

     5,079        5,308   

Gathering, processing and transportation

     7,543        7,651   

Production and ad valorem taxes

     957        1,025   

Depletion and accretion

     6,217        5,077   

General and administrative

     3,072        2,675   
  

 

 

 

Total expense

     22,868        21,736   
  

 

 

 

Income before income taxes

     18,999        12,430   

Income tax expense

     210        178   
  

 

 

 

Net income

   $ 18,789      $ 12,252   

Other comprehensive income

    

Reclassification adjustments related to settlements of derivative contracts—net of income taxes

     (9,372     (5,075

Net change in derivative fair value—net of income taxes

     19,626        (6,099
  

 

 

   

 

 

 

Other comprehensive income

     10,254        (11,174
  

 

 

   

 

 

 

Comprehensive income

   $ 29,043      $ 1,078   

Pro forma information

    

Pro Forma general partner’s interest in net income

   $ 19      $ 12   

Pro Forma limited partners’ interest in net income

   $ 18,770      $ 12,240   

Pro forma earnings per unit:

    

Pro forma net income per limited partner units:

    

Common units (basic)

   $        $     

Subordinated units

   $        $     

Common units (diluted)

   $        $     

Weighted-average limited partner units outstanding:

    

Common units (basic)

    

Subordinated units

    

Common units (diluted)

                

The accompanying notes are an integral part of these carve out financial statements.

 

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Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Carve out balance sheets

(in thousands–unaudited)

 

      As of  
     March 31,
2012
     December 31,
2011
 

 

  

 

 

    

 

 

 

ASSETS

     

Current assets

     

Accounts receivable

   $ 8,806       $ 9,217   

Derivative assets at fair value

     38,901         29,075   
  

 

 

 

Total current assets

     47,707         38,292   

Oil and gas properties, full cost method (including unevaluated cost of $0 and $0, respectively)—net

     310,936         306,465   

Derivative assets at fair value

     57,446         50,892   
  

 

 

 
   $ 416,089       $ 395,649   
  

 

 

 

LIABILITIES AND OWNER’S EQUITY

     

Current liabilities

     

Accrued liabilities

   $ 8,080       $ 10,784   

Current deferred taxes

     362         287   
  

 

 

 

Total current liabilities

     8,442         11,071   

Asset retirement obligations

     10,782         10,652   

Commitments and contingencies (Note 6)

     

Deferred income taxes

     3,100         3,017   

Owner’s equity

     

Accumulated other comprehensive income

     89,018         78,764   

Owner’s capital

     304,747         292,145   
  

 

 

 

Owner’s equity

     393,765         370,909   
  

 

 

 
   $ 416,089       $ 395,649   

 

  

 

 

    

 

 

 

The accompanying notes are an integral part of these carve out financial statements.

 

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Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Carve out statements of cash flows

(in thousands–unaudited)

 

      For the three months
ended March 31,
 
     2012     2011  

 

  

 

 

   

 

 

 

Operating activities:

    

Net income

   $ 18,789      $ 12,252   

Adjustments to reconcile net income to net cash provided by operating activities:

    

Depletion and accretion

     6,217        5,077   

Deferred income taxes

     243        94   

Non-cash gain from derivative activities

     (6,419       

Change in accounts receivable

     619        (497

Change in accrued liabilities

     (2,727     (3,721
  

 

 

 

Net cash provided by operating activities

     16,722        13,205   
  

 

 

 

Investing activities:

    

Capital expenditures

     (10,535     (8,392
  

 

 

 

Net cash used by investing activities

     (10,535     (8,392
  

 

 

 

Financing activities:

    

Net transfers to parent

     (6,187     (4,813
  

 

 

 

Net cash used by financing activities

     (6,187     (4,813
  

 

 

 

Net change in cash

              

Cash at beginning of period

              
  

 

 

 

Cash at end of period

   $      $   
  

 

 

 

Working capital related to capital expenditures

   $ 2,968      $ 2,139   

 

  

 

 

   

 

 

 

 

The accompanying notes are an integral part of these carve out financial statements.

 

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Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Carve out statement of owner’s equity

for the three months ended March 31, 2012

(in thousands-unaudited)

 

      Accumulated
Other
Comprehensive
Income
     Owner’s
Capital
    Owner’s
Equity
 

 

  

 

 

    

 

 

   

 

 

 

Balances at January 1, 2012

   $ 78,764       $ 292,145      $ 370,909   

Net change in hedge derivative fair value, net of income taxes of $85

     10,254                10,254   

Net income

             18,789        18,789   

Net transfers to parent

             (6,187     (6,187
  

 

 

    

 

 

   

 

 

 

Balances at March 31, 2012

   $ 89,018       $ 304,747      $ 393,765   

 

The accompanying notes are an integral part of these carve out financial statements.

 

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Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Unaudited notes to carve out financial statements

Note 1. Formation of the partnership and description of business

Quicksilver Production Partners LP, a Delaware limited partnership (“QPP” or the “Partnership”), was formed in November 2011 by Quicksilver Resources Inc. (“Quicksilver”) to acquire and develop oil and natural gas properties and to acquire, own, and operate related assets. Quicksilver currently owns all of the equity interests in QPP. QPP plans to pursue an initial public offering of its limited partner units (the “Offering”) during the second or third quarter of 2012.

Effective upon the closing of this offering, Quicksilver will contribute certain oil and natural gas properties (the “Partnership Properties”) and certain commodity derivatives novated by Quicksilver in exchange for a combination of QPP common, subordinated and general partner units and cash. The contribution will be accounted for as a combination of entities under common control, whereby the assets and liabilities contributed will be recorded based on the predecessor’s historical cost. Quicksilver has agreed upon terms with a financial institution that previously would not allow Quicksilver to novate a certain derivative to us. This derivative will now be novated to us upon the closing of this offering.

The Partnership Properties are located in Tarrant, Hood, Johnson, Hill and Somervell Counties in North Texas. As explained in Note 2 below, QPP Predecessor consists of a “carve out” of the Partnership Properties and the commodity derivatives from the consolidated financial statements of Quicksilver. QPP Predecessor is not now, and has never been, a separately identifiable legal entity from Quicksilver, nor has it operated independently from Quicksilver. After the closing of the Offering, Quicksilver will continue to own approximately 50% of the Partnership’s limited partner interests and 100% of the general partner interests.

Note 2. Summary of significant accounting policies

Basis of presentation

The accompanying carve out financial statements and related notes thereto represent the carve out financial position, results of operations, cash flows, and changes in owner’s equity of the Barnett Shale Assets and derivatives, referred to as QPP Predecessor. The carve out financial statements have been prepared in accordance with SEC rules and related staff accounting bulletins governing carve out financial statements. Certain expenses incurred by Quicksilver are only indirectly attributable to its ownership of the Barnett Shale Assets as Quicksilver owns interests in numerous other oil and natural gas properties in the Barnett Shale and elsewhere in North America. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such expenses to QPP Predecessor, so that the accompanying carve out financial statements reflect substantially all the costs attendant to QPP’s operations. A review of subsequent events was carried out through June 21, 2012, the date the financial statements were issued.

The accompanying condensed consolidated interim financial statements have not been audited. In management’s opinion, the accompanying condensed consolidated interim financial statements contain all adjustments necessary to fairly present our financial position as of March 31, 2012 and our results of operations and cash flows for the three months ended March 31, 2011 and 2012. All such adjustments are of a normal recurring nature. The results for interim periods are not necessarily indicative of annual results.

 

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Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Unaudited notes to carve out financial statements—(continued)

 

Use of estimates

Preparing financial statements requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during each reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from management’s estimates.

Significant estimates underlying these financial statements include the estimated quantities of proved natural gas, NGL and oil reserves (including the associated future net cash flows from those proved reserves) used to compute depletion expense and prepare the ceiling test for oil and gas properties. Revenue contains estimates based upon expectations for actual deliveries and prices received. Substantial judgment is also required to estimate the fair value of asset retirement obligations. Income taxes also involve the use of considerable judgment in the estimation and evaluation of deferred income tax assets and assessment of uncertain tax positions, although QPP is not subject to federal income taxes, so such deferred taxes and uncertain tax positions primarily relate to Texas franchise tax.

Cash

Quicksilver provides cash as needed to support operation of QPP Predecessor and collects cash from sales of its production. Consequently, the accompanying Carve Out Balance Sheets do not include any cash balances. Cash received or paid by Quicksilver on behalf of the QPP Predecessor is reflected as net transfers to parent on the accompanying Carve Out Statements of Owner’s Equity.

Hedging and derivatives

QPP Predecessor utilizes financial derivative instruments to mitigate risk associated with the prices received for its production. All derivatives are recognized as either an asset or liability on the balance sheet measured at their fair value determined by reference to published future market prices and interest rates. For derivatives instruments that qualify as cash flow hedges, the effective portions of gains and losses are deferred in accumulated other comprehensive income and recognized in revenue in the period in which the hedged transaction is recognized. Gains or losses on hedges terminated prior to their original expiration date are deferred and recognized as earnings during the period in which the hedged transaction is recognized. If it is probable the hedged transaction will not occur, the deferred gain or loss would be immediately recorded to earnings. Changes in value of ineffective portions of hedges, if any, are recognized currently as a component of other revenue. For derivatives that do not qualify as cash flow hedges, realized and unrealized gains and losses attributable to future production months are recognized in the income statement as other revenue.

Financial derivatives are entered into with counterparties who are lenders under Quicksilver’s Amended and Restated U.S. Credit Facility. Quicksilver’s Amended and Restated U.S. Credit

 

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Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Unaudited notes to carve out financial statements—(continued)

 

Facility and internal credit policies require that any counterparties meet or exceed BBB- or Baa3 from Standard and Poor’s or Moody’s, respectively. The fair value for each derivative takes into consideration credit risk, whether it be QPP Predecessor’s counterparties’ or QPP Predecessor’s own. Derivatives are recorded in the balance sheet as current and non-current derivative assets and liabilities as determined by the expected timing of settlements.

Oil and gas properties

The accompanying carve out financial statements have been prepared using the full cost method of accounting for oil and gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in a country-wide cost center. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved oil and gas reserves. Excluded from amounts subject to depletion are costs associated with unevaluated properties.

Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations or the cost center ceiling. The cost center ceiling, which is measured each quarter, is defined as the sum of (1) estimated future net revenue, discounted at 10% per annum, from proved reserves, based on the unweighted average of the first-day-of-the-month prices for the preceding 12 months, adjusted to reflect local differentials and contract provisions, (2) the cost of properties not being amortized, (3) the lower of cost or market value of unproved properties included in the cost being amortized, less (4) income tax effects related to differences between the book and tax basis of the natural gas and oil properties. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required. Note 4 to these financial statements contains further discussion of the ceiling test.

To establish a value for its oil and gas properties at January 1, 2008, QPP Predecessor used the pro rata portion of the Standardized Measure of its proved reserves to Quicksilver’s to allocate the full cost pool of Quicksilver. Unevaluated costs were specifically identified in segregating costs to QPP Predecessor’s properties.

Asset retirement obligations

The fair value of asset retirement obligations is recorded in the period in which it is legally or contractually incurred. Upon initial recognition of the asset retirement liability, an asset retirement cost is capitalized by increasing the carrying amount of the asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost is recognized as expense through depletion over the asset’s useful life. Changes in the liability for

 

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Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Unaudited notes to carve out financial statements—(continued)

 

the asset retirement obligations are recognized for (1) the passage of time and (2) revisions to either the timing or the amount of estimated cash flows. Accretion expense is recognized for the impacts of increasing the discounted amount to its estimated settlement value.

Owner’s equity

QPP Predecessor was not a separate legal entity during the period covered by these carve out financial statements, therefore none of Quicksilver’s debt is directly attributable to QPP Predecessor’s ownership of the Barnett Shale Assets, and no formal intercompany financing arrangement related to the Barnett Shale Assets exists between Quicksilver and QPP Predecessor. Therefore, the change in net assets in each year that is not attributable to current period earnings is reflected as an increase or decrease to owner’s net equity for that year. Additionally, the accompanying carve out statements of income and comprehensive income do not include any allocation of interest expense incurred by Quicksilver as (i) it is impractical to unwind the elements of Quicksilver’s complex capital structure to determine what debt, if any, relates directly to the operations of the Predecessor, (ii) intercompany debt and related interest expense did not historically exist between Quicksilver and the QPP Predecessor and (iii) Quicksilver was able to develop the Partnership Properties with cash flows from its operations primarily due to high natural gas prices in 2007 and 2008.

Revenue recognition

Revenue is recognized when title to the products transfers to the purchaser. The “sales method” is employed to account for all production revenue, whereby revenue is recognized on all production sold to purchasers, regardless of whether the sales are proportionate to QPP Predecessor’s ownership in the property. A receivable or liability is recognized only to the extent that an imbalance on a specific property is greater than the expected remaining proved reserves.

Environmental compliance and remediation

Environmental compliance costs, including ongoing maintenance and monitoring, are expensed as incurred. Those environmental remediation costs which improve a property are capitalized.

Allocation of general and administrative costs incurred by Quicksilver

The accompanying carve out financial statements include allocations of costs for salaries and benefits, rent, accounting and legal services and other general and administrative expenses incurred by Quicksilver. These costs have been allocated to these carve out financials based on QPP Predecessor’s share of Quicksilver’s U.S. production as measured on a Mcfe basis. In management’s estimation, the allocation methodologies used are reasonable and result in an allocation of the cost of doing business borne by Quicksilver on behalf of QPP Predecessor; however, these allocations are not indicative of the cost of future operations or the amount of future allocations.

 

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Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Unaudited notes to carve out financial statements—(continued)

 

Stock-based compensation

The Partnership does not have its own employees nor has it granted any stock-based compensation. However, during the periods presented, a portion of the general and administrative (“G&A”) expenses allocated within these carve out financials was non-cash stock-based compensation recorded on the books of Quicksilver. The allocated amount of stock-based compensation was $0.9 million for both the three months ended March 31, 2012 and 2011.

Income taxes

QPP Predecessor’s operations are currently included in the federal income tax return of Quicksilver which is subject to federal income taxes. Following the Offering, each partner of QPP will be separately taxed on its share of taxable income. Therefore, no provision for current or deferred federal income taxes has been provided for in the accompanying carve out financial statements. However, QPP Predecessor remains subject to the Texas franchise tax. Deferred tax liability and related income tax expense were recognized for the expected future tax effect of the Texas franchise tax assessed at 1% of taxable margin.

Segment reporting

QPP Predecessor has only one operating segment, the upstream development of oil and natural gas reserves. Additionally, all of QPP Predecessor’s properties are located in the U.S. and all of its production is derived from customers located in the U.S.

Earnings per unit

During the periods presented, QPP Predecessor’s assets were wholly owned by Quicksilver. Earnings per unit have not been presented because no units were outstanding.

Recently issued accounting standards

In June 2011, the FASB issued an amendment to accounting guidance to update the presentation of comprehensive income in consolidated financial statements. Under the amended guidance, the presentation of total comprehensive income, the components of net income, and the components of other comprehensive income may be made either in a single continuous statement of comprehensive income or in two separate but consecutive statements. This guidance became effective for us beginning with the quarter ended March 31, 2012 and did not have an impact on our financial statements.

In May 2011, the FASB issued an amendment to the accounting guidance for fair value measurement and disclosure. Among other things, the guidance expands the disclosure requirements around fair value measurements categorized in Level 3 of the fair value hierarchy and requires disclosure of the level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position but whose fair value must be disclosed. It also clarifies and expands upon existing requirements for measurement of the fair value of financial

 

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Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Unaudited notes to carve out financial statements—(continued)

 

assets and liabilities as well as instruments classified in shareholders’ equity. This guidance became effective for us beginning with the quarter ended March 31, 2012. The adoption of this accounting pronouncement did not have an effect on our financial statements.

