UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

 

(Mark One)

 

For the quarterly period ended March 31, 2016

 

OR

 

For the transition period from               to              

Commission file number: 001-36725

 

Atlas Energy Group, LLC

(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  x    No  o

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  o

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  o    No  x

The number of outstanding common units of the registrant on May 12, 2016 was 26,027,992.

 

 

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ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

TABLE OF CONTENTS

 

 

 

 

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES

CONDENSED COMBINED CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

 

 

See accompanying notes to condensed combined consolidated financial statements.

 

 

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ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES

CONDENSED COMBINED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

 

 

See accompanying notes to condensed combined consolidated financial statements.

 

 

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ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES

CONDENSED COMBINED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)

 

 

See accompanying notes to condensed combined consolidated financial statements.

 

 

 

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ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES

CONDENSED COMBINED CONSOLIDATED STATEMENT OF UNITHOLDERS’ EQUITY

(in thousands, except unit data)

(Unaudited)

 

 

See accompanying notes to condensed combined consolidated financial statements.

 

 

 

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ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES

CONDENSED COMBINED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

 

 

See accompanying notes to condensed combined consolidated financial statements.

 

 

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ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

NOTE 1—BASIS OF PRESENTATION

We are a publicly traded (OTCQX: ATLS) Delaware limited liability company formed in October 2011. Unless the context otherwise requires, references to “Atlas Energy Group, LLC,” “the Company,” “we,” “us,” “our” and “our company,” refer to Atlas Energy Group, LLC, and our combined and consolidated subsidiaries.

On February 27, 2015, our former owner, Atlas Energy, L.P. (“Atlas Energy”), transferred its assets and liabilities, other than those related to its midstream assets, to us, and effected a pro rata distribution of our common units representing a 100% interest in us, to Atlas Energy’s unitholders (the “Separation”). Concurrently with the distribution of our units, Atlas Energy and its remaining midstream interests merged with Targa Resources Corp. (“Targa”; NYSE: TRGP) and ceased trading.

At March 31, 2016, our operations primarily consisted of our ownership interests in the following:

At March 31, 2016, we had 26,027,992 common limited partner units issued and outstanding. The common units are a class of limited liability company interests in us. The holders of common units are entitled to participate in company distributions and exercise the rights or privileges available to holders of common units as outlined in the limited liability company agreement.

The accompanying condensed combined 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 Form 10-K. It is suggested that these interim condensed combined consolidated financial

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statements be read in conjunction with the financial statements and the notes thereto included in our latest Annual Report Form 10-K. 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. Certain amounts in the prior year’s financial statements have been reclassified to conform to the current year presentation due to the adoption of certain accounting standards (see Note 4). 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 and Combination

Our condensed combined consolidated financial statements for the three months ended March 31, 2016 and 2015, subsequent to the transfer of assets on February 27, 2015, include our accounts and accounts of our subsidiaries. Our condensed combined consolidated financial statements for the portion of 2015 which is prior to the transfer of assets on February 27, 2015, were derived from the separate records maintained by Atlas Energy and may not necessarily be indicative of the conditions or results of operations that would have existed if we had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various entities comprising us, Atlas Energy’s net investment in us is shown as equity in the condensed combined consolidated financial statements. U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed combined consolidated balance sheets and related condensed combined consolidated statements of operations. Such estimates included allocations made from the historical accounting records of Atlas Energy, based on management’s best estimates, in order to derive the financial statements of us. Actual balances and results could be different from those estimates. Transactions between us and other Atlas Energy operations have been identified in the condensed combined consolidated financial statements as transactions between affiliates.

In connection with Atlas Energy’s merger with Targa and the concurrent Separation, we were required to repay $150.0 million of Atlas Energy’s term loan credit facility, which was issued in July 2013 for $240.0 million. In accordance with U.S. GAAP, we included $150.0 million of Atlas Energy’s original term loan at the time of issuance, and the related interest expense, within our historical financial statements. Atlas Energy’s other historical borrowings were allocated to our historical financial statements in the same ratio. We used proceeds from the issuance of our Series A preferred units (see Note 9) and borrowings under our term loan credit facilities to fund the $150.0 million payment.

We determined that ARP and AGP are variable interest entities (“VIE’s”) based on their respective partnership agreements, our power, as the general partner, to direct activities that most significantly impact their economic performance, and our ownership of the incentive distribution rights. Accordingly, we consolidate the financial statements of ARP and AGP into our condensed combined consolidated financial statements. Our VIE’s operating results and assets balances are presented separately in Note 11 – Operating Segment Information. As the general partner for both ARP and AGP, we have unlimited liability for the obligations of ARP and AGP except for those contractual obligations that are expressly made without recourse to the general partner. The non-controlling interests in ARP and AGP are reflected as (income) loss attributable to non-controlling interests in the condensed combined consolidated statements of operations and as a component of unitholders’ equity on the condensed combined consolidated balance sheets. All material intercompany transactions have been eliminated.

In accordance with established practice in the oil and gas industry, our condensed combined consolidated financial statements include our pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Drilling Partnerships in which ARP has an interest. Such interests generally approximate 30%. Our condensed combined consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of ARP’s Drilling Partnerships. Rather, ARP calculates these items specific to its own economics.

On June 5, 2015, ARP completed the acquisition of our coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma for approximately $31.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). ARP funded the purchase price using proceeds from the issuance of 6,500,000 common limited partner units. The Arkoma Acquisition had an effective date of January 1, 2015. ARP accounted for the Arkoma Acquisition as a transaction between entities under common control in its standalone consolidated financial statements.

Use of Estimates

The preparation of our condensed combined 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 combined consolidated financial statements, as well as

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the reported amounts of revenue and costs and expenses during the reporting periods. Our condensed combined consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization and fair value of derivative instruments. Such estimates included estimated allocations made from the historical accounting records of Atlas Energy in order to derive the historical financial statements of us. The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Actual results could differ from those estimates.

Liquidity and Capital Resources

Our primary sources of liquidity are cash distributions received with respect to our ownership interests in ARP, AGP, and Lightfoot. Our primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures, and distributions to unitholders, which we expect to fund through operating cash flow, and cash distributions received.

We rely on the cash flows from the distributions received on our ownership interests in ARP, AGP, and Lightfoot. The amount of cash that ARP and AGP can distribute to their partners, including us, principally depends upon the amount of cash they each generate from their operations. ARP’s and AGP’s 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 ARP’s and AGP’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on ARP’s and AGP’s liquidity position and ability to make distributions. Reductions of such distributions to us would adversely affect our ability to fund our cash requirements and obligations and meet our financial covenants under our credit agreements.

On May 5, 2016, the Board of Directors elected to suspend ARP’s common unit and Class C preferred distributions, beginning with the month of March of 2016, due to the continued lower commodity price environment. As a result of ARP’s distribution suspension and uncertainty regarding future covenant compliance, we classified $70.8 million of our outstanding amounts on our first and second lien credit agreements, net of $0.2 million deferred financing costs, as current portion of long-term debt within our condensed combined consolidated balance sheet as of March 31, 2016. To the extent commodity prices remain low or decline further, we, ARP or AGP experience disruptions in the financial markets impacting our/their respective longer-term access to or cost of capital, or ARP experiences any of the other impacts to its liquidity discussed below, our/their respective ability to fund capital expenditures or future growth projects may be further impacted. Based on projected market conditions, continued declines in commodity prices and recent conversations with its administrative agent, ARP expects that its borrowing base will be redetermined to a level below its outstanding borrowings of $672.0 million under the ARP Credit Agreement (as defined below) as of March 31, 2016.  If ARP’s borrowing base is redetermined below its current outstanding borrowings and ARP is unable to repay the deficiency or deposit additional collateral to eliminate such deficiency, or if ARP experiences any other event of default on its debt obligations, or if other debt agreements cross-default, and the lenders accelerate the maturity of any other outstanding debts, we and ARP, as applicable, will not have sufficient liquidity to repay all of the outstanding indebtedness, and as a result, there would be substantial doubt regarding our ability to continue as a going concern.

