UNITED STATES  

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

For the quarterly period ended June 30, 2016

OR

For the transition period from               to              

Commission file number: 000-55603

 

Atlas Growth Partners, L.P.

(Exact name of registrant as specified in its charter)

 

 

Registrant’s telephone number, including area code: 412-489-0006

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ¨     No  x

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x     No  ¨

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.

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes  ¨     No  x

The number of outstanding common limited partner units of the registrant on August 4, 2016 was 23,300,410.

 

 

 

1

---

ATLAS GROWTH PARTNERS, L.P.

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

TABLE OF CONTENTS

 

 

2

---

Forward-Looking Statements

The matters discussed within this report include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates and projections. While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. Some of the key factors that could cause actual results to differ from our expectations include:

 

 

 

 

 

 

 

 

 

 

 

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

Other factors that could cause actual results to differ from those implied by the forward-looking statements in this report are more fully described under “Risk Factors” in our prospectus for our public offering, as amended and supplemented and Part II, “Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2016. Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this report are made only as of the date hereof. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments.

 

3

---

ATLAS GROWTH PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

 

 

See accompanying notes to condensed consolidated financial statements.

 

 

4

---

ATLAS GROWTH PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

 

 

See accompanying notes to condensed consolidated financial statements.

 

 

5

---

ATLAS GROWTH PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in thousands, except unit data)

(Unaudited)

 

 

See accompanying notes to condensed consolidated financial statements.

 

 

6

---

ATLAS GROWTH PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

 

 

See accompanying notes to condensed consolidated financial statements.

 

 

7

---

ATLAS GROWTH PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

NOTE 1 – BASIS OF PRESENTATION

We are a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”) with operations primarily focused in the Eagle Ford Shale in south Texas. Our general partner, Atlas Growth Partners GP, LLC (“AGP GP”) owns 100% of the general partner Class A units and all of the incentive distribution rights through which it manages and effectively controls us. Unless the context otherwise requires, references to “Atlas Growth Partners, L.P.,” “Atlas Growth Partners,” “the Partnership,” “we,” “us,” “our” and “our company”, refer to Atlas Growth Partners, L.P. and our consolidated subsidiaries.

At June 30, 2016, Atlas Energy Group, LLC (“ATLS” or “Atlas Energy”), a publicly traded Delaware limited liability company (OTC: ATLS) that manages and controls us through its general partner interest and through the terms of the partnership agreement, owned a 2.1% limited partner interest in us and 80.0% of AGP GP’s general partner Class A units, which are entitled to receive 2% of the cash distributed by us without any obligation to make further capital contributions (see Note 9). Current and former members of ATLS management own the remaining 20% interest in AGP GP’s general partner Class A units.

In addition to its general and limited partner interest in us, ATLS also holds general and limited partner interests in Atlas Resource Partners, L.P. (“ARP”), a publicly traded Delaware master-limited partnership (OTC: ARPJ) and an independent developer and producer of natural gas, oil and NGLs, with operations in basins across the United States, and in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, which incubate new MLPs and invest in existing MLPs.

To date, we have funded our operations through the private placement of 23,300,410 of our common limited partner units at a purchase price of $10.00 per unit which ended June 30, 2015 (the “Private Placement Offering”). The common units are a class of limited partner interests in us. The holders of common units are entitled to participate in partnership distributions, exercise the rights or privileges available to them, have limited voting rights and have limited liability, all as outlined in the partnership agreement.

Our registration statement on Form S-1 (Registration Number: 333-207537) was declared effective by the Securities and Exchange Commission on April 5, 2016. We are offering in the aggregate up to 100,000,000 Class A common units and Class T common units, each representing limited partner interests in us, pursuant to a primary offering on a "best efforts" basis. We must receive minimum offering proceeds of $1.0 million to break escrow, and the maximum offering proceeds of the primary offering may not exceed $1.0 billion. The Class A common units will be sold for a cash purchase price of $10.00 and the Class T common units will be sold for a cash purchase price of $9.60, with the remaining $0.40 constituting the Class T common unitholders' deferred payment obligation to us. We are also offering up to 21,505,376 Class A common units at $9.30 per unit pursuant to a distribution reinvestment plan.

The accompanying condensed consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2015 was derived from audited financial statements, have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission and are presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in our Form S-1. It is suggested that these condensed financial statements be read in conjunction with the financial statements and the notes thereto included in our Form S-1. In management’s opinion, all adjustments necessary for a fair presentation of our financial position, results of operations and cash flows for the periods disclosed have been made. The results of operations for the interim periods presented may not necessarily be indicative of the results of operations for the full year.