In December 2011, the FASB issued an amendment to the accounting guidance for the disclosure of arrangements that permit offsetting assets and liabilities. The amendment expands the disclosure requirements to require both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The amendment is effective for fiscal years, and interim periods within those years, beginning on or after January 1, 2013 and shall be applied retrospectively. We do not expect the adoption of this accounting pronouncement to have a material impact on our financial statements when implemented.

No other pronouncements materially affecting our financial statements have been issued.

Note 3. Derivatives and fair value measures

The following table details the estimated fair value of all derivative instruments where “Level 2” inputs are the basis of the derivative fair value estimates at March 31, 2012 and 2011:

 

      Derivatives at
March  31,

2012
     Derivatives at
December 31, 2011
 
     Asset      Liability      Asset      Liability  

 

  

 

 

    

 

 

    

 

 

    

 

 

 
                          (in thousands)  

Level 2 inputs

   $ 96,347       $       $ 79,967       $ 364   

The fair value of all derivative instruments included in these disclosures was estimated using prices quoted in active markets for the periods covered by the derivatives and the value reported by counterparties. Estimates were determined by applying the net differential between the prices in each derivative and market prices for future periods to the amounts stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at the credit adjusted risk free rates.

As of March 31, 2012, QPP Predecessor had price swaps covering 30 Mmcfd of its anticipated natural gas production for 2012 through 2015 and 3 Mbbld of its anticipated natural gas liquid production for 2012. These price swaps were designated by Quicksilver as cash flow hedges.

 

F-11


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Unaudited notes to carve out financial statements—(continued)

 

The estimated fair value of QPP Predecessor’s derivative instruments were as follows:

 

      Asset derivatives      Liability derivatives  
     March 31,
2012
     December 31,
2011
    

March 31,

2012

     December 31,
2011
 

 

  

 

 

    

 

 

    

 

 

    

 

 

 
     (in thousands)      (in thousands)  

Derivatives designated as hedges:

           

Commodity contracts reported in:

           

Current derivative assets

   $ 26,900       $ 18,997       $       $   

Noncurrent derivative assets

     38,052         34,461                   

Current derivative liabilities

                             364   

Noncurrent derivative liabilities

                               
  

 

 

 

Total derivatives designated as hedges

   $ 64,952       $ 53,458       $       $ 364   

 

  

 

 

    

 

 

    

 

 

    

 

 

 

 

      Asset derivatives      Liability derivatives  
     March 31,
2012
     December 31,
2011
    

March 31,

2012

     December 31,
2011
 

 

  

 

 

    

 

 

    

 

 

    

 

 

 
     (in thousands)      (in thousands)  

Derivatives not designated as hedges:

           

Commodity contracts reported in:

           

Current derivative assets

   $ 12,001       $ 10,078       $       $   

Noncurrent derivative assets

     19,394         16,431                   

Current derivative liabilities

                               

Noncurrent derivative liabilities

                               
  

 

 

 

Total derivatives not designated as hedges

   $ 31,395       $ 26,509       $       $   

The changes in the carrying value of QPP Predecessor’s derivatives for the three months ended March 31, 2012 and 2011 are presented below:

 

      For the three
months ended
March 31,
 
     2012     2011  

 

  

 

 

   

 

 

 
     (in thousands)  

Derivative fair value at beginning of period

   $ 79,603      $ 41,230   

Change in receivable

     (208       

Settlements reported in production revenue

     (9,103     (5,075

Unrealized gains (losses) reported in other comprehensive income

     19,636        (6,213

Net unrealized gains reported in other revenue (not designated as hedge)

     6,419          
  

 

 

 

Derivative fair value at end of period

   $ 96,347      $ 29,942   

Gains from the effective portion of derivative assets held in accumulated other comprehensive income expected to be reclassified into earnings during the twelve months ending March 31, 2013 will result in revenue of $33.5 million, net of income taxes.

At December 31, 2011, anticipated production in future years were less than the notional volume covered by derivatives for natural gas. A derivative that previously qualified as a cash flow hedge

 

F-12


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Unaudited notes to carve out financial statements—(continued)

 

no longer met the requirements for hedge accounting. Future changes in the valuation of this derivative will be recognized in the Carve Out Statement of Income and Comprehensive Income, and the remaining net value at March 31, 2012 in accumulated other comprehensive income of $25.8 million will be recognized into production revenue over the remaining term of the derivative.

Note 4. Oil and gas properties—full cost method

Oil and gas properties were as follows:

 

      March 31,
2012
    December 31,
2011
 

 

  

 

 

   

 

 

 
     (in thousands)  

Oil and gas properties

    

Subject to depletion

   $ 856,831      $ 846,273   

Unevaluated properties

              

Accumulated depletion and impairment

     (545,895     (539,808
  

 

 

 

Total

   $ 310,936      $ 306,465   

Ceiling tests for QPP Predecessor’s oil and gas properties were performed for the country-wide cost center, on an annual basis using year-end balances and values for 2011 and prior years, and also as of March 31, 2012 using balances as of that date.

Note 5. Asset retirement obligations

The following table provides a reconciliation of the changes in estimated asset retirement obligations from January 1, 2011 through March 31, 2012:

 

      For the three
months ended
March 31,
2012
 

 

  

 

 

 
     (in thousands)  

Beginning asset retirement obligations

   $ 10,652   

Accretion expense

     130   
  

 

 

 

Ending asset retirement obligations

   $ 10,782   

Note 6. Commitments and contingencies

QPP Predecessor is subject to potential claims and litigation in the normal course of operations. Quicksilver’s management does not believe that any liability resulting from any pending or threatened litigation will have a material effect on QPP Predecessor’s operations or financial results of its activities.

 

F-13


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Unaudited notes to carve out financial statements—(continued)

 

Note 7. Income taxes

No provision for federal or state income taxes is made in QPP Predecessor’s carve out financial statements except for the Texas franchise tax which is an income tax assessed at the Quicksilver level because the taxable income or loss will be included in the income tax returns of the individual partners of the Partnership with the exception of Texas franchise taxes. The tables below present federal taxable income (loss) and net income on an unaudited pro forma basis.

A reconciliation between the statutory federal income tax rate and the pro forma effective income tax rate for QPP Predecessor’s income taxes that were included in the financial statements follows:

 

      For the three
months ended
March 31,
 
     

 

 

    

 

 

 
     2012      2011  

 

  

 

 

    

 

 

 

Statutory rate

     35.00%         35.00%   

Permanent differences

     1.37%         1.68%   

State income tax, net of federal benefit

     0.73%         0.99%   
  

 

 

 

Effective tax rate

     37.10%         37.67%   

The following table reconciles net income before income taxes to pro forma federal taxable income (loss) for the periods indicated (in thousands):

 

      For the three
months ended
March 31,
 
     

 

 

   

 

 

 
     2012     2011  

 

  

 

 

   

 

 

 

Net income before taxes

   $ 18,999      $ 12,430   

Permanent differences

     742        596   

Tax basis depreciation, depletion and amortization, net of financial reporting basis

     (12,772     (14,006
  

 

 

 

Pro forma federal taxable income (loss)

   $ 6,969      $ (980

QPP Predecessor’s financial reporting bases of its net fixed assets exceeded the tax bases of its net fixed assets by $255.1 million and $200.3 million for the three months ended March 31, 2012 and the three months ended March 31, 2011, respectively.

The following details pro forma net income reflecting a tax provision calculated on a separate return basis for QPP Predecessor (in thousands):

 

      For the three
months ended
March 31,
 
     

 

 

   

 

 

 
     2012     2011  

 

  

 

 

   

 

 

 

Net income before taxes

   $ 18,999      $ 12,430   

Tax provision

     (7,047     (4,684
  

 

 

 

Pro forma net income

   $ 11,952      $ 7,746   

 

F-14


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Unaudited notes to carve out financial statements—(continued)

 

Note 8. Accounts receivable

Accounts receivable consist solely of unpaid production revenue.

Note 9. Pro forma net income (loss) per limited partner unit

Unaudited pro forma net income per limited partner unit is determined by dividing the net income available to holders of common units, after deducting the general partner’s 0.1% interest in net income, by the number of common units and subordinated units expected to be outstanding at the closing of the Offering. All units were assumed to have been outstanding since January 1, 2009. Basic and diluted net income per unit are equivalent as there will be no dilutive units at the date of the closing of the Offering of the common units of the Partnership.

 

F-15


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Report of independent registered public accounting firm

To the Owners of Quicksilver Production Partners LP Predecessor,

We have audited the accompanying carve out balance sheets of Quicksilver Production Partners LP Predecessor (the “Predecessor”) as of December 31, 2011 and 2010, and the related carve out statements of income and comprehensive income, cash flows, and owner’s equity for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Predecessor’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. The Predecessor is not required to have, nor were we engaged to perform, an audit of its 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 Predecessor’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.

The accompanying financial statements have been prepared from the separate records maintained by Quicksilver Resources Inc. and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Predecessor had been operated as an unaffiliated entity. Portions of certain expenses represent allocations made from and are applicable to Quicksilver Resources Inc. as a whole.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Quicksilver Production Partners LP Predecessor as of December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the financial statements, on December 31, 2009, the Predecessor adopted Accounting Standards Update No. 2010-3, “Oil and Gas Reserve Estimation and Disclosures.”

/s/ Deloitte & Touche LLP

Fort Worth, Texas

May 10, 2012

 

F-16


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Carve out statements of income and comprehensive income

(in thousands)

 

      For the years ended December 31,  
     2011     2010     

2009

 

 

 

 

Production revenue

       

Natural gas

   $ 70,765      $ 54,995       $ 68,664   

NGL

     75,827        67,117         65,218   

Oil

     4,876        5,803         8,142   
  

 

 

 

Total production revenue

     151,468        127,915         142,024   
  

 

 

 

Total revenue

     151,468        127,915         142,024   
  

 

 

 

Operating expense

       

Lease operating

     22,125        20,257         19,023   

Gathering, processing and transportation

     30,841        32,705         41,891   

Production and ad valorem taxes

     4,266        5,565         6,673   

Depletion and accretion

     22,629        21,050         37,978   

Impairment of oil and gas properties

                    60,045   

General and administrative

     10,959        12,389         16,132   
  

 

 

 

Total expense

     90,820        91,966         181,742   
  

 

 

 

Income (loss) before income taxes

     60,648        35,949         (39,718

Income tax expense

     1,038        838         86   
  

 

 

 

Net income (loss)

   $ 59,610      $ 35,111       $ (39,804

Other comprehensive income

       

Reclassification adjustments related to settlements of derivative contracts—net of income taxes

     (21,248               

Net change in derivative fair value—net of income taxes

     59,194        40,818           
  

 

 

 

Other comprehensive income

     37,946        40,818           
  

 

 

 

Comprehensive income

     97,556        75,929         (39,804

Unaudited pro forma information

       

Pro Forma general partner’s interest in net income (loss)

   $ 60      $ 35       $ (40

Pro Forma limited partners’ interest in net income (loss)

   $ 59,550      $ 35,076       $ (39,764

Pro forma earnings per unit:

       

Pro forma net income (loss) per limited partner units:

       

Common units (basic)

   $      $       $   

Subordinated units

   $      $       $   

Common units (diluted)

   $      $       $   

Weighted-average limited partner units outstanding:

       

Common units (basic)

       

Subordinated units

       

Common units (diluted)

  

 

 

   

 

 

    

 

 

 

The accompanying notes are an integral part of these carve out financial statements.

 

F-17


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Carve out balance sheets

(in thousands)

 

      As of December 31,  
     2011      2010  

 

 

ASSETS

     

Current assets

     

Accounts receivable

   $ 9,217       $ 10,529   

Derivative assets at fair value

     29,075         15,660   
  

 

 

 

Total current assets

     38,292         26,189   

Oil and gas properties, full cost method (including unevaluated cost of $0 and $2,794, respectively)—net

     306,465         284,329   

Derivative assets at fair value

     50,892         25,570   
  

 

 

 
   $ 395,649       $ 336,088   
  

 

 

 

LIABILITIES AND OWNER’S EQUITY

     

Current liabilities

     

Accrued liabilities

   $ 10,784       $ 10,984   

Current deferred taxes

     287         152   
  

 

 

 

Total current liabilities

     11,071         11,136   

Asset retirement obligations

     10,652         3,962   

Commitments and contingencies (Note 6)

     

Deferred income taxes

     3,017         2,156   

Owner’s equity

     

Accumulated other comprehensive income

     78,764         40,818   

Owner’s capital

     292,145         278,016   
  

 

 

    

 

 

 

Owner’s equity

     370,909         318,834   
  

 

 

    

 

 

 

 

   $ 395,649       $ 336,088   

The accompanying notes are an integral part of these carve out financial statements.

 

F-18


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Carve out statements of cash flows

(in thousands)

 

      For the years ended December 31,  
                 2011                 2010                 2009  

 

 

Operating activities:

      

Net income (loss)

   $ 59,610      $ 35,111      $ (39,804

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

      

Depletion and accretion

     22,629        21,050        37,978   

Deferred income taxes

     205        562        (305

Impairment of oil and gas properties

                   60,045   

Change in accounts receivable

     1,312        2,014        4,529   

Change in accrued liabilities

     (745     (1,346     (98
  

 

 

 

Net cash provided by operating activities

     83,011        57,391        62,345   
  

 

 

 

Investing activities:

      

Capital expenditures

     (37,530     (39,814     (41,882
  

 

 

 

Net cash used by investing activities

     (37,530     (39,814     (41,882
  

 

 

 

Financing activities:

      

Net transfers to parent

     (45,481     (17,577     (20,463
  

 

 

 

Net cash used by financing activities

     (45,481     (17,577     (20,463
  

 

 

 

Net change in cash

                     

Cash at beginning of period

                     
  

 

 

 

Cash at end of period

   $      $      $   
  

 

 

 

Working capital related to capital expenditures

   $ 2,945      $ 2,400      $ 800   

 

The accompanying notes are an integral part of these carve out financial statements.

 

F-19


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Carve out statements of owner’s equity

for the years ended December 31, 2011, 2010 and 2009

(in thousands)

 

      Accumulated
Other
Comprehensive
Income
     Owner’s
Capital
    Owner’s
Equity
 

 

    

 

 

   

 

 

 

Balances at January 1, 2009

                   $       $ 320,749      $ 320,749   

Net loss

             (39,804     (39,804

Net transfers to parent

             (20,463     (20,463

Balances at December 31, 2009

             260,482        260,482   

Net change in hedge derivative fair value, net of income taxes of $412

     40,818                40,818   

Net income

             35,111        35,111   

Net transfers to parent

             (17,577     (17,577

Balances at December 31, 2010

     40,818         278,016        318,834   

Net change in hedge derivative fair value, net of income taxes of $427

     37,946                37,946   

Net income

             59,610        59,610   

Net transfers to parent

             (45,481     (45,481

Balances at December 31, 2011

                   $ 78,764       $ 292,145      $ 370,909   

 

The accompanying notes are an integral part of these carve out financial statements.

 

F-20


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Notes to carve out financial statements

Note 1. Formation of the partnership and description of business

Quicksilver Production Partners LP, a Delaware limited partnership (“QPP” or the “Partnership”), was formed in November 2011 by Quicksilver Resources Inc. (“Quicksilver”) to acquire and develop oil and natural gas properties and to acquire, own, and operate related assets. Quicksilver currently owns all of the equity interests in QPP. QPP plans to pursue an initial public offering of its limited partner units (the “Offering”) during the second or third quarter of 2012.