We, ARP and AGP continually monitor our/their respective capital markets and their capital structures and may make changes from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening the balance sheet, meeting debt service obligations and/or achieving cost efficiency. For example, we and ARP could pursue options such as refinancing, restructuring or reorganizing our/its indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address its liquidity concerns and high debt levels. There is no certainty that we or ARP will be able to implement any such options, and we and ARP cannot provide any assurances that any refinancing or changes to our or its debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for its stakeholders, including cancellation of debt income (“CODI”) which would be directly allocated to its unitholders and reported on such unitholders’ separate returns (see Item 1A – Risk Factors for additional information). It is possible additional adjustments to our, ARP’s or AGP’s strategic plan and outlook may occur based on market conditions and our/their respective needs at that time, which could include selling assets, liquidating all or a portion of ARP’s hedge portfolio, seeking additional partners to develop our/their respective assets, reducing or suspending the payments of distributions to preferred unitholders and/or reducing our/their respective planned capital programs. Strategies involving further reduction or suspension of distributions to unitholders by AGP would adversely affect our ability to fund our cash requirements and obligations.

Atlas Resource Partners - Liquidity and Capital Resources

 

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ARP has historically funded its operations, acquisitions and cash distributions primarily through cash generated from operations, amounts available under its credit facilities and equity and debt offerings. ARP’s future cash flows are subject to a number of variables, including oil and natural gas prices. The lower commodity prices discussed above have negatively impacted ARP’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on ARP’s liquidity position.

On May 10, 2016, ARP entered into a ninth amendment (the “Ninth Amendment”) to its Second Amended and Restated Credit Agreement, dated July 31, 2013 (as amended from time to time, the “ARP Credit Agreement”), with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, to, among other things, waive the requirement that ARP’s ratio of current assets to current liabilities (as calculated pursuant to the ARP Credit Agreement) not be less than 1.0 to 1.0 as of March 31, 2016 and waive the requirement that ARP’s ratio of the total First Lien Debt to EBITDA (as calculated pursuant to the ARP Credit Agreement) not be greater than 2.75 to 1.0 as of March 31, 2016, and required ARP to repay $2.5 million of outstanding borrowings. ARP is party to a Second Lien Credit Agreement, dated February 23, 2015, with certain lenders and Wilmington Trust, National Association, as administrative agent (the “ARP Term Loan Facility”), which contains the same financial covenants as those in the ARP Credit Agreement, and were automatically waived as a result of the Ninth Amendment to the Credit Agreement. Based on the terms of the Ninth Amendment to the ARP Credit Agreement and uncertainty regarding future covenant compliance, we classified $672.0 million of ARP’s outstanding amounts under the ARP Credit Agreement and $234.2 million of ARP’s outstanding amounts under the ARP Term Loan Facility, net of $10.0 million deferred financing costs and $5.8 million unamortized discount, as current portion of long-term debt within our condensed consolidated balance sheet as of March 31, 2016.

ARP’s borrowing base, and thus its borrowing capacity, under the ARP Credit Agreement is impacted by the level of its oil and natural gas reserves. Downward revisions of its oil and natural gas reserves volume and value due to low commodity prices, the impact of lower estimated capital spending in response to lower prices, performance revisions, sales of assets or the incurrence of certain types of additional debt, among other items, could cause a reduction of its borrowing base in the future, and these reductions could be significant.  The ARP Credit Agreement is currently in the process of its semi-annual redetermination. Based on projected market conditions, continued declines in commodity prices and recent conversations with its administrative agent, ARP expects that its borrowing base will be redetermined to a level below its outstanding borrowings of $672.0 million under the ARP Credit Agreement as of March 31, 2016. In the case of a borrowing base deficiency, the ARP Credit Agreement requires ARP to repay the deficiency, which it is permitted to do in equal monthly installments over a four-month period, or deposit additional collateral to eliminate such deficiency.  If ARP’s borrowing base is redetermined below its current outstanding borrowings and ARP is unable to repay the deficiency or deposit additional collateral to eliminate such deficiency, there would be substantial doubt regarding ARP’s ability to continue as a going concern.

In addition, if ARP is unable to remain in compliance with the covenants under its credit facilities or the indentures governing its senior notes, absent relief from its lenders or noteholders, as applicable, ARP may be forced to repay or refinance such indebtedness. Upon the occurrence of an event of default, the lenders under ARP’s credit facilities or holders or its notes, as applicable, could elect to declare all amounts outstanding immediately due and payable and the lenders could terminate all commitments to extend further credit. A breach of any of the covenants (including if ARP’s borrowing base is redetermined below its current outstanding borrowings and it is unable to repay the deficiency or deposit additional collateral to eliminate such deficiency) in these credit facilities or the indentures governing ARP’s senior notes, respectively, could result in an event of default thereunder as well as a cross-default under ARP’s other debt agreements and, in either case, our credit agreement.  If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, ARP will not have sufficient liquidity to repay all of its outstanding indebtedness, and as a result, there would be substantial doubt regarding ARP’s ability to continue as a going concern.  

As discussed above, ARP continually monitors the capital markets and its capital structure and may make changes to its capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening its balance sheet, meeting its debt service obligations and/or achieving cost efficiency. Although ARP has a significant hedge position for the remainder of 2016 through 2018, the forecasted long-term downturn in commodity prices has had a detrimental impact on ARP’s financial position. For example, ARP could pursue options such as refinancing, restructuring or reorganizing its indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address its liquidity concerns and high debt levels. ARP is evaluating various options with the lenders under the ARP Credit Agreement and ARP Term Loan Facility, and holders of ARP’s Senior Notes, but there is no certainty that ARP will be able to implement any such options, and ARP cannot provide any assurances that any refinancing or changes in its debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for its stakeholders, including CODI which would be

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directly allocated to its unitholders and reported on such unitholders’ separate returns (see Item 1A – Risk Factors for additional information).  

ARP also continues to implement various cost saving measures to reduce its capital, operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. ARP will continue to be opportunistic and aggressive in managing its cost structure and, in turn, its liquidity to meet its capital and operating needs. ARP cannot provide any assurances that any of these efforts will be successful or will result in cost reductions or cash flows or the timing of any such cost reductions or additional cash flows. It is also possible additional adjustments to ARP’s plan and outlook may occur based on market conditions and ARP’s needs at that time, which could include selling assets, liquidating all or a portion of its hedge portfolio, seeking additional partners to develop its assets, reducing or suspending the payments of distributions to preferred unitholders and/or reducing its planned capital program.  In addition, to the extent commodity prices remain low or decline further, or ARP experiences disruptions in ARP’s longer-term access to or cost of capital, ARP’s ability to fund future capital expenditures or growth projects may be further impacted.  

