10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2016

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-36725

Atlas Energy Group, LLC

(Exact name of registrant as specified in its charter)

Delaware	45-3741247
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Park Place Corporate Center One 1000 Commerce Drive, Suite 400 Pittsburgh, Pennsylvania	15275
(Address of principal executive offices)	(Zip code)

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.

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

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 August 4, 2016 was 26,037,992.

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ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

TABLE OF CONTENTS

		Page
PART 1. FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Condensed Combined Consolidated Balance Sheets as of June 30, 2016 and December 31, 2015	7
	Condensed Combined Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2016 and 2015	8
	Condensed Combined Consolidated Statements of Comprehensive Loss for the Three and Six Months Ended June 30, 2016 and 2015	9
	Condensed Combined Consolidated Statement of Unitholders’ Equity for the Six Months Ended June 30, 2016	10
	Condensed Combined Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2016 and 2015	11
	Notes to Condensed Combined Consolidated Financial Statements	12
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	64
Item 4.	Controls and Procedures	66
PART II. OTHER INFORMATION
Item 1A	Risk Factors	67
Item 6.	Exhibits	70
SIGNATURES		71

FORWARD-LOOKING STATEMENTS

3

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

• the potential adverse effects of ARP’s filings under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) and restructuring transactions on our operations, management and employees and the risks associated with operating our business during the restructuring process;

• risks and uncertainties associated with ARP’s Chapter 11 proceedings including the ability to achieve the anticipated benefits therefrom;

• our limited operating history as a separate public company, and that our historical financial information is not necessarily representative of the results that we would have achieved had we been the owner or operator of our assets and may not be a reliable indicator of our future results;

• whether we are able to continue to achieve some or all of the expected benefits of the separation from Atlas Energy;

• the fact that our primary assets are our partnership interests, including the IDRs, in ARP and partnership interests in AGP and, therefore, our cash flow is dependent on the ability of ARP and AGP to make distributions in respect of those partnership interests;  

• our ability to meet our liquidity needs, including as a result of any reduction or elimination of distributions from ARP or AGP and their ability to meet their liquidity needs, and ability to satisfy covenants in our, ARP’s and AGP’s debt documents;

• actions that we, ARP and AGP may take in connection with our and its liquidity needs, including the ability to service our, ARP’s and AGP’s debt;

• restrictive covenants in our, ARP’s and AGP’s indebtedness that may adversely affect operational flexibility;

• the demand for natural gas, oil, NGLs and condensate;

• the price volatility of natural gas, oil, NGLs and condensate;

• changes in the differential between benchmark prices for oil and natural gas and wellhead prices that we, ARP and AGP achieve;

• effects of partial depletion or drainage by earlier offset drilling on our, ARP’s and AGP’s acreage;  

• economic conditions and instability in the financial markets;

• the impact of our common units being quoted on the OTCQX Best Market and not listed on a national securities exchange;

• changes in the market price of our common units;

• future financial and operating results;

• economic conditions and instability in the financial markets;

• effects of debt payment obligations on our distributable cash;

• the impact of ARP’s securities being quoted on the OTC rather than listed on the New York Stock Exchange;

• resource potential;

4

• success in efficiently developing and exploiting our, ARP’s and AGP’s reserves and economically finding or acquiring additional recoverable reserves;  

• the accuracy of estimated natural gas and oil reserves;

• the financial and accounting impact of hedging transactions;

• the ability to fulfill the respective substantial capital investment needs of us, ARP and AGP;

• expectations with regard to acquisition activity, or difficulties encountered in connection with acquisitions;

• the limited payment of dividends or distributions, or failure to declare a dividend or distribution, on outstanding common units or other equity securities;

• any issuance of additional common units or other equity securities, and any resulting dilution or decline in the market price of any such securities;

• potential changes in tax laws that may impair ARP’s ability to obtain capital funds through investment partnerships;

• the ability of ARP to raise funds through its investment partnerships or through access to capital markets;

• the ability to obtain adequate water to conduct drilling and production operations, and to dispose of the water used in and generated by these operations, at a reasonable cost and within applicable environmental rules;

• the effects of unexpected operational events and drilling conditions, and other risks associated with drilling operations;

• access to sufficient amounts of carbon dioxide for tertiary recovery operations;

• impact fees and severance taxes;

• changes and potential changes in the regulatory and enforcement environment in the areas in which we, ARP and AGP conduct business;

• the effects of intense competition in the natural gas and oil industry;

• general market, labor and economic conditions and related uncertainties;

• the ability to retain certain key customers;

• dependence on the gathering and transportation facilities of third parties;

• the availability of drilling rigs, equipment and crews;

• potential incurrence of significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment;

• uncertainties with respect to the success of drilling wells at identified drilling locations;

• ability to identify all risks associated with the acquisition of oil and natural gas properties, pipeline, facilities or existing wells, and the sufficiency of indemnifications we receive from sellers to protect us from such risks;

• expirations of undeveloped leasehold acreage;

• uncertainty regarding operating expenses, general and administrative expenses and exploration and development costs;

• exposure to financial and other liabilities of the managing general partners of the investment partnerships;

• the ability to comply with, and the potential costs of compliance with, new and existing federal, state, local and other laws and regulations applicable to our, ARP’s and AGP’s business and operations;

• restrictions on hydraulic fracturing;

• ability to integrate operations and personnel from acquired businesses;

• exposure to new and existing litigations;

• the potential failure to retain certain key employees and skilled workers;

• development of alternative energy resources; and

5

• the effects of a cyber event or terrorist attack.  

The foregoing list is not exclusive. Other factors that could cause actual results to differ from those implied by the forward-looking statements in this document are more fully described in “Item 1A: Risk Factors” of our annual report on Form 10-K for the year ended December 31, 2015. Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this document speak only as of the date on which the statements were made. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments except as required by law.  

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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)

	June 30,			December 31,
	2016			2015
ASSETS
Current assets:
Cash and cash equivalents	$	43,502		$	31,214
Accounts receivable		64,904			65,920
Current portion of derivative asset		99,654			159,763
Subscriptions receivable		—			19,877
Prepaid expenses and other		17,105			22,997
Current deferred financing costs		12,162			—
Total current assets		237,327			299,771
Property, plant and equipment, net		1,273,453			1,316,897
Goodwill and intangible assets, net		14,028			14,095
Long-term derivative asset		135,231			198,371
Other assets, net		37,261			54,112
Total assets	$	1,697,300		$	1,883,246
LIABILITIES AND UNITHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable		40,421			52,550
Liabilities associated with drilling contracts		—			21,483
Current portion of derivative payable to Drilling Partnerships		956			2,574
Accrued interest		24,130			25,452
Accrued well drilling and completion costs		2,182			33,555
Accrued liabilities		29,711			42,440
Current portion of long-term debt		1,553,277			4,250
Total current liabilities		1,650,677			182,304
Long-term debt, net, less current portion		72,362			1,568,064
Asset retirement obligations and other		140,104			124,919
Commitments and contingencies (Note 9)
Unitholders’ equity (deficit):
Common unitholders’ equity (deficit)		(145,033	)		(103,148	)
Series A preferred equity		42,113			40,875
Warrants		1,868			—
Accumulated other comprehensive income		2,273			4,284
		(98,779	)		(57,989	)
Non-controlling interests		(67,064	)		65,948
Total unitholders’ equity (deficit)		(165,843	)		7,959
Total liabilities and unitholders’ equity (deficit)	$	1,697,300		$	1,883,246

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)

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Revenues:
Gas and oil production	$	54,782		$	99,077		$	106,375		$	205,637
Well construction and completion		(1,326	)		16,956			774			40,611
Gathering and processing		1,600			2,177			3,095			4,361
Administration and oversight		495			547			950			1,806
Well services		4,190			6,102			8,622			12,726
Gain (loss) on mark-to-market derivatives		(74,090	)		(26,896	)		(27,637	)		78,689
Other, net		545			284			870			216
Total revenues		(13,804	)		98,247			93,049			344,046
Costs and expenses:
Gas and oil production		31,570			43,619			68,226			89,608
Well construction and completion		(1,153	)		14,745			673			35,315
Gathering and processing		2,191			2,516			4,470			4,933
Well services		1,474			2,139			3,652			4,337
General and administrative		27,995			18,405			49,915			60,333
Depreciation, depletion and amortization		32,307			43,276			66,579			87,732
Total costs and expenses		94,384			124,700			193,515			282,258
Operating income (loss)		(108,188	)		(26,453	)		(100,466	)		61,788
Gain (loss) on asset sales and disposal		(502	)		97			(493	)		86
Interest expense		(35,844	)		(33,187	)		(65,292	)		(67,938	)
Gain (loss) on early extinguishment of debt, net		(27	)		—			20,418			—
Other income (loss)		(6,156	)		—			(6,156	)		—
Net income (loss)		(150,717	)		(59,543	)		(151,989	)		(6,064	)
Preferred unitholders’ dividends		—			(1,004	)		(339	)		(1,337	)
(Income) loss attributable to non-controlling interests		114,637			38,740			109,297			(19,558	)
Net loss attributable to unitholders’/owner’s interests	$	(36,080	)	$	(21,807	)	$	(43,031	)	$	(26,959	)
Allocation of net loss attributable to unitholders’/owner’s interests:
Portion applicable to owner’s interest (period prior to the transfer of assets on February 27, 2015)	$	—		$	—		$	—		$	(10,475	)
Portion applicable to unitholders’ interests (period subsequent to the transfer of assets on February 27, 2015)		(36,080	)		(21,807	)		(43,031	)		(16,484	)
Net loss attributable to unitholders’/owner’s interests	$	(36,080	)	$	(21,807	)	$	(43,031	)	$	(26,959	)
Net loss attributable to unitholders per common unit (Note 2):
Basic	$	(1.39	)	$	(0.84	)	$	(1.65	)	$	(0.63	)
Diluted	$	(1.39	)	$	(0.84	)	$	(1.65	)	$	(0.63	)
Weighted average common units outstanding (Note 2):
Basic		26,031			26,011			26,029			26,011
Diluted		26,031			26,011			26,029			26,011

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 LOSS

(in thousands)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Net loss	$	(150,717	)	$	(59,543	)	$	(151,989	)	$	(6,064	)
Other comprehensive loss:
Derivative instruments designated as cash flow hedges:
Reclassification to mark-to-market gains	(5,555		)		(25,778	)		(9,070	)		(53,121	)
Total other comprehensive loss	(5,555		)		(25,778	)		(9,070	)		(53,121	)
Comprehensive loss	(156,272		)		(85,321	)		(161,059	)		(59,185	)
Comprehensive loss attributable to non-controlling interests	118,967				51,125			116,356			12,182
Comprehensive loss attributable to unitholders’ interest	$	(37,305	)	$	(34,196	)	$	(44,703	)	$	(47,003	)

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 (DEFICIT)

(in thousands, except unit data)

(Unaudited)

	Series A Preferred Equity					Common Unitholders’ Equity (Deficit)					Warrants			Accumulated Other			Non-				Total Unitholders’
	Units		Amount			Units		Amount			Units		Amount		Comprehensive Income				Controlling Interest				Equity (Deficit)
Balance at December 31, 2015		1,621,427	$	40,875			26,010,766	$	(103,148	)	—	$	—		$	4,284			$	65,948			$	7,959
Issuance of units and warrants		63,025		1,576			—		(1,576	)	4,668,044		1,868			—				(2,721		)		(853	)
Distributions to non-controlling interests		—		—			—		—		—		—			—				(16,837		)		(16,837	)
Net issued and unissued units under incentive plan		—		—			27,226		2,541		—		—			—				(298		)		2,243
Distribution equivalent rights paid on unissued units under incentive plans		—		—			—		—		—		—			—				(11		)		(11	)
Distribution payable		—		338			—		—		—		—			—				3,392				3,730
Gain on sale from subsidiary unit issuances		—		—			—		181		—		—			—				(181		)		—
Dividends paid to preferred equity unitholders		—		(1,015	)		—		—		—		—			—				—				(1,015	)
Other comprehensive loss		—		—			—		—		—		—			(2,011		)		(7,059		)		(9,070	)
Net income (loss)		—		339			—		(43,031	)	—		—			—				(109,297		)		(151,989	)
Balance at June 30, 2016		1,684,452	$	42,113			26,037,992	$	(145,033	)	4,668,044	$	1,868		$	2,273			$	(67,064		)	$	(165,843	)) )

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)

	Six Months Ended June 30,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(151,989	)	$	(6,064	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		66,579			87,732
Gain on early extinguishment of debts, net		(20,418	)		—
(Gain) loss on derivatives		38,303			(71,808	)
Amortization of deferred financing costs and discount and premium on long-term debt		12,281			15,670
Non-cash compensation expense		2,235			5,083
Paid-in-kind interest		3,632			—
(Gain) loss on asset sales and disposal		493			(86	)
Other (income) loss		6,156			—
Distributions paid to non-controlling interests		(16,848	)		(62,831	)
Equity income in unconsolidated companies		(715	)		(154	)
Distributions received from unconsolidated companies		863			838
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other		94,754			92,497
Accounts payable and accrued liabilities		(62,206	)		(98,913	)
Net cash used in operating activities		(26,880	)		(38,036	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(25,147	)		(82,609	)
Net cash paid for acquisitions		—			(49,060	)
Other		1,282			(2,079	)
Net cash used in investing activities		(23,865	)		(133,748	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under term loan facilities		—			115,848
Repayments under term loan facilities		(4,250	)		(193,203	)
Borrowings under ARP’s revolving credit facility		135,000			231,000
Repayments under ARP’s revolving credit facility		(57,500	)		(377,000	)
Borrowings under ARP’s second lien term loan facility		—			242,500
ARP senior note repurchases		(5,528	)		—
Net proceeds from issuance of Series A units		—			40,000
Net proceeds from issuance of ARP and AGP units to the public		(2,721	)		123,885
Dividends to preferred unitholders		(1,015	)		(667	)
Net investment from (distributions to) Atlas Energy		—			(19,758	)
Deferred financing costs, distribution equivalent rights and other		(953	)		(9,102	)
Net cash provided by financing activities		63,033			153,503
Net change in cash and cash equivalents		12,288			(18,281	)
Cash and cash equivalents, beginning of year		31,214			58,358
Cash and cash equivalents, end of period	$	43,502		$	40,077

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 (OTC: 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 June 30, 2016, our operations primarily consisted of our ownership interests in the following:

· 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 23.3% limited partner interest (consisting of 20,962,485 common and 3,749,986 preferred limited partner units) in Atlas Resource Partners, L.P. (“ARP”), a publicly traded Delaware master limited partnership (“MLP”) (OTC: ARPJ) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”), with operations in basins across the United States. As part of its exploration and production activities, ARP sponsors and manages tax-advantaged investment partnerships (“Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas and oil production activities;

· all of the incentive distribution rights, an 80.0% general partner interest and a 2.1% limited partner interest in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations primarily focused in the Eagle Ford Shale in South Texas. On June 30, 2015, AGP concluded a private placement offering, during which it issued $233.0 million of its common limited partner units. Of the $233.0 million of gross funds raised, we purchased $5.0 million common limited partner units. AGP’s registration statement on Form S-1 (Registration Number: 333-207537) was declared effective by the Securities and Exchange Commission on April 5, 2016. AGP is offering in the aggregate up to 100,000,000 Class A common units and Class T common units, each representing limited partner interests in AGP, pursuant to a primary offering on a "best efforts" basis. AGP must receive minimum offering proceeds of $1.0 million to break escrow, and the maximum offering proceeds of the primary offering may not exceed $1.0 billion. The Class A common units will be sold for a cash purchase price of $10.00 and the Class T common units will be sold for a cash purchase price of $9.60, with the remaining $0.40 constituting the Class T common unitholders' deferred payment obligation to AGP. AGP is also offering up to 21,505,376 Class A common units at $9.30 per unit pursuant to a distribution reinvestment plan; and

· 12.0% limited partner interest in Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and a 15.4% general partner interest in Lightfoot Capital Partners GP, LLC (“Lightfoot G.P.” and together with Lightfoot L.P., “Lightfoot”), the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of the Company’s board of directors, is the Chairman of the Board. Lightfoot L.P. focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt. We account for our investment in Lightfoot under the equity method of accounting. During both the three months ended June 30, 2016 and 2015, we received net cash distributions of approximately $0.4 million. During both the six months ended June 30, 2016 and 2015, we received net cash distributions of approximately $0.8 million.

At June 30, 2016, we had 26,037,992 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

12

financial statements contained in Form 10-K. It is suggested that these interim condensed combined consolidated financial statements be read in conjunction with the financial statements and the notes thereto included in our latest Annual Report on 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 5). 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 six months ended June 30, 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 10) 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 each of their respective economic performance, and our ownership of each of their respective 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 12 – 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 $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.

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

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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.

Ability for the Company and ARP to Continue as a Going Concern

On July 25, 2016, ARP and certain of its subsidiaries and us, solely with respect to certain sections thereof, entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with (i) lenders holding 100% of ARP’s senior secured revolving credit facility (the “First Lien Lenders”), (ii) lenders holding 100% of ARP’s second lien term loan (the “Second Lien Lenders”) and (iii) holders (the “Consenting Noteholders” and, collectively with the First Lien Lenders and the Second Lien Lenders, and their respective successors or permitted assigns that become party to the Restructuring Support Agreement, the “Restructuring Support Parties”) of approximately 80% of the aggregate principal amount outstanding of the 7.75% ARP Senior Notes due 2021 (the “7.75% ARP Senior Notes”) and the 9.25% ARP Senior Notes due 2021 (the “9.25% ARP Senior Notes” and, together with the 7.75% ARP Senior Notes, the “Notes”) of ARP’s subsidiaries, Atlas Resource Partners Holdings, LLC and Atlas Resource Finance Corporation (together, the “Issuers”). Under the Restructuring Support Agreement, the Restructuring Support Parties have agreed, subject to certain terms and conditions, to support ARP’s restructuring (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”). See Note 3, “ARP Restructuring Support Agreement,” for further information.

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

The Restructuring, including as a result of ARP monetizing certain hedges to pay down borrowings outstanding under ARP’s senior secured credit facility, will result in a reduction of ARP’s existing debt by approximately $900 million and elimination of approximately $80 million of ARP’s annual debt service obligations. Pursuant to the Plan, ARP’s business assets and operations will vest in a limited liability company, which will be classified as a corporation for U.S. federal income tax purposes (“New Holdco”). ARP expects to consummate the Plan and emerge from Chapter 11 before the end of the third quarter of 2016. Interested parties should refer to the information and the limitations and qualifications discussed in ARP’s disclosure statement related to ARP’s Restructuring (the “ARP Disclosure Statement”) which was filed as Exhibit 99.1 to ARP’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 25, 2016.