Effective upon the closing of this offering, Quicksilver will contribute certain oil and natural gas properties (the “Partnership Properties”), certain commodity derivatives novated by Quicksilver and enter into a derivative with the economic effect of a specified derivative contract entered into between Quicksilver and an unaffiliated financial institution in exchange for a combination of QPP common, subordinated and general partner units and cash. The contribution will be accounted for as a combination of entities under common control, whereby the assets and liabilities contributed will be recorded based on the predecessor’s historical cost.

The Partnership Properties are located in Tarrant, Hood, Johnson, Hill and Somervell Counties in North Texas. As explained in Note 2 below, QPP Predecessor consists of a “carve out” of the Partnership Properties and the commodity derivatives from the consolidated financial statements of Quicksilver. QPP Predecessor is not now, and has never been, a separately identifiable legal entity from Quicksilver, nor has it operated independently from Quicksilver. After the closing of the Offering, Quicksilver will continue to own approximately 50% of the Partnership’s limited partner interests and 100% of the general partner interests.

Note 2. Summary of significant accounting policies

Basis of presentation

The accompanying carve out financial statements and related notes thereto represent the carve out financial position, results of operations, cash flows, and changes in owner’s equity of the Barnett Shale Assets and derivatives, referred to as QPP Predecessor. The carve out financial statements have been prepared in accordance with SEC rules and related staff accounting bulletins governing carve out financial statements. Certain expenses incurred by Quicksilver are only indirectly attributable to its ownership of the Barnett Shale Assets as Quicksilver owns interests in numerous other oil and natural gas properties in the Barnett Shale and elsewhere in North America. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such expenses to QPP Predecessor, so that the accompanying carve out financial statements reflect substantially all the costs attendant to QPP’s operations. A review of subsequent events was carried out through May 10, 2012, the date the financial statements were issued.

Use of estimates

Preparing financial statements requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during each reporting period. Management believes its estimates and assumptions are

 

F-21


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Notes to carve out financial statements—(continued)

 

reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from management’s estimates.

Significant estimates underlying these financial statements include the estimated quantities of proved natural gas, NGL and oil reserves (including the associated future net cash flows from those proved reserves) used to compute depletion expense and prepare the ceiling test for oil and gas properties. Revenue contains estimates based upon expectations for actual deliveries and prices received. Substantial judgment is also required to estimate the fair value of asset retirement obligations. Income taxes also involve the use of considerable judgment in the estimation and evaluation of deferred income tax assets and assessment of uncertain tax positions, although QPP is not subject to federal income taxes, so such deferred taxes and uncertain tax positions primarily relate to Texas franchise tax.

Cash

Quicksilver provides cash as needed to support operation of QPP Predecessor and collects cash from sales of its production. Consequently, the accompanying Carve Out Balance Sheets do not include any cash balances. Cash received or paid by Quicksilver on behalf of the QPP Predecessor is reflected as net transfers to parent on the accompanying Carve Out Statements of Owner’s Equity.

Hedging and derivatives

QPP Predecessor utilizes financial derivative instruments to mitigate risk associated with the prices received for its production. All derivatives are recognized as either an asset or liability on the balance sheet measured at their fair value determined by reference to published future market prices and interest rates. For derivatives instruments that qualify as cash flow hedges, the effective portions of gains and losses are deferred in accumulated other comprehensive income and recognized in revenue in the period in which the hedged transaction is recognized. Gains or losses on hedges terminated prior to their original expiration date are deferred and recognized as earnings during the period in which the hedged transaction is recognized. If it is probable the hedged transaction will not occur, the deferred gain or loss would be immediately recorded to earnings. Changes in value of ineffective portions of hedges, if any, are recognized currently as a component of other revenue. For derivatives that do not qualify as cash flow hedges, unrealized gains and losses attributable to future production months are recognized in the income statement.

Financial derivatives are entered into with counterparties who are lenders under Quicksilver’s Amended and Restated U.S. Credit Facility or entered into with Quicksilver through a derivative agreement that will provide QPP Predecessor with the economic effect of a specified derivative contract entered into between Quicksilver and an unaffiliated financial institution. Quicksilver’s Amended and Restated U.S. Credit Facility and internal credit policies require that any counterparties meet or exceed BBB- or Baa3 from Standard and Poor’s or Moody’s, respectively. The fair value for each derivative takes into consideration credit risk, whether it be QPP Predecessor’s counterparties’ or QPP Predecessor’s own. Derivatives are recorded in the balance sheet as current and non-current derivative assets and liabilities as determined by the expected timing of settlements.

 

F-22


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Notes to carve out financial statements—(continued)

 

Oil and gas properties

The accompanying carve out financial statements have been prepared using the full cost method of accounting for oil and gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in a country-wide cost center. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved oil and gas reserves. Excluded from amounts subject to depletion are costs associated with unevaluated properties.

Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations or the cost center ceiling. The cost center ceiling, which is measured each quarter, is defined as the sum of (1) estimated future net revenue, discounted at 10% per annum, from proved reserves, based on the unweighted average of the first-day-of-the-month prices for the preceding 12 months, adjusted to reflect local differentials and contract provisions, (2) the cost of properties not being amortized, (3) the lower of cost or market value of unproved properties included in the cost being amortized, less (4) income tax effects related to differences between the book and tax basis of the natural gas and oil properties. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required. Note 4 to these financial statements contains further discussion of the ceiling test.

To establish a value for its oil and gas properties at January 1, 2008, QPP Predecessor used the pro rata portion of the Standardized Measure of its proved reserves to Quicksilver’s to allocate the full cost pool of Quicksilver. Unevaluated costs were specifically identified in segregating costs to QPP Predecessor’s properties.

Asset retirement obligations

The fair value of asset retirement obligations is recorded in the period in which it is legally or contractually incurred. Upon initial recognition of the asset retirement liability, an asset retirement cost is capitalized by increasing the carrying amount of the asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost is recognized as expense through depletion over the asset’s useful life. Changes in the liability for the asset retirement obligations are recognized for (1) the passage of time and (2) revisions to either the timing or the amount of estimated cash flows. Accretion expense is recognized for the impacts of increasing the discounted fair value to its estimated settlement value.

 

F-23


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Notes to carve out financial statements—(continued)

 

Owner’s equity

QPP Predecessor was not a separate legal entity during the period covered by these carve out financial statements, therefore none of Quicksilver’s debt is directly attributable to QPP Predecessor’s ownership of the Barnett Shale Assets, and no formal intercompany financing arrangement related to the Barnett Shale Assets exists between Quicksilver and QPP Predecessor. Therefore, the change in net assets in each year that is not attributable to current period earnings is reflected as an increase or decrease to owner’s net equity for that year. Additionally, the accompanying carve out statements of income and comprehensive income do not include any allocation of interest expense incurred by Quicksilver as (i) it is impractical to unwind the elements of Quicksilver’s complex capital structure to determine what debt, if any, relates directly to the operations of the Predecessor, (ii) intercompany debt and related interest expense did not historically exist between Quicksilver and the QPP Predecessor and (iii) Quicksilver was able to develop the Partnership Properties with cash flows from its operations primarily due to high natural gas prices in 2007 and 2008.

Revenue recognition

Revenue is recognized when title to the products transfers to the purchaser. The “sales method” is employed to account for all production revenue, whereby revenue is recognized on all production sold to purchasers, regardless of whether the sales are proportionate to QPP Predecessor’s ownership in the property. A receivable or liability is recognized only to the extent that an imbalance on a specific property is greater than the expected remaining proved reserves.

Environmental compliance and remediation

Environmental compliance costs, including ongoing maintenance and monitoring, are expensed as incurred. Those environmental remediation costs which improve a property are capitalized.

Allocation of general and administrative costs incurred by Quicksilver

The accompanying carve out financial statements include allocations of costs for salaries and benefits, rent, accounting and legal services and other general and administrative expenses incurred by Quicksilver. These costs have been allocated to these carve out financials based on QPP Predecessor’s share of Quicksilver’s U.S. production as measured on a Mcfe basis. In management’s estimation, the allocation methodologies used are reasonable and result in an allocation of the cost of doing business borne by Quicksilver on behalf of QPP Predecessor; however, these allocations are not indicative of the cost of future operations or the amount of future allocations.

Stock-based compensation

The Partnership does not have its own employees nor has it granted any stock-based compensation. However, during the periods presented, a portion of the general and administrative (“G&A”) expenses allocated within these carve out financials was non-cash stock-

 

F-24


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Notes to carve out financial statements—(continued)

 

based compensation recorded on the books of Quicksilver. The allocated amount of stock-based compensation was $3.3 million, $5.1 million and $5.9 million for 2011, 2010 and 2009, respectively.

Income taxes

QPP Predecessor’s operations are currently included in the federal income tax return of Quicksilver which is subject to federal income taxes. Following the Offering, each partner of QPP will be separately taxed on its share of taxable income. Therefore, no provision for current or deferred federal income taxes has been provided for in the accompanying carve out financial statements. However, QPP Predecessor remains subject to the Texas franchise tax. Deferred tax liability and related income tax expense were recognized for the expected future tax effect of the Texas franchise tax assessed at 1% of taxable margin.

Segment reporting

QPP Predecessor has only one operating segment, the upstream development of oil and natural gas reserves. Additionally, all of QPP Predecessor’s properties are located in the U.S. and all of its production is derived from customers located in the U.S.

During 2011, Lone Star NGL Development LP and Targa Liquids Marketing and Trade each individually accounted for 17% of receipts for our production revenue. During 2010, Louis Dreyfus Energy Services LP and Targa Liquids Marketing and Trade individually accounted for 19% and 14%, respectively, of receipts for our production revenue. During 2009, Louis Dreyfus Energy Services LP, BG Energy Merchants LLC and Dynergy Liquids Marketing and Trade individually accounted for 19%, 11% and 16%, respectively, of receipts for our production revenue.

Earnings per unit

During the periods presented, QPP Predecessor’s assets were wholly owned by Quicksilver. Earnings per unit have not been presented because no units were outstanding.

Recently issued accounting standards

In January 2010, the FASB issued Accounting Standards Update 2010-03 (“ASU 2010-03”), Oil and Gas Reserve Estimations and Disclosures. This update aligns the current oil and natural gas reserve estimation and disclosure requirements of ASC Topic 932, Extractive Activities—Oil and Gas, with the requirements in the Securities and Exchange Commission’s final rule, Modernization of Oil and Gas Reporting Requirements (the “Final Rule”), which was issued on December 31, 2008 and was effective for the year ended December 31, 2009. The Final Rule was designed to modernize and update the oil and natural gas disclosure requirements to align with current practices and changes in technology.

In April 2010, the FASB issued ASU 2010-14, which amends the guidance on oil and natural gas reporting in Accounting Standards Codification 932.10.S99-1 by adding the Codification of SEC

 

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Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Notes to carve out financial statements—(continued)

 

Regulation S-X, Rule 4-10 as amended by the SEC Final Rule 33-8995. Both ASU 2010-03 and ASU 2010-14 are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments.

In January 2010, the FASB issued ASU 2010-06, “Improving Disclosures About Fair Value Measurements,” which provides amendments to fair value disclosures. ASU 2010-06 requires additional disclosures and clarifications of existing disclosures for recurring and nonrecurring fair value measurements. The revised guidance for transfers into and out of Level l and Level 2 categories, as well as increased disclosures around inputs to fair value measurement, was adopted January 1, 2010, with the amendments to Level 3 disclosures effective beginning after January 1, 2011. ASU 2010-06 concerns disclosure only. Both the current and future adoption does not have a material impact on our or our predecessor’s financial position or results of operations.

In 2012 the following pronouncements will impact our financial statements.

In June 2011, the FASB issued an amendment to accounting guidance to update the presentation of comprehensive income in consolidated financial statements. Under the amended guidance, the presentation of total comprehensive income, the components of net income, and the components of other comprehensive income may be made either in a single continuous statement of comprehensive income or in two separate but consecutive statements. This guidance will be effective for us beginning with the quarter ended March 31, 2012 and requires retrospective application to earlier periods presented.

In May 2011, the FASB issued an amendment to the accounting guidance for fair value measurement and disclosure. Among other things, the guidance expands the disclosure requirements around fair value measurements categorized in Level 3 of the fair value hierarchy and requires disclosure of the level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position but whose fair value must be disclosed. It also clarifies and expands upon existing requirements for measurement of the fair value of financial assets and liabilities as well as instruments classified in shareholders’ equity. This guidance will be effective for us beginning with the quarter ended March 31, 2012. The adoption of this accounting pronouncement is expected to require us to expand upon existing disclosures.

In December 2011, the FASB issued an amendment to the accounting guidance for the disclosure of arrangements that permit offsetting assets and liabilities. The amendment expands the disclosure requirements to require both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The amendment is effective for fiscal years, and interim periods within those years, beginning on or after January 1, 2013 and shall be applied retrospectively. We do not expect the adoption of this accounting pronouncement to have a material impact on our financial statements when implemented.

No other pronouncements materially affecting our financial statements have been issued.

 

F-26


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Notes to carve out financial statements—(continued)

 

Note 3. Derivatives and fair value measures

The following table details the estimated fair value of all derivative instruments where “Level 2” inputs are the basis of the derivative fair value estimates at December 31, 2011 and 2010:

 

      Asset Derivatives at
December 31,
     Liability Derivatives at
December 31,
 
             2011              2010              2011              2010  

 

  

 

 

    

 

 

    

 

 

    

 

 

 
            (in thousands)  

Level 2 inputs

   $ 79,967       $ 41,230       $ 364       $   

The fair value of all derivative instruments included in these disclosures was estimated using prices quoted in active markets for the periods covered by the derivatives and the value reported by counterparties. Estimates were determined by applying the net differential between the prices in each derivative and market prices for future periods to the amounts stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at the credit adjusted risk free rates.

As of December 31, 2011, QPP Predecessor had price swaps covering 30 Mmcfd of its anticipated natural gas production for 2012 through 2015 and 3 Mbbld of its anticipated natural gas liquid production for 2012. These price swaps were designated by Quicksilver as cash flow hedges.

The estimated fair value of QPP Predecessor’s derivative instruments were as follows:

 

      Asset Derivatives at
December 31,
     Liability Derivatives at
December 31,
 
     2011      2010      2011      2010  

 

  

 

 

    

 

 

    

 

 

    

 

 

 
                   (in thousands)  

Derivatives designated as hedges:

           

Commodity contracts reported in:

           

Current derivative assets

   $ 18,997       $ 15,660       $       $   

Noncurrent derivative assets

     34,461         25,570                   

Current derivative liabilities

                     364           

Noncurrent derivative liabilities

                               
  

 

 

 

Total derivatives designated as hedges

   $ 53,458       $ 41,230       $ 364       $   
      Asset Derivatives at
December 31,
     Liability Derivatives at
December 31,
 
     2011      2010      2011      2010  

 

  

 

 

    

 

 

    

 

 

    

 

 

 
                   (in thousands)  

Derivatives not designated as hedges:

           

Commodity contracts reported in:

           

Current derivative assets

   $ 10,078       $       $       $   

Noncurrent derivative assets

     16,431                           

Current derivative liabilities

                               

Noncurrent derivative liabilities

                               
  

 

 

 

Total derivatives not designated as hedges

   $ 26,509       $       $       $   

 

F-27


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Notes to carve out financial statements—(continued)

 

The changes in the net carrying value of QPP Predecessor’s derivatives for the year ended December 31, 2011 are presented below:

 

      2011     2010  
           (in thousands)  

Derivative fair value at beginning of period

   $ 41,230      $   

Net settlements reported in revenue

     (21,463       

Unrealized gains reported in other comprehensive income

     59,836        41,230   
  

 

 

 

Net derivative fair value at end of period

   $ 79,603      $ 41,230   

Gains from the effective portion of derivative assets held in accumulated other comprehensive income expected to be reclassified into earnings during 2012 would result in revenue of $28.4 million, net of income taxes.