Atlas Growth Partners - Liquidity and Capital Resources

 

AGP has historically funded its operations, acquisitions and cash distributions primarily through cash generated from operations and financing activities, including its recent private placement. AGP’s 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 AGP’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on AGP’s liquidity position.

Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common unitholders per unit is computed by dividing net income (loss) attributable to common unitholders, which is determined after the deduction of net income attributable to participating securities and the preferred unitholders’ interests, if applicable, by the weighted average number of common unitholders units outstanding during the period.

Unvested unit-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities. A portion of our phantom unit awards, which consist of common units issuable under the terms of our long-term incentive plans and incentive compensation agreements, contain non-forfeitable rights to distribution equivalents. The participation rights result in a non-contingent transfer of value each time we declare a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis.

The following is a reconciliation of net income (loss) allocated to the common unitholders for purposes of calculating net income (loss) attributable to common unitholders per unit (in thousands, except unit data):

 

 

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Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards and convertible preferred units, as calculated by the treasury stock or if converted methods, as applicable. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of our long-term incentive plan.

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

 

 

Rabbi Trust

In 2011, we established an excess 401(k) plan relating to certain executives. In connection with the plan, we established a “rabbi” trust for the contributed amounts. At March 31, 2016 and December 31, 2015, we reflected $3.9 million and $5.6 million, respectively, related to the value of the rabbi trust within other assets, net on our condensed combined consolidated balance sheets, and recorded corresponding liabilities of $3.9 million and $5.6 million as of those same dates, respectively, within asset retirement obligations and other on our condensed combined consolidated balance sheets. During the three months ended March 31, 2016, a $2.3 million distribution was made to participants related to the rabbi trust. No distributions were made to participants related to the rabbi trust for the three months ended March 31, 2015.

Recently Issued 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 combined consolidated financial statements.

In August 2015, the FASB updated the accounting guidance related to the balance sheet presentation of debt issuance costs specific to line-of-credit arrangements. The updated accounting guidance allows the option of presenting deferred debt issuance costs related to line-of-credit arrangements as an asset, and subsequently amortizing over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. We adopted the updated accounting guidance effective January 1, 2016 and it did not have a material impact on our condensed combined consolidated financial statements.

In February 2015, the FASB updated the accounting guidance related to consolidation under the variable interest entity and voting interest entity models. The updated accounting guidance modifies the consolidation guidance for variable interest entities, limited partnerships and similar legal entities. We adopted this accounting guidance upon its effective date of January 1, 2016, and it did not have a material impact on our condensed combined consolidated financial statements.

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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 combined consolidated financial statements. 

In May 2014, the FASB updated the accounting guidance 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. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. We are currently in the process of determining the impact that the updated accounting guidance will have on our condensed combined 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 three months ended March 31, 2016 and 2015, we recognized $18.7 million and $26.4 million, respectively, of non-cash property, plant and equipment additions, within the changes in accounts payable and accrued liabilities on our condensed combined consolidated statements of cash flows.

ARP capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP were 6.7% and 6.1% for the three months ended March 31, 2016 and 2015, respectively. The amounts of interest capitalized by ARP was $2.4 million and $3.9 million for the three months ended March 31, 2016 and 2015, respectively.

For the three months ended March 31, 2016 and 2015, we recorded $1.7 million and $1.6 million, respectively, of accretion expense related to ARP and AGP’s asset retirement obligations within in depreciation, depletion and amortization in our condensed combined consolidated statements of operations. For the three months ended March 31, 2016 and 2015, ARP incurred liabilities of $2.8 million and $0.2 million, respectively, in asset retirement obligations in our condensed consolidated balance sheet due to the liquidation of some of ARP’s Drilling Partnerships.

 

 

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NOTE 4—DEBT

Total debt consists of the following at the dates indicated (in thousands):

 

 

In April 2015, the FASB updated the accounting guidance related to the balance sheet presentation of debt issuance costs. The updated accounting guidance requires that debt issuance costs be presented as a direct deduction from the associated debt obligation. We adopted this accounting guidance upon its effective date of January 1, 2016. The retrospective effect of the reclassification resulted in the following changes:  

 

Cash Interest. Cash payments for interest by us and our subsidiaries on our/their respective borrowings were $42.6 million and $38.5 million for the three months ended March 31, 2016 and 2015, respectively.

 

Term Loan Facilities

First Lien Credit Facility. On March 30, 2016, we, together with New Atlas Holdings, LLC (the “Borrower”) and Atlas Lightfoot, LLC, entered into a third amendment (the “Third Amendment”) to our credit agreement with Riverstone Credit Partners, L.P., as administrative agent (“Riverstone”), and the lenders (the “Lenders”) from time to time party thereto (the “First Lien Credit Agreement”).

The outstanding loans under the First Lien Credit Agreement were bifurcated between the existing First Lien Credit Agreement and the new Second Lien Credit Agreement (defined below), with $35.0 million and $35.8 million (including $2.4 million in deemed prepayment premium) in borrowings outstanding, respectively. In connection with the execution of the Third Amendment, the Borrower made a prepayment of approximately $4.25 million of the outstanding principal, which was classified as current portion of long-term debt on our condensed combined consolidated balance sheet at December 31, 2015, and $0.5 million of interest. The Third Amendment amended the First Lien Credit Agreement to, among other things:

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Second Lien Credit Agreement. Also on March 30, 2016, we and the Borrower entered into a new second lien credit agreement (the “Second Lien Credit Agreement”) with Riverstone and the Lenders. As described above, $35.8 million of the indebtedness previously outstanding under the First Lien Credit Agreement was moved under the Second Lien Credit Agreement.

The Second Lien Credit Agreement matures on March 30, 2019, subject to an optional extension (the “Extension Option”) to March 30, 2020, assuming certain conditions are met, including a Total Leverage Ratio (as defined in the Second Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee. Borrowings under the Second Lien Credit Agreement are secured on a second priority basis by security interests in the same collateral that secures borrowings under the First Lien Credit Agreement.

Borrowings under the Second Lien Credit Agreement bear interest at a rate of 30%, payable in-kind through an increase in the outstanding principal. If the First Lien Credit Agreement is repaid in full prior to March 30, 2018, the rate will be reduced to 20%. If the Extension Option is exercised, the rate will again be increased to 30%. If our market capitalization is greater than $75 million, we can issue common units in lieu of increasing the principal to satisfy the interest obligation.

The Borrower may prepay the borrowings under the Second Lien Credit Agreement without premium at any time. The Second Lien Credit Agreement includes the same mandatory prepayment events as the First Lien Credit Agreement, subject to the Borrower’s discretion to prepay either the First Lien Credit Agreement or the Second Lien Credit Agreement.

The Second Lien Credit Agreement contains the same negative and affirmative covenants and events of default as the First Lien Credit Agreement, including customary covenants that limit the Borrower’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions. In addition, the Second Lien Credit Agreement requires that we maintain an Asset Coverage Ratio (as defined in the Second Lien Credit Agreement) of not less than 2.00 to 1.00 as of September 30, 2017 and each fiscal quarter ending thereafter.