 

 

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

Our condensed consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiaries. Transactions between us and other ATLS operations have been identified in the condensed consolidated

8

---

financial statements as transactions between affiliates, where applicable. All material intercompany transactions have been eliminated.

Use of Estimates

The preparation of our condensed consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of our condensed consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. Our condensed consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, accruals for well drilling and completion costs, depletion, depreciation and amortization and fair value of derivative instruments. The oil and gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery.  Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Actual results could differ from those estimates.

Liquidity and Capital Resources

We have historically funded our operations, acquisitions and cash distributions primarily through cash generated from operations and financing activities, including the Private Placement Offering completed in 2015. Our future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted our revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on our liquidity position.

ARP Restructuring and Chapter 11 Bankruptcy Proceedings

On July 25, 2016, ARP and certain of its subsidiaries and ATLS, solely with respect to certain sections thereof, entered into a restructuring support agreement with ARP’s lenders (the “Restructuring Support Agreement”) for a prepackaged restructuring that will reduce debt on its balance sheet and position ARP for the future (the “Restructuring”). We and ARP are affiliates through the ownership by our common parent, ATLS. ARP’s Restructuring is expected to be completed before the end of the third quarter of 2016, after which ARP should emerge from Chapter 11, backed by its stakeholders, committed to investing capital to develop its exploration and production assets, as well as its tax-advantaged drilling partnership program.

On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York. The cases commenced thereby are being jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.”

We are not a party to the Restructuring Support Agreement, and the ARP Restructuring is not expected to materially impact us.

The ARP Restructuring is not expected to materailly impact ATLS or its ownership interest in us, including ATLS’s control of our general partner, AGP GP. The debt structure of ATLS was recently modified, and ATLS is not a party to the ARP Restructuring. ATLS remains controlled by the same ownership group and management team and thus, the ARP Restructuring is not expected to have a material impact on the ability of management to operate us or the other ATLS businesses.

Segment Reporting

We derive revenue from our gas and oil production. These production facilities have been aggregated into one reportable segment, because the facilities have similar long-term economic characteristics, products and types of customers.

Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of the general partner’s interest, by the weighted average number of common limited partner units outstanding during the period. The general partner’s interest in net income (loss) is calculated on a quarterly basis based upon our Class A units and incentive distributions to be distributed for

9

---

the quarter (see Note 9), with a priority allocation of net income to the general partner’s incentive distributions, if any, in accordance with the Partnership Agreement, and the remaining net income (loss) allocated with respect to the general partner’s and limited partners’ ownership interests.

We present net income (loss) per unit under the two-class method, which considers whether the incentive distributions represent a participating security. The two-class method considers whether the Partnership Agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the Partnership Agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, our management believes the Partnership Agreement contractually limits cash distributions to available cash; therefore, undistributed earnings are not allocated to the incentive distribution rights.

The following is a reconciliation of net loss allocated to the common limited partners for purposes of calculating net loss attributable to common limited partners per unit (in thousands):

 

 

Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of common limited partner warrants, as calculated by the treasury stock method.

The following table sets forth the reconciliation of our weighted average number of common units used to compute basic net income (loss) attributable to common unit holders per unit with those used to compute diluted net income (loss) attributable to common unit holders per unit (in thousands):

 

 

Recently Issued Accounting Standards

As stated in our Form S-1, we qualify for emerging growth company status; however, we do not elect this exemption in relation to accounting standards.

In February 2016, the Financial Accounting Standards Board (“FASB”) updated the accounting guidance related to leases. The updated accounting guidance requires lessees to recognize a lease asset and liability at the commencement date of all leases (with the exception of short-term leases), initially measured at the present value of the lease payments. The updated guidance is effective for us as of January 1, 2019 and requires a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest period presented. We are currently in the process of determining the impact that the updated accounting guidance will have on our condensed consolidated financial statements.

10

---

In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. We adopted this accounting guidance on January 1, 2016, and provided enhanced disclosures, as applicable, within our condensed consolidated financial statements.

In May 2014, the FASB issued an accounting standards update related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. This update is effective for annual reporting periods beginning after December 15, 2017. We are currently in process of determining the impact that the update will have on our condensed consolidated financial statements and our method of adoption.