ARP intends to continue to operate its businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, it is contemplated that all of ARP’s suppliers, vendors, employees, royalty owners, trade partners and landlords will be unimpaired by the Plan and will be satisfied in full in the ordinary course of business, and ARP’s existing trade contracts and terms will be maintained. To assure ordinary course operations, ARP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to ARP, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.

The Chapter 11 Filings constituted an event of default that accelerated all of ARP’s outstanding debt obligations under the ARP First Lien Credit Facility (as defined below), the ARP Second Lien Term Loan (as defined below) and the indenture governing the ARP Notes. Any efforts to enforce such payments are automatically stayed as a result of ARP’s Chapter 11 Filings, and the holders’ rights of enforcement are subject to the applicable provisions of Chapter 11.  Accordingly, we classified all of ARP’s outstanding debt obligations as a current liability on our condensed combined consolidated balance sheet as of June 30, 2016. See Note 5, Debt, for further information.

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ARP’s Restructuring is not expected to materially impact us or our ownership interest in AGP or Lightfoot. We are not a party to ARP’s Restructuring. We remain controlled by the same ownership group and management team and thus, we expect that ARP’s Restructuring will not have a material impact on the ability of management to operate us or the other businesses.

The significant risks and uncertainties related to ARP’s Chapter 11 Filings raise substantial doubt about ARP’s and our ability to continue as a going concern. Our condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. Our condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we and ARP cannot continue as a going concern, adjustments to the carrying values and classification of our and ARP’s assets and liabilities and the reported amounts of income and expenses could be required and could be material.

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 private placement offering completed in 2015. 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.

AGP is not a party to the Restructuring Support Agreement, and ARP’s Restructuring is not expected to materially impact AGP.

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 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, fair value of derivative and other financial instruments and fair value of certain gas and oil properties and asset retirement obligations. 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.

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.

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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):

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Net loss	$	(150,717	)	$	(59,543	)	$	(151,989	)	$	(6,064	)
Preferred unitholders’ dividends		—			(1,004	)		(339	)		(1,337	)
(Income) loss attributable to non-controlling interests		114,637			38,740			109,297			(19,558	)
Loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015)		—			—			—			10,475
Net loss attributable to common unitholders		(36,080	)		(21,807	)		(43,031	)		(16,484	)
Less: Net income attributable to participating securities – phantom units(1)		—			—			—			—
Net loss utilized in the calculation of net loss attributable to common unitholders per unit – diluted(1)	$	(36,080	)	$	(21,807	)	$	(43,031	)	$	(16,484	)

(1) Net income (loss) attributable to common unitholders for the net income (loss) attributable to common unitholders per unit calculation is net income (loss) attributable to common unitholders, less income allocable to participating securities. For the three months ended June 30, 2016, and 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 352,000 and 69,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the six months ended June 30, 2016 and 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 307,000 and 67,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.

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):

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Weighted average number of common unitholders per unit—basic		26,031		26,011		26,029		26,011
Add effect of dilutive incentive awards(1)		—		—		—		—
Add effect of dilutive convertible preferred units(2)		—		—		—		—
Weighted average number of common unitholders per unit—diluted		26,031		26,011		26,029		26,011

(1) For the three months ended June 30, 2016 and 2015, approximately 2,692,000 and 750,000 phantom units, respectively, were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive. For the six months ended June 30, 2016, and 2015, approximately 2,691,000 and 567,000 phantom units, respectively, were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive.

(2) For each of the three months and six months ended June 30, 2016 and 2015, potential common units issuable upon conversion of our Series A preferred units were excluded from the computation of diluted earnings attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive.

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 June 30, 2016 and December 31, 2015, we reflected $4.1 million and $5.6 million, respectively, related to the value of the rabbi trust within other assets, net on our condensed combined

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consolidated balance sheets, and recorded corresponding liabilities of $4.1 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 six months ended June 30, 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 six months ended June 30, 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.

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—RESTRUCTURING SUPPORT AGREEMENT

As disclosed in Note 2, on July 25, 2016, ARP and certain of its subsidiaries and us, solely with respect to certain sections thereof, entered into the Restructuring Support Agreement with the Restructuring Support Parties.  On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. Under the Restructuring Support Agreement, the Restructuring Support Parties have agreed, subject to certain terms and conditions, to support ARP’s Restructuring pursuant to the Plan.

In particular, under the Plan, on the Plan’s effective date (the “Plan Effective Date”), the First Lien Lenders will receive cash payment of all obligations owed to them by ARP pursuant to the senior secured revolving credit facility (other than $440 million of principal and face amount of letters of credit) and become lenders under an exit facility credit agreement (the “First Lien Exit Facility”), composed of a $410 million conforming reserve-based tranche and a $30 million non-conforming tranche. The non-conforming tranche will mature on May 1, 2017 and the conforming reserve-based tranche will mature on August 23, 2019. In addition, ARP will enter into a new second lien credit agreement (the “Second Lien Exit Facility” and, together with the First Lien Exit Facility, the “Exit Facilities”). The Second Lien Lenders will receive a pro rata share of the Second Lien Exit Facility, which will have an aggregate principal amount of $250 million plus the amounts resulting from the accrual of paid in kind interest on the principal amount of $250 million from the commencement of ARP’s Chapter 11 Filings, with interest expense paid in cash to be reduced to 2% and the remainder to be paid-in-kind from the

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commencement date through May 1, 2017 at a rate equal to Adjusted LIBO Rate plus 9% per annum. During the next 15-month period, cash and in-kind interest will vary based on a pricing grid tied to ARP’s leverage ratio under the ARP revolving credit facility. After such 15-month period, interest will accrue at a rate equal to Adjusted LIBO Rate plus 9% per annum and will be payable in cash. In addition to the Second Lien Exit Facility, the Second Lien Lenders will receive a pro rata share of 10% of the common equity interests of New HoldCo, subject to dilution by a management incentive plan. Holders of the Notes, in exchange for 100% of the $668 million aggregate principal amount of Notes outstanding plus accrued but unpaid interest as of the commencement of the Chapter 11 cases, will receive, on the Plan Effective Date, 90% of the common equity interests of New HoldCo as of the Plan Effective Date, subject to dilution by a management incentive plan.

Under the Plan, holders of ARP’s limited partnership units will receive no recovery. On the Plan Effective Date, all of ARP’s preferred limited partnership units and common limited partnership units will be cancelled without the receipt of any consideration.

ARP intends to continue to operate its businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, all suppliers, vendors, employees, royalty owners, trade partners and landlords will be unimpaired by the Plan and will be satisfied in full in the ordinary course of business, and ARP’s existing trade contracts and terms will be maintained. To assure ordinary course operations, ARP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to ARP, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.

Under the Plan, on the Plan Effective Date, a wholly owned subsidiary of the Company (“ARP Mgt LLC”) will receive a preferred share of New HoldCo. The preferred share will entitle ARP Mgt LLC to receive 2% of the economics of New HoldCo (subject to dilution if catch-up contributions are not made with respect to future equity issuances, other than pursuant to the management incentive plan) and certain other rights as provided for in the Restructuring Support Agreement. Four of the seven initial members of the board of directors of New HoldCo are representatives of ARP Mgt LLC (the “New HoldCo Class A Directors”). For so long as ARP Mgt LLC holds such preferred share, the New HoldCo Class A Directors will be appointed by a majority of ARP’s Class A Directors then in office. New HoldCo will have a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in New HoldCo's limited liability company agreement), subject to the receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of New HoldCo unaffiliated with ARP Mgt LLC voting in favor of the exercise of the right to purchase the preferred share.

In accordance with, and subject to the terms and conditions of, the Restructuring Support Agreement, each of the Restructuring Support Parties has agreed, among other things, to: (i) support and take all commercially reasonable actions necessary or reasonably requested by ARP to facilitate consummation of the Restructuring in accordance with the Plan and the related term sheets, including without limitation, if applicable, to timely vote to accept the Plan; (ii) use commercially reasonable efforts to support the confirmation of the Plan and approval of the Disclosure Statement and the solicitation procedures; (iii) not object to, delay, interfere, impede, or take any other action to delay, interfere or impede, directly or indirectly, with the Restructuring, confirmation of the Plan, or approval of the Disclosure Statement or the solicitation procedures; and (iv) not object to our efforts to enter into the Exit Facilities, and not object to, or support the efforts of any other person to oppose or object to, the Exit Facilities.

In accordance with, and subject to the terms and conditions of, the Restructuring Support Agreement, ARP has agreed, subject to applicable fiduciary duties, among other things, to: (i) support and complete the Restructuring and all transactions set forth in the Plan and the Restructuring Support Agreement; (ii) complete the Restructuring and all transactions set forth or described in the Plan; (iii) take any and all necessary actions in furtherance of the Restructuring, the Restructuring Support Agreement and the Plan; (iv) make commercially reasonable efforts to obtain any and all required regulatory and/or third-party approvals for the Restructuring; and (v) operate the business in the ordinary course, taking into account the Restructuring.

The Restructuring Support Agreement may be terminated upon the occurrence of certain events, including the failure to meet specified milestones related to filing, confirmation and consummation of the Plan, among other requirements, and in the event of certain breaches by the parties under the Restructuring Support Agreement. There can be no assurance that the restructuring transactions will be consummated.

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NOTE 4—PROPERTY, PLANT AND EQUIPMENT

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

		June 30,		December 31,			Estimated Useful Lives
		2016		2015			in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	571,761		$	569,377
Pre-development costs		7,125			6,529
Wells and related equipment		3,173,064			3,157,708
Total proved properties		3,751,950			3,733,614
Unproved properties		213,047			213,047
Support equipment		44,264			44,921
Total natural gas and oil properties		4,009,261			3,991,582
Pipelines, processing and compression facilities		61,139			59,733		15 – 20
Rights of way		829			829		20 – 40
Land, buildings and improvements		9,798			9,798		3 – 40
Other		18,422			18,405		3 – 10
		4,099,449			4,080,347
Less – accumulated depreciation, depletion and amortization		(2,825,996	)		(2,763,450	)
	$	1,273,453		$	1,316,897

During the six months ended June 30, 2016 and 2015, we recognized $18.7 million and $29.0 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 was 6.6% for both the three months ended June 30, 2016 and 2015.  The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP were 6.7% and 6.4% for the six months ended June 30, 2016 and 2015, respectively. The amounts of interest capitalized by ARP were $2.4 million and $4.1 million for the three months ended June 30, 2016 and 2015, respectively. The amounts of interest capitalized by ARP were $4.8 million and $8.0 million for the six months ended June 30, 2016 and 2015, respectively.

For the three months ended June 30, 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 depreciation, depletion and amortization in our condensed combined consolidated statements of operations. For the six months ended June 30, 2016 and 2015, we recorded $3.3 million and $3.2 million, respectively, of accretion expense related to ARP and AGP’s asset retirement obligations within depreciation, depletion and amortization in our condensed combined consolidated statements of operations.  For the three months ended June 30, 2016 and 2015, ARP recorded liabilities of $9.9 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.  For the six months ended June 30, 2016 and 2015, ARP recorded liabilities of $12.9 million and $0.5 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 5—DEBT

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

	June 30,			December 31,
	2016			2015
Term loan facilities	$	72,619		$	72,700
Deferred financing costs	(257		)		(3,813	)
ARP First Lien Credit Facility	669,500				592,000
ARP Second Lien Term Loan	244,534				243,783
ARP 7.75% Senior Notes—due 2021	354,385				374,619
ARP 9.25% Senior Notes—due 2021	312,096				324,080
ARP deferred financing costs	(27,238		)		(31,055	)
Total debt, net	1,625,639				1,572,314
Less current maturities	(1,553,277		)		(4,250	)
Total long-term debt, net	$	72,362		$	1,568,064

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:

Condensed Combined Consolidated Balance Sheet	Previously Filed		Adjustment			Restated
December 31, 2015:
Other assets, net	$	88,980	$	(34,868	)	$	54,112
Long-term debt, less current portion	$	1,602,932	$	(34,868	)	$	1,568,064

Cash Interest.  Cash payments for interest by us and our subsidiaries on our/their respective borrowings were $16.4 million and $13.2 million for the three months ended June 30, 2016 and 2015, respectively, and $59.1 million and $51.7 million for the six months ended June 30, 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:

· provide the ability for us and the Borrower to enter into the new Second Lien Credit Agreement (defined below);

· shorten the maturity date of the First Lien Credit Agreement to September 30, 2017, subject to an optional extension to September 30, 2018 by the Borrower, assuming certain conditions are met, including a First Lien Leverage Ratio (as defined in the First Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee;

· modify the applicable cash interest rate margin for ABR Loans and Eurodollar Loans to 0.50% and 1.50%, respectively, and add a pay-in-kind interest payment of 11% of the principal balance per annum;

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· allow the Borrower to make mandatory pre-payments under the First Lien Credit Agreement or the new Second Lien Credit Agreement, in its discretion, and add additional mandatory pre-payment events, including a monthly cash sweep for balances in excess of $4 million; 

· provide that the First Lien Credit Agreement may be prepaid without premium;

· replace the existing financial covenants with (i) the requirement that we maintain a minimum of $2 million in EBITDA on a trailing twelve-month basis, beginning with the quarter ending June 30, 2016, and (ii) the incorporation into the First Lien Credit Agreement of the financial covenants included in ARP’s credit agreement, beginning with the quarter ending June 30, 2016;

· prohibit the payment of cash distributions on our common and preferred units;

· require the receipt of quarterly distributions from AGP and Lightfoot; and

· add a cross-default provision for defaults by ARP.

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 is presented in the table above net of an unamortized discount of $1.9 million as of June 30, 2016, related to the 4,668,044 warrants issued in connection with the Second Lien Credit Agreement (see Note 10).

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.

As a result of the cross-default, on July 11, 2016, we entered into waiver agreements (the “Waivers”) with Riverstone and the Lenders in connection with the First Lien Credit Agreement and the Second Lien Credit Agreement. Pursuant to the Waivers, Riverstone and the Lenders agreed to waive under the First Lien Credit Agreement and the Second Lien Credit Agreement:

· the cross-defaults relating to ARP’s default, for so long as the forbearing parties continue to forbear from exercising their rights and remedies; and

· the potential default relating to ARP’s ongoing negotiations with its lenders and noteholders to the extent any resulting restructuring is completed prior to October 31, 2016

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We and ARP’s future debt maturities, excluding any future payment-in-kind interest payments, are as follows: $1,580.5 million, $35.0 million and $35.8 million, respectively, for the years ending December 31, 2016, 2017 and 2019, 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 a 5% or more unitholder participated in approximately 12% of the loan syndication.

ARP First Lien Credit Facility

ARP is party to a Second Amended and Restated Credit Agreement, dated as of July 31, 2013 by and among ARP, the lenders from time to time party thereto, and Wells Fargo Bank, National Association, as administrative agent, as amended, supplemented or modified from time to time (the “ARP First Lien Credit Facility”), which provides for a senior secured revolving credit facility with a maximum borrowing base of $1.5 billion scheduled to mature in July 2018.

On June 8, 2016, ARP received notice from Wells Fargo Bank, National Association, as administrative agent under the ARP First Lien Credit Facility that its borrowing base had been redetermined in accordance with the ARP First Lien Credit Facility and reduced from $700.0 million to $530.0 million. As of June 30, 2016, $669.5 million in borrowings were outstanding (which includes $4.2 million in letters of credit) under the ARP First Lien Credit Facility, resulting in a borrowing base deficiency of $143.7 million. The ARP First Lien Credit Facility provides that within 30 days after ARP’s receipt of a notification of a borrowing base deficiency, ARP must elect to cure the borrowing base deficiency through any combination of the following actions: (i) repay amounts outstanding under the ARP First Lien Credit Facility sufficient to cure the borrowing base deficiency, either within 30 days after receipt of the borrowing base deficiency notice or in four equal monthly installments beginning on July 11, 2016; or (ii) pledge as collateral additional oil and gas properties acceptable to the administrative agent and lenders sufficient to cure the borrowing base deficiency within 60 days after receipt of the borrowing base deficiency notice. As part of the discussions with ARP’s lenders and noteholders (see Notes 1 and 3), ARP determined not to make the first installment payment that was due on July 11, 2016.

In connection therewith and in support of negotiations with ARP’s First Lien Lenders, Second Lien Lenders, and Consenting Noteholders, on July 11, 2016, ARP and certain of its subsidiaries entered into two forbearance agreements: (i) with Wells Fargo Bank, National Association, as administrative agent, and the other lenders under the ARP First Lien Credit Facility (the “ARP First Lien Credit Forbearance”) and (ii) with the Consenting Noteholders of the 7.75% ARP Senior Notes and the 9.25% ARP Senior Notes (the “ARP Notes Forbearance”).

Pursuant to the ARP First Lien Credit Forbearance, the administrative agent and the lenders representing approximately 81% of the outstanding indebtedness under the ARP First Lien Credit Facility agreed to forbear from exercising their rights and remedies arising from non-payment of the first installment of the borrowing base deficiency cure due on July 11, 2016 and related cross-defaults (the “ARP Specified Default”) until the earliest to occur of (i) July 27, 2016, (ii) the occurrence of an event of default under the ARP First Lien Credit Facility (unrelated to the ARP Specified Default) or (iii) the exercise by any holder of indebtedness outstanding under the ARP Second Lien Term Loan, the ARP Notes or any other material indebtedness of ours of rights or remedies against us or the other loan parties or their respective property.

Pursuant to the ARP Notes Forbearance, the holders of approximately 78% of the aggregate outstanding principal amount of the 7.75% ARP Senior Notes and approximately 82% of the 9.25% ARP Senior Notes agreed to forbear from exercising their rights and remedies arising from the cross-default that resulted from the ARP Specified Default until the earliest to occur of (i) July 27, 2016, (ii) another event of default under the 7.75% ARP Senior Notes indenture or the 9.25% ARP Senior Notes indenture or (iii) any other holder of the ARP Notes commences a legal proceeding against us or the other loan parties or their respective property. The holders of a majority of the Second Lien Term Loan were supportive of the forbearance.

ARP’s borrowing base is scheduled for semi-annual redeterminations in May and November of each year. Up to $20.0 million of the ARP First Lien Credit Facility may be in the form of standby letters of credit, of which $4.2 million was outstanding at June 30, 2016. ARP’s obligations under the ARP First Lien Credit Facility are secured by mortgages on ARP’s oil and gas properties and first priority security interests in substantially all of ARP’s assets. Additionally, obligations under the ARP First Lien Credit Facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. At June 30, 2016, the weighted average interest rate on outstanding borrowings under the ARP First Lien Credit Facility was 4.0%.

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The ARP First Lien Credit Facility 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 First Lien Credit Facility also requires that ARP maintain a ratio of First Lien Debt to EBITDA (ratio as defined in the ARP First Lien Credit Facility) of not greater than 2.75 to 1.00, and a ratio of current assets to current liabilities (ratio as defined in the ARP First Lien Credit Facility) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. ARP was not in compliance with these covenants as of June 30, 2016.  