At December 31, 2011, anticipated production in future years were less than the notional volume covered by derivatives for natural gas. A derivative that previously qualified as a cash flow hedge no longer met the requirements for hedge accounting. Future changes in the valuation of this derivative will be recognized in the Carve Out Statement of Income and Comprehensive Income, and the remaining net value at December 31, 2011 in accumulated other comprehensive income of $26.2 million will be ratably recognized into production revenue over the remaining term of the derivative.

We recognized a $2.0 million change in fair value for counterparty credit risk related to the derivative for which hedge accounting no longer applied.

Note 4. Oil and gas properties—full cost method

Oil and gas properties were as follows:

 

      December 31,  
     2011     2010  

 

 
     (in thousands)  

Oil and gas properties

    

Subject to depletion

   $ 846,273      $ 798,935   

Unevaluated properties

            2,794   

Accumulated depletion and impairment

     (539,808     (517,400
  

 

 

 

Total

   $ 306,465      $ 284,329   

Unevaluated properties not subject to depletion

 

       December 31, 2010   
     Unevaluated Costs Incurred During  
     2010      2009      2008      Prior      Total  

 

  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     (In thousands)  

Acquisition costs

   $ 25       $ 271       $ 772       $ 1,726       $ 2,794   

 

F-28


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Notes to carve out financial statements—(continued)

 

Full cost ceiling test and impairment

Pursuant to the ceiling test limitation prescribed by the SEC for companies using the full cost method of accounting, QPP Predecessor recorded a non-cash ceiling test impairment totaling $60 million in 2009. The impairment was a result of significant declines in natural gas and NGL prices.

Other matters

The depletion rate per Mcfe was $1.01, $0.87 and $1.15 for 2011, 2010 and 2009, respectively. Capitalized overhead costs that directly relate to exploration and development activities were $1.1 million, $0.6 million and $0.5 million for 2011, 2010 and 2009, respectively.

Note 5. Asset retirement obligations

The following table provides a reconciliation of the changes in the estimated asset retirement obligation from January 1, 2010 through December 31, 2011:

 

      December 31,  
     2011      2010  

 

 
     (in thousands)  

Beginning asset retirement obligations

   $ 3,962       $ 3,131   

Incremental liability incurred

     363         58   

Accretion expense

     221         174   

Change in estimates

     6,106         599   
  

 

 

 

Ending asset retirement obligations

   $ 10,652       $ 3,962   

The change in estimates for 2011 is primarily attributable to increased estimated costs to plug and abandon wells and retire equipment. The change in estimates for 2010 is primarily due to lower natural gas and NGL prices relative to prices at the beginning of 2010, which had the effect of shortening the economic life of certain wells and increasing what would otherwise have been the present value of future retirement obligations.

Note 6. Contingencies

QPP Predecessor’s activities are subject to potential claims and litigation in the normal course of operations. Quicksilver’s management does not believe that any liability resulting from any pending or threatened litigation will have a material effect on QPP Predecessor’s operations or financial results.

Note 7. Income taxes

No provision for federal or state income taxes is made in QPP Predecessor’s financial statements except for the Texas franchise tax which is an income tax assessed at the Quicksilver level because the taxable income or loss will be included in the income tax returns of the individual partners of the Partnership with the exception of Texas franchise taxes. The tables below present federal taxable income (loss) and net income (loss) on an unaudited pro forma basis.

 

F-29


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Notes to carve out financial statements—(continued)

 

A reconciliation between the statutory federal income tax rate and the pro forma effective income tax rate for QPP Predecessor’s income taxes that were included in the financial statements follows:

 

      Unaudited
Years Ended December 31,
 
     2011     2010     2009  

 

 

Statutory rate

     35.00     35.00     35.00

Permanent differences

     0.61     1.26     (0.81 )% 

State income tax, net of federal benefit

     1.12     1.52     (0.15 )% 
  

 

 

 

Pro forma effective tax rate

     36.73         37.78         34.04

The following table reconciles net income (loss) before income taxes to pro forma federal taxable income for the periods indicated (in thousands):

 

      Unaudited
Years Ended December 31,
 
     2011     2010     2009  

 

 

Net income (loss) before taxes

   $ 60,648      $ 35,949      $ (39,718

Permanent differences

     1,051        1,292        913   

Impairments

                   60,045   

Tax basis depreciation, depletion and amortization, net of financial reporting basis

     (53,592     (53,846     (37,266
  

 

 

 

Pro forma federal taxable income (loss)

   $ 8,107      $ (16,605   $ (16,026

QPP Predecessor’s financial reporting basis of its net fixed assets exceeded the tax basis of its net fixed assets by $248.0 million, $190.0 million and $132.9 million for 2011, 2010 and 2009, respectively.

The following details pro forma net income (loss) reflecting a tax provision calculated on a separate return basis for QPP Predecessor (in thousands):

 

      Unaudited
Years Ended December 31,
 
     2011     2010     2009  

 

 

Net income (loss) before taxes

   $ 60,648      $ 35,949      $ (39,718

Tax provision

     (22,276     (13,579     13,520   
  

 

 

 

Pro forma net income (loss)

   $ 38,372      $ 22,370      $ (26,198

Note 8. Accounts receivable

Accounts receivable consist solely of unpaid production revenue.

Note 9. Unaudited pro forma net income (loss) per limited partner unit

Unaudited pro forma net income (loss) per limited partner unit is determined by dividing the net income (loss) available to holders of common units, after deducting the general partner’s 0.1%

 

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Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Notes to carve out financial statements—(continued)

 

interest in net income (loss), by the number of common units and subordinated units expected to be outstanding at the closing of the Offering. All units were assumed to have been outstanding since January 1, 2009. Basic and diluted net income (loss) per unit are equivalent as there will be no dilutive units at the date of the closing of the Offering of the common units of the Partnership.

Note 10. Stock-based compensation

The following information regarding Quicksilver’s stock-based compensation is being provided in satisfaction of Staff Accounting Bulletin Topic 1.B.1. A portion of the amounts recognized by Quicksilver has been included in QPP Predecessor’s carve out financial statements.

Stock options

The following summarizes the values from and assumptions Quicksilver utilized for the Black-Scholes option pricing model:

 

      2011      2010      2009  

 

 

Weighted average grant date fair value

   $ 9.16       $ 9.88       $ 3.36   

Weighted average grant date

     Jan 3, 2011         Jan 4, 2010         Jan 2, 2009   

Weighted average risk-free interest rate

     2.38%         3.00%         1.90%   

Expected life (in years)

     6.0         6.0         6.0   

Weighted average volatility

     66.77%         66.76%         56.76%   

Expected dividends

                       

 

 

The following table summarizes Quicksilver’s stock option activity for 2011:

 

      Shares    

Wtd Avg
Exercise

Price

    

Wtd Avg

Remaining
Contractual
Life

    

Aggregate
Intrinsic

Value

 

 

    

 

 

 
                         (In thousands)  

Outstanding at January 1, 2011

     3,348,642      $ 11.10         

Granted

     834,970        14.88         

Exercised

     (209,221     6.21         

Cancelled

     (150,231     10.78         

Expired

     (63,464     23.62         
  

 

 

         

Outstanding at December 31, 2011

     3,760,696      $ 12.01         7.5       $ 922   
  

 

 

         

Exercisable at December 31, 2011

     1,815,782      $ 11.79         6.8       $ 597   

 

    

 

 

 

An estimated 3.7 million of Quicksilver stock options will become vested including those options already exercisable. These unexercised options have a weighted average exercise price of $12.03 and a weighted average remaining contractual life of 7.5 years.

Compensation expense related to stock options of $7.0 million, $6.7 million and $4.5 million was recognized by Quicksilver for 2011, 2010 and 2009, respectively. Cash received by Quicksilver

 

F-31


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Notes to carve out financial statements—(continued)

 

from the exercise of stock options totaled $1.3 million, $1.8 million and $4.0 million for the years 2011, 2010 and 2009, respectively. The total intrinsic value of Quicksilver options exercised during 2011, 2010 and 2009, was $1.2 million, $2.8 million and $4.3 million, respectively.

Restricted stock and restricted stock units

The following table summarizes Quicksilver’s restricted stock and stock unit activity for 2011:

 

      Payable in shares      Payable in cash  
     Shares     Wtd Avg
Grant Date
Fair Value
     Shares     Wtd Avg
Grant Date
Fair Value
 

 

   

 

 

 

Outstanding at January 1, 2011

     2,329,089      $ 11.27         372,633      $ 10.31   

Granted

     1,389,404        13.89         214,515        14.88   

Vested

     (1,115,235     12.17         (154,505     9.88   

Cancelled

     (142,958     12.23         (62,797     13.19   
  

 

 

      

 

 

   

Outstanding at December 31, 2011

     2,460,300      $ 12.29         369,846      $ 13.12   

 

   

 

 

 

At December 31, 2010, Quicksilver had unrecognized compensation cost related to outstanding unvested restricted stock and restricted stock units of $13.9 million. As of December 31, 2011, Quicksilver’s unrecognized compensation cost related to outstanding unvested restricted stock and restricted stock units was $17.3 million, which is expected to be recognized in expense over the next 2 years. Grants of restricted stock and restricted stock units by Quicksilver during 2011 had an estimated grant date fair value of $19.3 million. For 2011, 2010 and 2009, Quicksilver recognized compensation expense of $13.9 million, $13.3 million and $14.6 million, respectively. The total fair value of Quicksilver shares vested during 2011, 2010 and 2009 was $13.6 million, $16.4 million and $11.0 million, respectively.

Note 11. Supplemental oil and gas information (unaudited)

Oil and gas reserves

Proved oil and gas reserves estimates for QPP Predecessor’s assets, which are located entirely in the U.S. were prepared by independent petroleum engineers from Schlumberger Data & Consulting Services. The reserve reports were prepared in accordance with guidelines established by the SEC. Natural gas, NGL and oil prices used are the unweighted average of the first-day-of-the-month prices for the preceding 12 months, adjusted to reflect local differentials, without any escalation except in those instances where the sale of production was covered by contract, in which case the applicable contract prices, including fixed and determinable escalations, were used for the duration of the contract, and thereafter the unweighted 12-month average price was used. Operating cost, production and ad valorem taxes and future development cost were based on year-end costs with no escalation.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The following

 

F-32


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Notes to carve out financial statements—(continued)

 

reserve data represents estimates only and should not be construed as being exact. Moreover, the present values should not be construed as the current market value of QPP Predecessor’s natural gas and oil reserves or the costs that would be incurred to obtain equivalent reserves.

Changes in proved reserves for the three years ended December 31, 2011 were as follows:

 

      Natural gas
(Mmcf)
    NGL (Mbbl)     Oil (Mbbl)     Mmcfe  

 

   

 

 

 

December 31, 2008

     217,037        24,605        351        366,773   

Revisions(1)

     14,130        5,453        (43     46,590   

Extensions and discoveries

     12,540        1,631        19        22,440   

Production

     (17,651     (2,404     (156     (33,011
  

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2009

     226,056        29,285        171        402,792   

Revisions(1)

     (960     1,864        35        10,434   

Extensions and discoveries

     15,298        2,647        38        31,408   

Purchases in place(2)

     9,806                      9,806   

Production

     (12,727     (1,814     (78     (24,079
  

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2010

     237,473        31,982        166        430,361   

Revisions(1)

     (35,630     (2,988     4        (53,533

Extensions and discoveries

     6,368        1,170        32        13,580   

Production

     (12,440     (1,565     (53     (22,149
  

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2011

     195,771        28,599        149        368,259   

 

   

 

 

 

 

(1)   Revisions for each period presented reflect upward (downward) changes in previous estimates attributable to changes in operating and development costs, new information gained primarily from development drilling activity and production history and changes to development plans. Revisions include (43,400) Mmcfe, (12,700) Mmcfe and 74,100 Mmcfe for such matters in 2011, 2010 and 2009, respectively. Revisions also include (10,100) Mmcfe, 23,200 Mmcfe and (27,500) Mmcfe for changes in sales price in 2011, 2010 and 2009.

 

(2)   Purchases of reserves in place were related to the acquisition of additional working interests in certain wells in which QPP Predecessor already held working interests.

Estimated net quantities of proved oil and natural gas reserves of QPP Predecessor were as follows as of the dates indicated:

 

      Natural gas
(Mmcf)
     NGL (Mbbl)      Oil (Mbbl)      Mmcfe  

 

    

 

 

 

Proved developed reserves

           

December 31, 2008

     180,111         21,326         314         309,951   

December 31, 2009

     192,800         25,618         132         347,300   

December 31, 2010

     192,758         25,374         86         345,514   

December 31, 2011

     169,458         24,439         93         316,649   

Proved undeveloped reserves

           

December 31, 2008

     36,926         3,279         37         56,822   

December 31, 2009

     33,256         3,667         39         55,492   

December 31, 2010

     44,715         6,608         80         84,847   

December 31, 2011

     26,313         4,160         56         51,610   

 

    

 

 

 

 

F-33


Table of Contents
Index to Financial Statements

Quicksilver Production Partners LP Predecessor

Notes to carve out financial statements—(continued)

 

Capitalized costs and costs incurred relating to oil and natural gas producing activities

The carrying value of oil and natural gas properties was as follows as of the dates indicated:

 

      2011     2010     2009  

 

 
     (in thousands)  

Properties and equipment—full cost method:

      

Proved properties

   $ 846,273      $ 798,935      $ 756,863   

Unevaluated properties

            2,794        2,794   

Accumulated depletion and impairment

     (539,808     (517,400     (496,523
  

 

 

   

 

 

   

 

 

 

Net capitalized costs

   $ 306,465      $ 284,329      $ 263,134   

 

 

The following table summarizes the capital costs incurred as of the dates indicated:

 

      2011      2010      2009  

 

 
     (in thousands)  

Proved acreage

   $       $ 9,179       $   

Development costs

     37,530         30,635         41,882   
  

 

 

    

 

 

    

 

 

 

Total

   $ 37,530       $ 39,814       $ 41,882   

 

 

The following table summarizes results of operations of QPP Predecessor’s proved properties:

 

      2011      2010      2009  

 

 
     (in thousands)  

Production revenue

   $ 151,468       $ 127,915       $ 142,024   

Operating expense

     57,232         58,527         67,587   

Depletion and accretion

     22,629         21,050         37,978   

Impairment expense

                     60,045   
  

 

 

    

 

 

    

 

 

 
     71,607         48,338         (23,586

Income tax expense

     1,038         838         86   
  

 

 

    

 

 

    

 

 

 

Results from producing activities

   $ 70,569       $ 47,500       $ (23,672

 

 

Standardized Measure

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) do not purport to present the fair market value of QPP Predecessor’s oil and gas properties. An estimate of such value should consider, among other factors, anticipated future commodity prices, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, estimated future capital and operating costs and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision.