 

NOTE 3 – PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment at the dates indicated (in thousands):

 

 

During the six months ended June 30, 2016 and 2015, we recognized $0.1 million and $0.6 million, respectively, of non-cash property, plant and equipment additions, which were included within the changes in accounts payable and accrued liabilities on our condensed consolidated statements of cash flows.

For the three months ended June 30, 2016 and 2015, we recorded $7,000 and $4,000, respectively, of accretion expense related to our asset retirement obligations within in depreciation, depletion and amortization in our condensed consolidated statements of operations. For the six months ended June 30, 2016 and 2015, we recorded $11,000 and $7,000, respectively, of accretion expense related to our asset retirement obligations within in depreciation, depletion and amortization in our condensed consolidated statements of operations.

 

 

NOTE 4 – DERIVATIVE INSTRUMENTS

We use swaps in connection with our commodity price risk management activities. We do not apply hedge accounting to any of our derivative instruments. As a result, gains and losses associated with derivative instruments are recognized as gains on mark-to-market derivatives on our condensed consolidated statements of operations.

We enter into commodity future option contracts to achieve more predictable cash flows by hedging our exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while other natural gas liquids contracts are based on an OPIS Mt. Belvieu index.

11

---

We recorded net derivative liabilities of $0.3 million and net derivative assets of $0.4 million on our condensed consolidated balance sheets at June 30, 2016 and December 31, 2015, respectively.

The following table summarizes the commodity derivative activity for the period indicated (in thousands):

 

 

 

The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our condensed consolidated balance sheets as of the date indicated (in thousands):

 

 

As of June 30, 2016, we had the following commodity derivatives:

Crude Oil – Fixed Price Swaps

 

 

On May 1, 2015, we entered into a secured credit facility agreement with a syndicate of banks. As of June 30, 2016, the lenders under the credit facility have no commitment to lend to us under the credit facility, but we and our subsidiaries have the ability to enter into derivative contracts to manage our exposure to commodity price movements which will benefit from the collateral securing the credit facility. Obligations under the credit facility are secured by mortgages on our oil and gas properties and first priority security interest in substantially all of our assets. The credit facility may be amended in the future if we and the lenders agree to increase the borrowing base and the lenders’ commitments thereunder. The secured credit

12

---

facility agreement contains covenants that limit our and our subsidiaries’ ability to incur indebtedness, grant liens, make loans or investments, make distributions, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions, including a sale of all or substantially all of our assets. We were in compliance with these covenants as of June 30, 2016. In addition, our credit facility includes customary events of default, including failure to timely pay, breach of covenants, bankruptcy, cross-default with other material indebtedness (including obligations under swap agreements in excess of any agreed upon threshold amount), and change of control provisions.

 

 

NOTE 5 – FAIR VALUE OF FINANCIAL INSTRUMENTS

We use a market approach fair value methodology to value our outstanding derivative contracts. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair value of our financial instruments into the three level hierarchy (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. As of June 30, 2016 and December 31, 2015, all of our derivative financial instruments were classified as Level 2.

Information for financial instruments measured at fair value at June 30, 2016 and December 31, 2015 was as follows (in thousands):

 

 

Other Financial Instruments

Our other current assets and liabilities on our condensed consolidated balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1.

The fair value of the warrants associated with the issuance of common limited partner units in 2015 (see Note 8) was measured using a Black-Scholes pricing model which is based on Level 3 inputs including an exercise price of $10.00, discount rate of 0.5%, an expected term of 1.5 years, expected dividend yield of 7.0% and estimated volatility rate of 50%. The volatility rate used was consistent with that of ARP. The estimated fair value per warrant was $1.47, which includes a $0.37 liquidity adjustment. There were no warrants issued for the three and six months ended June 30, 2016.

 

 

NOTE 6 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Relationship with ATLS. We do not directly employ any persons to manage or operate our business. These functions are provided by employees of ATLS and/or its affiliates. AGP GP receives an annual management fee in connection with its management of us equivalent to 1% of capital contributions per annum. During the three months ended June 30, 2016 and 2015, we paid approximately $0.6 million and $0.3 million, respectively, related to this management fee. During the six months ended June 30, 2016 and 2015, we paid approximately $1.1 million and $0.6 million, respectively, related to this

13

---

management fee. We were required to pay AGP GP an amount equal to any actual, out-of-pocket expenses related to the Private Placement Offering and the formation and financing of us, including legal costs incurred by AGP GP, which payments were approximately 2% of the gross proceeds of the Private Placement Offering. Other indirect costs, such as rent for offices, are allocated by ARP at the direction of ATLS based on the number of its employees who devoted their time to activities on our behalf. We reimburse ATLS at cost for direct costs incurred on our behalf. We reimburse all necessary and reasonable costs allocated to us by ATLS. All of the costs paid or payable to ATLS and AGP GP discussed above were included in general and administrative expenses – affiliate in the condensed consolidated statements of operations. As of June 30, 2016 and December 31, 2015, we had payables to ATLS of $0.5 million and $0.7 million, respectively, related to the management fee, direct costs and allocated indirect costs, which was recorded in advances from affiliates in the condensed consolidated balance sheets.