ARP’s Chapter 11 Filings constituted an event of default that accelerated ARP’s obligations under the ARP First Lien Credit Facility and as a result, we classified $669.5 million of ARP’s outstanding amounts under the ARP First Lien Credit Facility as current portion of long-term debt and $12.2 million of deferred financing costs related to the ARP First Lien Credit Facility as current assets within our condensed combined consolidated balance sheet as of June 30, 2016.Any efforts to enforce such payments are automatically stayed as a result of the Chapter 11 Filings, and the holders’ rights of enforcement are subject to the applicable provisions of Chapter 11.

Pursuant to the ARP Restructuring Support Agreement, ARP completed the sale of substantially all of its commodity hedge positions on July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under the ARP First Lien Credit Facility. Accordingly, approximately $440 million remained outstanding under the ARP First Lien Credit Facility as of July 27, 2016, the date of ARP’s Chapter 11 Filings.

On the Plan Effective Date, ARP expect to enter into the new ARP First Lien Exit Facility, which will replace the ARP First Lien Credit Facility (see Note 3).

ARP Second Lien Term Loan

ARP is party to a Second Lien Credit Agreement, dated as of February 23, 2015 by and among ARP, the lenders from time to time party thereto, and Wilmington Trust, National Association, as administrative agent, as amended, supplemented or modified from time to time (the “ARP Second Lien Term Loan”), which provides for a second lien term loan in an original principal amount of $250.0 million. The ARP Second Lien Term Loan matures on February 23, 2020. The Second Lien Term Loan is presented in the table above net of unamortized discount of $5.5 million as of June 30, 2016.

ARP’s obligations under the ARP Second Lien Term Loan are secured on a second priority basis by security interests in all of ARP’s assets and those of its restricted subsidiaries that guarantee the ARP First Lien Credit Facility. In addition, the obligations under the ARP Second Lien Term Loan are guaranteed by ARP’s material restricted subsidiaries. At June 30, 2016, the weighted average interest rate on outstanding borrowings under the ARP Second Lien Term Loan was 10.0%.

The ARP Second Lien Term Loan contains customary covenants including, without limitation, covenants that limit ARP’s ability to make restricted payments, take on indebtedness, issue preferred units, 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 Second Lien Term Loan contains covenants substantially similar to those in the ARP First Lien Credit Facility, including, among others, restrictions on swap agreements, debt of unrestricted subsidiaries, drilling and operating agreements and the sale or discount of receivables. ARP was not in compliance with the financial covenants as of June 30, 2016.  

ARP’s Chapter 11 Filings constituted an event of default that accelerated ARP’s obligations under the ARP Second Lien Term Loan and as a result, we classified $244.5 million of ARP’s outstanding amounts under the ARP Second Lien Term Loan, which is net of $5.5 million unamortized discount and $9.4 million deferred financing costs, as current portion of long-term debt within our condensed combined consolidated balance sheet as of June 30, 2016.  Any efforts to enforce such payments are automatically stayed as a result of the Chapter 11 Filings, and the holders’ rights of enforcement are subject to the applicable provisions of Chapter 11.

On the Plan Effective Date, ARP expects to enter into the new ARP Second Lien Exit Facility, which will replace the ARP Second Lien Term Loan (see Note 3).

ARP Senior Notes

At June 30, 2016, ARP had $354.4 million outstanding of its 7.75% ARP Senior Notes due 2021. The 7.75% ARP Senior Notes were presented net of a $0.3 million unamortized discount as of June 30, 2016.

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At June 30, 2016, ARP had $312.1 million outstanding of its 9.25% ARP Senior Notes due 2021. The 9.25% ARP Senior Notes were presented net of a $0.8 million unamortized discount as of June 30, 2016.

In January and February 2016, ARP executed transactions to repurchase $20.3 million of its 7.75% Senior Notes and $12.1 million of its 9.25% Senior Notes for $5.5 million, which included $0.6 million of interest. As a result of these transactions, we recognized $26.5 million as gain on early extinguishment of debt, net of accelerated amortization of deferred financing costs of $0.9 million, in our condensed combined consolidated statement of operations for the six months ended June 30, 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 June 30, 2016.

On June 6, 2016, ARP and certain of its subsidiaries, Wells Fargo Bank, National Association, as resigning trustee (“Wells Fargo”) and U.S. Bank National Association, as successor trustee (“U.S. Bank”), entered into an Instrument of Resignation, Appointment and Acceptance (the “Instrument”). In connection with the Instrument, Wells Fargo resigned as trustee, note custodian, registrar and paying agent under the Indenture dated as of July 30, 2013, as supplemented and amended and ARP accepted such resignation and appointed U.S. Bank as the successor trustee, note custodian, registrar and paying agent under the such indenture.

ARP’s Chapter 11 Filings constituted an event of default that accelerated ARP’s obligations under the 7.75% ARP Senior Notes and the 9.25% ARP Senior Notes and as a result, we classified $354.4 million of ARP’s outstanding amounts under the 7.75% ARP Senior Notes, which is net of $0.3 million unamortized discount and $9.5 million deferred financing costs, and $312.1 million of ARP’s outstanding amounts under the 9.25% ARP Senior Notes, which is net of $0.8 million unamortized discount and $8.3 million deferred financing costs, as current portion of long-term debt within our condensed combined consolidated balance sheet as of June 30, 2016. Any efforts to enforce such payments are automatically stayed as a result of the Chapter 11 Filings, and the holders’ rights of enforcement are subject to the applicable provisions of Chapter 11.

On the Plan Effective Date, the 7.75% Senior Notes and the 9.25% Senior Notes (together with accrued but unpaid interest) will be cancelled and the holders will receive 90% of the common equity interests of New HoldCo (see Note 3).

NOTE 6—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.

ARP and AGP 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 $234.6 million and $358.1 million at June 30, 2016 and December 31, 2015, respectively. Of the $2.3 million of net gain in accumulated other comprehensive income within unitholders’ equity on our condensed combined consolidated balance sheet related to derivatives at June 30, 2016, we expect to reclassify $1.5 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

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production revenues will be reclassified to our condensed combined consolidated statements of operations in later periods as the remaining contracts expire.

Pursuant to the ARP Restructuring Support Agreement, ARP completed the sale of certain of substantially all of its commodity hedge positions on July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under the ARP First Lien Credit Facility.

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

		Three Months Ended June 30,					Six Months Ended June 30,
	2016			2015			2016			2015
Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets(1)	$	5,555		$	25,778		$	9,070		$	53,121
Portion of settlements attributable to subsequent mark to market gains (losses)		39,835			14,922			85,265			30,125
Total cash settlements on commodity derivative contracts	$	45,390		$	40,700		$	94,335		$	83,246
Gains recognized on cash settlement(2)	$	4,732		$	3,678		$	10,666		$	6,881
Gains (losses) recognized on open derivative contracts(2)		(78,822	)		(30,574	)		(38,303	)		71,808
Gains (losses) on mark-to-market derivatives	$	(74,090	)	$	(26,896	)	$	(27,637	)	$	78,689

(1) Recognized in gas and oil production revenue.

(2) Recognized in gain on mark-to-market derivatives.

During the three and six months ended June 30, 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 June 30, 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 June 30, 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):

Offsetting Derivatives as of June 30, 2016	Gross Amounts Recognized			Gross Amounts Offset			Net Amount Presented
Current portion of derivative assets	$	183		$	(183	)	$	—
Long-term portion of derivative assets		55			(55	)		—
Total derivative assets	$	238		$	(238	)	$	—
Current portion of derivative liabilities	$	(320	)	$	183		$	(137	)
Long-term portion of derivative liabilities		(218	)		55			(163	)
Total derivative liabilities	$	(538	)	$	238		$	(300	)
Offsetting Derivatives as of December 31, 2015
Current portion of derivative assets	$	399		$	(96	)	$	303
Long-term portion of derivative assets		162			(53	)		109
Total derivative assets	$	561		$	(149	)	$	412
Current portion of derivative liabilities	$	(96	)	$	96		$	—
Long-term portion of derivative liabilities		(53	)		53			—
Total derivative liabilities	$	(149	)	$	149		$	—

At June 30, 2016, AGP had the following commodity derivatives:

Type	Production Period Ending December 31,	Volumes(1)	Average Fixed Price(1)		Fair Value (Liability)			Total Type
					(in thousands)(2)			(in thousands)(2)
Crude Oil – Fixed Price Swaps	2016(3)	31,600	$	46.350	$	(95	)
	2017	37,100	$	49.968	$	(79	)
	2018	26,500	$	48.850	$	(126	)
						AGP’s net liabilities		$	(300)

(1) Volumes for crude oil are stated in barrels.

(2) Fair value of crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable.

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

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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):

Offsetting Derivatives as of June 30, 2016	Gross Amounts Recognized		Gross Amounts Offset		Net Amount Presented
Current portion of derivative assets	$	99,654	$	—	$	99,654
Long-term portion of derivative assets		135,231		—		135,231
Total derivative assets	$	234,885	$	—	$	234,885
Current portion of derivative liabilities	$	—	$	—	$	—
Long-term portion of derivative liabilities		—		—		—
Total derivative liabilities	$	—	$	—	$	—
Offsetting Derivatives as of December 31, 2015
Current portion of derivative assets	$	159,460	$	—	$	159,460
Long-term portion of derivative assets		198,262		—		198,262
Total derivative assets	$	357,722	$	—	$	357,722
Current portion of derivative liabilities	$	—	$	—	$	—
Long-term portion of derivative liabilities		—		—		—
Total derivative liabilities	$	—	$	—	$	—

At June 30, 2016, ARP had the following commodity derivatives:

Type	Production Period Ending December 31,	Volumes(1)	Average Fixed Price(1)		Fair Value Asset		Total Type
					(in thousands)(2)		(in thousands)(2)
Natural Gas – Fixed Price Swaps	2016(3)	26,910,000	$	4.224	$	32,326
	2017	50,120,000	$	4.221	$	51,933
	2018	40,300,000	$	4.168	$	45,498
	2019	15,860,000	$	4.019	$	15,945
							$	145,702
Natural Gas – Put Options – Drilling Partnerships	2016(3)	720,000	$	4.150	$	814
							$	814
Crude Oil – Fixed Price Swaps	2016(3)	820,500	$	81.685	$	26,449
	2017	1,200,000	$	77.610	$	30,412
	2018	1,080,000	$	76.281	$	24,184
	2019	540,000	$	68.371	$	7,324
							$	88,369
					Total net ARP assets		$	234,885

(1) Volumes for natural gas are stated in million British Thermal Units. Volumes for crude oil are stated in barrels.

(2) Fair value for natural gas fixed price swaps and natural gas put options based on forward NYMEX natural gas prices, as applicable. Fair value for crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable.

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

Secured Hedge Facility

At June 30, 2016, ARP had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under ARP’s revolving credit facility, ARP is required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. ARP, as general partner

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of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility and guarantees their obligations under it. Before executing any hedge transaction, a participating Drilling Partnership is required to, among other things, provide mortgages on its oil and gas properties and first priority security interests in substantially all of its assets to the collateral agent for the benefit of the counterparties. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, 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.

An event of default occurred under the secured hedging facility agreement upon ARP’s filing of voluntary petitions for relief under Chapter 11.  The lenders under the secured hedge facility agreed to forbear from exercising remedies in respect of such event of default while the Chapter 11 Filings are pending and, upon occurrence of the effective date of the Plan contemplated by ARP’s Restructuring Support Agreement, such event of default will no longer be deemed to exist or to continue under the secured hedge facility.

In addition, it will be an event of default under ARP’s revolving credit facility if ARP, as general partner of the Drilling Partnerships, breaches an obligation governed by the secured hedge facility and the effect of such breach is to cause amounts owing under swap agreements governed by the secured hedge facility to become immediately due and payable.

NOTE 7—FAIR VALUE OF FINANCIAL INSTRUMENTS

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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 June 30, 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 June 30, 2016 and December 31, 2015 were as follows (in thousands):

	Level 1		Level 2			Level 3		Total
As of June 30, 2016
Assets, gross
Rabbi trust	$	4,072	$	—		$	—	$	4,072
ARP Commodity swaps		—		234,071			—		234,071
ARP Commodity puts		—		814			—		814
AGP Commodity swaps		—		238			—		238
Total assets, gross		4,072		235,123			—		239,195
Liabilities, gross
AGP Commodity swaps		—		(538	)		—		(538	)
Total derivative liabilities, gross		—		(538	)		—		(538	)
Total assets, fair value, net	$	4,072	$	234,585		$	—	$	238,657
As of December 31, 2015
Assets, gross
Rabbi trust	$	5,584	$	—		$	—	$	5,584
ARP Commodity swaps		—		355,329			—		355,329
ARP Commodity puts		—		2,393			—		2,393
AGP Commodity swaps		—		561			—		561
Total assets, gross		5,584		358,283			—		363,867
Liabilities, gross
AGP Commodity swaps		—		(149	)		—		(149	)
Total derivative liabilities, gross	$	—	$	(149	)	$	—	$	(149	)
Total assets, fair value, net	$	5,584	$	358,134		$	—	$	363,718

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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 June 30, 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 $1,020.7 million and $929.2 million, respectively, compared with the carrying amounts of $1,661.6 million and $1,614.7 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.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

Management estimated the fair values of ARP’s natural gas and oil properties transferred to ARP upon liquidations of certain Drilling Partnerships (see Note 8) based on discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, ARP’s future operating and development costs of the assets, the respective natural gas, oil and natural gas liquids forward price curves, and estimated salvage values using ARP’s historical experience and external estimates of recovery values. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs.

Management estimated the fair value of asset retirement obligations transferred to ARP upon liquidations of certain Drilling Partnerships (see Note 4) based on discounted cash flow projections using ARP’s historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future considering inflation rates, federal and state regulatory requirements, and ARP’s assumed credit-adjusted risk-free interest rate. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs.

Management estimated the fair value of the Warrants associated the Second Lien Credit Agreement (see Note 10) using a Black-Scholes pricing model which is based on Level 3 inputs including a unit price on the date of issuance of $0.50, exercise price of $0.20, risk free rate of 1.8%, a term of 10 years, and estimated volatility rate of 57%. The volatility rate used is consistent with that of ARP and similar sized entities within the industry. The estimated fair value per warrant was $0.40.

NOTE 8—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 management fee in connection with its management of AGP equivalent to 1% of capital contributions per annum. During the three months ended June 30, 2016 and 2015, AGP paid approximately $0.6 million and $0.3 million related to AGP GP for this management fee. During the six months ended June 30, 2016 and 2015, AGP paid approximately $1.1 million and $0.6 million related to AGP GP for this management fee. We charge direct costs, such as salary and wages, and allocate indirect costs, such as rent for offices, 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.

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In March 2016, ARP transferred $36.7 million of investor capital raised and $13.3 million of accrued well drilling and completion costs incurred by ARP to the Atlas Eagle Ford 2015 L.P. private drilling partnership for activities directly related to their program. In June 2016, ARP transferred $5.2 million of funds to certain of the Drilling Partnerships that were projected to make monthly or quarterly distributions to their limited partners over the next several months and/or quarter to ensure accessible distribution funding coverage in accordance with the respective Drilling Partnerships’ operations and partnership agreements in the event ARP experiences a prolonged restructuring period as ARP performs all administrative and management functions for the Drilling Partnerships. On July 26, 2016, ARP adopted certain amendments to the Drilling Partnerships’ partnership agreements, in accordance with ARP’s ability to amend the Drilling Partnerships’ partnership agreements to cure an ambiguity in or correct or supplement any provision of the Drilling Partnerships’ partnership agreements as may be inconsistent with any other provision, to provide that bankruptcy and insolvency events, such as the Chapter 11 Filings, with respect to the managing general partner will not cause the managing general partner to cease to serve as the managing general partner of the Drilling Partnerships nor cause the termination of the Drilling Partnerships.

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. During the quarter ended June 30, 2016, ARP recorded $7.2 million and $12.4 million of gas and oil properties and asset retirement obligations, respectively, transferred to ARP as a result of certain Drilling Partnership liquidations. The gas and oil properties and asset retirement obligations were recorded at their fair values on the respective dates of the Drilling Partnerships’ liquidation and transfer to ARP (see Note 7) and resulted in a non-cash loss of $6.2 million, net of liquidation and transfer adjustments, for the three and six months ended June 30, 2016, which was recorded in other income/(loss) in the condensed consolidated statement of operations.

As of June 30, 2016 and December 31, 2015, ARP had trade receivables of $8.9 million and $6.6 million, respectively, from certain of the Drilling Partnerships, which were recorded in accounts receivable in the condensed consolidated balance sheets.  As of June 30, 2016 and December 31, 2015, ARP had trade payables of $1.5 million and $3.0 million, respectively, to certain of the Drilling Partnerships, which were 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 5), our Series A preferred units (Note 10) and our general partner and limited partner interest in Lightfoot (see Note 1).

NOTE 9—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 June 30, 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

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reflect that the agreed upon limited partner investment return will be achieved during the subordination period, ARP will 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 both the three months ended June 30, 2016 and 2015, $0.5 million 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.  For the six months ended June 30, 2016 and 2015, $0.6 million and $1.1 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 June 30, 2016, we and our subsidiaries are committed to expend approximately $4.6 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 10—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.

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. The Warrants include a cashless exercise provision entitling the Lenders to surrender a portion of the underlying common units that has a value equal to the aggregate exercise price in lieu of paying cash upon exercise of a warrant. As a result of issuance of the Warrants, we recognized a $1.9 million debt discount on the Second Lien Credit Agreement, which will be amortized over the term of the debt, and a corresponding $1.9 million increase to unitholders’ equity – warrants on our condensed combined balance sheet as of June 30, 2016.

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

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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.

On May 12, 2016, due to the income tax ramifications of potential options we were 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. The delayed vesting schedule did not have a significant impact on the compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the three and six months ended June 30, 2016 or our remaining unrecognized compensation expense related to such awards.

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 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 June 30, 2016, ARP did not issue any common limited partner units under the equity distribution program. During the three months ended June 30, 2015, ARP issued 2,403,288 common limited partner units under the equity distribution agreement for net proceeds of $17.5 million, net of $0.5 million in commissions and offering expenses paid.  During the six months ended June 30, 2016, ARP issued 245,175 common limited partner units under the equity distribution program for net proceeds of $0.2 million, net of $4,000 in commissions and offering expenses paid. During the six months ended June 30, 2015, ARP issued 2,885,824 common limited partner units under the equity distribution agreement for net proceeds of $21.4 million, net of $0.6 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 and six months ended June 30, 2016 and 2015.