Under the Standardized Measure, future cash inflows were estimated by applying the unweighted average of the preceding 12-month first-day-of-the-month prices, adjusted for

 

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Quicksilver Production Partners LP Predecessor

Notes to carve out financial statements—(continued)

 

contracts with price floors but excluding hedges, and unescalated year-end costs to the estimated future production of the year-end reserves. These prices have varied widely and have a significant impact on both the quantities and value of the proved reserves as reduced prices cause wells to reach the end of their economic life much sooner and also make certain proved undeveloped locations uneconomical, both of which reduce reserves. The following representative prices were used in the Standardized Measure and were adjusted by field for appropriate regional differentials:

 

      December 31,  
     2011      2010      2009  

 

 

Natural gas—Henry Hub (per Mmbtu)

   $ 4.12       $ 4.38       $ 3.87   

NGL—Mont Belvieu (per Bbl)

   $ 47.16       $ 37.56       $ 24.94   

Oil—WTI Cushing (per Bbl)

   $ 95.71       $ 79.43       $ 61.18   

 

 

Future cash inflows were reduced by estimated future production and development costs based on year-end costs and held constant to determine pre-tax cash inflows. Consistent with the presentation on the Carve Out Income Statement, future federal income taxes have not been deducted from future net revenue in the calculation of the Partnership’s Standardized Measure, as the operations of QPP Predecessor are currently included in the federal income tax return of Quicksilver. Following the initial public offering of the Partnership, Quicksilver Production Partners LP will be treated as a partnership with each partner being separately taxed on its share of the Partnership’s taxable income. Future net cash inflows after Texas franchise taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.

The Standardized Measure at December 31, 2011, 2010 and 2009 was as follows:

 

      December 31,  
     2011     2010     2009  

 

 
     (in thousands)  

Future revenue

   $ 2,074,461      $ 2,157,679      $ 1,515,697   

Future production costs

     (1,055,065     (1,035,574     (859,334

Future development costs

     (124,501     (142,674     (92,004

Future income taxes

     (7,116     (8,849     (4,356
  

 

 

   

 

 

   

 

 

 

Future net cash flows

     887,779        970,582        560,003   

10% discount

     (477,920     (559,242     (304,456
  

 

 

   

 

 

   

 

 

 

Standardized Measure of discounted future cash flows relating to proved reserves

   $ 409,859      $ 411,340      $ 255,547   

 

 

 

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Quicksilver Production Partners LP Predecessor

Notes to carve out financial statements—(continued)

 

The primary changes in the Standardized Measure of discounted estimated future net cash flows were as follows for 2011, 2010, and 2009:

 

      Years ended December 31,  
     2011     2010     2009  

 

 
     (in thousands)  

Standardized Measure, beginning of year

   $ 411,340      $ 255,547      $ 333,876   

Sales of oil and gas net of production cost

     (72,773     (69,388     (74,438

Net changes in price and production cost

     33,547        183,159        (58,441

Extensions and discoveries

     16,114        6,391        18,283   

Previously estimated development costs incurred during the year

     21,784        20,570        2,506   

Changes in estimated future development costs

     6,639        (49,539     1,728   

Purchase and sale of reserves, net

            6,222          

Revisions of estimates

     (70,188     34,851        30,396   

Accretion of discount

     41,485        25,718        33,588   

Net change in income taxes

     583        (5,138     372   

Timing and other differences

     21,328        2,947        (32,323
  

 

 

 

Standardized Measure, end of year

   $ 409,859      $ 411,340      $ 255,547   

 

 

 

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Appendix A

Form of First Amended and Restated Agreement of Limited Partnership of Quicksilver Production Partners LP

 

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Appendix B

Glossary of terms

The following includes a description of the meanings of some of the oil and gas industry and other terms used in this prospectus.

Definitions

As used in this prospectus unless the context otherwise requires:

 

“Bbl”

   means a stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

“Bbld”

   means Bbl per day.

“Bcf”

   means billion cubic feet of natural gas.

“Bcfe”

   means billion cubic feet of natural gas equivalents.

“Btu”

   means a British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit, and one million Btu is approximately equal to an Mcf of dry natural gas.

“CFTC”

   means Commodities Futures Trading Commission.

“Code”

   means the Internal Revenue Code of 1986, as amended.

“Crestwood”

   means Crestwood Midstream Partners LP (formerly known as Quicksilver Gas Services LP).

“Dodd-Frank Act”

   means the Dodd-Frank Wall Street Reform and Consumer Protection Act.

“EPA”

   means the U.S. Environmental Protection Agency.

“Exchange Act”

   means the U.S. Securities Exchange Act of 1934, as amended.

“GAAP”

   means accounting principles generally accepted in the United States.

“GHG”

   means greenhouse gas.

“IRS”

   means the U.S. Internal Revenue Service.

“Mbbl”

   means thousand Bbl.

“Mbbld”

   means thousand Bbl per day.

“Mcf”

   means thousand cubic feet of natural gas.

“Mcfe”

   means one thousand cubic feet of natural gas equivalents, which equals one Bbl of oil or NGL equaling six Mcf of natural gas. This is a physical correlation of energy content and does not reflect a value or price relationship between the commodities.

“Mmbtu”

   means million Btu.

“Mmcf”

   means million cubic feet of natural gas.

“Mmcfd”

   means million cubic feet of natural gas per day.

“Mmcfe”

   means million cubic feet of natural gas equivalents.

“Mmcfed”

   means million cubic feet of natural gas equivalents per day.

“net production”

   means working interest production less royalties.

“net revenue interest”

   means working interest less royalties.

“NGL” or “NGLs”

   means natural gas liquids.

“NYMEX”

   means the New York Mercantile Exchange.

“NYSE”

   means the New York Stock Exchange.

“oil”

   means oil and condensate.

 

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“OPEC”

   means the Organization of Petroleum Exporting Countries.

“proved developed reserves”

   means proved reserves that can be expected to be recovered from existing wells using existing equipment and operating methods.

“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. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) 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. 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. 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. 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 (i) 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 (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. 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 twelve-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.

 

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“proved undeveloped reserves”

   means proved oil and natural gas 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 drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. 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 been proved effective by actual tests in the area and in the same reservoir.

“realized price”

   means the cash market price received.

“recompletion”

   means the completion for production of an existing wellbore in another formation from that which the well has been previously completed.

“reservoir”

   means a porous and permeable underground formation containing an accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

“SEC”

   means the U.S. Securities and Exchange Commission.

“Securities Act”

   means U.S. Securities Act of 1933, as amended.

“Standardized Measure”

   means the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue.

“Tcfe”

   means trillion cubic feet of natural gas equivalents.

“unitization”

   means the process of obtaining approval from working interest owners, mineral owners and regulatory agencies to conduct operations across lease lines.

“wellbore assignment”

  

means an assignment covering all of the grantor’s rights, title and interest in and to (i) all casing, tubing, surface equipment and all other surface and subsurface material and equipment used directly and solely for the operation of a well, and (ii) all oil, natural gas and related hydrocarbons and fluids that may be produced from a well.

“working interest”

   means the cost-bearing operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production.

“workover”

   means operations on a producing well to restore or increase production.

“WTI”

   means West Texas Intermediate crude oil that is used as a benchmark for oil prices in the United States.

 

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Appendix C

Summary reserve reports

 

Data & Consulting Services

Division of Schlumberger Technology Corporation

 

Two Robinson Plaza, Suite 200

Pittsburgh, PA 15205

Tel: 412-787-5403

Fax: 412-787-2906

  LOGO

22 February 2012

Quicksilver Production Partners LP

801 Cherry Street

Suite 3700, Unit 19

Fort Worth, Texas 76102

Dear Gentlemen:

At the request of Quicksilver Production Partners LP (QPP), through their letter of engagement, Data & Consulting Services (DCS) Division of Schlumberger Technology Corporation has evaluated the proved reserves of certain QPP oil and gas interests located in the United States (U.S.) as of 31 December 2011. All evaluated properties are located in Texas, operated by QPP, and are productive in the Barnett Shale. This report was completed as of the date of this letter and has been prepared using constant prices and costs and conforms to our understanding of the U.S. Securities and Exchange Commission (SEC) guidelines and applicable financial accounting rules. All prices, costs, and cash flow estimates are expressed in U.S. dollars (US$). It is our understanding that the properties evaluated by DCS comprise one hundred percent (100%) of QPP’s proved reserves. We believe that the assumptions, data, methods, and procedures used in preparing this report are appropriate for the purpose of this report. The Lead Evaluator for this evaluation was Charles M. Boyer II, PG, CPG, and his qualifications, independence, objectivity, and confidentiality meet the requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

 

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Table 1 summarizes the estimates of the net reserves and future net revenue, as of 31 December 2011, for the evaluated properties. Unescalated prices and costs were used for all properties contained in this evaluation.

Table 1

Estimated Net Reserves And Income

Certain Proved Oil And Gas Interests

Unescalated Prices And Costs

Quicksilver Production Partners LP

As Of 31 December 2011

 

     

Proved

Producing

Reserves

    

Proved

Nonproducing

Reserves

    

Proved

Undeveloped

Reserves

   

Total

Proved

Reserves

 

 

 

Remaining Net Reserves

          

Oil—MMbbls

     0.076         0.017         0.056        0.149   

Gas—Bscf

     159.447         10.012         26.313        195.771   

NGL—MMbbls

     23.124         1.315         4.160        28.599   

Income Data (MM$)

          

Future Net Revenue

     1,677.198         99.683         297.580        2,074.461   

Deductions

          

Operating Expense

     745.907         37.283         129.548        912.738   

Production Taxes

     116.086         6.419         19.822        142.327   

Investment

     0.15         10.248         90.947        101.345   

Abandonment

     21.68         0.233         1.242        23.156   

Future Net Cashflow

     793.375         45.500         56.020        894.895   

Discounted PV @ 10% (MM$)

     399.760         18.364         (5.341     412.783   

 

 

Note: Proved producing reserves include Inactive and Salt Water Disposal well costs.

Values in the tables of this report may not add up arithmetically due to rounding procedure in the computer software program used to prepare the economic projections. All hydrocarbon liquids are reported as 42 gallon barrels. Gas volumes are reported at the standard pressure and temperature bases of the area where the gas is sold.

We are independent with respect to QPP as provided in the SEC regulations. Neither the employment of nor the compensation received by DCS was contingent upon the values estimated for the properties included in this report.

Oil and gas reserves by definition fall into one of the following categories: proved, probable, and possible. The proved category is further divided into: developed and undeveloped. The developed reserve category is even further divided into the appropriate reserve status subcategories: producing and non-producing. Non-producing reserves include shut-in and behind-pipe reserves. The reserves included in this report include only proved reserves and do not include probable or possible reserves. QPP has an active exploration and development program to develop their interests in certain tracts not classified as proved at this time. Future drilling may

 

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result in the reclassification of additional volumes to the proved reserve category. However, changes in the regulatory requirements for oil and gas operations may impact future development plans and the ability of the company to recover the estimated proved undeveloped reserves. The reserves and income attributable to the various reserve categories included in this report have not been adjusted to reflect the varying degrees of risk associated with them.

Reserve estimates are strictly technical judgments. The accuracy of any reserve estimate is a function of the quality and quantity of data available and of the engineering and geological interpretations. The reserve estimates presented in this report are believed reasonable; however, they are estimates only and should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify their revision. A portion of these reserves are for undeveloped locations and producing or non-producing wells that lack sufficient production history to utilize conventional performance-based reserve estimates. In these cases, the reserves are based on volumetric estimates and recovery efficiencies along with analogies to similar producing areas. These reserve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data. As additional production and pressure data becomes available, these estimates may be revised up or down. Actual future prices may vary significantly from the prices used in this evaluation; therefore, future hydrocarbon volumes recovered and the income received from these volumes may vary significantly from those estimated in this report. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

Standard geological and engineering methods generally accepted by the petroleum industry were used in the estimation of QPP’s reserves. Deterministic methods were used for all reserves included in this report. The appropriate combination of conventional decline curve analysis (DCA), production data analysis, volumetrics, and type curves were used to estimate the remaining reserves in the various producing areas. Volumetric calculations were based on data and maps provided by QPP. Comparisons were made to similar properties for which more complete data were available for areas of new development.

All prices used in preparation of this report were based on the twelve month unweighted arithmetic average of the first day of the month price for the period January through December 2011. The resulting Henry Hub gas price used was $4.120/MMBtu and the resulting West Texas Intermediate oil price used was $95.71/Bbl. The prices were adjusted for local differentials, gravity and Btu where applicable. These adjustments are made for each well based on the differences between the actual product prices received by well and the reference prices over a twelve month period. The resulting average prices in this evaluation are $3.64/Mscf for gas, $91.01/Bbl for oil and $47.16/BBl for NGL. The average prices were calculated using the total net future revenue by product prior to taxes and expenses divided by the total net reserves by product. As required by SEC guidelines, all pricing was held constant for the life of the projects (no escalation).

Operating costs used in this report were based on values reported by QPP and reviewed by DCS. Well costs include direct expenses, allocated general and administrative overhead (G&A), production taxes, marketing, transportation, and compression charges. QPP’s estimates for

 

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capital costs for all non-producing and undeveloped wells are included in the evaluation. QPP has indicated to us that they have the ability and intent to implement their capital expenditure program as scheduled. Operating costs and capital costs were held constant for the life of the projects (no escalation).

Net revenue (sales) is defined as the total proceeds from the sale of oil, condensate, natural gas liquids (NGL), and gas adjusted for commodity price basis differential and gathering/ transportation expense. Future net income (cashflow) is future net revenue less net lease operating expenses, state severance or production taxes, operating/development capital expenses and net salvage. Future net income (cashflow) for nonoperated wells includes those general and administrative (G&A) deductions charged by the operator for a particular well or project on a monthly basis; operated well G&A deductions include only those expenses estimated as necessary to continue production activities. Future plugging, abandonment, and salvage costs are included at the economic life of each well or unit. No provisions for State or Federal income taxes have been made in this evaluation. The present worth (discounted cashflow) at various discount rates is calculated on a monthly basis.

In the conduct of our evaluation, we have not independently verified the accuracy and completeness of information and data furnished by QPP with respect to ownership interests, historical gas production, costs of operation and development, product prices, payout balances, and agreements relating to current and future operations and sales of production. If in the course of our examination something came to our attention which brought into question the validity or sufficiency of any of the information or data provided by QPP, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or independently verified such information or data.

In our opinion the above-described estimates of QPP’s proved reserves and supporting data are, in the aggregate, reasonable. It is also our opinion that the above-described estimates of QPP’s proved reserves conform to the definitions of proved oil and gas reserves promulgated by the SEC. These reserves definitions are provided at the conclusion of this letter.

All data used in this study were obtained from QPP, public industry information sources, or the non-confidential files of DCS. A field inspection of the properties was not made in connection with the preparation of this report. The potential environmental liabilities attendant to ownership and/or operation of the properties have not been addressed in this report. Abandonment and clean-up costs and possible salvage value of the equipment were considered in this report.

In evaluating the information at our disposal related to this report, we have excluded from our consideration all matters which require a legal or accounting interpretation, or any interpretation other than those of an engineering or geological nature. In assessing the conclusions expressed in this report pertaining to all aspects of oil and gas evaluations, especially pertaining to reserve evaluations, there are uncertainties inherent in the interpretation of engineering data, and such conclusions represent only informed professional judgments.

Data and worksheets used in the preparation of this evaluation will be maintained in our files in Pittsburgh and will be available for inspection by anyone having proper authorization from QPP.

 

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We appreciate the opportunity to perform this evaluation and are available should you need further assistance in this matter.