Relationship with ARP. At the direction of ATLS, we reimburse ARP for direct costs, such as salaries and wages, charged to us based on ATLS employees who incurred time to activities on our behalf and indirect costs, such as rent and other general and administrative costs, allocated to us based on the number of ATLS employees who devoted their time to activities on our behalf. In addition, Anthem Securities, Inc. (“Anthem”), our affiliate and a wholly owned subsidiary of ARP, acted as dealer manager for our Private Placement Offering, which was completed in June 2015. As the dealer manager, Anthem received compensation from us equal to a maximum of 12% of the gross proceeds of the Private Placement Offering as selling commissions, marketing efforts, and other issuance costs. We recorded $10.1 million and $12.3 million of costs to Anthem within common limited partners’ interests on our condensed consolidated statements of partners’ capital for the three and six months ended June 30, 2015, respectively. As the Private Placement Offering concluded on June 30, 2015, no costs were included on our condensed consolidation statement of partners’ capital for the three and six months ended June 30, 2016, respectively. Anthem is currently acting as the dealer manager for our issuance and sale in a continuous offering of up to a maximum agreement amount of 100,000,000 common units representing limited partner interests in us as further described in our registration statement on Form S-1. We will pay Anthem (1) compensation equal to 3.00% of the gross proceeds of the offering (Anthem may reallow up to 1.50% of gross offering proceeds it receives as dealer manager fees to participating broker-dealers, but expects to reallow 1.25% of gross offering proceeds to participating broker-dealers); (2) 7.00% and 3.00% of aggregate gross proceeds from the sale of Class A common units and Class T common units, respectively, as sales commissions; (3) with respect to Class T common units, a distribution and unitholder servicing fee in the aggregate amount of 4.00% of the gross proceeds from the sale of Class T common units, which distribution and unitholder servicing fee will be withheld from cash distributions otherwise payable to the purchasers of Class T common units at a rate of $0.025 per quarter per unit. As of June 30, 2016 and December 31, 2015, we had a $2.4 million payable and $8.7 million receivable, respectively, to/from ARP related to the direct costs, indirect cost allocation, dealer manager costs and timing of funding of cash accounts, which was recorded in advances to/from affiliates in the condensed consolidated balance sheets.

 

 

NOTE 7 – COMMITMENTS AND CONTINGENCIES

General Commitments

As of June 30, 2016, certain of our executives are parties to employment agreements with ATLS that provide compensation and certain other benefits. The agreements provide for severance payments under certain circumstances.

As of June 30, 2016, we did not have any commitments related to our drilling and completion and capital expenditures.

Legal Proceedings

We and our subsidiaries are parties to various routine legal proceedings arising out of the ordinary course of business. Our management and our subsidiaries believe that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations.

 

 

NOTE 8 – ISSUANCES OF UNITS

Under the terms of our initial offering, we offered in a private placement $500.0 million of our common limited partner units. The termination date of the Private Placement Offering was December 31, 2014, subject to two 90 day extensions to the extent that we had not sold $500.0 million of common units at any extension date. We exercised each of such extensions. Under the terms of the offering, an investor received, for no additional consideration, warrants to purchase additional common units in an amount equal to 10% of the common units purchased by such investor. The warrants are exercisable at a price of $10.00 per common unit being purchased and may be exercised from and after the warrant date (generally, the date upon which we give the holder notice of a liquidity event) until the expiration date (generally, the date

14

---

that is one day prior to the liquidity event or, if the liquidity event is a listing on a national securities exchange, 30 days after the liquidity event occurs). Under the warrant, a liquidity event is defined as either (i) a listing of the common units on a national securities exchange, (ii) a business combination with or into an existing publicly-traded entity, or (iii) a sale of all or substantially all of our assets.