In May 2015, in connection with the Arkoma Acquisition, ARP issued 6,500,000 of its common limited partner units in a public offering at a price of $7.97 per unit, yielding net proceeds of $49.7 million. ARP used a portion of the net proceeds to fund the Arkoma Acquisition and to reduce borrowings outstanding under ARP’s First Lien Credit Facility.

In April 2015, ARP issued 255,000 of its 10.75% Class E ARP Preferred Units at a public offering price of $25.00 per unit for net proceeds of $6.0 million.

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 ARP Preferred Units to the seller at a value of $25.00 per unit.

On May 12, 2016, due to the income tax ramifications of the potential options ARP was 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 August 31 ,2016. The delayed vesting schedule did not have a significant impact on ARP’s compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the three and six months ended June 30, 2016 or our remaining unrecognized compensation expense related to such awards.

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On July 12, 2016, ARP received notification from the New York Stock Exchange that the NYSE commenced proceedings to delist ARP’s common units as a result of ARP’s failure to comply with the continued listed standards set forth in Section 802.01C of the NYSE Listed Company Manual to maintain an average closing price of $1.00 per unit over a consecutive 30 day period. The Class D ARP Preferred Units and Class E ARP Preferred Units were also delisted from the NYSE. ARP’s common units, Class D ARP Preferred Units, and Class E ARP Preferred Units began trading on the OTC market on July 13, 2016 with the ticker symbol “ARPJ” for ARP’s common units, “ARPJP” for Class D ARP Preferred Units, and “ARPJN” for Class E ARP Preferred Units.

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 $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 six months ended June 30, 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 six months ended June 30, 2015, we recorded gains of $2.9 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.

NOTE 11—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 entered into on March 30, 2016 (see Note 5), we are prohibited from paying future cash distributions on our common and preferred units.

During the six months ended June 30, 2016, we paid a distribution of $1.0 million to Class A preferred unitholders. During the six months ended June 30, 2015, we paid a distribution of $0.7 million to Class A preferred unitholders.

ARP Cash Distributions. ARP has a monthly cash distribution program whereby ARP distributes all of its available cash (as defined in the 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. In July 2015, the remaining 39,654 Class B Preferred Units were converted into ARP common limited partner units.

The Class C ARP Preferred Units received 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. On May 5, 2016, the Board of

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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.

ARP pays quarterly distributions on its 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 quarterly distributions on its 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 June 16, 2016, the Board of Directors elected to suspend the distributions on the Class D ARP Preferred Units and the Class E ARP Preferred Units, beginning with the second quarter 2016 distribution, due to the continued lower commodity price environment.  The Class D ARP Preferred Units and Class E ARP Preferred Units accrued distributions of $1.9 million and $0.1 million, respectively, from April 15, 2016 through June 30, 2016.  However, due to the distribution suspension and ARP’s recent Chapter 11 filings, these amounts were not earned as the preferred units will be cancelled without receipt of any consideration on the Plan Effective Date.

During the six months ended June 30, 2016, ARP paid four monthly cash distributions totaling $5.1 million to common limited partners ($0.0125 per unit per month); $2.5 million to Preferred Class C limited partners ($0.0125 per unit per month); and $0.2 million to the General Partner Class A holder ($0.0125 per unit per month). During the six months ended June 30, 2015, ARP paid six monthly cash distributions totaling $71.2 million to common limited partners ($0.1966 per unit in both January and February 2015 and $0.1083 per unit in March through June 2015); $4.0 million to Preferred Class C limited partners ($0.1966 per unit in both January and February 2015 and $0.17 per unit in March through June 2015); and $3.6 million to the General Partner Class A holder ($0.1966 per unit in both January and February 2015 and $0.1083 per unit in March through June 2015).

During the six months ended June 30, 2016, ARP paid two distributions totaling $4.4 million to Class D Preferred units ($0.5390625 per unit) for the period October 15, 2016 through April 14, 2016. During the six months ended June 30, 2015, ARP paid two distributions totaling $4.1 million to Class D Preferred units ($0.6169270 per unit for the period October 2, 2014 through January 14, 2015 and $0.539063 per unit for the period January 15, 2015 through April 14, 2015).

During the six months ended June 30, 2016, ARP paid two distributions totaling $0.3 million to Class E Preferred units ($0.671875 per unit) for the period October 15, 2015 through April 14, 2016.  No distributions were paid to Class E Preferred units during the six months ended June 30, 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 six months ended June 30, 2016, AGP paid a distribution of $8.2 million to common limited partners ($0.1750 per unit per quarter) and $0.2 million to the general partner’s Class A units ($0.1750 per unit per quarter). During the six months ended June 30, 2015, AGP paid a distribution of $3.8 million to common limited partners ($0.1750 per unit per quarter) and $0.1 million to the general partner’s Class A units ($0.1750 per unit per quarter).

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NOTE 12—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 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):

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Atlas Resource Partners:
Revenues(1)	$	(16,824	)	$	96,125		$	86,384		$	339,714
Operating costs and expenses	(57,125		)		(75,822	)	(116,327		)		(163,640	)
Depreciation, depletion and amortization expense	(29,008		)		(42,494	)	(59,053		)		(85,485	)
Gain (loss) on asset sales and disposal	(502		)		97		(493		)		86
Interest expense	(31,954		)		(24,716	)	(59,659		)		(49,913	)
Gain on early extinguishment of debt	—				—		26,498				—
Other income (loss)		(6,156	)		—			(6,156	)		—
Segment income (loss)	$	(141,569	)	$	(46,810	)	$	(128,806	)	$	40,762
Atlas Growth Partners:
Revenues	$	2,559		$	1,865		$	5,993		$	4,176
Operating costs and expenses	(3,421		)		(3,243	)	(6,924		)		(8,312	)
Depreciation, depletion and amortization expense	(3,299		)		(782	)	(7,526		)		(2,247	)
Segment loss	$	(4,161	)	$	(2,160	)	$	(8,457	)	$	(6,383	)
Corporate and other:
Revenues	$	461		$	257		$	672		$	156
General and administrative	(1,531		)		(2,359	)	(3,685		)		(22,574	)
Interest expense	(3,890		)		(8,471	)	(5,633		)		(18,025	)
Loss on early extinguishment of debt	(27		)		—		(6,080		)		—
Segment loss	$	(4,987	)	$	(10,573	)	$	(14,726	)	$	(40,443	)
Reconciliation of segment loss to net loss:
Segment income (loss):
Atlas Resource Partners	$	(141,569	)	$	(46,810	)	$	(128,806	)	$	40,762
Atlas Growth Partners	(4,161		)		(2,160	)	(8,457		)		(6,383	)
Corporate and other		(4,987	)		(10,573	)		(14,726	)		(40,443	)
Net loss	$	(150,717	)	$	(59,543	)	$	(151,989	)	$	(6,064	)
Reconciliation of segment revenues to total revenues:
Segment revenues:
Atlas Resource Partners(1)	$	(16,824	)	$	96,125		$	86,384		$	339,714
Atlas Growth Partners	2,559				1,865		5,993				4,176
Corporate and other	461				257		672				156
Total revenues(1)	$	(13,804	)	$	98,247		$	93,049		$	344,046
Capital expenditures:
Atlas Resource Partners	$	5,650		$	26,993		$	18,820		$	69,491
Atlas Growth Partners	778				3,175		6,327				13,118
Corporate and other	—				—		—				—
Total capital expenditures	$	6,428		$	30,168		$	25,147		$	82,609

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	June 30,		December 31,
	2016		2015
Balance sheet:
Goodwill:
Atlas Resource Partners	$	13,639	$	13,639
Atlas Growth Partners	—			—
Corporate and other	—			—
Total goodwill	$	13,639	$	13,639
Total assets:
Atlas Resource Partners	$	1,540,386	$	1,699,949
Atlas Growth Partners	135,721			159,622
Corporate and other	21,193			23,675
Total assets	$	1,697,300	$	1,883,246

1) Revenues include gains (losses) on mark to market derivatives. A $73.3 million loss on ARP’s mark-to-market derivatives is included for the three months ended June 30, 2016 related to increases in commodity future prices relative to ARP’s commodity fixed price swaps during the three months ended June 30, 2016 as compared to the prior year period.

NOTE 13—SUBSEQUENT EVENTS

Atlas Resource Partners

First Lien Credit Facility Installment Payment. As part of the ongoing discussions with ARP’s lenders and noteholders, ARP determined not to make the first installment payment that was due under the ARP First Lien Credit Facility on July 11, 2016 (see Note 5).

NYSE Compliance.On July 12, 2016, ARP received notification from the New York Stock Exchange that the NYSE commenced proceedings to delist ARP’s common units (see Note 10).

Restructuring Support Agreement. On July 25, 2016, ARP and certain of their subsidiaries and us, solely with respect to certain sections thereof, entered into the Restructuring Support Agreement with the Restructuring Support Parties.  On July 27, 2016, ARP and certain of their subsidiaries filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court (see Note 3).

Sale of ARP’s Commodity Hedge Positions. Pursuant to the ARP Restructuring Support Agreement, ARP completed the sale of substantially all of its commodity hedge positions on July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under the ARP First Lien Credit Facility (See Note 5).

Conversion of Preferred Units and Warrants. On July 31, the 3,749,986 Class C ARP Preferred Units that were issued to us on July 31, 2013, were converted into 3,749,986 common units and the associated warrant issued to us to purchase 562,497 of ARP’s common units expired.

Atlas Growth Partners

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

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ITEM 2: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 

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 (OTC: 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 June 30, 2016, our operations primarily consisted of our ownership interests in the following:

· 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 23.3% limited partner interest (consisting of 20,962,485 common and 3,749,986 preferred limited partner units) in ARP, a publicly traded Delaware master limited partnership (“MLP”) (OTC: ARPJ) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”), with operations in basins across the United States. As part of its exploration and production activities, ARP sponsors and manages tax-advantaged investment partnerships (“Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas and oil production activities;

· All of the incentive distribution rights, an 80.0% general partner interest and a 2.1% limited partner interest in AGP, a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations primarily focused in the Eagle Ford Shale in South Texas. On June 30, 2015, AGP concluded a private placement offering, during which it issued $233.0 million of its common limited partner units. Of the $233.0 million of gross funds raised, we purchased $5.0 million common limited partner units. AGP’s registration statement on Form S-1 (Registration Number: 333-207537) was declared effective by the Securities and Exchange Commission on April 5, 2016. AGP is offering in the aggregate up to 100,000,000 Class A common units and Class T common units, each representing limited partner interests in AGP, pursuant to a primary offering on a "best efforts" basis. AGP must receive minimum offering proceeds of $1.0 million to break escrow, and the maximum offering proceeds of the primary offering may not exceed $1.0 billion. The Class A common units will be sold for a cash purchase price of $10.00 and the Class T common units will be sold for a cash purchase price of $9.60, with the remaining $0.40 constituting the Class T common unitholders' deferred payment obligation to AGP. AGP is also offering up to 21,505,376 Class A common units at $9.30 per unit pursuant to a distribution reinvestment; and

· 15.4% general partner interest and 12.0% limited partner interest in Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and Lightfoot Capital Partners GP, LLC (“Lightfoot G.P.”), its general partner (collectively, “Lightfoot”), which incubate new MLPs and invest in existing MLPs.

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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 June 30, 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 12 – 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 Item 1: “Financial Statements (Unaudited)” - Note 2).

RECENT DEVELOPMENTS

First Lien Credit Agreement

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”).  See “Credit Facilities – Term Loan Facilities” below.

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. See “Credit Facilities – Term Loan Facilities” below.

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. See “Issuance of Units” below.

NYSE Compliance

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. See “Issuance of Units” below.

Atlas Resource Partners

Restructuring and Chapter 11 Bankruptcy Proceedings

On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York (the

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“Bankruptcy Court,” and the cases commenced thereby, the “Chapter 11 Filings”). See “Liquidity and Capital Resources” below for more information.

Restructuring Support Agreement

On July 25, 2016, ARP and certain of its subsidiaries and us, solely with respect to certain sections thereof, entered into the Restructuring Support Agreement with the Restructuring Support Parties.  On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. Under the Restructuring Support Agreement, the Restructuring Support Parties have agreed, subject to certain terms and conditions, to support ARP’s Restructuring pursuant to the Plan.

In particular, under the Plan, on the Plan’s effective date (the “Plan Effective Date”), the First Lien Lenders will receive cash payment of all obligations owed to them by ARP pursuant to the senior secured revolving credit facility (other than $440 million of principal and face amount of letters of credit) and become lenders under an exit facility credit agreement (the “First Lien Exit Facility”), composed of a $410 million conforming reserve-based tranche and a $30 million non-conforming tranche. The non-conforming tranche will mature on May 1, 2017 and the conforming reserve-based tranche will mature on August 23, 2019. In addition, ARP will enter into a new second lien credit agreement (the “Second Lien Exit Facility” and, together with the First Lien Exit Facility, the “Exit Facilities”). The Second Lien Lenders will receive a pro rata share of the Second Lien Exit Facility, which will have an aggregate principal amount of $250 million plus the amounts resulting from the accrual of paid in kind interest on the principal amount of $250 million from the commencement of ARP’s Chapter 11 Filings, with interest expense paid in cash to be reduced to 2% and the remainder to be paid-in-kind from the commencement date through May 1, 2017 at a rate equal to Adjusted LIBO Rate plus 9% per annum. During the next 15-month period, cash and in-kind interest will vary based on a pricing grid tied to ARP’s leverage ratio under the ARP revolving credit facility. After such 15-month period, interest will accrue at a rate equal to Adjusted LIBO Rate plus 9% per annum and will be payable in cash. In addition to the Second Lien Exit Facility, the Second Lien Lenders will receive a pro rata share of 10% of the common equity interests of New HoldCo, subject to dilution by a management incentive plan. Holders of the Notes, in exchange for 100% of the $668 million aggregate principal amount of Notes outstanding plus accrued but unpaid interest as of the commencement of the Chapter 11 cases, will receive, on the Plan Effective Date, 90% of the common equity interests of New HoldCo as of the Plan Effective Date, subject to dilution by a management incentive plan.

Under the Plan, holders of ARP’s limited partnership units will receive no recovery. On the Plan Effective Date, all of ARP’s preferred limited partnership units and common limited partnership units will be cancelled without the receipt of any consideration.

ARP intends to continue to operate its businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, all suppliers, vendors, employees, royalty owners, trade partners and landlords will be unimpaired by the Plan and will be satisfied in full in the ordinary course of business, and ARP’s existing trade contracts and terms will be maintained. To assure ordinary course operations, ARP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to ARP, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.

Under the Plan, on the Plan Effective Date, a wholly owned subsidiary of the Company (“ARP Mgt LLC”) will receive a preferred share of New HoldCo. The preferred share will entitle ARP Mgt LLC to receive 2% of the economics of New HoldCo (subject to dilution if catch-up contributions are not made with respect to future equity issuances, other than pursuant to the management incentive plan) and certain other rights as provided for in the Restructuring Support Agreement. Four of the seven initial members of the board of directors of New HoldCo are representatives of ARP Mgt LLC (the “New HoldCo Class A Directors”). For so long as ARP Mgt LLC holds such preferred share, the New HoldCo Class A Directors will be appointed by a majority of ARP’s Class A Directors then in office. New HoldCo will have a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in New HoldCo's limited liability company agreement), subject to the receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of New HoldCo unaffiliated with ARP Mgt LLC voting in favor of the exercise of the right to purchase the preferred share.

In accordance with, and subject to the terms and conditions of, the Restructuring Support Agreement, each of the Restructuring Support Parties has agreed, among other things, to: (i) support and take all commercially reasonable actions

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necessary or reasonably requested by ARP to facilitate consummation of the Restructuring in accordance with the Plan and the related term sheets, including without limitation, if applicable, to timely vote to accept the Plan; (ii) use commercially reasonable efforts to support the confirmation of the Plan and approval of the Disclosure Statement and the solicitation procedures; (iii) not object to, delay, interfere, impede, or take any other action to delay, interfere or impede, directly or indirectly, with the Restructuring, confirmation of the Plan, or approval of the Disclosure Statement or the solicitation procedures; and (iv) not object to our efforts to enter into the Exit Facilities, and not object to, or support the efforts of any other person to oppose or object to, the Exit Facilities.

In accordance with, and subject to the terms and conditions of, the Restructuring Support Agreement, ARP has agreed, subject to applicable fiduciary duties, among other things, to: (i) support and complete the Restructuring and all transactions set forth in the Plan and the Restructuring Support Agreement; (ii) complete the Restructuring and all transactions set forth or described in the Plan; (iii) take any and all necessary actions in furtherance of the Restructuring, the Restructuring Support Agreement and the Plan; (iv) make commercially reasonable efforts to obtain any and all required regulatory and/or third-party approvals for the Restructuring; and (v) operate the business in the ordinary course, taking into account the Restructuring.

The Restructuring Support Agreement may be terminated upon the occurrence of certain events, including the failure to meet specified milestones related to filing, confirmation and consummation of the Plan, among other requirements, and in the event of certain breaches by the parties under the Restructuring Support Agreement. There can be no assurance that the restructuring transactions will be consummated.

Liquidation of Hedge Portfolio

On July 27, 2016, pursuant to ARP’s Restructuring Support Agreement, ARP completed the sale of certain of its commodity hedge positions on July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under the ARP First Lien Credit Facility. Accordingly, approximately $440 million remains outstanding under the ARP First Lien Credit Facility as of July 27, 2016.

NYSE Delisting

On July 12, 2016, ARP received notification from the New York Stock Exchange (“NYSE”) that the NYSE commenced proceedings to delist ARP’s common units as a result of its failure to comply with the continued listed standards set forth in Section 802.01C of the NYSE Listed Company Manual to maintain an average closing price of $1.00 per unit over a consecutive 30 day period. ARP’s Class D Preferred Units and Class E Preferred Units were also delisted from the NYSE. ARP’s common units, Class D Preferred Units, and Class E Preferred Units began trading on the OTC market on July 13, 2016 with the ticker symbol “ARPJ” for its common units, “ARPJP” for its Class D Preferred Units, and “ARPJN” for its Class E Preferred Units.

Forbearance Agreements

On July 11, 2016, ARP and certain of its subsidiaries entered into two forbearance agreements: (i) with Wells Fargo Bank, National Association, as administrative agent, and the other lenders under the First Lien Credit Facility and (ii) with certain holders of ARP’s 7.75% Senior Notes and certain holders of ARP’s 9.25% Senior Notes to forbear from exercising rights and remedies arising from non-payment of the first installment of the borrowing base deficiency cure due on July 11, 2016 and any associated cross-defaults until July 27, 2016 or another event of default occurred. See “Credit Facilities – Credit Facility” section below.

Suspension of ARP’s Preferred D and Preferred E Unit Distributions.

On June 16, 2016, our Board of Directors elected to suspend ARP’s 8.625% Class D Cumulative Redeemable Perpetual Preferred Units and ARP’s 10.75% Class E Cumulative Redeemable Perpetual Preferred Units distributions, beginning with the second quarter 2016 distribution, due to the continued lower commodity price environment.