In connection with the Second Lien Credit Agreement, on April 27, 2016, we issued to the Lenders, warrants (the “Warrants”) to purchase up to 4,668,044 common units representing limited partner interests at an exercise price of $0.20 per unit. The Warrants expire on March 30, 2026 and are subject to customary anti-dilution provisions. On April 27, 2016, we entered into a registration rights agreement pursuant to which we agreed to register the offer and resale of our common units underlying the Warrants as well as any common units issued as in-kind interest payments under the Second Lien Credit Agreement.

As a result of the Third Amendment to the First Lien Credit Agreement and the Second Lien Credit Agreement, ARP’s distribution suspension and uncertainty regarding ARP’s future covenant compliance, we classified $70.8 million of our outstanding amounts on our first and second lien credit agreements, net of $0.2 million deferred financing costs, as current portion of long-term debt within our condensed combined consolidated balance sheet as of March 31, 2016.   we and ARP’s future debt maturities, excluding any future payment-in-kind interest payments, are as follows: $992.9 million and $667.7 million respectively, for the years ending December 31, 2017 and 2021, respectively.

In connection with the Term Loan Facilities, the lenders thereunder syndicated participations in loans underlying the facilities.  As a result, certain of the Company’s current and former officers participated in approximately 12% of the loan syndication and warrants and a foundation affiliated with 5% or more unitholder participated in approximately 12% of the loan syndication.

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ARP Credit Facility

ARP is a party to a ARP Credit Agreement with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, which provides for a senior secured revolving credit facility with a borrowing base of $700.0 million as of March 31, 2016 and a maximum facility amount of $1.5 billion scheduled to mature in July 2018. At March 31, 2016, $672.0 million was outstanding under the credit facility.

ARP’s borrowing base is scheduled for semi-annual redeterminations in May and November of each year. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which $4.2 million was outstanding at March 31, 2016. ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. At March 31, 2016, the weighted average interest rate on outstanding borrowings under the credit facility was 3.6%.

The ARP Credit Agreement contains customary covenants including, without limitation, covenants that limit ARP’s ability to incur additional indebtedness (but which permits second lien debt in an aggregate principal amount of up to $300.0 million and third lien debt that satisfies certain conditions including pro forma financial covenants), grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merge or consolidate with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets.  The ARP Credit Agreement also requires that ARP maintain a ratio of First Lien Debt to EBITDA (ratio as defined in the Credit Agreement) of not greater than 2.75 to 1.00, and a ratio of current assets to current liabilities (ratio as defined in the ARP Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

On May 10, 2016, ARP entered into the Ninth Amendment to the ARP Credit Agreement, to, among other things, waive the requirement that ARP’s ratio of current assets to current liabilities (as calculated pursuant to the ARP Credit Agreement) not be less than 1.0 to 1.0 as of March 31, 2016 and waive the requirement that ARP’s ratio of the total First Lien Debt to EBITDA (as calculated pursuant to the ARP Credit Agreement) not be greater than 2.75 to 1.0 as of March 31, 2016, and required ARP to repay $2.5 million of outstanding borrowings. As a result of the Ninth Amendment to the ARP Credit Agreement and uncertainty regarding future covenant compliance, we classified $672.0 million of ARP’s outstanding amounts under the ARP Credit Agreement as current portion of long-term debt within our condensed consolidated balance sheet as of March 31, 2016. See Note 2 for additional disclosure regarding ARP’s liquidity and capital resources.

ARP’s Credit Agreement is currently in the process of its semi-annual redetermination. Based on projected market conditions, continued declines in commodity prices and recent conversations with its administrative agent, ARP expects that its borrowing base will be redetermined to a level below its outstanding borrowings under the ARP Credit Agreement as of March 31, 2016. In the case of a borrowing base deficiency, the ARP Credit Agreement requires ARP to repay the deficiency, which it is permitted to do in equal monthly installments over a four-month period, or deposit additional collateral to eliminate such deficiency.  See Note 2 for additional disclosure regarding our liquidity and capital resources.

ARP Term Loan Facility

ARP is party to the ARP Term Loan Facility, which provides for a second lien term loan in an original principal amount of $250.0 million. The ARP Term Loan Facility matures on February 23, 2020. The ARP Term Loan Facility is presented in the table above net of unamortized discount of $5.8 million at March 31, 2016.

ARP’s obligations under the ARP Term Loan Facility are secured on a second priority basis by security interests in all of its assets and those of its restricted subsidiaries that guarantee ARP’s existing first lien revolving credit facility. In addition, the obligations under the ARP Term Loan Facility are guaranteed by ARP’s material restricted subsidiaries. At March 31, 2016, the weighted average interest rate on outstanding borrowings under the ARP Term Loan Facility was 10.0%.

The ARP Term Loan Facility contains customary covenants including, without limitation, covenants that limit ARP’s ability to make restricted payments, take on indebtedness, issue preferred stock, grant liens, conduct sales of assets and subsidiary stock, make distributions from restricted subsidiaries, conduct affiliate transactions and engage in other business activities. In addition, the ARP Term Loan Facility contains covenants substantially similar to those in the ARP Credit Agreement, including, among others, restrictions on swap agreements, debt of unrestricted subsidiaries, drilling and operating agreements and the sale or discount of receivables. The financial covenants of the Term Loan Facility were automatically waived as a result of the Ninth Amendment to the Credit Agreement. Based on the terms of the Ninth Amendment to the ARP Credit Agreement and uncertainty regarding future covenant compliance, we classified $234.2 million of ARP’s outstanding amounts under the ARP Term Loan Facility, net of $10.0 million deferred financing costs and $5.8 million

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unamortized discount, as current portion of long-term debt within our condensed consolidated balance sheet as of March 31, 2016. See Note 2 for additional disclosure regarding our liquidity and capital resources.

ARP Senior Notes

At March 31, 2016, ARP had $354.4 million outstanding of its 7.75% senior unsecured notes due 2021 (“7.75% ARP Senior Notes”). The 7.75% ARP Senior Notes were presented net of a $0.4 million unamortized discount as of March 31, 2016.

At March 31, 2016, ARP had $312.1 million outstanding of its 9.25% senior unsecured notes due 2021 (“9.25% ARP Senior Notes”). The 9.25% ARP Senior Notes were presented net of a $0.9 million unamortized discount as of March 31, 2016.

In January and February 2016, ARP executed transactions to repurchase portions of its senior unsecured notes.  As of March 31, 2016, ARP repurchased approximately $20.3 million of its 7.75% Senior Notes due 2021 and approximately $12.1 million of its 9.25% Senior Notes due 2021 for approximately $5.5 million, which includes $0.6 million of interest.  As a result of these transactions, ARP recognized approximately $26.5 million as gain on early extinguishment of debt in the first quarter of 2016.

The 7.75% ARP Senior Notes and 9.25% ARP Senior Notes are guaranteed by certain of ARP’s material subsidiaries. The guarantees under the 7.75% ARP Senior Notes and 9.25% ARP Senior Notes are full and unconditional and joint and several, subject to certain customary automatic release provisions, including, in certain circumstances, the sale or other disposition of all or substantially all the assets of, or all of the equity interests in, the subsidiary guarantor, or the subsidiary guarantor is declared “unrestricted” for covenant purposes, and any subsidiaries of ARP, other than the subsidiary guarantors, are minor. There are no restrictions on ARP’s ability to obtain cash or any other distributions of funds from the guarantor subsidiaries.

The indentures governing the 7.75% ARP Senior Notes and 9.25% ARP Senior Notes contain covenants including, without limitation, covenants that limit ARP’s ability to incur certain liens, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of ARP’s assets. ARP was in compliance with these covenants as of March 31, 2016.