Through the completion of our Private Placement Offering on June 30, 2015, we issued approximately $233.0 million, or 23,300,410 of our common limited partner units, in exchange for proceeds to us, net of dealer manager fees and commissions and expenses, of $203.4 million. ATLS purchased 500,010 common units for $5.0 million during the offering. In connection with the issuance of common limited partner units, unitholders received 2,330,041 warrants to purchase our common units at an exercise price of $10.00 per unit.

During the six months ended June 30, 2015, we sold an aggregate of 5,956,400 common limited partner units at a gross offering price of $10.00 per unit. In connection with the issuance of common limited partner units, unitholders received 595,640 warrants to purchase our common limited partner units at an exercise price of $10.00 per unit.

 

 

NOTE 9 – CASH DISTRIBUTIONS

We have a cash distribution policy under which we distribute to holders of common units and Class A units on a quarterly basis a target distribution of $0.175 per unit, or $0.70 per unit per year, to the extent we have sufficient available cash after establishing appropriate reserves and paying fees and expenses, including reimbursements of expenses to the general partner and its affiliates. Distributions are generally paid within 45 days of the end of the quarter to unitholders of record on the applicable record date. Unitholders are entitled to receive distributions from us beginning with the quarter following the quarter in which we first admit them as limited partners.

During the six months ended June 30, 2016, we paid a distribution of $8.2 million to common limited partners ($0.1750 per unit per quarter) and $0.2 million to the general partner’s Class A units ($0.1750 per unit per quarter). During the six months ended June 30, 2015, we paid a distribution of $3.8 million to common limited partners ($0.1750 per unit per quarter) and $0.1 million to the general partner’s Class A units ($0.1750 per unit per quarter).

 

 

NOTE 10 – SUBSEQUENT EVENTS

Cash Distributions. On August 3, 2016, we declared a quarterly distribution of $0.1750 per common unit for the quarter ended June 30, 2016. The $4.2 million distribution, including $0.1 million to our general partner, will be paid on August 12, 2016 to unitholders of record at the close of business on June 30, 2016.

 

 

15

---

BUSINESS OVERVIEW

We are a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”) with operations primarily focused in the Eagle Ford Shale in south Texas. Our general partner, Atlas Growth Partners GP, LLC (“AGP GP”) owns 100% of the general partner Class A units and all of the incentive distribution rights through which it manages and effectively controls us.

At June 30, 2016, Atlas Energy Group, LLC (“ATLS” or “Atlas Energy”), a publicly traded Delaware limited liability company (OTC: ATLS) that manages and controls us through its general partner interest and through the terms of the partnership agreement, owned a 2.1% limited partner interest in us and 80% of AGP GP’s general partner Class A units, which are entitled to receive 2% of the cash distributed without any obligation to make further capital contributions. Current and former members of ATLS management own the remaining 20% interest in AGP GP’s general partner Class A units.

In addition to its general and limited partner interest in us, ATLS also holds general and limited partner interests in Atlas Resource Partners, L.P. (“ARP”), a publicly traded Delaware master-limited partnership (OTC: ARPJ) and an independent developer and producer of natural gas, oil and NGLs, with operations in basins across the United States, and in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, which incubate new MLPs and invest in existing MLPs.

FINANCIAL PRESENTATION

Our consolidated balance sheets at June 30, 2016 and December 31, 2015, and the consolidated statements of operations for the three and six months ended June 30, 2016 and 2015 include our accounts and our wholly-owned subsidiaries. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the consolidated balance sheets and related consolidated statements of operations. Actual balances and results could be different from those estimates. All significant intercompany transactions and balances have been eliminated in the consolidation of the financial statements.

RECENT DEVELOPMENTS

ARP Restructuring and Chapter 11 Bankruptcy Proceedings

 

On July 25, 2016, ARP and certain of its subsidiaries and ATLS, solely with respect to certain sections thereof, entered into a restructuring support agreement with ARP’s lenders (the “Restructuring Support Agreement”) for a prepackaged restructuring that will reduce debt on its balance sheet and position ARP for the future (the “Restructuring”). We and ARP are affiliates through the ownership by our common parent, ATLS. ARP’s Restructuring is expected to be completed before the end of the third quarter of 2016, after which ARP should emerge from Chapter 11, backed by its stakeholders, committed to investing capital to develop its exploration and production assets, as well as its tax-advantaged drilling partnership program.

 

On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York. The cases commenced thereby are being jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.”

 

We are not a party to the Restructuring Support Agreement, and the ARP Restructuring is not expected to materially impact us.