Sincerely yours,

 

/s/ Denise L. Delozier

   

/s/ Charles M. Boyer II

Denise L. Delozier     Charles M. Boyer II, PG, CPG
Senior Engineer     Advisor—Unconventional Reservoirs
   

Pittsburgh GPE Manager

/s/ Walter K. Sawyer

   
Walter K. Sawyer, PE    
Principal Consultant    

 

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SECURITIES AND EXCHANGE COMMISSION

REGULATION S-X, RULE 210.4-10 (a)

RESERVES DEFINITIONS

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) 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

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

 

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(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

 

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(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas 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

 

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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

(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.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological,

 

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geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are 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.

Note to paragraph (a)(26): 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).

(27) 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.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas 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.

(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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

 

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Index to Financial Statements

Reserve and Economic Evaluation Of

Proved Reserves

Of Certain Quicksilver Production Partners LP

Oil, Gas, And Hedge Interests

As Of 31 December 2010

Executive Summary

Prepared For

Quicksilver Production Partners LP

Fort Worth, Texas

Prepared By

Schlumberger Data & Consulting Services

Pittsburgh, Pennsylvania

November 2011

 

 

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Data & Consulting Services

Division of Schlumberger Technology Corporation

 

Two Robinson Plaza, Suite 200

Pittsburgh, PA 15205

Tel: 412-787-5403

Fax: 412-787-2906

  LOGO

11 November 2011

Quicksilver Production Partners LP

801 Cherry Street

Suite 3700, Unit 19

Fort Worth, Texas 76102

Dear Gentlemen:

At the request of Quicksilver Production Partners LP (Quicksilver LP), through their letter of engagement, Data & Consulting Services (DCS) Division of Schlumberger Technology Corporation has evaluated the proved reserves of certain Quicksilver LP oil and gas interests located in the United States (U.S.) as of 31 December 2010. All evaluated properties are located in Texas, operated by Quicksilver LP, and are productive in the Barnett Shale. This report was completed as of the date of this letter and has been prepared using constant prices and costs and conforms to our understanding of the U.S. Securities and Exchange Commission (SEC) guidelines and applicable financial accounting rules. All prices, costs, and cash flow estimates are expressed in U.S. dollars (US$). It is our understanding that the properties evaluated by DCS comprise one hundred percent (100%) of Quicksilver LP’s proved reserves. We believe that the assumptions, data, methods, and procedures used in preparing this report are appropriate for the purpose of this report. The Lead Evaluator for this evaluation was Charles M. Boyer II, PG, CPG, and his qualifications, independence, objectivity, and confidentiality meet the requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

 

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The results of the Proved reserve evaluation are summarized in Table 1. Fig. 1 illustrates the distribution by Proved reserve category for the present value at a 10% discount rate (PV10).

Table 1

Estimated net reserves and income

certain proved oil and gas interests

unescalated prices and costs

Quicksilver Production Partners LP

as of 31 December 2010

 

     

Proved

producing

reserves

    

Proved

nonproducing

reserves

    

Proved

undeveloped

reserves

    

Total

proved

reserves

 

 

 

Remaining Net Reserves

           

Oil—Mbbls

     72.9         12.8         80.1         165.7   

Gas—MMscf

     177,242.7         15,515.2         44,714.6         237,472.5   

NGL—Mbbls

     24,571.0         802.7         6,608.5         31,982.2   

Income Data (M$)

           

Future Net Revenue

     1,633,536.3         90,892.5         433,250.7         2,157,679.5   

Deductions

           

Operating Expense

     675,199.1         42,977.3         172,405.0         890,581.5   

Production Taxes

     109,680.3         6,179.3         29,132.9         144,992.5   

Investment

     0.0         7,573.2         123,970.4         131,543.6   

Abandonment

     9,111.6         349.5         1,669.6         11,130.7   

Future Net Cashflow

     839,545.2         33,813.3         106,072.8         979,431.3   

Discounted PV @ 10% (M$)

     398,232.7         15,780.3         835.4         414,848.3   

 

 

Note: Proved producing reserves include Inactive and Salt Water Disposal well costs.

 

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Fig. 1—

  Present value distribution by Proved reserve category—calculated using a 10% discount rate (MM$), unescalated prices and costs.

The values in the table above may not add up arithmetically or exactly match the attached cash flows due to rounding procedures in the computer software program used to prepare the economic projections. Cash flows summarized by reserve category and state are included in the attachments of this report. Well count summaries are not accurate in several of the attached cash flows. Many proved non-producing wells are counted in the current proved producing well counts.

Reserves estimates

Standard geological and engineering methods generally accepted by the petroleum industry were used in the estimation of Quicksilver LP’s reserves. Deterministic methods were used for all reserves included in this report. The appropriate combination of conventional decline curve analysis (DCA), production data analysis, volumetrics, and type curves were used to estimate the remaining reserves. Volumetric calculations were based on data and maps provided by Quicksilver LP. Comparisons were made to similar properties for which more complete data were available for areas of new development.

Reserve estimates are strictly technical judgments. The accuracy of any reserve estimate is a function of the quality and quantity of data available and of the engineering and geological interpretations. The reserve estimates presented in this report are believed reasonable; however,

 

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they are estimates only and should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify their revision. A portion of these reserves are for undeveloped locations and producing or non-producing wells that lack sufficient production history to utilize conventional performance-based reserve estimates. In these cases, the reserves are based on volumetric estimates and recovery efficiencies along with analogies to similar producing areas. These reserve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data. As additional production and pressure data becomes available, these estimates may be revised up or down. Actual future prices may vary significantly from the prices used in this evaluation; therefore, future hydrocarbon volumes recovered and the income received from these volumes may vary significantly from those estimated in this report. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

Reserve categories

Reserves were assigned to the proved developed producing (PDP), proved developed non-producing (PDNP), and proved undeveloped (PUD) reserve categories. Oil and gas reserves by definition fall into one of the following categories: proved, probable, and possible. The proved category is further divided into: developed and undeveloped. The developed reserve category is even further divided into the appropriate reserve status subcategories: producing and non-producing. Non-producing reserves include shut-in and behind-pipe reserves. The reserves evaluated in this report conform to the U.S. Securities and Exchange Commission Regulation S-X, Rule 210.4-10 (a). These reserve definitions are presented in the Reserve Definitions section of this report.

In our opinion the above-described estimates of Quicksilver LP’s reserves and supporting data are, in the aggregate, reasonable. It is also our opinion that the above-described estimates of Quicksilver LP’s proved reserves conform to the definitions of proved oil and gas reserves promulgated by the SEC.

Quicksilver LP has an active exploration and development program to develop their interests in certain tracts not classified as proved at this time. Future drilling may result in the reclassification of additional volumes to the proved reserve category. However, changes in the regulatory requirements for oil and gas operations may impact future development plans and the ability of the company to recover the estimated proved undeveloped reserves. The reserves and income attributable to the various reserve categories included in this report have not been adjusted to reflect the varying degrees of risk associated with them.

Economic terms

Net revenue (sales) is defined as the total proceeds from the sale of oil, condensate, natural gas liquids (NGL), and gas adjusted for commodity price basis differential and gathering/ transportation expense. Future net income (cashflow) is future net revenue less net lease operating expenses, state severance or production taxes, operating/development capital expenses and net salvage. Future net income (cashflow) for nonoperated wells includes those general and administrative (G&A) deductions charged by the operator for a particular well or project on a

 

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monthly basis; operated well G&A deductions include only those expenses estimated as necessary to continue production activities. Future plugging, abandonment, and salvage costs are included at the economic life of each well or unit. No provisions for State or Federal income taxes have been made in this evaluation. The present worth (discounted cashflow) at various discount rates is calculated on a monthly basis.

Pricing and economic parameters

All product prices, costs, and economic parameters used in this report were supplied by Quicksilver LP and reviewed by DCS. Data from Quicksilver LP were accepted as presented. All prices used in preparation of this report were based on the twelve month unweighted arithmetic average of the first day of the month price for the period January through December 2010. The resulting Henry Hub gas price used was $4.380/MMBtu and the resulting West Texas Intermediate oil price used was $79.43/Bbl. The prices were adjusted for local differentials, gravity and Btu where applicable. As required by SEC guidelines, all pricing was held constant for the life of the projects (no escalation). Quicksilver LP’s estimates for capital costs for all non-producing and undeveloped wells are included in the evaluation. Quicksilver LP has indicated to us that they have the ability and intent to implement their capital expenditure program as scheduled.

Future plugging and abandonment, net of salvage costs, were added at the economic life of each well or project. The costs are based on estimated plugging costs by area. The addition of plugging costs to the properties reduces both the total proved undiscounted cash flow and the present worth value discounted at 10% by $11,130.7M and $1,426.3M respectively. The cash flow summaries by reserve category excluding the plugging and salvage are included in the No Abandonment section of this report.

Ownership

The leasehold interests were supplied by Quicksilver LP and were accepted as presented. No attempt was made by the undersigned to verify the title or ownership of the interests evaluated.

General

All data used in this study were obtained from Quicksilver LP, public industry information sources, or the non-confidential files of DCS. A field inspection of the properties was not made in connection with the preparation of this report.

The potential environmental liabilities attendant to ownership and/or operation of the properties have not been addressed in this report. Abandonment and clean-up costs and possible salvage value of the equipment were considered in this report.

In the conduct of our evaluation, we have not independently verified the accuracy and completeness of information and data furnished by Quicksilver LP with respect to ownership interests, historical gas production, costs of operation and development, product prices, payout balances, and agreements relating to current and future operations and sales of production. If in the course of our examination something came to our attention which brought into question the

 

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validity or sufficiency of any of the information or data provided by Quicksilver LP, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or independently verified such information or data.

In evaluating the information at our disposal related to this report, we have excluded from our consideration all matters which require a legal or accounting interpretation, or any interpretation other than those of an engineering or geological nature. In assessing the conclusions expressed in this report pertaining to all aspects of oil and gas evaluations, especially pertaining to reserve evaluations, there are uncertainties inherent in the interpretation of engineering data, and such conclusions represent only informed professional judgments.

We are independent with respect to Quicksilver LP as provided in the SEC regulations. Neither the employment of nor the compensation received by DCS was contingent upon the values estimated for the properties included in this report.

Data and worksheets used in the preparation of this evaluation will be maintained in our files in Pittsburgh and will be available for inspection by anyone having proper authorization by Quicksilver LP.

We appreciate the opportunity to perform this evaluation and are available should you need further assistance in this matter.

Sincerely yours,

 

/s/ Denise L. Delozier     /s/ Charles M. Boyer II
Denise L. Delozier     Charles M. Boyer II, PG, CPG
Senior Engineer     Consulting Services Manager—NE Basin
    Advisor—Unconventional Reservoirs
/s/ Walter K. Sawyer    
Walter K. Sawyer, PE    
Principal Consultant    

 

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Reserves definitions

 

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SECURITIES AND EXCHANGE COMMISSION

REGULATION S-X, RULE 210.4-10 (a)

RESERVES DEFINITIONS

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) 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

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

 

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(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

 

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(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas 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

 

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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

(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.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

 

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(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are 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.

Note to paragraph (a)(26): 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).

(27) 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.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas 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.

(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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

 

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Index to Financial Statements

Reserve and Economic Evaluation Of

Proved Reserves

Of Certain Quicksilver Production Partners LP

Oil And Gas Interests

As Of 31 December 2009

Executive Summary

Prepared For

Quicksilver Production Partners LP

Fort Worth, Texas

Prepared By

Schlumberger Data & Consulting Services

Pittsburgh, Pennsylvania

November 2011

 

 

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Table of Contents
Index to Financial Statements

Data & Consulting Services

Division of Schlumberger Technology Corporation

 

Two Robinson Plaza, Suite 200

Pittsburgh, PA 15205

Tel: 412-787-5403

Fax: 412-787-2906

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12 December 2011

Quicksilver Production Partners LP

801 Cherry Street

Suite 3700, Unit 19

Fort Worth, Texas 76102

Dear Gentlemen:

At the request of Quicksilver Production Partners LP (Quicksilver LP), through their letter of engagement, Data & Consulting Services (DCS) Division of Schlumberger Technology Corporation has evaluated the proved reserves of certain Quicksilver LP oil and gas interests located in the United States (U.S.) as of 31 December 2009. All evaluated properties are located in Texas, operated by Quicksilver LP, and are productive in the Barnett Shale. This report was completed as of the date of this letter and has been prepared using constant prices and costs and conforms to our understanding of the U.S. Securities and Exchange Commission (SEC) guidelines and applicable financial accounting rules. All prices, costs, and cash flow estimates are expressed in U.S. dollars (US$). It is our understanding that the properties evaluated by DCS comprise one hundred percent (100%) of Quicksilver LP’s proved reserves. We believe that the assumptions, data, methods, and procedures used in preparing this report are appropriate for the purpose of this report. The Lead Evaluator for this evaluation was Charles M. Boyer II, PG, CPG, and his qualifications, independence, objectivity, and confidentiality meet the requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

 

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The results of the Proved reserve evaluation are summarized in Table 1. Fig. 1 illustrates the distribution by Proved reserve category for the present value at a 10% discount rate (PV10).

Table 1

Estimated net reserves and income

certain proved oil and gas interests

unescalated prices and costs

Quicksilver Production Partners LP

as of 31 December 2009

 

      Proved
producing
reserves
     Proved
nonproducing
reserves
     Proved
undeveloped
reserves
   

Total

proved
reserves

 

 

  

 

 

    

 

 

    

 

 

   

 

 

 

Remaining Net Reserves

          

Oil—Mbbls

     112.8         19.2         39.3        171.3   

Gas—MMscf

     176,978.3         15,821.6         33,255.9        226,055.8   

NGL—Mbbls

     24,457.4         1,160.1         3,667.8        29,285.3   

Income Data (M$)

          

Future Net Revenue

     1,225,265.6         83,802.7         206,628.7        1,515,697.0   

Deductions

          

Operating Expense

     627,191.9         42,613.7         92,677.8        762,483.4   

Production Taxes

     77,649.8         5,493.1         13,708.2        96,851.1   

Investment

     0.0         12,141.9         69,604.8        81,746.7   

Abandonment

     8,743.1         427.1         1,087.2        10,257.4   

Future Net Cashflow

     511,680.8         23,126.8         29,550.7        564,358.3   

Discounted PV @ 10% (M$)

     260,233.4         8,119.9         (11,176.7     257,176.6   

 

 

Note: Proved producing reserves include Inactive and Salt Water Disposal well costs.

 

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Fig. 1—

  Present value distribution by Proved reserve category—calculated using a 10% discount rate (MM$), unescalated prices and costs.

The values in the tables above may not add up arithmetically or exactly match the attached cash flows due to rounding procedures in the computer software program used to prepare the economic projections. Cash flows summarized by reserve category and state are included in the attachments of this report. Well count summaries are not accurate in several of the attached cash flows. Many proved non-producing wells are counted in the current proved producing well counts.

Reserves estimates

Standard geological and engineering methods generally accepted by the petroleum industry were used in the estimation of QRI’s reserves. Deterministic methods were used for all reserves included in this report. The appropriate combination of conventional decline curve analysis (DCA), production data analysis, volumetrics, reservoir simulation, and type curves were used to estimate the remaining reserves. Volumetric calculations were based on data and maps provided by QRI. Any reservoir simulation efforts were conducted using EclipseTM, which is DCS’s multi-phase reservoir simulator designed specifically for evaluating fractured shale formations. Comparisons were made to similar properties for which more complete data were available for areas of new development.