 

 

NOTE 5—DERIVATIVE INSTRUMENTS

ARP and AGP use a number of different derivative instruments, principally swaps and options, in connection with their commodity price risk management activities.  ARP and AGP do not apply hedge accounting to any of their derivative instruments. As a result, gains and losses associated with derivative instruments are recognized in earnings.

AGP and ARP enter into commodity future option contracts to achieve more predictable cash flows by hedging their exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while ethane, propane, butane and iso butane contracts are based on the respective Mt. Belvieu price.  These contracts were recorded at their fair values.

We recorded net derivative assets on our condensed combined consolidated balance sheets of $355.3 million and $358.1 million at March 31, 2016 and December 31, 2015, respectively. Of the $3.5 million of net gain in accumulated other comprehensive income within unitholders’ equity on our condensed combined consolidated balance sheet related to derivatives at March 31, 2016, we expect to reclassify $2.7 million of gains to our condensed combined consolidated statement of operations over the next twelve-month period as these contracts expire. Aggregate gains of $0.8 million of gas and oil production revenues will be reclassified to our condensed combined consolidated statements of operations in later periods as the remaining contracts expire.

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The following table summarizes the commodity derivative activity and presentation in our condensed combined consolidated statement of operations for the periods indicated (in thousands):

 

 

During the three months ended March 31, 2015, we received approximately $4.9 million in net proceeds from the early termination of our remaining natural gas and oil derivative positions for production periods from 2015 through 2018.  The net proceeds from the early termination of these derivatives were used to reduce indebtedness under our Term Loan Facilities.

Atlas Growth Partners

On May 1, 2015, AGP entered into a secured credit facility agreement with a syndicate of banks. As of March 31, 2016, the lenders under the credit facility have no commitment to lend to AGP under the credit facility, but AGP and its subsidiaries have the ability to enter into derivative contracts to manage their exposure to commodity price movements which will benefit from the collateral securing the credit facility. Obligations under the credit facility are secured by mortgages on AGP’s oil and gas properties and first priority security interests in substantially all of its assets. The credit facility may be amended in the future if AGP and the lenders agree to increase the borrowing base and the lenders’ commitments thereunder. The secured credit facility agreement contains covenants that limit AGP and its 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 its assets. AGP was in compliance with these covenants as of March 31, 2016. In addition, AGP’s credit facility includes customary events of default, including failure to timely pay, breach of covenants, bankruptcy, cross-default with other material indebtedness (including obligations under swap agreements in excess of any agreed upon threshold amount), and change of control provisions.

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

 

 

At March 31, 2016, AGP had the following commodity derivatives:

 

 

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Atlas Resource Partners

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

 

 

At March 31, 2016, ARP had the following commodity derivatives:

 

 

 

 

 

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NOTE 6—FAIR VALUE OF FINANCIAL INSTRUMENTS

We and our subsidiaries use a market approach fair value methodology to value our financial instruments. 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 and our subsidiaries separate the fair value of our financial instruments into the three level hierarchy (Levels 1, 2 and 3) based on our/their assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. As of March 31, 2016 and December 31, 2015, all derivative financial instruments were classified as Level 2.

Information for our and our subsidiaries’ financial instruments measured at fair value at March 31, 2016 and December 31, 2015 were as follows (in thousands):

 

 

Other Financial Instruments

We and our subsidiaries’ other current assets and liabilities on our condensed combined 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 estimated fair values of our and ARP’s debt at March 31, 2016 and December 31, 2015, which consist of borrowings under our term loan facilities, ARP’s senior notes and borrowings under ARP’s term loan and revolving credit facility, were $1,096.9 million and $929.2 million, respectively, compared with the carrying amounts of $1,624.4 million and $1,572.3 million, respectively. The carrying values of outstanding borrowings under the ARP revolving credit facility, which bear interest at variable interest rates, approximated their estimated fair value. The estimated fair values of the ARP senior notes and term loan facility were based upon the market approach and calculated using the yields of the ARP senior notes and term loan facility as provided by financial institutions and thus were categorized as Level 3 values.

 

 

NOTE 7—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Relationship with ARP. ARP does not directly employ any persons to manage or operate its business. These functions are provided by employees of us and/or our affiliates.

Relationship with AGP. AGP does not directly employ any persons to manage or operate its business. These functions are provided by employees of us and/or our affiliates. Atlas Growth Partners, GP, LLC (“AGP GP”) receives an annual

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management fee in connection with its management of AGP equivalent to 1% of capital contributions per annum. During the three months ended March 31, 2016 and 2015, AGP paid approximately $0.6 million and $0.3 million related to AGP GP for this management fee. Other indirect costs, such as rent for offices, are allocated to AGP by us based on the number of its employees who devoted substantially all of their time to activities on its behalf. AGP reimburses us at cost for direct costs incurred on its behalf. AGP will reimburse all necessary and reasonable costs allocated by the general partner. AGP was required to pay AGP GP an amount equal to any actual, out-of-pocket expenses related to its private placement offering and the formation and financing of AGP, including legal costs incurred by AGP GP, which payments were approximately 2% of the gross proceeds of its private placement offering.

Relationship with Drilling Partnerships. ARP conducts certain activities through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. ARP serves as the ultimate general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the ultimate general partner, ARP is liable for the Drilling Partnerships’ liabilities and can be liable to limited partners of the Drilling Partnerships if it breaches its responsibilities with respect to the operations of the Drilling Partnerships. ARP is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Drilling Partnership’s revenue and costs and expenses according to the respective partnership agreements. In March 2016, ARP transferred $36.7 million of investor capital raised and $13.3 million of accrued well drilling and completion costs incurred to the Atlas Eagle Ford 2015 L.P. private drilling partnership for activities directly related to their program. ARP intends to continue to fund the Drilling Partnerships’ operations and obligations, as necessary, until they are liquidated. Depending on commodity pricing and each of the Drilling Partnerships’ reserves value, ARP expects to realize all outstanding receivables from the Drilling Partnerships’ through the receipt of cash flows from their operations and/or the transfer of net assets and liabilities to ARP upon their liquidation. As of March 31, 2016 and December 31, 2015, ARP had receivables of $7.9 million and $6.6 million, respectively, from certain of the Drilling Partnerships’, which was recorded in accounts receivable in the condensed consolidated balance sheets.  As of March 31, 2016 and December 31, 2015, ARP had payables of $3.9 million and $3.0 million, respectively, to certain of the Drilling Partnerships’, which was recorded in accounts payable in the condensed consolidated balance sheets.

Other Relationships.  We have other related party transactions with regard to our Term Loan Facilities (see Note 4), our Series A preferred units (Note 9) and our general partner and limited partner interest in Lightfoot (see Note 1).

 

 

NOTE 8—COMMITMENTS AND CONTINGENCIES

ARP is the ultimate managing general partner of the Drilling Partnerships and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. ARP has structured certain Drilling Partnerships to allow limited partners to have the right to present their interests for purchase. Generally for Drilling Partnerships with this structure, ARP is not obligated to purchase more than 5% to 10% of the units in any calendar year, no units may be purchased during the first five years after closing for the Drilling Partnership, and ARP may immediately suspend the presentment structure for a Drilling Partnership by giving notice to the limited partners that it does not have adequate liquidity for redemptions. In accordance with the Drilling Partnership agreement, the purchase price for limited partner interests would generally be based upon a percentage of the present value of future cash flows allocable to the interest, discounted at 10%, as of the date of presentment, subject to estimated changes by ARP to reflect current well performance, commodity prices and production costs, among other items. Based on its historical experience, as of March 31, 2016, the management of ARP believes that any such estimated liability for redemptions of limited partner interests in Drilling Partnerships which allow such transactions would not be material.