 

The ARP Restructuring is not expected to materially impact ATLS or its ownership interest in us, including ATLS’s control of our general partner, AGP GP. The debt structure of ATLS was recently modified, and ATLS is not a party to the ARP Restructuring. ATLS remains controlled by the same ownership group and management team and thus, the ARP Restructuring is not expected to have a material impact on the ability of management to operate us or the other ATLS businesses.

Effective Registration Statement. Our registration statement on Form S-1 (Registration Number: 333-207537) was declared effective by the Securities and Exchange Commission on April 5, 2016. We are offering in the aggregate up to 100,000,000 Class A common units and Class T common units, each representing limited partner interests in us, pursuant to a

16

---

primary offering on a "best efforts" basis. We must receive minimum offering proceeds of $1.0 million to break escrow, and the maximum offering proceeds of the primary offering may not exceed $1.0 billion. The Class A common units will be sold for a cash purchase price of $10.00 and the Class T common units will be sold for a cash purchase price of $9.60, with the remaining $0.40 constituting the Class T common unitholders' deferred payment obligation to us. We are also offering up to 21,505,376 Class A common units at $9.30 per unit pursuant to a distribution reinvestment plan.

Cash Distributions. On August 3, 2016, we declared a quarterly distribution of $0.1750 per common unit for the quarter ended June 30, 2016. The $4.2 million distribution, including $0.1 million to our general partner, will be paid on August 12, 2016 to unitholders of record at the close of business on June 30, 2016.

GENERAL TRENDS AND OUTLOOK

We expect our business to be affected by key trends in natural gas and oil production markets. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines since the fourth quarter of 2014 through the second quarter of 2016. The causes of these declines are based on a number of factors, including, but not limited to, a significant increase in natural gas, oil and NGL production. While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments in the development of new natural gas, oil and NGL reserves.

Our future gas and oil reserves, production, cash flow, our ability to make payments on our obligations and our ability to make distributions to our unitholders, including ATLS, depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. We face the challenge of natural production declines and volatile natural gas, oil and NGL prices. As initial reservoir pressures are depleted, natural gas and oil production from particular wells decrease. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. To the extent we would not have access to sufficient capital, our ability to drill and acquire more reserves would be negatively impacted.

RESULTS OF OPERATIONS

Gas and Oil Production

Production Profile. Currently, our gas and oil production revenues and expenses consist of our gas and oil production activities derived from our wells drilled in the Eagle Ford, Marble Falls and Mississippi Lime plays. We have established production positions in the following operating areas:

17

---

There were no gross or net dry wells drilled during the periods presented below. The following table presents the number of wells we drilled and the number of wells we turned in line, both gross and net during the periods indicated:

 

18

---

Production Volumes. The following table presents total net natural gas, crude oil and NGL production volumes and production volumes per day for the three and six months ended June 30, 2016 and 2015:

 

 

19

---

Production Revenues, Prices and Costs. Production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for oil. The following table presents our production revenues and average sales prices for our natural gas, oil, and natural gas liquids production for the three and six months ended June 30, 2016 and 2015 along with our average production costs, which include lease operating expenses, taxes, and transportation and compression costs, in each of the reported periods:

 

 

 

20

---

 

The increase in gas and oil production revenues for the three months ended June 30, 2016 as compared to the prior year period consisted of a $1.9 million increase attributable to production from our Eagle Ford operations, partially offset by a $0.3 million decrease attributable to our Marble Falls operations. The increase in gas and oil production revenues for the six months ended June 30, 2016 as compared to the prior year period consisted of a $3.3 million increase attributable to production from our Eagle Ford operations, partially offset by a $0.7 million decrease attributable to our Marble Falls operations and a $0.1 million decrease attributable to our Mississippi Lime operations.

The increase in gas and oil production expenses for the three months ended June 30, 2016 as compared to the prior year period primarily consisted of a $0.5 million increase attributable to our Eagle Ford operations, partially offset by a decrease of $0.2 million attributable to our Marble Falls operations. Total production costs per Mcfe decreased for the three months ended June 30, 2016 as compared to the prior year period primarily as a result of the decrease in our gas and oil production in Marble Falls and the addition of production in the Eagle Ford Shale, which has lower production costs per Mcfe.

The increase in gas and oil production expenses for the six months ended June 30, 2016 as compared to the prior year period primarily consisted of a $0.9 million increase attributable to our Eagle Ford operations, partially offset by a decrease of $0.4 million attributable to our Marble Falls operations. Total production costs per Mcfe decreased for the six months ended June 30, 2016 as compared to the prior year period primarily as a result of the decrease in our gas and oil production in Marble Falls and the addition of production in the Eagle Ford Shale, which has lower production costs per Mcfe.