Reserve estimates are strictly technical judgments. The accuracy of any reserve estimate is a function of the quality and quantity of data available and of the engineering and geological interpretations. The reserve estimates presented in this report are believed reasonable; however,

 

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they are estimates only and should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify their revision. A portion of these reserves are for undeveloped locations and producing or non-producing wells that lack sufficient production history to utilize conventional performance-based reserve estimates. In these cases, the reserves are based on volumetric estimates and recovery efficiencies along with analogies to similar producing areas. These reserve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data. As additional production and pressure data becomes available, these estimates may be revised up or down. Actual future prices may vary significantly from the prices used in this evaluation; therefore, future hydrocarbon volumes recovered and the income received from these volumes may vary significantly from those estimated in this report. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

Reserve categories

Reserves were assigned to the proved developed producing (PDP), proved developed non-producing (PDNP), and proved undeveloped (PUD) reserve categories. Oil and gas reserves by definition fall into one of the following categories: proved, probable, and possible. The proved category is further divided into: developed and undeveloped. The developed reserve category is even further divided into the appropriate reserve status subcategories: producing and non-producing. Non-producing reserves include shut-in and behind-pipe reserves. The reserves evaluated in this report conform to the U.S. Securities and Exchange Commission Regulation S-X, Rule 210.4-10 (a). These reserve definitions are presented in the Reserve Definitions section of this report.

In our opinion the above-described estimates of QRI’s reserves and supporting data are, in the aggregate, reasonable. It is also our opinion that the above-described estimates of QRI’s proved reserves conform to the definitions of proved oil and gas reserves promulgated by the SEC.

QRI has an active exploration and development program to develop their interests in certain tracts not classified as proved at this time. Future drilling may result in the reclassification of additional volumes to the proved reserve category. However, changes in the regulatory requirements for oil and gas operations may impact future development plans and the ability of the company to recover the estimated proved undeveloped reserves. The reserves and income attributable to the various reserve categories included in this report have not been adjusted to reflect the varying degrees of risk associated with them.

Economic terms

Net revenue (sales) is defined as the total proceeds from the sale of oil, condensate, natural gas liquids (NGL), and gas adjusted for commodity price basis differential and gathering/ transportation expense. Future net income (cashflow) is future net revenue less net lease operating expenses, state severance or production taxes, operating/development capital expenses and net salvage. Future net income (cashflow) for nonoperated wells includes those general and

 

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administrative (G&A) deductions charged by the operator for a particular well or project on a monthly basis; operated well G&A deductions include only those expenses estimated as necessary to continue production activities. Future plugging, abandonment, and salvage costs are included at the economic life of each well or unit. No provisions for State or Federal income taxes have been made in this evaluation. The present worth (discounted cashflow) at various discount rates is calculated on a monthly basis.

Pricing and economic parameters

All product prices, costs, and economic parameters used in this report were supplied by Quicksilver LP and reviewed by DCS. Data from Quicksilver LP were accepted as presented. All prices used in preparation of this report were based on the twelve month unweighted arithmetic average of the first day of the month price for the period January through December 2009. The resulting Henry Hub gas price used was $3.870/MMBtu and the resulting West Texas Intermediate oil price used was $61.18/Bbl. The prices were adjusted for local differentials, gravity and Btu where applicable. As required by SEC guidelines, all pricing was held constant for the life of the projects (no escalation). Quicksilver LP’s estimates for capital costs for all non-producing and undeveloped wells are included in the evaluation. Quicksilver LP has indicated to us that they have the ability and intent to implement their capital expenditure program as scheduled.

Future plugging and abandonment, net of salvage costs, were added at the economic life of each well or project. The costs are based on estimated plugging costs by area. The addition of plugging costs to the properties reduces both the total proved undiscounted cash flow and the present worth value discounted at 10% by $10,257.5M and $1,264.2M respectively. The cash flow summaries by reserve category excluding the plugging and salvage are included in the No Abandonment section of this report.

Ownership

The leasehold interests were supplied by Quicksilver LP and were accepted as presented. No attempt was made by the undersigned to verify the title or ownership of the interests evaluated.

General

All data used in this study were obtained from Quicksilver LP, public industry information sources, or the non-confidential files of DCS. A field inspection of the properties was not made in connection with the preparation of this report.

The potential environmental liabilities attendant to ownership and/or operation of the properties have not been addressed in this report. Abandonment and clean-up costs and possible salvage value of the equipment were considered in this report.

In the conduct of our evaluation, we have not independently verified the accuracy and completeness of information and data furnished by Quicksilver LP with respect to ownership interests, historical gas production, costs of operation and development, product prices, payout balances, and agreements relating to current and future operations and sales of production. If in

 

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the course of our examination something came to our attention which brought into question the validity or sufficiency of any of the information or data provided by Quicksilver LP we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or independently verified such information or data.

In evaluating the information at our disposal related to this report, we have excluded from our consideration all matters which require a legal or accounting interpretation, or any interpretation other than those of an engineering or geological nature. In assessing the conclusions expressed in this report pertaining to all aspects of oil and gas evaluations, especially pertaining to reserve evaluations, there are uncertainties inherent in the interpretation of engineering data, and such conclusions represent only informed professional judgments.

We are independent with respect to Quicksilver LP as provided in the SEC regulations. Neither the employment of nor the compensation received by DCS was contingent upon the values estimated for the properties included in this report.

Data and worksheets used in the preparation of this evaluation will be maintained in our files in Pittsburgh and will be available for inspection by anyone having proper authorization by Quicksilver LP.

We appreciate the opportunity to perform this evaluation and are available should you need further assistance in this matter.

Sincerely yours,

 

/s/    Denise L. Delozier     /s/    Charles M. Boyer II

Denise L. Delozier

   

Charles M. Boyer II, PG, CPG

Senior Engineer

   

Consulting Services Manager—NE Basin

   

Advisor—Unconventional Reservoirs

/s/    Walter K. Sawyer

   

Walter K. Sawyer, PE

   

Principal Consultant

   

 

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Reserves definitions

 

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SECURITIES AND EXCHANGE COMMISSION

REGULATION S-X, RULE 210.4-10 (a)

RESERVES DEFINITIONS

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) 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

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

 

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(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

 

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(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves.    Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas 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

 

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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

(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.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

 

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(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are 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.

Note to paragraph (a)(26): 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).

(27) 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.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas 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.

(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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties.    Properties with no proved reserves.

 

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Index to Financial Statements

Reserve and Economic Evaluation Of

Proved Reserves

Of Certain Quicksilver Production Partners LP

Oil And Gas Interests

As Of 31 December 2008

Executive Summary

Prepared For

Quicksilver Production Partners LP

Fort Worth, Texas

Prepared By

Schlumberger Data & Consulting Services

Pittsburgh, Pennsylvania

November 2011

 

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Data & Consulting Services

Division of Schlumberger Technology Corporation

 

Two Robinson Plaza, Suite 200

Pittsburgh, PA 15205

Tel: 412-787-5403

Fax: 412-787-2906

  LOGO

11 November 2011

Quicksilver Production Partners LP

801 Cherry Street

Suite 3700, Unit 19

Fort Worth, Texas 76102

Dear Gentlemen:

At the request of Quicksilver Production Partners LP (Quicksilver LP), through their letter of engagement, Data & Consulting Services (DCS) Division of Schlumberger Technology Corporation has evaluated the proved reserves of certain Quicksilver LP oil and gas interests located in the United States (U.S.) as of 31 December 2008. All evaluated properties are located in Texas, operated by Quicksilver LP, and are productive in the Barnett Shale. This report was completed as of the date of this letter and has been prepared using constant prices and costs and conforms to our understanding of the U.S. Securities and Exchange Commission (SEC) guidelines and applicable financial accounting rules. All prices, costs, and cash flow estimates are expressed in U.S. dollars (US$). It is our understanding that the properties evaluated by DCS comprise one hundred percent (100%) of Quicksilver LP’s proved reserves. We believe that the assumptions, data, methods, and procedures used in preparing this report are appropriate for the purpose of this report. The Lead Evaluator for this evaluation was Charles M. Boyer II, PG, CPG, and his qualifications, independence, objectivity, and confidentiality meet the requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

 

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The results of the Proved reserve evaluation are summarized in Table 1. Fig. 1 illustrates the distribution by Proved reserve category for the present value at a 10% discount rate (PV10).

Table 1

Estimated net reserves and income

certain proved oil and gas interests

unescalated prices and costs

Quicksilver Production Partners LP

as of 31 December 2008

 

     

Proved

producing

reserves

    

Proved

nonproducing

reserves

    

Proved

undeveloped

reserves

    

Total

proved

reserves

 

 

 

Remaining Net Reserves

           

Oil—Mbbls

     295.2         18.5         37.1         350.8   

Gas—MMscf

     162,611.9         17,498.6         36,926.8         217,037.3   

NGL—Mbbls

     20,150.3         1,175.8         3,278.9         24,605.0   

Income Data (M$)

           

Future Net Revenue

     1,302,814.5         116,396.8         266,209.6         1,685,420.6   

Deductions

           

Operating Expense

     691,467.9         52,136.5         116,218.5         859,822.9   

Production Taxes

     73,254.6         6,440.5         22,263.4         101,958.5   

Investment

     0.0         15,204.7         64,361.2         79,565.9   

Abandonment

     8,587.8         427.1         931.9         9,946.8   

Future Net Cashflow

     529,504.1         42,187.9         62,434.7         634,126.8   

Discounted PV @ 10% (M$)

     308,808.1         21,225.9         5,845.2         335,879.2   

 

 

 

Note:   Proved producing reserves include Inactive and Salt Water Disposal well costs.

 

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Fig. 1—

  Present value distribution by Proved reserve category—calculated using a 10% discount rate (MM$), unescalated prices and costs.

The values in the tables above may not add up arithmetically or exactly match the attached cash flows due to rounding procedures in the computer software program used to prepare the economic projections. Cash flows summarized by reserve category and state are included in the attachments of this report. Well count summaries are not accurate in several of the attached cash flows. Many proved non-producing wells are counted in the current proved producing well counts.

Reserves estimates

A combination of conventional decline curve analysis (DCA), production data analysis, volumetrics, reservoir simulation, and type curves were used to estimate the remaining reserves in all producing areas. ARIESTM was utilized as the software platform for conducting the DCA analysis and economic evaluation. Volumetric calculations were based on data and maps provided by Quicksilver LP. Any reservoir simulation efforts were conducted using ECLIPSE™, which is DCS’s multi-phase reservoir simulator designed for evaluating fractured shale formations. ECLIPSE™ was used to develop forecasts for the Barnett Shale reserves in Texas. Quicksilver LP provided isopach maps and production data from Quicksilver LP horizontal wells and analogous offset wells to their lease acreage positions in which they have no interest. These data were used in conjunction with the simulator to generate a family of type curves that were applied to all undeveloped wells and locations.

 

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Data & Consulting Services

Division of Schlumberger Technology Corporation

 

11 November 2011

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LOGO

 

Reserve estimates are strictly technical judgments. The accuracy of any reserve estimate is a function of the quality and quantity of data available and of the engineering and geological interpretations. The reserve estimates presented in this report are believed reasonable; however, they are estimates only and should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify their revision. A portion of these reserves are for undeveloped locations and producing or non-producing wells that lack sufficient production history to utilize conventional performance-based reserve estimates. In these cases, the reserves are based on volumetric estimates and recovery efficiencies along with analogies to similar producing areas. These reserve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data. As additional production and pressure data becomes available, these estimates may be revised up or down. Actual future prices may vary significantly from the prices used in this evaluation; therefore, future hydrocarbon volumes recovered and the income received from these volumes may vary significantly from those estimated in this report. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

Reserve categories

Reserves were assigned to the proved developed producing (PDP), proved developed non-producing (PDNP), and proved undeveloped (PUD) reserve categories. Oil and gas reserves by definition fall into one of the following categories: proved, probable, and possible. The proved category is further divided into: developed and undeveloped. The developed reserve category is even further divided into the appropriate reserve status subcategories: producing and non-producing. Non-producing reserves include shut-in and behind-pipe reserves. The proved reserves evaluated in this report conform to the Securities and Exchange Commission Regulation S-X, Rule 4-10 (a). These reserve definitions are presented in the Reserve Definitions section of this report.

In our opinion the above-described estimates of Quicksilver LP’s reserves and supporting data are, in the aggregate, reasonable. It is also our opinion that the above-described estimates of Quicksilver LP’s proved reserves conform to the definitions of proved oil and gas reserves promulgated by the SEC.

Quicksilver LP has an active exploration and development program to develop their interests in certain tracts not classified as proved at this time. Future drilling may result in the reclassification of additional volumes to the proved reserve category. However, changes in the regulatory requirements for oil and gas operations may impact future development plans and the ability of the company to recover the estimated proved undeveloped reserves. The reserves and income attributable to the various reserve categories included in this report have not been adjusted to reflect the varying degrees of risk associated with them.

Economic terms

Net revenue (sales) is defined as the total proceeds from the sale of oil, condensate, natural gas liquids (NGL), and gas adjusted for commodity price basis differential and gathering/ transportation expense. Future net income (cashflow) is future net revenue less net lease

 

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Index to Financial Statements

Data & Consulting Services

Division of Schlumberger Technology Corporation

 

11 November 2011

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LOGO

 

operating expenses, state severance or production taxes, operating/development capital expenses and net salvage. Future net income (cashflow) for nonoperated wells includes those general and administrative (G&A) deductions charged by the operator for a particular well or project on a monthly basis; operated well G&A deductions include only those expenses estimated as necessary to continue production activities. Future plugging, abandonment, and salvage costs are included at the economic life of each well or unit. No provisions for State or Federal income taxes have been made in this evaluation. The present worth (discounted cashflow) at various discount rates is calculated on a monthly basis.

Pricing and economic parameters

All product prices, costs, and economic parameters used in this report were supplied by Quicksilver LP. Data from Quicksilver LP were accepted as presented. All pricing and costs were held constant for the life of the projects (no escalation). All prices used in this report were based on current contracts or 31 December 2008 Spot prices adjusted for local differentials, gravity and Btu where applicable. The base Spot prices used were $44.60/Bbl for oil and $5.710/MMBtu for gas.

Future plugging and abandonment, net of salvage costs, were added at the economic life of each well or project. The costs are based on estimated plugging costs by area. The addition of plugging costs to the properties reduces both the total proved undiscounted cash flow and the present worth value discounted at 10% by $9,907.9M and $1,841.1M respectively. The cash flow summaries by reserve category excluding the plugging and salvage are included in the No Abandonment section of this report.

Ownership

The leasehold interests were supplied by Quicksilver LP and were accepted as presented. No attempt was made by the undersigned to verify the title or ownership of the interests evaluated.

General

All data used in this study were obtained from Quicksilver LP, public industry information sources, or the non-confidential files of DCS. A field inspection of the properties was not made in connection with the preparation of this report.

The potential environmental liabilities attendant to ownership and/or operation of the properties have not been addressed in this report. Abandonment and clean-up costs and possible salvage value of the equipment were considered in this report.

In the conduct of our evaluation, we have not independently verified the accuracy and completeness of information and data furnished by Quicksilver LP with respect to ownership interests, historical gas production, costs of operation and development, product prices, payout balances, and agreements relating to current and future operations and sales of production. If in the course of our examination something came to our attention which brought into question the validity or sufficiency of any of the information or data provided by Quicksilver LP, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or independently verified such information or data.

 

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Data & Consulting Services

Division of Schlumberger Technology Corporation

 

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LOGO

 

In evaluating the information at our disposal related to this report, we have excluded from our consideration all matters which require a legal or accounting interpretation, or any interpretation other than those of an engineering or geological nature. In assessing the conclusions expressed in this report pertaining to all aspects of oil and gas evaluations, especially pertaining to reserve evaluations, there are uncertainties inherent in the interpretation of engineering data, and such conclusions represent only informed professional judgments.