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First Lien Credit FacilityBorrowing Base Redetermination.

On June 8, 2016, ARP received notice from Wells Fargo Bank, National Association, as administrative agent under the ARP First Lien Credit Facility that ARP’s borrowing base had been redetermined in accordance with the ARP First Lien Credit Facility and reduced from $700.0 million to $530.0 million. See “Credit Facilities – First Lien Credit Facility” section below.

Suspension of ARP’s Common Unit and Class C ARP Preferred Unit Distributions.

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

Senior Note Repurchases.

In January and February 2016, ARP executed transactions to repurchase $20.3 million of their 7.75% ARP Senior Notes and $12.1 million of their 9.25% ARP Senior Notes for $5.5 million. As a result of these transactions, ARP recognized $26.5 million as gain on early extinguishment of debt in the first quarter of 2016. (See Item 1: “Financial Statements (Unaudited)” – Note 5 for further details).

Atlas Growth Partners

Effective Registration Statement

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

Cash Distributions

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

GENERAL TRENDS AND OUTLOOK

We expect our 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.

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

Our subsidiaries’ future gas and oil reserves, production, cash flow, the ability to make payments on debts 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.  Based on current market conditions, ARP believes that a reduction in its debt and cash

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interest obligations is needed to improve its financial position and flexibility and to position it to take advantage of opportunities that may arise out of the current industry downturn.

RESULTS OF OPERATIONS

Gas and Oil Production

Production Profile. At June 30, 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 June 30, 2016, our subsidiaries have established production positions in the following operating areas:

· the Eagle Ford Shale in south Texas, in which ARP and AGP acquired acreage and producing wells in November 2014;

· AGP’s and ARP’s Barnett Shale and Marble Falls play, both in the Fort Worth Basin in northern Texas. The Barnett Shale contains mostly dry gas and the Marble Falls play contains liquids rich gas and oil;

· ARP’s coal-bed methane producing natural gas assets in (1) the Raton Basin in northern New Mexico and the Black Warrior Basin in central Alabama, which ARP acquired in 2013; (2) the Central Appalachia Basin in West Virginia and Virginia, which ARP acquired in 2014, and; (3) the Arkoma Basin in eastern Oklahoma, which ARP acquired from us in 2015.

· ARP’s Rangely field in northwest Colorado, a mature tertiary CO2 flood with low-decline oil production, where ARP has a 25% non-operated net working interest position following its acquisition on June 30, 2014;

· ARP’s Appalachia Basin assets, including the Marcellus Shale, a rich, organic shale that generally contains dry, pipeline-quality natural gas, and the Utica Shale, which lies several thousand feet below the Marcellus Shale, is much thicker than the Marcellus Shale and trends primarily towards wet natural gas in the central region and dry gas in the eastern region; the Chattanooga Shale in northeastern Tennessee, which enables ARP to access other formations in that region such as the Monteagle and Ft. Payne Limestone; and the New Albany Shale in southwestern Indiana, a biogenic shale play with a long-lived and shallow decline profile; and

· AGP’s and ARP’s Mid-Continent assets, including Mississippi Lime and Hunton plays in northwestern Oklahoma, an oil and NGL-rich area, where AGP participated in non-operated well drilling since 2014, and ARP’s Niobrara Shale assets in northeastern Colorado, a predominantly biogenic shale play that produces dry gas.

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 and six months ended June 30, 2016 and 2015:

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Atlas Resource Partners:
Gross wells drilled(4)		—		2		—		7
Net wells drilled(1)		—		2		—		5
Gross wells turned in line(3)		—		10		—		31
Net wells turned in line(1) (3)		—		3		—		10

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Atlas Growth Partners:
Gross wells drilled(4)	—	—	—	—
Net wells drilled(2)	—	—	—	—
Gross wells turned in line(3)	—	2	2	2
Net wells turned in line(2) (3)	—	2	2	2

(1) Includes (i) ARP’s percentage interest in the wells in which it has a direct ownership interest and (ii) ARP’s percentage interest in the wells based on its percentage ownership in its Drilling Partnerships.

(2) Includes AGP’s percentage interest in the wells in which it has a direct ownership interest.

(3) Wells turned in line refers to wells that have been drilled, completed, and connected to a gathering system.

(4) Neither ARP nor AGP drilled any exploratory wells during the three and six months ended June 30, 2016 and 2015; neither ARP nor AGP had any gross or net dry wells within their operating areas during the three and six months ended June 30, 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 and six months ended June 30, 2016 and 2015:

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Production volumes per day:(1)(2)
Atlas Resource Partners:
Appalachia:(3)
Natural gas (Mcfd)		31,010		34,230		31,278		34,692
Oil (Bpd)		322		386		308		373
NGLs (Bpd)		321		262		306		251
Total (Mcfed)		34,870		38,120		34,962		38,434
Coal-bed Methane(3):
Natural gas (Mcfd)		116,743		131,310		118,646		132,714
Oil (Bpd)		—		—		—		—
NGLs (Bpd)		—		—		—		—
Total (Mcfed)		116,743		131,310		118,646		132,714
Barnett/Marble Falls:
Natural gas (Mcfd)		32,385		47,369		34,603		48,487
Oil (Bpd)		236		633		279		691
NGLs (Bpd)		1,233		2,095		1,345		2,184
Total (Mcfed)		41,198		63,740		44,347		65,736
Rangely:
Natural gas (Mcfd)		—		—		—		—
Oil (Bpd)		2,269		2,390		2,312		2,376
NGLs (Bpd)		235		260		245		256
Total (Mcfed)		15,026		15,904		15,341		15,793
Eagle Ford:
Natural gas (Mcfd)		471		200		430		349
Oil (Bpd)		1,188		1,500		1,275		1,525
NGLs (Bpd)		98		42		90		74
Total (Mcfed)		8,188		9,450		8,618		9,939
Mid-Continent:(3)
Natural gas (Mcfd)		4,231		6,735		4,738		7,330
Oil (Bpd)		149		383		190		448
NGLs (Bpd)		338		534		381		574
Total (Mcfed)		7,154		12,237		8,166		13,466
Total Atlas Resource Partners:
Natural gas (Mcfd)		184,839		219,844		189,695		223,571
Oil (Bpd)		4,164		5,293		4,364		5,412
NGLs (Bpd)		2,226		3,194		2,367		3,340
Total (Mcfed)		223,178		270,761		230,080		276,083
Atlas Growth Partners:
Natural gas (Mcfd)		414		481		457		604
Oil (Bpd)		853		320		996		405
NGLs (Bpd)		75		62		80		81
Total (Mcfed)		5,982		2,773		6,910		3,516
Total production volumes per day:
Natural gas (Mcfd)		185,253		220,325		190,152		224,175
Oil (Bpd)		5,017		5,613		5,359		5,817
NGLs (Bpd)		2,300		3,256		2,447		3,421
Total (Mcfed)		229,159		273,534		236,990		279,599

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	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Production:(1)(2)
Atlas Resource Partners:
Natural gas (MMcf)		16,820		20,006		34,524		40,466
Oil (000’s Bbls)		379		482		794		980
NGLs (000’s Bbls)		203		291		431		605
Total (MMcfe)		20,309		24,639		41,875		49,971
Atlas Growth Partners:
Natural gas (MMcf)		38		44		83		109
Oil (000’s Bbls)		78		29		181		73
NGLs (000’s Bbls)		7		6		15		14
Total (MMcfe)		544		252		1,258		636
Total production:
Natural gas (MMcf)		16,858		20,050		34,608		40,576
Oil (000’s Bbls)		457		511		975		1,053
NGLs (000’s Bbls)		209		296		445		619
Total (MMcfe)		20,854		24,892		43,132		50,607

(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 and six months ended June 30, 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:

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Production revenues (in thousands):(1)
Atlas Resource Partners:
Natural gas revenue	$	27,890	$	56,548	$	59,174	$	123,089
Oil revenue		20,958		35,861		36,270		68,246
NGLs revenue		2,549		4,851		4,445		10,174
Total revenues	$	51,397	$	97,260	$	99,889	$	201,509
Atlas Growth Partners:
Natural gas revenue	$	74	$	114	$	161	$	291
Oil revenue		3,220		1,631		6,154		3,646
NGLs revenue		91		72		171		191
Total revenues	$	3,385	$	1,817	$	6,486	$	4,128
Total production revenues:
Natural gas revenue	$	27,964	$	56,662	$	59,335	$	123,380
Oil revenue		24,178		37,492		42,424		71,892
NGLs revenue		2,640		4,923		4,616		10,365
Total revenues	$	54,782	$	99,077	$	106,375	$	205,637

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	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Average sales price:
Atlas Resource Partners:
Natural gas (per Mcf):(2)
Total realized price, after hedge(3)(4)	$	3.52	$	3.33	$	3.46	$	3.46
Total realized price, before hedge(3)	$	1.70	$	2.14	$	1.74	$	2.34
Oil (per Bbl):(2)
Total realized price, after hedge(4)	$	81.16	$	83.19	$	79.06	$	81.98
Total realized price, before hedge	$	42.08	$	53.35	$	35.50	$	48.32
NGLs (per Bbl):(2)
Total realized price, after hedge(4)	$	12.59	$	22.58	$	10.32	$	22.53
Total realized price, before hedge	$	12.59	$	13.78	$	10.32	$	13.95
Atlas Growth Partners:
Natural gas (per Mcf):(2)
Total realized price, after hedge	$	1.97	$	2.61	$	1.94	$	2.66
Total realized price, before hedge	$	1.97	$	2.61	$	1.94	$	2.66
Oil (per Bbl):(2)
Total realized price, after hedge(4)	$	41.25	$	56.01	$	35.17	$	49.79
Total realized price, before hedge	$	41.48	$	55.84	$	33.96	$	49.72
NGLs (per Bbl):(2)
Total realized price, after hedge	$	13.39	$	12.76	$	11.77	$	13.06
Total realized price, before hedge	$	13.39	$	12.76	$	11.77	$	13.06
Production costs (per Mcfe):(2)
Atlas Resource Partners:
Lease operating expenses(4)	$	1.15	$	1.36	$	1.20	$	1.36
Production taxes		0.18		0.16		0.18		0.20
Transportation and compression		0.22		0.24		0.24		0.24
	$	1.56	$	1.77	$	1.62	$	1.79
Atlas Growth Partners:
Lease operating expenses(4)	$	0.91	$	1.47	$	0.87	$	1.15
Production taxes		0.30		0.36		0.25		0.33
Transportation and compression		0.11		0.09		0.10		0.05
	$	1.32	$	1.92	$	1.22	$	1.53
Total production costs:
Lease operating expenses(4)	$	1.15	$	1.37	$	1.19	$	1.36
Production taxes		0.19		0.17		0.18		0.20
Transportation and compression		0.22		0.24		0.23		0.23
	$	1.55	$	1.77	$	1.61	$	1.79

(1) Includes the impact of cash settlements on ARP’s commodity derivative contracts not previously included within accumulated other comprehensive income following ARP’s decision to de-designate hedges beginning on January 1, 2015 (see Item 1: “Financial Statements (Unaudited)” – Note 6). Cash settlements on ARP’s commodity derivative contracts excluded from production revenues, consisted of $30.1 million and $9.0 million for natural gas and $9.8 million and $4.2 million for oil for the three months ended June 30, 2016 and 2015, respectively; $58.5 million and $14.6 million for natural gas and $26.5 million and $12.1 million for oil for the six months ended June 30, 2016 and 2015, respectively. Cash settlements on ARP’s natural gas derivative contracts excluded from production revenues were $1.7 million and $3.4 million for the three months ended June 30, 2015, respectively. AGP’s oil derivative contracts which were entered into subsequent to our decision to discontinue hedge accounting beginning on January 1, 2015. AGP’s cash settlements on commodity derivative contracts excluded from production revenues consisted of $0.2 million for oil for both of the three and six month periods ended June 30, 2016.

(2) “Mcf” represents thousand cubic feet; “Mcfe” represents thousand cubic feet equivalents; and “Bbl” represents barrels.

(3) Excludes the impact of subordination of ARP’s production revenue to investor partners within its Drilling Partnerships for the three and six months ended June 30, 2016 and 2015. Including the effect of this subordination, ARP’s average realized gas sales price was $3.45 per Mcf ($1.63 per Mcf before the effects of financial hedging) and $3.28 per Mcf ($2.09 per Mcf before the effects of financial hedging) for the three months ended June 30, 2016 and 2015, respectively, and $3.41 per Mcf ($1.69 per Mcf before the effects of financial hedging) and $3.40 per Mcf ($2.29 per Mcf before the effects of financial hedging) for the six months ended June 30, 2016 and 2015, respectively.

(4) Excludes the effects of ARP’s proportionate share of lease operating expenses associated with subordination of its production revenue to investor partners within its Drilling Partnerships for three and six months ended June 30, 2016 and 2015. Including the effects of these costs, ARP’s total lease operating expenses per Mcfe were $0.39 per Mcfe ($0.66 per Mcfe for total production costs) and $0.92 per Mcfe ($1.26 per Mcfe for total production costs) for the three months ended June 30, 2016 and 2015, respectively, and $0.53 per Mcfe ($0.81 per Mcfe for total production costs) and $0.92 per Mcfe ($1.28 per Mcfe for total production costs) for the six months ended June 30, 2016 and 2015, respectively. Including the effects

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of these costs, total lease operating expenses per Mcfe were $1.11 per Mcfe ($1.51 per Mcfe for total production costs) and $1.34 per Mcfe ($1.75 per Mcfe for total production costs) for the threee months ended June 30, 2016 and 2015 and $1.16 per Mcfe ($1.58 per Mcfe for total production costs) and $1.34 per Mcfe ($1.77 per Mcfe for total production costs) for the six months ended June 30, 2016 and 2015, respectively. 

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in thousands)				(in thousands)
Gas and oil production revenues	$	54,782	$	99,077	$	106,375	$	205,637
Gas and oil production costs	$	31,570	$	43,619	$	68,226	$	89,608

The $44.3 million decrease in production revenues for the three months ended June 30, 2016 as compared to the prior year period consisted of a $19.6 million decrease attributable to ARP’s coal-bed methane operations, an $11.8 million decrease attributable to AGP’s and ARP’s Barnett Shale/Marble Falls operations, a $7.3 million decrease associated with ARP’s Rangely operations, a $4.4 million decrease attributable to ARP’s Eagle Ford operations, a $2.3 million decrease attributable to ARP’s Mid-Continent operations and a $0.8 million decrease attributable to ARP’s Appalachia operations, partially offset by a $1.9 million increase associated with AGP’s Eagle Ford operations. Our gas and oil production revenue decreases in all operating areas were attributed to lower production volumes and decreases in commodity prices compared to the prior year period.

The $99.3 million decrease in production revenues for the six months ended June 30, 2016 as compared to the prior year period consisted of a $43.6 million decrease attributable to ARP’s coal-bed methane operations, a $25.2 million decrease attributable to AGP’s and ARP’s Barnett Shale/Marble Falls operations, a $16.2 million decrease associated with ARP’s Rangely operations, an $8.6 million decrease attributable to ARP’s Eagle Ford operations, a $5.6 million decrease attributable to ARP’s and AGP’s Mid-Continent operations and a $3.2 million decrease attributable to ARP’s Appalachia operations, partially offset by a $3.1 million increase associated with AGP’s Eagle Ford operations. Our gas and oil production revenue decreases in all operating areas were attributed to lower production volumes and decreases in commodity prices compared to the prior year period.

The $12.0 million decrease in production costs for the three months ended June 30, 2016 as compared to the prior year period primarily consisted of a $4.7 million decrease attributable to ARP’s coal-bed methane assets, a $4.2 million decrease attributable to AGP’s and ARP’s Barnett Shale/Marble Falls assets, a $2.3 million decrease attributable to ARP’s Appalachia operations and a $0.9 million decrease attributable to ARP’s Mid-Continent assets, partially offset by a $0.1 million increase attributable to ARP’s Rangely assets.

The $21.4 million decrease in production costs for the six months ended June 30, 2016 as compared to the prior year period primarily consisted of a $7.8 million decrease attributable to ARP’s coal-bed methane assets, an $8.7 million decrease attributable to AGP’s and ARP’s Barnett Shale/Marble Falls assets, a $3.7 million decrease attributable to ARP’s Appalachia operations and a $1.6 million decrease attributable to ARP’s Mid-Continent assets, partially offset by a $0.4 million increase attributable to AGP’s and ARP’s Eagle Ford assets.

Well Construction and Completion

Drilling Program Results. At June 30, 2016, our well construction and completion revenues and expenses consisted solely of ARP’s activities. The number of wells ARP drills will vary within ARP’s partnership management segment depending on the amount of capital it raises through its Drilling Partnerships, the cost of each well, the depth or type of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. Well construction and completion revenues and costs and expenses incurred represent the billings and costs associated with the completion of wells for Drilling Partnerships ARP sponsors. As ARP’s drilling contracts with the Drilling Partnerships are on a “cost-plus” basis, an increase or decrease in its average cost per well also results in a proportionate increase or decrease in its average revenue per well, which directly affects the number of wells ARP drills.

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The following table presents the amounts of Drilling Partnership investor capital raised and deployed, as well as sets forth information relating to these revenues and the related costs and number of net wells associated with these revenues during the periods indicated (dollars in thousands):

	Three Months Ended June 30,					Six Months Ended June 30,
	2016			2015		2016		2015
Drilling partnership investor capital:
Raised	$	—		$	—	$	—	$	—
Deployed	$	—		$	16,956	$	2,100	$	40,611
Average construction and completion:
Revenue per well	$	—		$	6,472	$	1,548	$	3,136
Cost per well		—			5,628		1,346		2,727
Gross profit per well	$	—		$	844	$	202	$	409
Gross profit margin	$	(173	)	$	2,211	$	101	$	5,296
Partnership net wells associated with revenue recognized(1):
Appalachia - Utica		—			2		—		2
Barnett/Marble Falls		—			—		—		5
Eagle Ford		—			—		1		1
Mississippi Lime/Hunton		—			1		—		5
Total		—			3		1		13

(1) Consists of ARP’s Drilling Partnership net wells for which well construction and completion revenue was recognized on a “cost-plus” basis.

The $2.4 million and $5.2 million decreases in well construction and completion gross profit margin during the three and six month periods ended June 30, 2016, respectively, as compared to the respective prior year period was due to a decrease in the number of ARP’s partnership wells for which completion activities were being performed related to timing and the economics of such activities during the challenging commodity price environment along with a downward revision to ARP’s estimated total costs to complete wells, which resulted in an unfavorable adjustment to ARP’s gross profit margin  recognized on ARP’s percentage of completion basis for the wells in progress.  