OTHER REVENUES AND EXPENSES

 

 

Gain (Loss) on Mark-to-Market Derivatives. We recognize changes in fair value of derivatives immediately within gain (loss) on mark-to-market derivatives on our condensed consolidated statements of operations. The recognized losses during the three and six months ended June 30, 2016 are related to the change in oil prices during the three and six months ended June 30, 2016 as compared to the prior year period.

 

General and Administrative Expenses. The decrease for the three months ended June 30, 2016 as compared to the prior year period was due to a $0.1 million decrease in other corporate activities. The decrease for the six months ended June 30, 2016 as compared to the prior year period was due to a $1.8 million decrease in salaries, wages and other corporate activity costs allocated to us by ATLS and ARP in connection with the completion of our private placement offering in June 2015.

21

---

Depreciation, Depletion and Amortization. The increase in depreciation, depletion and amortization for the three and six months ended June 30, 2016 was primarily due to a $2.5 million and a $5.2 million increase in our depletion expense as compared to the prior year period, respectively.  The following table presents our depletion expense per Mcfe for our operations for the respective periods (in thousands, except per Mcfe data):

 

 

The increases in depletion expense, depletion expenses as a percentage of gas and oil revenues and depletion expenses per Mcfe, were primarily due to an increase in our depletion expense associated with the expansion of our Eagle Ford operations, partially offset by a decrease in oil volumes from our Marble Falls operations.

LIQUIDITY AND CAPITAL RESOURCES

General

We have historically funded our operations, acquisitions and cash distributions primarily through cash generated from operations and financing activities, including our private placement offering completed in June 2015. Our future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted our revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on our liquidity position.

Cash Flows— Six Months Ended June 30, 2016 Compared with the Six Months Ended June 30, 2015

 

 

The change in cash flows provided by (used in) operating activities when compared with the comparable prior year period was primarily due to:

The change in cash flows used in investing activities when compared with the comparable prior year period was primarily due to:

22

---

The change in cash flows (used in) provided by financing activities when compared with the comparable prior year period was primarily due to:

Capital Requirements

At June 30, 2016, our capital expenditures primarily relate to our well drilling and leasehold acquisition costs. The following table summarizes our total capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):

 

 

During the three months ended June 30, 2016, our total capital expenditures consisted primarily of $0.6 million for wells drilled compared with $3.0 million for the comparable prior year period and approximately $3,000 of leasehold acquisition costs compared with $0.2 million for the prior year comparable period.

During the six months ended June 30, 2016, our total capital expenditures consisted primarily of $6.0 million for wells drilled compared with $12.3 million for the comparable prior year period and $0.1 million of leasehold acquisition costs compared with $0.8 million for the prior year comparable period.

As of June 30, 2016, we did not have any commitments for our drilling and completion and capital expenditures, excluding acquisitions.

OFF BALANCE SHEET ARRANGEMENTS

As of June 30, 2016, we did not have any off-balance sheet commitment arrangements for our drilling and completion and capital expenditures, excluding acquisitions 

CREDIT FACILITY

On May 1, 2015, we entered into a secured credit facility agreement with Wells Fargo. As of June 30, 2016, the lenders under the credit facility have no commitment to lend to us and we have a zero-dollar borrowing base under the credit facility, but we and our subsidiaries have the ability to enter into derivative contracts to manage our exposure to commodity price movements that will benefit from the collateral securing the credit facility. Obligations under the credit facility are secured by mortgages on our oil and gas properties and first priority security interest in substantially all of our assets. The credit facility may be amended in the future if we request a borrowing base redetermination and the lenders agree to establish the borrowing base and related commitments thereunder. We may request a borrowing base redetermination under our secured credit facility. We are in discussions with our lenders to set a borrowing base for our credit facility. If the borrowing base is redetermined to an amount greater than zero dollars, the credit facility would allow us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semiannually by our lenders in their sole discretion. Once established, our borrowing base will be subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil and natural gas reserves, which takes into account the prevailing oil and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. A future decline in commodity prices could result in a redetermination that lowers our borrowing base at that time and, in such case, we could be required to repay any indebtedness outstanding at that time in excess of the borrowing base. If we borrow under the credit facility and we are unable to repay any borrowings in excess of a decreased borrowing base, we would be in default and no longer able to make any distributions to our unitholders.