We are independent with respect to Quicksilver LP as provided in the SEC regulations. Neither the employment of nor the compensation received by DCS was contingent upon the values estimated for the properties included in this report.

Data and worksheets used in the preparation of this evaluation will be maintained in our files in Pittsburgh and will be available for inspection by anyone having proper authorization by Quicksilver LP.

We appreciate the opportunity to perform this evaluation and are available should you need further assistance in this matter.

Sincerely yours,

 

/s/  Denise L. Delozier

  

/s/  Charles M. Boyer II

Denise L. Delozier

Senior Engineer

  

Charles M. Boyer II, PG, CPG

Consulting Services Manager—NE Basin

Advisor—Unconventional Reservoirs

/s/  Walter K. Sawyer

  

Walter K. Sawyer, PE

Principal Consultant

  

 

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Reserves definitions

 

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SECURITIES AND EXCHANGE COMMISSION

REGULATION S-X, RULE 4-10 (A)

RESERVES DEFINITIONS

Oil and Gas Producing Activities

Such activities include (A) the search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations; (B) the acquisition of property rights or properties for the purpose of further exploration and/or for the purpose of removing the oil or gas from existing reservoirs on those properties; and (C) the construction, drilling and production activities necessary to retrieve oil and gas from its natural reservoirs, and the acquisition, construction, installation, and maintenance of field gathering and storage systems—including lifting the oil and gas to the surface and gathering, treating, field processing (as in the case of processing gas to extract liquid hydrocarbons) and field storage. For purposes of this section, the oil and gas production function shall normally be regarded as terminating at the outlet valve on the lease or field storage tank; if unusual physical or operational circumstances exist, it may be appropriate to regard the production functions as terminating at the first point at which oil, gas, or gas liquids are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal.

Oil and gas producing activities do not include (A) the transporting, refining and marketing of oil and gas; (B) activities relating to the production of natural resources other than oil and gas; (C) the production of geothermal steam or the extraction of hydrocarbons as a by-product of the production of geothermal steam or associated geothermal resources as defined in the Geothermal Steam Act of 1970; and (D) the extraction of hydrocarbons from shale, tar sands, or coal.

The SEC stated in a September 18, 1989 accounting bulletin “since coalbed methane gas can be recovered from coal in its natural state and location, it should be included in proved reserves, provided that it complies in all other respects with the SEC definitions of proved oil and gas reserves including the requirement that methane production be economical at current prices, costs (net of the tax credit) and existing operating conditions.” We have also interpreted this bulletin to include shale gas.

Proved Oil and Gas Reserves

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

 

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Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved Developed Oil and Gas Reserves

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved Undeveloped Reserves

Proved undeveloped oil and gas reserves are 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 drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. 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 been proved effective by actual tests in the area and in the same reservoir.

 

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Common Units

 

 

LOGO

 

 

Common Units Representing Limited Partner Interests

Prospectus

 

J.P. Morgan    Credit Suisse

 

BofA Merrill Lynch   Citigroup   Deutsche Bank Securities
RBC Capital Markets     Wells Fargo Securities

 

Goldman, Sachs & Co.   UBS Investment Bank   Baird

 

BB&T Capital Markets     Comerica Securities

                    , 2012

Through and including                     , 2012 (25 days after the commencement of this offering), all dealers that effect transactions in our common units, whether or not participating in this offering, may be required to deliver a prospectus. This delivery is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to its unsold allotments or subscriptions.


Table of Contents
Index to Financial Statements

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. The underwriters have agreed to reimburse us for a portion of our expenses.

 

SEC registration fee

   $  28,650   

FINRA filing fee

     25,500   

Stock exchange listing fee

     *   

Underwriter structuring fee

     *   

Printing and engraving expenses

     *   

Accounting fees and expenses

     *   

Legal fees and expenses

     *   

Transfer agent and registrar fees

     *   

Miscellaneous

     *   
  

 

 

 

Total

   $ *   

 

 

 

*   To be provided by amendment.

Item 14. Indemnification of directors and officers.

Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever. We will generally indemnify our general partner and its affiliates and any manager, managing member, director, officer, fiduciary, trustee or other person who has control of our general partner or any of its affiliates to the fullest extent permitted by law against all losses, claims, damages or similar events, except where in connection with the matter for which indemnification is sought such person acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful. The section of the prospectus entitled “The partnership agreement—Indemnification” is incorporated herein by reference.

We expect to enter into indemnification agreements with the officers and directors of our general partner which will generally indemnify them to the fullest extent permitted by law. Additionally, the directors and officers of our general partner will be covered by our directors’ and officers’ insurance policy.

Under the omnibus agreement, we will agree to indemnify Quicksilver and its subsidiaries and their respective officers, managers, directors, employees and agents for all claims, losses and expenses attributable to the services provided to us under the omnibus agreement, to the extent that such losses are not subject to Quicksilver’s indemnification obligations. Please read “Certain relationships and related party transactions—Agreements governing the transactions—Omnibus agreement” for a discussion of Quicksilver’s indemnification obligations.

 

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Reference is also made to the underwriting agreement filed as an exhibit to this registration statement, which provides for the indemnification of us, our general partner, its officers and directors, and any person who controls us or our general partner, including indemnification for liabilities under the Securities Act.

Item 15. Recent sales of unregistered securities.

In connection with the formation of Quicksilver Production Partners LP, we issued a general partner interest in us to Quicksilver Production Partners GP LLC and a limited partner interest in us to Quicksilver Resources Inc., in each case in an offering exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.

Item 16. Exhibits and financial statement schedules.

 

(a)   Exhibit Index

 

Exhibit
Number
          Description

 

 

  1.1      Form of Underwriting Agreement
  3.1 †       Certificate of Limited Partnership of Quicksilver Production Partners LP
  3.2 †       Agreement of Limited Partnership of Quicksilver Production Partners LP
  3.3      Form of First Amended and Restated Agreement of Limited Partnership of Quicksilver Production Partners LP (included as Appendix A to the prospectus)
  3.4 †       Certificate of Formation of Quicksilver Production Partners GP LLC
  3.5 †       First Amended and Restated Limited Liability Company Agreement of Quicksilver Production Partners GP LLC
  3.6         Certificate of Amendment to Certificate of Formation of Quicksilver Production Partners GP LLC
  3.7      Form of Second Amended and Restated Limited Liability Company Agreement of Quicksilver Production Partners GP LLC
  5.1      Opinion of Potter Anderson & Corroon LLP as to the legality of the securities being registered
  8.1      Opinion of Davis Polk & Wardwell LLP relating to tax matters
  10.1      Form of Credit Agreement
  10.2      Form of Exchange Agreement
  10.3      Quicksilver Production Partners LP 2012 Equity Plan
  10.4      Form of Phantom Unit Award Agreement pursuant to the Quicksilver Production Partners LP 2012 Equity Plan for Directors
  10.5      Form of Phantom Unit Award Agreement pursuant to the Quicksilver Production Partners LP 2012 Equity Plan for Employees
  10.6*         Form of Omnibus Agreement
  10.7*         Form of Tax Sharing Agreement

 

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Index to Financial Statements
Exhibit
Number
        Description

 

10.8      Amended and Restated Gas Gathering Agreement, effective September 1, 2008, between Cowtown Pipeline L.P. and Quicksilver Resources Inc.
10.9      First Amendment to Amended and Restated Gas Gathering Agreement, dated September 29, 2009, between Cowtown Pipeline L.P. and Quicksilver Resources Inc.
10.10     

Second Amendment to Gas Gathering Agreement, dated October 1, 2010, between Cowtown Pipeline L.P. and Quicksilver Resources Inc.

21.1      List of Subsidiaries of Quicksilver Production Partners LP
23.1      Consent of Deloitte & Touche LLP
23.2      Consent of Schlumberger Data & Consulting Services
23.3*      Consent of Potter Anderson & Corroon LLP (contained in Exhibit 5.1)
23.4*      Consent of Davis Polk & Wardwell LLP (contained in Exhibit 8.1)
24.1      Powers of Attorney (included on the signature page)
99.1†      Schlumberger Data & Consulting Services Summary of December 31, 2010 Reserves for Quicksilver Production Partners LP (included as Appendix C to the prospectus)
99.2†      Schlumberger Data & Consulting Services Summary of December 31, 2009 Reserves for Quicksilver Production Partners LP (included as Appendix C to the prospectus)
99.3†      Schlumberger Data & Consulting Services Summary of December 31, 2008 Reserves for Quicksilver Production Partners LP (included as Appendix C to the prospectus)
99.4†      Schlumberger Data & Consulting Services Summary of December 31, 2011 Reserves for Quicksilver Resources Inc.
99.5†      Schlumberger Data & Consulting Services Summary of December 31, 2011 Reserves for Quicksilver Production Partners LP (included as Appendix C to the prospectus)

 

 

*   To be filed by amendment.
  Previously filed.

Item 17. Undertakings.

(a) The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

(b) Insofar as indemnification for liabilities arising under the Securities Act 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 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 and will be governed by the final adjudication of such issue.

 

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(c) The undersigned registrant hereby undertakes that:

(i) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(ii) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus 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.

(d) The undersigned registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with Quicksilver Production Partners GP LLC, our general partner, or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to Quicksilver Production Partners GP LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

(e) The undersigned registrant undertakes to provide to the limited partners the financial statements required by Form 10-K for the first full fiscal year of operations of the partnership.

 

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Signatures

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Fort Worth, State of Texas, on June 22, 2012.

 

QUICKSILVER PRODUCTION PARTNERS LP

By:

  QUICKSILVER PRODUCTION PARTNERS GP LLC, its general partner

By:

 

/s/ Glenn Darden

 

Name:

 

Glenn Darden

 

Title:

  President and Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and on the dates presented.

 

Signature

  

Title

  

Date

/s/ Glenn Darden

Glenn Darden

  

President, Chief Executive Officer and Director

(Principal Executive Officer)

  

June 22, 2012

/s/ John C. Regan

John C. Regan

  

Senior Vice President, Chief Financial Officer and Chief Accounting Officer

(Principal Financial Officer and Principal Accounting Officer)

  

June 22, 2012

*

Thomas F. Darden

   Chairman of the Board of Directors   

June 22, 2012

*

Robert S. Boswell

   Director    June 22, 2012

*

Walker C. Friedman

   Director    June 22, 2012

*

M. Garrett Smith

   Director    June 22, 2012

 

*By:

 

/s/ Glenn Darden

 

Name:  

 

Glenn Darden

 

Title:

 

Attorney-in-fact

 


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Index to Financial Statements

KNOW ALL PERSONS BY THESE PRESENTS, that each individual whose signature appears below hereby constitutes and appoints each of Glenn Darden, John C. Regan and John C. Cirone, acting singly, his true and lawful agent, proxy and attorney-in-fact, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to (1) act on, sign and file with the Securities and Exchange Commission any and all amendments (including post-effective amendments) to this registration statement together with all schedules and exhibits thereto and any subsequent registration statement filed pursuant to Rule 462(b) under the Securities Act of 1933, as amended, together with all schedules and exhibits thereto, (2) act on, sign and file such certificates, instruments, agreements and other documents as may be necessary or appropriate in connection therewith, (3) act on and file any supplement to any prospectus included in this registration statement or any such amendment or any subsequent registration statement filed pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and (4) take any and all actions which may be necessary or appropriate in connection therewith, granting unto such agents, proxies and attorneys-in-fact, and each of them, full power and authority to do and perform each and every act and thing necessary or appropriate to be done, as fully for all intents and purposes as he might or could do in person, hereby approving, ratifying and confirming all that such agents, proxies and attorneys-in-fact or any of their substitutes may lawfully do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and on the dates presented.

 

Signature

  

Title

  

Date

/s/ Anne Darden Self

Anne Darden Self

   Director    June 22, 2012

/s/ Paul Coulter

Paul Coulter

   Director    June 22, 2012


Table of Contents
Index to Financial Statements

Index of exhibits

 

Exhibit
Number
           Description

 

 

  1.1*      

   Form of Underwriting Agreement
  3.1†      

   Certificate of Limited Partnership of Quicksilver Production Partners LP
  3.2†      

   Agreement of Limited Partnership of Quicksilver Production Partners LP
  3.3*      

   Form of First Amended and Restated Agreement of Limited Partnership of Quicksilver Production Partners LP (included as Appendix A to the prospectus)
  3.4†      

   Certificate of Formation of Quicksilver Production Partners GP LLC
  3.5†      

   First Amended and Restated Limited Liability Company Agreement of Quicksilver Production Partners GP LLC
  3.6      

   Certificate of Amendment to Certificate of Formation of Quicksilver Production Partners GP LLC
  3.7*      

   Form of Second Amended and Restated Limited Liability Company Agreement of Quicksilver Production Partners GP LLC
  5.1*      

   Opinion of Potter Anderson & Corroon LLP as to the legality of the securities being registered
  8.1*      

   Opinion of Davis Polk & Wardwell LLP relating to tax matters
  10.1*      

   Form of Credit Agreement
  10.2*      

   Form of Exchange Agreement
  10.3*      

   Quicksilver Production Partners LP 2012 Equity Plan
  10.4*      

   Form of Phantom Unit Award Agreement pursuant to the Quicksilver Production Partners LP 2012 Equity Plan for Directors
  10.5*      

   Form of Phantom Unit Award Agreement pursuant to the Quicksilver Production Partners LP 2012 Equity Plan for Employees
  10.6*      

   Form of Omnibus Agreement
  10.7*      

   Form of Tax Sharing Agreement
  10.8      

   Amended and Restated Gas Gathering Agreement, effective September 1, 2008, between Cowtown Pipeline L.P. and Quicksilver Resources Inc.
  10.9      

   First Amendment to Amended and Restated Gas Gathering Agreement, dated September 29, 2009, between Cowtown Pipeline L.P. and Quicksilver Resources Inc.
  10.10      

   Second Amendment to Gas Gathering Agreement, dated October 1, 2010, between Cowtown Pipeline L.P. and Quicksilver Resources Inc.
  21.1      

   List of Subsidiaries of Quicksilver Production Partners LP
  23.1       

   Consent of Deloitte & Touche LLP
  23.2       

   Consent of Schlumberger Data & Consulting Services
  23.3*      

   Consent of Potter Anderson & Corroon LLP (contained in Exhibit 5.1)
  23.4*      

   Consent of Davis Polk & Wardwell LLP (contained in Exhibit 8.1)
  24.1       

   Powers of Attorney (included on the signature page)


Table of Contents
Index to Financial Statements
Exhibit
Number
           Description

 

 

  99.1†      

   Schlumberger Data & Consulting Services Summary of December 31, 2010 Reserves for Quicksilver Production Partners LP (included as Appendix C to the prospectus)
  99.2†      

   Schlumberger Data & Consulting Services Summary of December 31, 2009 Reserves for Quicksilver Production Partners LP (included as Appendix C to the prospectus)
  99.3†      

   Schlumberger Data & Consulting Services Summary of December 31, 2008 Reserves for Quicksilver Production Partners LP (included as Appendix C to the prospectus)
  99.4†      

   Schlumberger Data & Consulting Services Summary of December 31, 2011 Reserves for Quicksilver Resources Inc.
  99.5†      

   Schlumberger Data & Consulting Services Summary of December 31, 2011 Reserves for Quicksilver Production Partners LP (included as Appendix C to the prospectus)

 

 

 

*   To be filed by amendment.
  Previously filed.