Administration and Oversight

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in thousands)				(in thousands)
Administration and oversight revenues	$	495	$	547	$	950	$	1,806

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At June 30, 2016, our administration and oversight revenues and expenses consist solely of ARP’s activities. Administration and oversight fee revenues represent supervision and administrative fees earned for the drilling and subsequent ongoing management of wells for ARP’s Drilling Partnerships. Typically, ARP receives a lower administration and oversight fee related to shallow, vertical wells it drills within the Drilling Partnerships, such as those in the Marble Falls play, as compared to deep, horizontal wells, such as those drilled in the Marcellus Shale and the Utica Shales. The following table presents the number of gross and net development wells ARP drilled for its Drilling Partnerships during the three and six months ended June 30, 2016 and 2015. There were no exploratory wells drilled during the three and six months ended June 30, 2016 and 2015.

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015			2016		2015
Gross partnership wells drilled:
Barnett/Marble Falls		—		—			—		2
Mississippi Lime/Hunton		—		—			—		2
Total		—		—			—		4
Net partnership wells drilled:
Barnett/Marble Falls		—		—			—		2
Mississippi Lime/Hunton		—		—			—		1
Total		—		—			—		3

The $0.9 million decrease in administration and oversight fee revenues during the six months ended June 30, 2016 compared to the prior year period was primarily due to a decrease in the number of wells spud within the six months ended June 30, 2016 compared with the prior year period.

Well Services

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in thousands)				(in thousands)
Well services revenues	$	4,190	$	6,102	$	8,622	$	12,726
Well services expenses	$	1,474	$	2,139	$	3,652	$	4,337

At June 30, 2016, our well services revenues and expenses consisted solely of ARP’s activities. Well services revenue and expenses represent the monthly operating fees ARP charges and the work ARP’s service company performs, including work performed for ARP’s Drilling Partnership wells during the drilling and completing phase as well as ongoing maintenance of these wells and other wells for which ARP serves as operator.

The $1.9 million and $4.1 million decreases in well services revenue during the three and six month periods ended June 30, 2016, respectively, as compared to the respective prior year period is primarily related to lower fee revenue associated with ARP’s salt water gathering and disposal systems within the Mississippi Lime and Marble Falls operating areas, which are utilized by ARP’s Drilling Partnership wells, and an increased number of wells having been shut in, which results in a reduction of the monthly operating fees which ARP charges the Drilling Partnerships.

The $0.7 million decreases in well services expenses during the three and six months ended June 30, 2016 as compared to the prior year periods are primarily related to lower labor costs.

Gathering and Processing

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(in thousands)						(in thousands)
Gathering and processing margin	$	(591	)	$	(339	)	$	(1,375	)	$	(572	)

At June 30, 2016, our gathering and processing margin consisted solely of ARP’s activities. Gathering and processing revenues and expenses include gathering fees ARP charges to its Drilling Partnership wells and the related expenses and gross margin for ARP’s processing plants in the New Albany Shale and the Chattanooga Shale. Generally, ARP charges a

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gathering fee to its Drilling Partnership wells equivalent to the fees it remits. In Appalachia, a majority of ARP’s Drilling Partnership wells are subject to a gathering agreement, whereby ARP remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, ARP charges its Drilling Partnership wells a 13% gathering fee. As a result, some of its gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%.

The $0.3 million and $0.8 million unfavorable movements in gathering and processing margin during the three and six month periods ended June 30, 2016, respectively, as compared to the respective prior year period was principally due to lower overall natural gas prices in Appalachia and lower gathering fees, particularly from ARP’s Marcellus Shale Drilling Partnership wells in Northeastern Pennsylvania, which are utilizing ARP’s gathering pipeline.

Other Revenues and Expenses

	Three Months Ended  June 30,						Six Months Ended June 30,
	2016			2015				2016			2015
	(in thousands)							(in thousands)
Other Revenues
Gain (loss) on mark-to-market derivatives	$	(74,090	)	$	(26,896	)		$	(27,637	)	$	78,689
Other, net		545			284				870			216
Other Expenses
General and administrative:
Atlas Energy Group	$	1,531		$	2,359			$	3,685		$	22,574
Atlas Growth Partners		2,703			2,759				5,392			7,337
Atlas Resource Partners		23,761			13,287				40,838			30,422
Total general and administrative	$	27,995		$	18,405			$	49,915		$	60,333
Depreciation, depletion and amortization:
Atlas Growth Partners	$	3,299		$	782			$	7,526		$	2,247
Atlas Resource Partners		29,008			42,494				59,053			85,485
Total depreciation, depletion and amortization	$	32,307		$	43,276			$	66,579		$	87,732
Interest expense:
Atlas Energy Group	$	3,890		$	8,471			$	5,633		$	18,025
Atlas Resource Partners		31,954			24,716				59,659			49,913
Total interest expense	$	35,844		$	33,187			$	65,292		$	67,938
Gain on asset sales and disposal – Atlas Resource Partners	$	(502	)	$	(97	)		$	(493	)	$	(86	)
(Gain) loss on extinguishment of debts, net:
Atlas Energy Group	$	27		$	—			$	6,080		$	—
Atlas Resource Partners		—			—				(26,498	)		—
Total (gain) loss on extinguishment of debts, net	$	27		$	—			$	(20,418	)	$	—
Other income (loss)		(6,156	)		—				(6,156	)		—
(Income) loss attributable to non-controlling interests		114,637			38,740				109,297			(19,558	)

Gain (Loss) on Mark-to-Market Derivatives. ARP and AGP recognize changes in the fair value of their derivatives immediately within gain (loss) on mark-to-market derivatives on their consolidated statements of operations. The recognized gains/(losses) are due to decreases/(increases) in commodity future prices relative to our commodity fixed price swaps during the three and six months ended June 30, 2016 as compared to the prior year period.

Other, Net. Our $0.3 million increase in other, net for the three months ended June 30, 2016 as compared to the prior year period was primarily due to a $0.2 million increase in income from our equity investment in Lightfoot.

Our $0.7 million increase in other, net for the six months ended June 30, 2016 as compared to the prior year period was primarily due to a $0.6 million increase in income from our equity investment in Lightfoot.

General and Administrative Expenses. Our $0.8 million decrease in general and administrative expenses for the three months ended June 30, 2016 is primarily due to a $1.3 million decrease in other corporate activities and a $0.2 million decrease in stock compensation expense, partially offset by a $0.7 million increase in non-recurring transaction costs. ARP’s

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$10.5 million increase in general and administrative expenses for the three months ended June 30, 2016 as compared to the prior year period is primarily due to a $7.4 million increase in ARP’s restructuring costs to various financial advisors and legal counsel, a $2.1 million increase in ARP’s salaries, wages and benefits and a $1.9 million increase in ARP’s syndication expense due to lower program fundraising activities, partially offset by a $1.1 million decrease in ARP’s non-cash stock compensation. AGP’s $0.1 million decrease in general and administrative expenses from the comparable prior year period is due to a decrease in salaries, wages and other corporate activities due to the completion of its private placement offering in June 2015.

Our $18.9 million decrease in general and administrative expenses for the six months ended June 30, 2016 is primarily due to a $16.5 million decrease in non-recurring transaction costs attributable to our spin-off from Atlas Energy during the prior year period and a $4.3 million decrease in other corporate activities, partially offset by a $1.9 million increase in stock compensation expense. ARP’s $10.4 million increase in general and administrative expenses for the six months ended June 30, 2016 as compared to the prior year period is primarily due to an $8.5 million increase in ARP’s salaries, wages and benefits, a $5.6 million increase in ARP’s restructuring costs to various financial advisors and legal counsel, and a $1.4 million increase in ARP’s syndication expenses due to lower program fundraising activities, partially offset by a $4.5 million decrease in ARP’s non-cash stock compensation and a $0.5 million decrease in other corporate expenses. AGP’s $1.9 million decrease in general and administrative expenses from the comparable prior year period is due to a decrease in salaries, wages and other corporate activities due to the completion of its private placement offering in June 2015.

Depreciation, Depletion and Amortization. The decrease in depreciation, depletion and amortization for the three and six months ended June 30, 2016 was primarily due to an $11.3 million and a $22.1 million decrease in AGP’s and ARP’s depletion expense. The following table presents total depletion expense, depletion as a percent of gas and oil production revenue and depletion expense per Mcfe for ARP’s and AGP’s operations for the respective periods (in thousands, except for percentage and per Mcfe data):

	Three Months Ended  June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Depletion expense:
Total	$	28,814		$	40,143		$	59,583		$	81,726
Depletion expense as a percentage of gas and oil production revenue		53	%		41	%		56	%		40	%
Depletion per Mcfe	$	1.38		$	1.61		$	1.38		$	1.61

Depletion expense varies from period to period and is directly affected by changes in ARP’s gas and oil reserve quantities, production levels, product prices and changes in the depletable cost basis of ARP’s gas and oil properties. The decreases in depletion expense and depletion expense per Mcfe when compared with the comparable prior year period were due to impairments of ARP’s proved properties recorded in the third and fourth quarters of 2015 as a result of lower forecasted commodity prices, which reduced the depletable cost basis of ARP’s proved gas and oil properties in the current year periods. The increases in the depletion expense as a percentage of gas and oil revenues when compared with the comparable prior year period were due to decreases in ARP’s gas and oil revenues as a result of lower commodity prices and production volumes in the current year periods, partially offset by the decreases in depletion expense described above. The fluctuations in depletion expense, depletion expenses as a percentage of gas and oil revenues and depletion expenses per Mcfe for the three and six months ended June 30, 2016 as compared to the prior year period, were all partially offset by an increase in AGP’s depletion expense associated with the expansion of its Eagle Ford operations.

Interest Expense. The decrease in our interest expense for the three months ended June 30, 2016 as compared to the prior year period consisted of $3.2 million of discount amortization for our Term Loan Facilities in the prior year period and $2.9 million of accelerated amortization of the discount of our Term Loan Facilities resulting from repayments made to reduce the outstanding balance during the prior year period and a $2.1 million decrease in interest on outstanding term loans primarily resulting from lower outstanding borrowings and the refinancing of the Deutsche Bank Term Loan in 2015 to the Riverstone Term Loan Facilities in March 2016 that among other things decreased the interest rate by approximately 6% per annum, partially offset by the $3.6 million of paid-in-kind interest on our current Riverstone Term Loan Facilities during the three months ended June 30, 2016. The increase in ARP’s interest expense during the three months ended June 30, 2016 as compared to the prior year period consisted of $4.1 million in accelerated amortization related to the reduction of the borrowing base of ARP’s First Lien Credit Facility in June 2016, a $1.9 million increase associated with higher outstanding borrowings under ARP’s First Lien Credit Facility, a $1.7 million decrease in ARP’s capitalized interest due to lower capital spending and a $0.2 million increase associated with amortization of ARP’s deferred financing costs, partially offset by a

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$0.7 million decrease associated with interest expense on ARP’s Senior Notes due to its repurchases in January and February of 2016.

The decrease in our interest expense for the six months ended June 30, 2016 as compared to the prior year period consisted of $5.7 million of accelerated amortization of the deferred financing costs associated with the portion of Atlas Energy’s Term Loan Facility allocated to us in February 2015, $3.2 million of discount amortization for our Term Loan Facilities in the prior year period, a $3.2 million decrease in interest on outstanding term loans primarily resulting from lower outstanding borrowings and the refinancing of the Deutsche Bank Term Loan in 2015 to the Riverstone Term Loan Facilities in March 2016 that among other things decreased the interest rate by approximately 6% per annum, $2.9 million of accelerated amortization of the discount of our Term Loan Facilities resulting from repayments made to reduce the outstanding balance during the prior year period and $1.3 million of discount amortization for our Term Loan Facilities with Deutsche Bank during the six months ended June 30, 2015, partially offset by the $3.6 million of paid-in-kind interest on our current Riverstone Term Loan Facilities and $0.3 million in amortization of deferred financing costs for the current Riverstone Term Loan Facilities during the six months ended June 30, 2016. The increase in ARP’s interest expense during the six months ended June 30, 2016 as compared to the prior year period consisted of $4.1 million associated with accelerated amortization of ARP’s deferred financing costs resulting from a reduction of the borrowing base of its First Lien Credit Facility in June 2016, a $3.8 million increase associated with ARP’s Term Loan Facility entered into February 2015, a $3.2 million decrease in ARP’s capitalized interest due to lower capital spending, a $2.7 million increase associated with higher outstanding borrowings under ARP’s First Lien Credit Facility and a $1.3 million increase associated with amortization of ARP’s deferred financing costs, partially offset by a $4.3 million decrease associated with accelerated amortization of ARP’s deferred financing costs resulting from a reduction of the borrowing base of its credit facility in February 2015 and a $1.1 million decrease associated with interest expense on ARP’s Senior Notes due to our repurchases in January and February of 2016.

Gain on Early Extinguishment of Debt. The gain on early extinguishment of debt for the six months ended June 30, 2016 represents a $26.5 million gain related to the repurchase of a portion of ARP’s 7.75% and 9.25% Senior Notes, partially offset by $3.7 million of accelerated amortization of deferred financing costs and $2.4 million of prepayment penalties related to the restructuring of our Term Loan Facility with Riverstone. Of ARP’s $26.5 million gain, $27.4 million related to the gain from the redemption of the principal values and accrued interest, partially offset by $0.9 million related to the accelerated amortization of the related deferred financing costs.

Other income (loss). The $6.2 million loss for the six months ended June 30, 2016 represents ARP’s non-cash loss, net of liquidation and transfer adjustments, of certain Drilling Partnerships’ liquidation and transfer of oil and gas properties and asset retirement obligations to ARP.

(Income) Loss Attributable to Non-Controlling Interests. (Income) loss attributable to non-controlling interests includes an allocation of ARP’s and AGP’s net income (losses) to non-controlling interest holders. The movement in loss attributable to non-controlling interests between the three months ended June 30, 2016 and the prior year comparable period was primarily due to an increase in ARP’s net loss during the current year period. ARP’s increase in net loss primarily related to the $46.3 million increase in the loss on mark-to-market derivatives and a $45.9 million decrease in gas and oil revenue due to lower production volumes and decreases in commodity prices compared to the prior year period.

The movement in income (loss) attributable to non-controlling interests between the six months ended June 30, 2016 and the prior year comparable period was primarily due to ARP’s net loss during the current year period. ARP’s net loss primarily related to the $105.8 million decrease in the gain (loss) on mark-to-market derivatives and a $101.6 million decrease in gas and oil revenue due to lower production volumes and decreases in commodity prices compared to the prior year period.

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

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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.

Ability for the Company and ARP to Continue as a Going Concern

On July 25, 2016, ARP and certain of its subsidiaries and us, solely with respect to certain sections thereof, entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with (i) lenders holding 100% of ARP’s senior secured revolving credit facility (the “First Lien Lenders”), (ii) lenders holding 100% of ARP’s second lien term loan (the “Second Lien Lenders”) and (iii) holders (the “Consenting Noteholders” and, collectively with the First Lien Lenders and the Second Lien Lenders, and their respective successors or permitted assigns that become party to the Restructuring Support Agreement, the “Restructuring Support Parties”) of approximately 80% of the aggregate principal amount outstanding of the 7.75% ARP Senior Notes due 2021 (the “7.75% ARP Senior Notes”) and the 9.25% ARP Senior Notes due 2021 (the “9.25% ARP Senior Notes” and, together with the 7.75% ARP Senior Notes, the “Notes”) of ARP’s subsidiaries, Atlas Resource Partners Holdings, LLC and Atlas Resource Finance Corporation (together, the “Issuers”). Under the Restructuring Support Agreement, the Restructuring Support Parties have agreed, subject to certain terms and conditions, to support ARP’s restructuring (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”). See “ARP Restructuring Support Agreement,” for further information.

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

The Restructuring, including as a result of ARP monetizing certain hedges to pay down borrowings outstanding under ARP’s senior secured credit facility, will result in a reduction of ARP’s existing debt by approximately $900 million and elimination of approximately $80 million of ARP’s annual debt service obligations. Pursuant to the Plan, ARP’s business assets and operations will vest in a limited liability company, which will be classified as a corporation for U.S. federal income tax purposes (“New Holdco”). ARP expects to consummate the Plan and emerge from Chapter 11 before the end of the third quarter of 2016. Interested parties should refer to the information and the limitations and qualifications discussed in ARP’s disclosure statement related to ARP’s Restructuring (the “ARP Disclosure Statement”) which was filed as Exhibit 99.1 to ARP’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 25, 2016.

ARP intends to continue to operate its businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, it is contemplated that all of ARP’s suppliers, vendors, employees, royalty owners, trade partners and landlords will be unimpaired by the Plan and will be satisfied in full in the ordinary course of business, and ARP’s existing trade contracts and terms will be maintained. To assure ordinary course operations, ARP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to ARP, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.

The Chapter 11 Filings constituted an event of default that accelerated all of ARP’s outstanding debt obligations under the ARP First Lien Credit Facility (as defined below), the ARP Second Lien Term Loan (as defined below) and the indenture governing the ARP Notes. Any efforts to enforce such payments are automatically stayed as a result of ARP’s Chapter 11 Filings, and the holders’ rights of enforcement are subject to the applicable provisions of Chapter 11.  Accordingly, we classified all of ARP’s outstanding debt obligations as a current liability on our condensed combined consolidated balance sheet as of June 30, 2016. See “Credit Facilities” below for further information.

ARP’s Restructuring is not expected to materially impact the Company or its ownership interest in AGP or Lightfoot. We are not a party to ARP’s Restructuring. We remain controlled by the same ownership group and management team and thus, we expect that ARP’s Restructuring will not have a material impact on the ability of management to operate us or the other businesses.

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The significant risks and uncertainties related to ARP’s Chapter 11 Filings raise substantial doubt about ARP’s and our ability to continue as a going concern. Our condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. Our condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we and ARP cannot continue as a going concern, adjustments to the carrying values and classification of our and ARP’s assets and liabilities and the reported amounts of income and expenses could be required and could be material.

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 private placement offering completed in 2015. 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.

AGP is not a party to the Restructuring Support Agreement, and ARP’s Restructuring is not expected to materially impact AGP.