In addition, our credit facility includes customary events of default, including failure to timely pay, breach of covenants, bankruptcy, cross-default with other material indebtedness (including obligations under swap agreements in excess of any agreed upon threshold amount), and change of control.

23

---

ISSUANCE OF UNITS

On April 5, 2016, we announced that the registration statement on Form S-1 (Registration Number: 333-207537) was declared effective by the Securities and Exchange Commission.

Under the terms of our initial offering, we offered in a private placement $500.0 million of our common limited partner units. The termination date of the private placement offering was December 31, 2014, subject to two 90 day extensions to the extent that we had not sold $500.0 million of common units at any extension date. We exercised each of such extensions. Under the terms of the offering, an investor received, for no additional consideration, warrants to purchase additional common units in an amount equal to 10% of the common units purchased by such investor. The warrants are exercisable at a price of $10.00 per common unit being purchased and may be exercised from and after the warrant date (generally, the date upon which we give the holder notice of a liquidity event) until the expiration date (generally, the date that is one day prior to the liquidity event or, if the liquidity event is a listing on a national securities exchange, 30 days after the liquidity event occurs). Under the warrant, a liquidity event is defined as either (i) a listing of the common units on a national securities exchange, (ii) a business combination with or into an existing publicly-traded entity, or (iii) a sale of all or substantially all of our assets.

Through the completion of our private placement offering on June 30, 2015, we issued approximately $233.0 million, or 23,300,410 of our common limited partner units, in exchange for proceeds to us, net of dealer manager fees and commissions and expenses, of $203.4 million. ATLS purchased 500,010 common units for $5.0 million during the offering. In connection with the issuance of common limited partner units, unitholders received 2,330,041 warrants to purchase our common units at an exercise price of $10.00 per unit.

During the six months ended June 30, 2015, we sold an aggregate of 5,956,400 of its common limited partner units at a gross offering price of $10.00 per unit. In connection with the issuance of common limited partner units, unitholders received 595,640 warrants to purchase our common limited partner units at an exercise price of $10.00 per unit.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

For a more complete discussion of the accounting policies and estimates that we have identified as critical in the preparation of our condensed consolidated financial statements, please refer to our Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Form S-1.

Recently Issued Accounting Standards

See Note 2 to our condensed consolidated financial statements for additional information related to recently issued accounting standards.

 

 

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and commodity prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of the market risk-sensitive instruments were entered into for purposes other than trading.

General

All of our assets and liabilities are denominated in U.S. dollars, and as a result, we do not have exposure to currency exchange risks.

We are exposed to various market risks, principally changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We manage these risks through regular operating and financing activities and periodic use of derivative financial instruments such as forward contracts and swap agreements. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on June 30, 2016. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our business.

24

---

Current market conditions elevate our concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us, if any. The counterparties related to our commodity derivative contracts are banking institutions or their affiliates, who also participate in ARP’s revolving credit facilities. The creditworthiness of our counterparties is monitored, and we currently believe them to be financially viable. We are not aware of any inability on the part of our counterparties to perform under their contracts and believe our exposure to non-performance is remote.

Commodity Price Risk. Our market risk exposures to commodities are due to the fluctuations in the commodity prices and the impact those price movements have on our financial results. To limit the exposure to changing commodity prices, we use financial derivative instruments, including financial swap and option instruments, to hedge portions of future production. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under these swap agreements, we receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not the obligation, to purchase or sell commodities at a fixed price for the relevant period.

Holding all other variables constant, including the effect of commodity derivatives, a 10% change in average commodity prices would result in a change to our net loss for the twelve-month period ending June 30, 2017 of approximately $1.8 million.

Realized pricing of natural gas, oil, and natural gas liquids production is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas, oil and natural gas liquids production. Pricing for natural gas, oil and natural gas liquids production has been volatile and unpredictable for many years.

As of June 30, 2016, we had the following commodity derivatives:

Crude Oil – Fixed Price Swaps

 

 

(1)“Bbl” represents barrels.

(2)The production volumes for 2016 include the remaining six months of 2016 beginning July 1, 2016.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2016, our disclosure controls and procedures were effective at the reasonable assurance level.

There have been no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

25

---

PART II

 

(1) Previously filed as an exhibit to registration statement on Form S-1 (File No. 333-207537) filed on October 21, 2015.

(2) Previously filed as an exhibit to Current Report on Form 8-K filed on April 6, 2016.

(3) Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed”.

26

---

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

 

 

27