While its historical structure has varied, ARP has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. ARP periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, ARP recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, ARP will

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recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized. For the three months ended March 31, 2016 and 2015, $0.1 million and $0.5 million, respectively, of ARP’s gas and oil production revenues, net of corresponding production costs, from certain Drilling Partnerships were subordinated, which reduced gas and oil production revenues and expenses.

As of March 31, 2016, we and our subsidiaries are committed to expend approximately $9.1 million on drilling and completion expenditures.

Legal Proceedings

We and our subsidiaries are parties to various routine legal proceedings arising out of the ordinary course of our business. Our and our subsidiaries’ management 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 9—ISSUANCES OF UNITS

We recognize gains or losses on ARP’s and AGP’s equity transactions as credits or debits, respectively, to unitholders’ equity on our condensed combined consolidated balance sheets rather than as income or loss on our condensed combined consolidated statements of operations. These gains or losses represent our portion of the excess or the shortage of the net offering price per unit of each of ARP’s and AGP’s common units as compared to the book carrying amount per unit.

On February 27, 2015 we issued and sold an aggregate of 1.6 million of our newly created Series A convertible preferred units, with a liquidation preference of $25.00 per unit (the “Series A Preferred Units”), at a purchase price of $25.00 per unit to certain members of our management, two management members of the Board, and outside investors. Holders of the Series A Preferred Units are entitled to monthly distributions of cash at a rate equal to the greater of (i) 10% of the liquidation preference per annum, increasing to 12% per annum, 14% per annum and 16% per annum on the first, second and third anniversaries of the of the private placement, respectively or (ii) the monthly equivalent of any cash distribution declared by us to holders of our common units, as well as Series A Preferred Units at a rate equal to 2% of the liquidation preference per annum. All or a portion of the Series A Preferred Units will be convertible into our units at the option of the holder at any time following the later of (i) the one year anniversary of the distribution and (ii) receipt of unitholder approval. The conversion price will be equal to the greater of (i) $8.00 per common unit; and (ii) the lower of (a) 110.0% of the volume weighted average price for our common units over the 30 trading days following the distribution date; and (b) $16.00 per common unit. We sold the Series A Preferred Units in a private transaction exempt from registration under Section 4(a)(2) of the Securities Act. The Series A Preferred Units resulted in proceeds to us of $40.0 million. We used the proceeds to fund a portion of the $150.0 million payment by us to Atlas Energy related to the repayment of Atlas Energy’s term loan (see Note 2). The Series A Purchase Agreement contains customary terms for private placements, including representations, warranties, covenants and indemnities. 

On August 26, 2015, at a special meeting of our unitholders, the unitholders approved changes to the terms of the Series A Preferred Units to provide that each Series A Preferred Unit will be convertible into common units at the option of the holder.

On January 7, 2016, we were notified by the NYSE that we were not in compliance with NYSE’s continued listing criteria under Section 802.01C of the NYSE Listed Company Manual because the average closing price of our common units had been less than $1.00 for 30 consecutive trading days.  We also were notified by the NYSE on December 23, 2015, that we were not in compliance with the NYSE’s continued listing criteria under Section 802.01B of the NYSE Listed Company Manual because our average market capitalization had been less than $50 million for 30 consecutive trading days and our stockholders’ equity had been less than $50 million. On March 18, 2016, we were notified by the NYSE that it determined to commence proceedings to delist our common units from the NYSE as a result of our failure to comply with the continued listing standard set forth in Section 802.01B of the NYSE Listed Company Manual to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million. The NYSE also suspended the trading of our common units at the close of trading on March 18, 2016. Our common units began trading on the OTCQX on Monday, March 21, 2016 under the ticker symbol: ATLS.

Atlas Resource Partners

ARP has an equity distribution agreement with Deutsche Bank Securities Inc., as representative of the several banks named therein (the “Agents”). Pursuant to the equity distribution agreement, ARP may sell from time to time through the Agents common units representing limited partner interests of ARP having an aggregate offering price of up to $100.0

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million. Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the New York Stock Exchange, the existing trading market for the common units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP will pay each of the Agents a commission, which in each case shall not be more than 2.0% of the gross sales price of common units sold through such Agent. Under the terms of the equity distribution agreement, ARP may also sell common units from time to time to any Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to an Agent as principal would be pursuant to the terms of a separate agreement between ARP and such Agent. During the three months ended March 31, 2016, ARP issued 245,175 common limited partner units under the equity distribution program for net proceeds of $0.2 million, net of approximately $19,000 in commissions and offering expenses paid. During the three months ended March 31, 2015, ARP issued 420,586 common limited partner units under the equity distribution program for net proceeds of $3.3 million, net of $0.1 million in commissions and offering expenses paid.

In August 2015, ARP entered into a distribution agreement with MLV & Co. LLC (“MLV”) which ARP terminated and replaced in November 2015, when ARP entered into a distribution agreement with MLV and FBR Capital Markets & Co. pursuant to which ARP may sell its 8.625% Class D Cumulative Redeemable Perpetual Preferred Units (“Class D ARP Preferred Units”) and 10.75% Class E Cumulative Redeemable Perpetual Preferred Units (“Class E ARP Preferred Units”). ARP did not issue any Class D Preferred Units nor Class E Preferred Units under the August 2015 and November 2015 preferred equity distribution programs for the three months ended March 31, 2016 and 2015.

On March 31, 2015, to partially pay its portion of the quarterly installment related to the Eagle Ford acquisition, ARP issued an additional 800,000 Class D Preferred Units to the seller at a value of $25.00 per unit.

On January 12, 2016, ARP was notified by the NYSE that it was not in compliance with NYSE’s continued listing criteria under Section 802.01C of the NYSE Listed Company Manual because the average closing price of its common units had been less than $1.00 for 30 consecutive trading days.  ARP is working to remedy this situation in a timely manner as set forth in the applicable NYSE rules in order to maintain its listing on the NYSE.

Atlas Growth Partners

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

Under the terms of AGP’s initial offering, AGP offered in a private placement $500.0 million of its common limited partner units. The termination date of the private placement offering was December 31, 2014, subject to two 90 day extensions to the extent that it had not sold $500.0 million of common units at any extension date. AGP 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 AGP gives the holder notice of a liquidity event) until the expiration date (generally, the date that is one day prior to the liquidity event or, if the liquidity event is a listing on a national securities exchange, 30 days after the liquidity event occurs). Under the warrant, a liquidity event is defined as either (i) a listing of the common units on a national securities exchange, (ii) a business combination with or into an existing publicly-traded entity, or (iii) a sale of all or substantially all of AGP’s assets.

Through the completion of AGP’s private placement offering on June 30, 2015, AGP issued approximately $233.0 million, or 23,300,410 of its common limited partner units, in exchange for proceeds to AGP, net of dealer manager fees and commissions and expenses, of $203.4 million. We 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 AGP’s common units at an exercise price of $10.00 per unit.