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

	Six Months Ended June 30,
	2016			2015
Net cash used in operating activities	$	(26,880	)	$	(38,036	)
Net cash used in investing activities		(23,865	)		(133,748	)
Net cash provided by financing activities		63,033			153,503

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

· an increase in our working capital of $94.7 million primarily due to decreases in accounts payable, accrued liabilities and liabilities associated with drilling contracts as a result of lower operating activities; and an increase due to derivative cash settlements; partially offset by lower accounts receivable, as a result of revenue declines, lower subscription receivables, due to a decline in ARP’s fund raising for well drilling activities, and an increase in cash outflow for well drilling liabilities;

· a decrease in oil and gas production costs of $21.4 million due to ARP’s cost control measures and lower production activities; and

· a decrease in general and administrative expenses of $10.4 million primarily due to our non-recurring transaction costs attributable to our spin-off from Atlas Energy during the prior year period, partially offset by ARP’s higher salaries, wages, and benefits and costs associated with its restructuring; and partially offset by

· a decrease in ARP’s and AGP’s gas and oil production revenues of $99.3 million, due to lower commodity pricing and production volumes;

· a decrease in ARP’s well construction and completion and well services margins totaling $8.6 million, due to lower revenue generating activities, partially offset by lower associated expenses; and

· an increase in cash interest of $7.4 million primarily due to ARP’s higher outstanding balances on its revolving credit facility and the debt under ARP’s term loan facility issued in February 2015, partially offset by ARP’s senior note repurchases in January and February 2016.

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

· a decrease of $57.5 million in capital expenditures due to lower capital expenditures related to our subsidiaries’ drilling activities; and

· a decrease of $49.1 million in net cash paid for acquisitions due primarily to ARP’s and AGP’s deferred purchase price payments and working capital settlements for ARP’s and AGP’s Eagle Ford acquisition in 2015.

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

· a decrease of $242.5 million in net borrowings under ARP’s term loan and credit facilities due to the second lien term loan proceeds of $242.5 million issued in the first quarter of 2015, net of $7.5 million of discount;

· a decrease of $126.8 million in net proceeds from the issuance of AGP’s common limited partner units under its private placement offering in first half of 2015 and the issuance of ARP’s common limited partner units in the first half of 2015 under ARP’s equity distribution program;

· a decrease of $40.0 million related to the issuance of our Series A preferred units;

· an increase of $5.5 million related to ARP’s senior note repurchases in the first quarter of 2016; and

· an increase of $0.3 million in distributions paid to preferred unitholders primarily due to the issuance of the Series A preferred units in the first quarter of 2015; partially offset by

· an increase of $223.5 million in net borrowings on ARP’s revolving credit facility;

· a decrease of $73.1 million in net repayments under our term loan facilities due to our $148.1 million payment to Atlas Energy in connection with the repayment of Atlas Energy’s then existing term loan in the first quarter of 2015, which was partially funded by the $115.3 million interim and term loan A facilities, net of $12.5 million of discount, entered into in the first quarter of 2015, and $45.1 million in repayments on the interim and term loan A facilities during the first half of 2015, partially offset by $4.3 million in net repayments in the first quarter of 2016 on our term loan facilities;

· an increase of $19.8 million related to the Arkoma transaction adjustment reflected in the first quarter of 2015; and

· a decrease of $8.1 million in deferred financing costs primarily related to the issuance of ARP’s $250.0 million second lien term loan in the first quarter of 2015;

During the six months ended June 30, 2016, the $3.6 million of paid-in-kind interest related to the Term Loan Facilities represented non-cash transactions. Our issuance of 4,668,044 warrants in connection with the Second Lien Credit Agreement during the six months ended June 30, 2016 represented a non-cash transaction.

Capital Requirements

At June 30, 2016, the capital requirements of our subsidiaries’ natural gas and oil production consist primarily of expenditures to maintain or increase production margin in future periods, as well as land, gathering and processing, and other non-drilling capital expenditures. The following table summarizes consolidated total capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):

	Three Months Ended  June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Total Capital Expenditures:
Atlas Resource Partners	$	5,650	$	26,993	$	18,820	$	69,491
Atlas Growth Partners		778		3,175		6,327		13,118
Total	$	6,428	$	30,168	$	25,147	$	82,609

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Atlas Resource Partners. During the three months ended June 30, 2016, ARP’s total capital expenditures consisted primarily of $2.2 million for wells drilled exclusively for ARP’s own account compared with $13.5 million for the comparable prior year period, a reduction of $0.2 million of investments in its Drilling Partnerships compared with $5.1 million for the prior year comparable period, $0.8 million of leasehold acquisition costs compared with $1.4 million for the prior year comparable period and $2.9 million of corporate and other costs compared with $7.0 million for the prior year comparable period.

During the six months ended June 30, 2016, ARP’s total capital expenditures consisted primarily of $9.8 million for wells drilled exclusively for ARP’s own account compared with $25.8 million for the comparable prior year period, $0.6 million of investments in its Drilling Partnerships compared with $18.7 million for the prior year comparable period, $2.0 million of leasehold acquisition costs compared with $3.8 million for the prior year comparable period and $6.4 million of corporate and other costs compared with $21.2 million for the prior year comparable period.

Atlas Growth Partners. During the three months ended June 30, 2016, AGP’s $0.8 million of total capital expenditures consisted primarily of its wells drilled and leasehold acquisition costs. During the three months ended June 30, 2015, AGP’s $3.2 million of total capital expenditures consisted primarily of its wells drilled and leasehold acquisition costs.

During the six months ended June 30, 2016, AGP’s $6.3 million of total capital expenditures consisted primarily of its wells drilled and leasehold acquisition costs. During the six months ended June 30, 2015, AGP’s $13.1 million of total capital expenditures consisted primarily of its wells drilled and leasehold acquisition costs.

We and our subsidiaries continuously evaluate acquisitions of gas and oil assets. In order to make any acquisitions in the future, we and our subsidiaries believe we will be required to access outside capital either through debt or equity placements or through joint venture operations with other energy companies. There can be no assurance that we or our subsidiaries will be successful in our and our subsidiaries’ efforts to obtain outside capital.

As of June 30, 2016, our subsidiaries are committed to expending approximately $4.6 million on drilling and completion and other capital expenditures.

Off-Balance Sheet Arrangements

As of June 30, 2016, our subsidiaries’ off-balance sheet arrangements were limited to ARP’s letters of credit outstanding of $4.2 million, and commitments to spend $4.6 million related to ARP’s and AGP’s drilling and completion and capital expenditures, excluding acquisitions.

ARP is the 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 June 30, 2016, management believes that any such estimated liability for redemptions of limited partner interests in Drilling Partnerships which allow such transactions would not be material.

CREDIT FACILITIES

As of June 30, 2016, we had not guaranteed any of ARP’s or AGP’s obligations or debt instruments.

Term Loan Facilities

First Lien Credit Facility. On March 30, 2016, we, together with the “Borrower and Atlas Lightfoot, LLC, entered into the Third Amendment to the First Lien Credit Agreement with Riverstone, as administrative agent, and the Lenders.

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

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$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:

· provide the ability for us and the Borrower to enter into the new Second Lien Credit Agreement (defined below);

· shorten the maturity date of the First Lien Credit Agreement to September 30, 2017, subject to an optional extension to September 30, 2018 by the Borrower, assuming certain conditions are met, including a First Lien Leverage Ratio (as defined in the First Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee;

· modify the applicable cash interest rate margin for ABR Loans and Eurodollar Loans to 0.50% and 1.50%, respectively, and add a pay-in-kind interest payment of 11% of the principal balance per annum;

· allow the Borrower to make mandatory pre-payments under the First Lien Credit Agreement or the new Second Lien Credit Agreement, in its discretion, and add additional mandatory pre-payment events, including a monthly cash sweep for balances in excess of $4 million;

· provide that the First Lien Credit Agreement may be prepaid without premium;

· replace the existing financial covenants with (i) the requirement that we maintain a minimum of $2 million in EBITDA on a trailing twelve-month basis, beginning with the quarter ending June 30, 2016, and (ii) the incorporation into the First Lien Credit Agreement of the financial covenants included in ARP’s credit agreement, beginning with the quarter ending June 30, 2016;

· prohibit the payment of cash distributions on our common and preferred units;

· require the receipt of quarterly distributions from AGP and Lightfoot; and

· add a cross-default provision for defaults by ARP.

Second Lien Credit Agreement. Also on March 30, 2016, we and the Borrower entered into the Second Lien Credit Agreement with Riverstone and the Lenders. $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 is presented net of an unamortized discount of $1.9 million as of June 30, 2016, related to the 4,668,044 warrants issued in connection with the Second Lien Credit Agreement (See “Issuance of Units” below).

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.

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As a result of the cross-default, on July 11, 2016, we entered into waiver agreements (the “Waivers”) with Riverstone and the Lenders in connection with the First Lien Credit Agreement and the Second Lien Credit Agreement. Pursuant to the Waivers, Riverstone and the Lenders agreed to waive under the First Lien Credit Agreement and the Second Lien Credit Agreement:

· the cross-defaults relating to the ARP’s default, for so long as the forbearing parties continue to forbear from exercising their rights and remedies; and

· the potential default relating to ARP’s ongoing negotiations with its lenders and noteholders to the extent any resulting restructuring is completed prior to October 31, 2016

We and ARP’s future debt maturities, excluding any future payment-in-kind interest payments, are as follows: $1,580.5 million, $35.0 million and $35.8 million respectively, for the years ending December 31, 2016, 2017 and 2019, 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.

ARP First Lien Credit Facility

ARP is party to a Second Amended and Restated Credit Agreement, dated as of July 31, 2013 by and among ARP, the lenders from time to time party thereto, and Wells Fargo Bank, National Association, as administrative agent, as amended, supplemented or modified from time to time (the “ARP First Lien Credit Facility”), which provides for a senior secured revolving credit facility with a maximum borrowing base of $1.5 billion scheduled to mature in July 2018.

On June 8, 2016, ARP received notice from Wells Fargo Bank, National Association, as administrative agent under the ARP First Lien Credit Facility that its borrowing base had been redetermined in accordance with the ARP First Lien Credit Facility and reduced from $700.0 million to $530.0 million. As of June 30, 2016, $669.5 million in borrowings were outstanding (which includes $4.2 million in letters of credit) under the ARP First Lien Credit Facility, resulting in a borrowing base deficiency of $143.7 million. The ARP First Lien Credit Facility provides that within 30 days after ARP’s receipt of a notification of a borrowing base deficiency, ARP must elect to cure the borrowing base deficiency through any combination of the following actions: (i) repay amounts outstanding under the ARP First Lien Credit Facility sufficient to cure the borrowing base deficiency, either within 30 days after receipt of the borrowing base deficiency notice or in four equal monthly installments beginning on July 11, 2016; or (ii) pledge as collateral additional oil and gas properties acceptable to the administrative agent and lenders sufficient to cure the borrowing base deficiency within 60 days after receipt of the borrowing base deficiency notice. As part of the discussions with ARP’s lenders and noteholders, ARP determined not to make the first installment payment that was due on July 11, 2016.

In connection therewith and in support of negotiations with ARP’s First Lien Lenders, Second Lien Lenders, and Consenting Noteholders, on July 11, 2016, ARP and certain of its subsidiaries entered into two forbearance agreements: (i) with Wells Fargo Bank, National Association, as administrative agent, and the other lenders under the ARP First Lien Credit Facility (the “ARP First Lien Credit Forbearance”) and (ii) with the Consenting Noteholders of the 7.75% ARP Senior Notes and the 9.25% ARP Senior Notes(the “ARP Notes Forbearance”).

Pursuant to the ARP First Lien Credit Forbearance, the administrative agent and the lenders representing approximately 81% of the outstanding indebtedness under the ARP First Lien Credit Facility agreed to forbear from exercising their rights and remedies arising from non-payment of the first installment of the borrowing base deficiency cure due on July 11, 2016 and related cross-defaults (the “ARP Specified Default”) until the earliest to occur of (i) July 27, 2016, (ii) the occurrence of an event of default under the ARP First Lien Credit Facility (unrelated to the ARP Specified Default) or (iii) the exercise by any holder of indebtedness outstanding under the ARP Second Lien Term Loan, the ARP Notes or any other material indebtedness of ours of rights or remedies against us or the other loan parties or their respective property.

Pursuant to the ARP Notes Forbearance, the holders of approximately 78% of the aggregate outstanding principal amount of the 7.75% ARP Senior Notes and approximately 82% of the 9.25% ARP Senior Notes agreed to forbear from exercising their rights and remedies arising from the cross-default that resulted from the ARP Specified Default until the earliest to occur of (i) July 27, 2016, (ii) another event of default under the 7.75% ARP Senior Notes indenture or the 9.25% ARP Senior Notes indenture or (iii) any other holder of the ARP Notes commences a legal proceeding against us or the other

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loan parties or their respective property. The holders of a majority of the Second Lien Term Loan were supportive of the forbearance.

ARP’s borrowing base is scheduled for semi-annual redeterminations in May and November of each year. Up to $20.0 million of the ARP First Lien Credit Facility may be in the form of standby letters of credit, of which $4.2 million was outstanding at June 30, 2016. ARP’s obligations under the ARP First Lien Credit Facility are secured by mortgages on ARP’s oil and gas properties and first priority security interests in substantially all of ARP’s assets. Additionally, obligations under the ARP First Lien Credit Facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. At June 30, 2016, the weighted average interest rate on outstanding borrowings under the ARP First Lien Credit Facility was 4.0%.

The ARP First Lien Credit Facility 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 First Lien Credit Facility also requires that ARP maintain a ratio of First Lien Debt to EBITDA (ratio as defined in the ARP First Lien Credit Facility) of not greater than 2.75 to 1.00, and a ratio of current assets to current liabilities (ratio as defined in the ARP First Lien Credit Facility) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. ARP was not in compliance with these covenants as of June 30, 2016.  

ARP’s Chapter 11 Filings constituted an event of default that accelerated ARP’s obligations under the ARP First Lien Credit Facility and as a result, we classified $669.5 million of ARP’s outstanding amounts under the ARP First Lien Credit Facility as current portion of long-term debt and $12.2 million of deferred financing costs related to the ARP First Lien Credit Facility as current assets within our condensed combined consolidated balance sheet as of June 30, 2016. Any efforts to enforce such payments are automatically stayed as a result of the Chapter 11 Filings, and the holders’ rights of enforcement are subject to the applicable provisions of Chapter 11.

Pursuant to the ARP Restructuring Support Agreement, ARP completed the sale of certain of substantially all of its commodity hedge positions on July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under the ARP First Lien Credit Facility. Accordingly, approximately $440 million remained outstanding under the ARP First Lien Credit Facility as of July 27, 2016, the date of ARP’s Chapter 11 Filings.

On the Plan Effective Date, ARP expects to enter into the new First Lien Exit Facility, which will replace the First Lien Credit Facility (see “Restructuring Support Agreement” above).

ARP Second Lien Term Loan

ARP is party to a Second Lien Credit Agreement, dated as of February 23, 2015 by and among ARP, the lenders from time to time party thereto, and Wilmington Trust, National Association, as administrative agent, as amended, supplemented or modified from time to time (the “ARP Second Lien Term Loan”), which provides for a second lien term loan in an original principal amount of $250.0 million. The ARP Second Lien Term Loan matures on February 23, 2020. The Second Lien Term Loan is presented net of unamortized discount of $5.5 million as of June 30, 2016.

ARP’s obligations under the ARP Second Lien Term Loan are secured on a second priority basis by security interests in all of ARP’s assets and those of its restricted subsidiaries that guarantee the ARP First Lien Credit Facility. In addition, the obligations under the ARP Second Lien Term Loan are guaranteed by ARP’s material restricted subsidiaries. At June 30, 2016, the weighted average interest rate on outstanding borrowings under the ARP Second Lien Term Loan was 10.0%.

The ARP Second Lien Term Loan contains customary covenants including, without limitation, covenants that limit ARP’s ability to make restricted payments, take on indebtedness, issue preferred units, 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 Second Lien Term Loan contains covenants substantially similar to those in the ARP First Lien Credit Facility, including, among others, restrictions on swap agreements, debt of unrestricted subsidiaries, drilling and operating agreements and the sale or discount of receivables. ARP was not in compliance with the financial covenants as of June 30, 2016.  

ARP’s Chapter 11 Filings constituted an event of default that accelerated ARP’s obligations under the ARP Second Lien Term Loan and as a result, we classified $244.5 million of ARP’s outstanding amounts under the ARP Second Lien Term Loan, which is net of $5.5 million unamortized discount and $9.4 million deferred financing costs, as current portion of

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long-term debt within our condensed combined consolidated balance sheet as of June 30, 2016.  Any efforts to enforce such payments are automatically stayed as a result of the Chapter 11 Filings, and the holders’ rights of enforcement are subject to the applicable provisions of Chapter 11.

On the Plan Effective Date, ARP expects to enter into the new ARP Second Lien Exit Facility, which will replace the ARP Second Lien Term Loan (see “Restructuring Support Agreement” above).

ARP Senior Notes

At June 30, 2016, ARP had $354.4 million outstanding of its 7.75% ARP Senior Notes due 2021. The 7.75% ARP Senior Notes were presented net of a $0.3 million unamortized discount as of June 30, 2016.

At June 30, 2016, ARP had $312.1 million outstanding of its 9.25% ARP Senior Notes due 2021. The 9.25% ARP Senior Notes were presented net of a $0.8 million unamortized discount as of June 30, 2016.

In January and February 2016, ARP executed transactions to repurchase $20.3 million of its 7.75% Senior Notes and $12.1 million of its 9.25% Senior Notes for $5.5 million, which included $0.6 million of interest. As a result of these transactions, we recognized $26.5 million as gain on early extinguishment of debt, net of accelerated amortization of deferred financing costs of $0.9 million, in our condensed combined consolidated statement of operations for the six months ended June 30, 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 June 30, 2016.

On June 6, 2016, ARP and certain of its subsidiaries, Wells Fargo Bank, National Association, as resigning trustee (“Wells Fargo”) and U.S. Bank National Association, as successor trustee (“U.S. Bank”), entered into an Instrument of Resignation, Appointment and Acceptance (the “Instrument”). In connection with the Instrument, Wells Fargo resigned as trustee, note custodian, registrar and paying agent under the Indenture dated as of July 30, 2013, as supplemented and amended and ARP accepted such resignation and appointed U.S. Bank as the successor trustee, note custodian, registrar and paying agent under the such indenture.

ARP’s Chapter 11 Filings constituted an event of default that accelerated ARP’s obligations under the 7.75% ARP Senior Notes and the 9.25% ARP Senior Notes and as a result, we classified $354.4 million of ARP’s outstanding amounts under the 7.75% ARP Senior Notes, which is net of $0.3 million unamortized discount and $9.5 million deferred financing costs, and $312.1 million of ARP’s outstanding amounts under the 9.25% ARP Senior Notes, which is net of $0.8 million unamortized discount and $8.3 million deferred financing costs, as current portion of long-term debt within our condensed combined consolidated balance sheet as of June 30, 2016. Any efforts to enforce such payments are automatically stayed as a result of the Chapter 11 Filings, and the holders’ rights of enforcement are subject to the applicable provisions of Chapter 11.

On the Plan Effective Date, the 7.75% ARP Senior Notes and the 9.25% ARP Senior Notes (together with accrued but unpaid interest) will be cancelled and the holders will receive 90% of the common equity interests of New HoldCo (see “Restructuring Support Agreement” above).