In connection with the issuance of ARP’s unit offerings during the three months ended March 31, 2016, we recorded gains of $0.2 million within unitholders’ equity and a corresponding decrease in non-controlling interests on our condensed combined consolidated balance sheet and condensed combined consolidated statement of unitholders’ equity. In connection with the issuance of ARP’s and AGP’s unit offerings for the three months ended March 31, 2015, we recorded gains of $0.2 million within equity and a corresponding decrease in non-controlling interests on our condensed combined consolidated balance sheets and condensed combined consolidated statement of unitholders’ equity.

 

 

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NOTE 10—CASH DISTRIBUTIONS

Our Cash Distributions. We have a cash distribution policy under which we distribute, within 50 days following the end of each calendar quarter, all of our available cash (as defined in our limited liability company agreement) for that quarter to our unitholders. As a result of the First Lien Credit Agreement and Second Lien Credit Agreement (see Note 4), we are prohibited from paying cash distributions on our common and preferred units.

During the three months ended March 31, 2016, we paid a distribution of $1.0 million to Class A preferred unitholders. No distributions were paid to Class A preferred unitholders during the three months ended March 31, 2015.

ARP Cash Distributions. ARP has a monthly cash distribution program whereby it distributes all of its available cash (as defined in ARP’s partnership agreement) for that month to its unitholders within 45 days from the month end. If ARP’s common unit distributions in any quarter exceed specified target levels, we will receive between 13% and 48% of such distributions in excess of the specified target levels. While outstanding, the Class B ARP Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.40 (or $0.1333 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. While outstanding, the Class C ARP Preferred Units  receive regular quarterly cash distributions equal to the greater of (i) $0.51 (or $0.17 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. ARP pays quarterly distributions on the Class D ARP Preferred Units at an annual rate of $2.15625 per unit, $0.5390625 per unit paid on a quarterly basis, or 8.625% of the $25.00 liquidation preference. ARP pays distributions on the Class E ARP Preferred Units at an annual rate of $2.6875 per unit, or $0.671875 per unit on a quarterly basis, or 10.75% of the $25.00 liquidation preference. On May 5, 2016, the Board of Directors elected to suspend ARP’s common unit and Class C Preferred Unit distributions, beginning with the month of March of 2016, due to the continued lower commodity price environment.

During the three months ended March 31, 2016, ARP paid three monthly cash distributions totaling approximately $3.8 million to common limited partners ($0.0125 per unit per month); $1.9 million to Preferred Class C limited partners ($0.17 per unit per month); and $0.1 million to the General Partner Class A holder ($0.0125 per unit per month). During the three months ended March 31, 2015, ARP paid three monthly cash distributions totaling approximately $42.8 million to common limited partners ($0.1966 per unit for both January and February 2015 and $0.1083 per unit for March 2015); $2.1 million to Preferred Class C limited partners ($0.1966 per unit for both January and February 2015 and $0.17 per unit for March 2015); and $3.0 million to the General Partner Class A holder ($0.1966 per unit for both January and February 2015 and $0.1083 per unit for March 2015).

During the three months ended March 31, 2016, ARP paid a distribution of $2.2 million to Class D Preferred limited partners ($0.5390625 per unit) for the period October 15, 2015 through January 14, 2016. During the three months ended March 31, 2015, ARP paid a distribution of $2.0 million to Class D Preferred limited partners ($0.6169270 per unit) for the period October 2, 2014 through January 14, 2015.

During the three months ended March 31, 2016, ARP paid a distribution of $0.2 million to Class E Preferred limited partners ($0.671875 per unit) for the period October 15, 2015 through January 14, 2016. No distributions were paid to Class E Preferred limited partners during the three months ended March 31, 2015.

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

During the three months ended March 31, 2016, AGP paid a distribution of $4.1 million to common limited partners ($0.1750 per unit) and $0.1 million to the general partner’s Class A units ($0.1750 per unit). During the three months ended March 31, 2015, AGP paid a distribution of $1.6 million to common limited partners ($0.1750 per unit) and approximately $33,000 to the general partner’s Class A units ($0.1750 per unit).

 

 

NOTE 11—OPERATING SEGMENT INFORMATION

Our operations include three reportable operating segments: ARP, AGP, and corporate and other. These operating segments reflect the way we manage our operations and make business decisions. Corporate and other includes our equity

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investment in Lightfoot (see Note 1), as well as our general and administrative and interest expenses. Operating segment data for the periods indicated were as follows (in thousands):

 

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NOTE 12—SUBSEQUENT EVENTS

Issuance of Warrants. Pursuant to the terms of the Second Lien Credit Agreement, on April 27, 2016 we issued to the Lenders warrants (the “Warrants”) to purchase an aggregate of up to 4,668,044 common units representing limited partner interests in us at an exercise price of $0.20 per unit. The Warrants expire on March 30, 2026 and are subject to customary anti-dilution provisions.

In connection with the issuance and sale of the Warrants, we entered into a registration rights agreement with the Lenders, dated April 27, 2016 (the “Registration Rights Agreement”), relating to the registered resale of the common units underlying the Warrants, as well as any common units issued as in-kind interest payments under the Second Lien Credit Agreement. Pursuant to the Registration Rights Agreement, we are required to file a shelf registration statement within 90 days of request by the Lenders and to use commercially reasonable efforts to cause such registration statement to become effective within 120 days of such request.

Long-Term Incentive Plan Vesting Delay. On May 12, 2016, due to the income tax ramifications of potential options we are currently considering, the Board of Directors delayed the vesting of approximately 911,900 units granted, under our long-term incentive plan, to employees, directors and officers, until March 2017. The phantom units were set to vest between June 8, 2016 and September 1, 2016.

Atlas Resource Partners

Cash Distributions. On April 15, 2016, ARP paid a quarterly distribution of $0.5390625 per Class D Preferred Unit, or $2.2 million, for the period from January 15, 2016 through April 14, 2016 to Class D Preferred Unitholders of record as of April 1, 2016.

On April 15, 2016, ARP paid a quarterly distribution of $0.671875 per Class E Preferred Unit, or $0.2 million, for the period from January 15, 2016 through April 14, 2016 to Class E Preferred Unitholders of record as of April 1, 2016.

On May 5, 2016, the Board of Directors elected to suspend ARP’s common unit and Class C preferred distributions, beginning with the month of March of 2016, due to the continued lower commodity price environment.

Ninth Amendment to the ARP Credit Agreement. On May 10, 2016, ARP entered into the Ninth Amendment to the ARP Credit Agreement (see Note 4).

Long-Term Incentive Plan Vesting Delay.  On May 12, 2016, due to the income tax ramifications of the options ARP is currently considering, the Board of Directors delayed the vesting date of approximately 110,000 units granted to employees, directors and officers until March 2017.  The phantom units were set to vest between May 15, 2016 and September 1, 2016.

 

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Atlas Growth Partners

Cash Distributions. On May 4, 2016, AGP declared a quarterly distribution of $0.1750 per common unit for the quarter ended March 31, 2016. The $4.2 million distribution, including $0.1 million to its general partner, will be paid on May 13, 2016 to unitholders of record at the close of business on March 31, 2016.

 

 

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Forward-Looking Statements

When used in this Form 10-Q, the words “believes,” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties more particularly described in “Item 1A. Risk Factors” in our annual report on Form 10-K for the year ended December 31, 2015, as supplemented by this Form 10-Q. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

We believe the assumptions underlying the condensed combined consolidated financial statements are reasonable. The historical financial statements included in this Form 10-Q reflect substantially all the assets and liabilities transferred from our former owner, Atlas Energy, on February 27, 2015. However, our historical condensed combined consolidated financial statements included herein may not necessarily reflect our results of operations, financial position and cash flows in the future or what they would have been had our predecessor been a separate, stand-alone company during the periods presented.

Unless the context otherwise requires, references in this Form 10-Q to “the Company,” “we,” “us,” “our” and “our company,” when used in a historical context or in the present tense, refer to the businesses and subsidiaries owned by Atlas Energy Group, LLC, a Delaware limited liability company, and its combined subsidiaries or that Atlas Energy contributed to Atlas Energy Group, LLC in connection with the separation and distribution on February 27, 2015 and refer to Atlas Energy Group, LLC, a Delaware limited liability company, and its combined subsidiaries. References to “Atlas Energy, L.P.” or “Atlas Energy” refer to Atlas Energy, L.P. and its consolidated subsidiaries, unless the context otherwise requires. References to “Atlas Energy Group, LLC” prior to the separation refer to Atlas Energy Group, LLC, a Delaware limited liability company that is currently the general partner of ARP. References in this Form 10-Q to “ARP” or “Atlas Resource Partners” refer to Atlas Resource Partners, L.P., a Delaware limited partnership, and references to “AGP” or “Atlas Growth Partners” refer to Atlas Growth Partners, L.P., a Delaware limited partnership.

BUSINESS OVERVIEW

We are a publicly traded (OTCQX: ATLS) Delaware limited liability company formed in October 2011.

On February 27, 2015, our former owner, Atlas Energy, L.P. (“Atlas Energy”), transferred its assets and liabilities, other than those related to its midstream assets, to us, and effected a pro rata distribution of our common units representing a 100% interest in us, to Atlas Energy’s unitholders (the “Separation”). Concurrently with the distribution of our units, Atlas Energy and its remaining midstream interests merged with Targa Resources Corp. (“Targa”; NYSE: TRGP) and ceased trading.

At March 31, 2016, our operations primarily consisted of our ownership interests in the following:

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FINANCIAL PRESENTATION

Our condensed combined consolidated financial statements were derived from the accounts of Atlas Energy and its controlled subsidiaries for the periods prior to February 27, 2015. Because a direct ownership relationship did not exist among all the various entities consolidated in our condensed combined consolidated financial statements, Atlas Energy’s net investment in us is shown as equity in the condensed combined consolidated financial statements. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the condensed combined consolidated balance sheets and related condensed combined consolidated statements of operations. Such estimates included allocations made from the historical accounting records of Atlas Energy, based on management’s best estimates, in order to derive our financial statements. Actual balances and results could be different from those estimates. All significant intercompany transactions and balances have been eliminated in the combination of the financial statements.

Our condensed combined consolidated financial statements contain our accounts and those of our combined consolidated subsidiaries, all of which are wholly-owned at March 31, 2016, except for ARP and AGP, which we determined are variable interest entities (“VIE’s”) based on their respective partnership agreements, our power, as the general partner, to direct activities that most significantly impact their economic performance, and our ownership of the incentive distribution rights. Accordingly, we consolidate the financial statements of ARP and AGP into our condensed combined consolidated financial statements. Our VIE’s operating results and assets balances are presented separately in Note 11 – Operating Segment Information. As the general partner for both ARP and AGP, we have unlimited liability for the obligations of ARP and AGP except for those contractual obligations that are expressly made without recourse to the general partner. The non-controlling interests in ARP and AGP are reflected as (income) loss attributable to non-controlling interests in the condensed combined consolidated statements of operations and as a component of unitholders’ equity on the condensed combined consolidated balance sheets. All material intercompany transactions have been eliminated. Throughout this section, when we refer to “our” condensed combined consolidated financial statements, we are referring to the condensed combined consolidated results for us, our wholly-owned subsidiaries and the consolidated results of ARP and AGP, adjusted for non-controlling interests in ARP and AGP. Certain amounts in the prior year’s consolidated financial statements have been reclassified due to the adoption of certain accounting standards (see Note 2 of the Financial Statements).

RECENT DEVELOPMENTS

 

 

 

 

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Atlas Resource Partners

Atlas Growth Partners

GENERAL TRENDS AND OUTLOOK

We expect our and our subsidiaries’ businesses to be affected by the following key trends. Our expectations are based on assumptions made by us and our subsidiaries and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our and our subsidiaries’ actual results may vary materially from our expected results.

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The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines since the fourth quarter of 2014 through the first 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 subsidiaries’ future gas and oil reserves, production, cash flow, the ability to make payments on debt and the ability to make distributions to unitholders, including ARP’s and AGP’s ability to make distributions to us, depend on our subsidiaries’ success in producing current reserves efficiently, developing existing acreage and acquiring additional proved reserves economically. Our subsidiaries 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. Our subsidiaries attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than produced. To the extent our subsidiaries do not have sufficient capital, our subsidiaries’ ability to drill and acquire more reserves will be negatively impacted.

RESULTS OF OPERATIONS

Gas and Oil Production

Production Profile. At March 31, 2016, our consolidated gas and oil production revenues and expenses consisted of our subsidiaries’ gas and oil production activities. ARP has focused its natural gas, crude oil and NGL production operations in various plays throughout the United States. AGP’s gas and oil production derives from its wells drilled in the Eagle Ford, Marble Falls and Mississippi Lime plays. Through March 31, 2016, our subsidiaries have established production positions in the following operating areas:

The following table presents the number of wells our subsidiaries drilled and the number of wells our subsidiaries turned in line, both gross and for our respective interests, during the three months ended March 31, 2016 and 2015:

 

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Production Volumes. The following table presents total net natural gas, crude oil and NGL production volumes and production per day for the three months ended March 31, 2016 and 2015:

 

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⁽¹⁾ Production quantities consist of the sum of (i) the proportionate share of production from wells in which our subsidiaries have a direct interest, based on the proportionate net revenue interest in such wells, and (ii) ARP’s proportionate share of production from wells owned by the Drilling Partnerships in which it has an interest, based on ARP’s equity interest in each such Drilling Partnership and based on each Drilling Partnership’s proportionate net revenue interest in these wells.

⁽²⁾ “MMcf” represents million cubic feet; “MMcfe” represent million cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day. Barrels are converted to Mcfe using the ratio of approximately 6 Mcf to one barrel.

⁽³⁾ Appalachia includes ARP’s production located in Pennsylvania, Ohio, New York, West Virginia (excluding the Cedar Bluff area) and the Chattanooga (Tennessee) and New Albany (Indiana) Shales; Coal-bed methane includes ARP’s production located in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama, the Cedar Bluff area of West Virginia and Virginia, and the Arkoma Basin in eastern Oklahoma; Mid-Continent includes ARP’s production located in the Mississippi Lime and Hunton plays and the Niobrara Shale (northeastern Colorado).

Production Revenues, Prices and Costs. Production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas and oil. The following table presents production revenues and average sales prices for AGP’s and ARP’s natural gas, oil, and NGLs production for the three months ended March 31, 2016 and 2015, along with average production costs, which include lease operating expenses, taxes, and transportation and compression costs, in each of the reported periods:

 

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