ATLAS RESOURCE PARTNERS SECURED HEDGE FACILITY

At June 30, 2016, ARP had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under ARP’s revolving credit facility, ARP is required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. ARP, as general partner

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of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility and guarantees their obligations under it. Before executing any hedge transaction, a participating Drilling Partnership is required to, among other things, provide mortgages on its oil and gas properties and first priority security interests in substantially all of its assets to the collateral agent for the benefit of the counterparties. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, 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.

An event of default occurred under the secured hedging facility agreement upon ARP’s filing of voluntary petitions for relief under Chapter 11.  The lenders under the secured hedge facility agreed to forbear from exercising remedies in respect of such event of default while the Chapter 11 Filings are pending and, upon occurrence of the effective date of the Plan contemplated by ARP’s Restructuring Support Agreement, such event of default will no longer be deemed to exist or to continue under the secured hedge facility.

In addition, it will be an event of default under ARP’s revolving credit facility if ARP, as general partner of the Drilling Partnerships, breaches an obligation governed by the secured hedge facility and the effect of such breach is to cause amounts owing under swap agreements governed by the secured hedge facility to become immediately due and payable.

ATLAS GROWTH PARTNERS SECURED CREDIT FACILITY

On May 1, 2015, AGP entered into a secured credit facility agreement with a syndicate of banks. As of June 30, 2016, the lenders under the credit facility have no commitment to lend to 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 interest 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 the ability of AGP and its subsidiaries to incur indebtedness, grant liens, make loans or investments, make distributions, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions, including a sale of all or substantially all of its assets. 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.

ISSUANCE 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.

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. The Warrants include a cashless exercise provision entitling the Lenders to surrender a portion of the underlying common units that has a value equal to the aggregate exercise price in lieu of paying cash upon exercise of a warrant. As a result of issuance of the Warrants, we recognized a $1.9 million debt discount on the Second Lien Credit Agreement, which will be amortized over the term of the debt, and a corresponding $1.9 million increase to unitholders’ equity – warrants on our condensed combined balance sheet as of June 30, 2016.

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

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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. 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.

On May 12, 2016, due to the income tax ramifications of potential options we were 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. The delayed vesting schedule did not have a significant impact on the compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the three and six months ended June 30, 2016 or our remaining unrecognized compensation expense related to such awards.

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 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 June 30, 2016, ARP did not issue any common limited partner units under the equity distribution program. During the three months ended June 30, 2015, ARP issued 2,403,288 common limited partner units under the equity distribution agreement for net proceeds of $17.5 million, net of $0.5 million in commissions and offering expenses paid.  During the six months ended June 30, 2016, ARP issued 245,175 common limited partner units under the equity distribution program for net proceeds of $0.2 million, net of $4,000 in commissions and offering expenses paid. During the six months ended June 30, 2015, ARP issued 2,885,824 common limited partner units under the equity distribution agreement for net proceeds of $21.4 million, net of $0.6 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”).

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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 and six months ended June 30, 2016 and 2015.

In May 2015, in connection with the Arkoma Acquisition, ARP issued 6,500,000 of its common limited partner units in a public offering at a price of $7.97 per unit, yielding net proceeds of $49.7 million. ARP used a portion of the net proceeds to fund the Arkoma Acquisition and to reduce borrowings outstanding under ARP’s First Lien Credit Facility.

In April 2015, ARP issued 255,000 of its 10.75% Class E ARP Preferred Units at a public offering price of $25.00 per unit for net proceeds of $6.0 million.

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 ARP Preferred Units to the seller at a value of $25.00 per unit.

On May 12, 2016, due to the income tax ramifications of the potential options ARP was 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 August 31,2016. The delayed vesting schedule did not have a significant impact on ARP’s compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the three and six months ended June 30, 2016 or our remaining unrecognized compensation expense related to such awards.

On July 12, 2016, ARP received notification from the New York Stock Exchange that the NYSE commenced proceedings to delist ARP’s common units as a result of ARP’s failure to comply with the continued listed standards set forth in Section 802.01C of the NYSE Listed Company Manual to maintain an average closing price of $1.00 per unit over a consecutive 30-day period. The Class D ARP Preferred Units and Class E ARP Preferred Units were also delisted from the NYSE. ARP’s common units, Class D ARP Preferred Units, and Class E ARP Preferred Units began trading on the OTC market on July 13, 2016 with the ticker symbol “ARPJ” for ARP’s common units, “ARPJP” for Class D ARP Preferred Units, and “ARPJN” for Class E ARP Preferred Units.

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 $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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Recently Issued Accounting Standards

See Notes 2 and 5 to our condensed combined consolidated financial statements for additional information related to recently issued accounting standards.

For a more complete discussion of the accounting policies and estimates that we have identified as critical in the preparation of our condensed combined consolidated financial statements, please refer to our Management’s Discussion and

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Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for fiscal year ended December 31, 2015.

ITEM 3: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

General

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

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

ARP and AGP are subject to the risk of loss on their derivative instruments that would incurred as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. ARP and AGP maintain credit policies with regard to their counterparties to minimize their overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the quarterly monitoring of our oil, natural gas and NGLs counterparties’ credit exposures; (iii) comprehensive credit reviews on significant counterparties from physical and financial transactions on an ongoing basis; (iv) the utilization of contractual language that affords them netting or set off opportunities to mitigate exposure risk; and (v) when appropriate, requiring counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk.  ARP’s assets related to derivatives as of June 30, 2016 represent financial instruments from ten counterparties; all of which are financial institutions that have an “investment grade” (minimum Standard & Poor’s rating of BBB+ or better) credit rating and are lenders associated with ARP’s revolving credit facility. Subject to the terms of ARP’s revolving credit facility, collateral or other securities are not exchanged in relation to derivatives activities with the parties in the revolving credit facility.

Interest Rate Risk. As of June 30, 2016, we had $72.6 million of outstanding borrowings under our term facilities and ARP had $669.5 million of outstanding borrowings under its revolving credit facility and $244.5 million of outstanding borrowings under its term loan facility. Holding all other variables constant, a hypothetical 100 basis-point or 1% change in variable interest rates would change our consolidated interest expense for the twelve-month period ending June 30, 2017 by $9.9 million, excluding the effect of non-controlling interests.

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

Holding all other variables constant, including the effect of commodity derivatives, a 10% change in average commodity prices would result in a change to our consolidated operating income for the twelve-month period ending June 30, 2017 of approximately $1.5 million, net of non-controlling interests.

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

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AGP’s and ARP’s exposure to changing natural gas, oil and natural gas liquids prices, AGP and ARP enter into natural gas and oil swap, put option and costless collar option contracts. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter (“OTC”) futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. OTC contracts are generally financial contracts which are settled with financial payments or receipts and generally do not require delivery of physical hydrocarbons. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while other natural gas liquids contracts are based on an OPIS Mt. Belvieu index.

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

Type	Production Period Ending December 31,	Volumes(1)		Average Fixed Price(1)
Crude Oil – Fixed Price Swaps	2016(2)		31,600	$	46.350
	2017		37,100	$	49.968
	2018		26,500	$	48.850

⁽¹⁾ Volumes for crude oil are stated in barrels.

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

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

Type	Production Period Ending December 31,	Volumes(1)		Average Fixed Price(1)
Natural Gas – Fixed Price Swaps	2016(2)		26,910,000	$	4.224
	2017		50,120,000	$	4.221
	2018		40,300,000	$	4.168
	2019		15,860,000	$	4.019
Natural Gas – Put Options – Drilling Partnerships	2016(2)		720,000	$	4.150
Crude Oil – Fixed Price Swaps	2016(2)		820,500	$	81.685
	2017		1,200,000	$	77.610
	2018		1,080,000	$	76.281
	2019		540,000	$	68.371

⁽¹⁾ Volumes for natural gas are stated in million British Thermal Units. Volumes for crude oil are stated in barrels.

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

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ITEM 4: CONTROLS AND PROCEDURES 

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

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

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

There have been no changes in our internal control over financial reporting during the second quarter of 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II

ITEM 1A: RISK FACTORS

There have been no material changes to the Risk Factors disclosed in Part I – Item 1A “–Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2015 except as follows.

We are subject to risks and uncertainties related to ARP’s Chapter 11 cases.

ARP and certain of its subsidiaries have filed voluntary petitions for relief under the Bankruptcy Code, and we are subject to certain risks and uncertainties associated with those bankruptcy cases. These risks include the following:

· our ability to continue as a going concern;

· whether the proposed Plan outlined in the Restructuring Support Agreement will be confirmed and consummated;

· our ability to retain key vendors or secure alternative supply sources;

· our ability to fund and execute our business plan;

· our ability to attract, motivate, and retain management;

· significant time and effort required to be spent by our senior management in dealing with the Chapter 11 cases; and

· negative effects and increased costs of a prolonged duration of the Chapter 11 cases.

We will also be subject to risks and uncertainties with respect to the actions and decisions of creditors and other third parties who have interests in the Chapter 11 cases that may be inconsistent with our plans. These risks and uncertainties could affect our business and operations in various ways and may increase the longer ARP and its subsidiaries have to operate under Chapter 11 bankruptcy protection.

ARP may not be able to obtain confirmation of the Plan, which could materially and adversely affect our business, financial condition and results of operations.

There can be no assurance that the Plan will be confirmed by the Bankruptcy Court. ARP might receive official objections to confirmation of the Plan from the various committees and stakeholders in the Chapter 11 proceedings. We cannot predict the impact that any objection might have on the Plan or on a Bankruptcy Court’s decision to confirm the Plan. Any objection may cause us and ARP to devote significant resources in response, which could materially and adversely affect our business, financial condition and results of operations.

While certain of ARP’s stakeholders have agreed to support the Plan under the Restructuring Support Agreement, if ARP is unable to implement the Plan, any alternative plan of reorganization will also require the willingness of certain stakeholders to agree to the exchange or modification of their interests. There can be no guarantee of success with respect to the Plan or any other plan of reorganization. If the Plan is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize ARP’s business. There can be no assurance as to whether ARP will successfully reorganize and emerge from Chapter 11 or, if ARP does successfully reorganize, as to when ARP would emerge from Chapter 11. If no plan of reorganization can be confirmed, or if the Bankruptcy Court otherwise finds that it would be in the best interest of holders of claims and interests, the Chapter 11 cases may be converted to cases under Chapter 7 of the Bankruptcy Code, pursuant to which a trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. There can be no assurance that a different outcome for ARP would not materially impact our business, financial condition and results of operations.

During the pendency of the Chapter 11 proceedings, our employees will face considerable distraction and uncertainty and we may experience increased levels of employee attrition. A loss of key personnel or material erosion of employee morale could have a material adverse effect on our ability to effectively, efficiently and safely conduct our business, and could impair our ability to execute our strategy and implement operational initiatives, thereby having a material adverse effect on our financial condition and results of operations.

Our ownership interests in ARP will be cancelled upon confirmation and consummation of the Plan, which could impact our liquidity for normal operating expenses, servicing our debt, capital expenditures and distributions to our unitholders and which raises significant risks and uncertainties about our ability to continue as a going concern.

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

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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.

Upon confirmation and consummation of the Plan, our ownership interests in ARP will be cancelled. Specifically, we will no longer hold common units, Class C preferred units or incentive distribution rights in ARP and will instead hold a 2% preferred economic interest in ARP. If we are unable to receive sufficient distributions on our interest in ARP in the future (together with our interests in AGP and Lightfoot), we will not have sufficient liquidity to repay all of our outstanding indebtedness.

In addition, the significant risks and uncertainties related to ARP’s Chapter 11 cases raise substantial doubt about ARP’s and our ability to continue as a going concern. Our condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. Our condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we and ARP cannot continue as a going concern, adjustments to the carrying values and classification of our and ARP’s assets and liabilities and the reported amounts of income and expenses could be required and could be material.

Unitholders are required to pay taxes on their share of our taxable income, including their share of ordinary income and capital gain upon dispositions of properties by us or ARP or cancellation of our or ARP’s debt, even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, gain, loss and deduction, or specific items thereof, may be substantially different than the unitholder’s interest in our economic profits.

Our unitholders are required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive any cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

For example, ARP has repurchased approximately $20.3 million of its 7.75% Senior Notes and approximately $12.1 million of our 9.25% Senior Notes at prices lower than face amount. In addition, ARP will recognize cancellation of indebtedness (“COD”) income and other amounts of income as a result of the transactions contemplated by the Plan, which could be substantial. These transactions will, and other similar transactions in the future may, result in COD income that will be allocated to our unitholders. Some or all of our unitholders may be allocated substantial amounts of such taxable income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect to each unitholder would depend on the unitholder’s individual tax position with respect to the units; however, taxable income allocations from us, including COD income, increase a unitholder’s tax basis in their units.

In addition, we and our subsidiaries may sell a portion of our properties and use the proceeds to pay down debt or acquire other properties rather than distributing the proceeds to our unitholders, and some or all of our unitholders may be allocated substantial taxable income with respect to that sale. A unitholder’s share of our taxable income upon a disposition of property by us may be ordinary income or capital gain or some combination thereof. Even where we dispose of properties that are capital assets, what otherwise would be capital gains may be recharacterized as ordinary income in order to “recapture” ordinary deductions that were previously allocated to that unitholder related to the same property.

A unitholder’s share of our taxable income and gain (or specific items thereof) may be substantially greater than, or our tax losses and deductions (or specific items thereof) may be substantially less than, the unitholder’s interest in our economic profits. This may occur, for example, in the case of a unitholder who purchases units at a time when the value of our units or of one or more of our properties is relatively low or a unitholder who acquires units directly from us in exchange for property whose fair market value exceeds its tax basis at the time of the exchange. Cash distributions from us decrease a unitholder’s tax basis in its units, and the amount, if any, of excess distributions over a unitholder’s tax basis in its units will, in effect, become taxable income to the unitholder, above and beyond the unitholder’s share of our taxable income and gain (or specific items thereof).

ITEM 3: DEFAULTS UPON SENIOR SECURITIES

On June 16, 2016, our Board of Directors elected to suspend ARP’s 8.625% Class D Cumulative Redeemable Perpetual Preferred Units and ARP’s 10.75% Class E Cumulative Redeemable Perpetual Preferred Units distributions, beginning with the second quarter 2016 distribution, due to the continued lower commodity price environment.

68

As of July 15, 2016, the cumulative unpaid dividends on ARP’s 8.625% Class D Cumulative Redeemable Perpetual Preferred Units and ARP’s 10.75% Class E Cumulative Redeemable Perpetual Preferred Units, were $2.2 million and $0.2 million, respectively.

ARP’s Chapter 11 Filings constituted an event of default that accelerated its obligations under ARP’s First Lien Credit Facility and as a result, we classified $669.5 million of ARP’s outstanding amounts under ARP’s First Lien Credit Facility as current portion of long-term debt within our condensed combined consolidated balance sheet as of June 30, 2016.  

ARP’s Chapter 11 Filings constituted an event of default that accelerated its obligations under ARP’s Second Lien Term Loan and as a result, we classified $244.5 million of ARP’s outstanding amounts under ARP’s Second Lien Term Loan, which is net of $5.5 million unamortized discount and $9.4 million deferred financing costs, as current portion of long-term debt within our condensed combined consolidated balance sheet as of June 30, 2016.  

ARP’s Chapter 11 Filings constituted an event of default that accelerated ARP’s obligations under ARP’s 7.75% Senior Notes and ARP’s 9.25% Senior Notes and as a result, we classified $354.4 million of our outstanding amounts under ARP’s 7.75% Senior Notes, which is net of $0.3 million unamortized discount and $9.5 million deferred financing costs, and $312.1 million of our outstanding amounts under ARP’s 9.25% Senior Notes, which is net of $0.8 million unamortized discount and $8.3 million deferred financing costs, as current portion of long-term debt within our condensed combined consolidated balance sheet as of June 30, 2016.

Any efforts to enforce these payments are automatically stayed as a result of ARP’s Chapter 11 Filings, and the holders’ rights of enforcement are subject to the applicable provisions of Chapter 11.

An event of default occurred under ARP’s secured hedging facility agreement upon ARP’s filing of voluntary petitions for relief under Chapter 11.  The lenders under ARP’s secured hedge facility agreed to forbear from exercising remedies in respect of such event of default while ARP’s Chapter 11 Filings are pending and, upon occurrence of the effective date of the Plan contemplated by the Restructuring Support Agreement, such event of default will no longer be deemed to exist or to continue under ARP’s secured hedge facility.

69

ITEM 6: EXHIBITS 

Exhibit Number	Exhibit Description
3.1(a)	Certificate of Formation of Atlas Resource Partners GP, LLC(1)
3.1(b)	Amendment to Certificate of Formation of Atlas Resource Partners GP, LLC(2)
3.2(a)	Second Amended and Restated Limited Liability Company Agreement of Atlas Resource Partners GP, LLC(3)
3.2(b)	Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of Atlas Resource Partners GP, LLC, dated as of November 3, 2014(2)
3.3(a)	Third Amended and Restated Limited Liability Company Agreement of Atlas Energy Group, LLC, dated as of February 27, 2015(4)
3.3(b)	Amendment No. 1 to the Third Amended and Restated Limited Liability Company Agreement of Atlas Energy Group, LLC, dated as of February 27, 2015(4)
3.3(c)	Amendment No. 2 to the Third Amended and Restated Limited Liability Company Agreement of Atlas Energy Group, LLC, dated as of April 27, 2016(5)
3.4	Certificate of Formation of Atlas Growth Partners GP, LLC(6)
3.5	Amended and Restated Limited Liability Company Agreement of Atlas Growth Partners GP, LLC, dated as of November 26, 2013(6)
4.1	Form of Warrant to Purchase Atlas Energy Group, LLC common units, issued effective as of March 30, 2016. (7)
10.1	Registration Rights Agreement, dated as of April 27, 2016, by and among Atlas Energy Group, LLC, Riverstone Credit Partners, L.P., AEG Asset Management, LLC and The Leon and Toby Cooperman Family Foundation. (7)
31.1	Rule 13(a)-14(a)/15(d)-14(a) Certification
31.2	Rule 13(a)-14(a)/15(d)-14(a) Certification
32.1	Section 1350 Certification
32.2	Section 1350 Certification
101.INS	XBRL Instance Document(8)
101.SCH	XBRL Schema Document(8)
101.CAL	XBRL Calculation Linkbase Document(8)
101.LAB	XBRL Label Linkbase Document(8)
101.PRE	XBRL Presentation Linkbase Document(8)
101.DEF	XBRL Definition Linkbase Document(8)

(1)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s Registration Statement on Form 10, as amended (File No. 1-35317).
(2)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on November 5, 2014.
(3)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended September 30, 2013.
(4)	Previously filed as an exhibit to our current report on Form 8-K filed on March 2, 2015.
(5)	Previously filed as an exhibit to our current report on Form 8-K filed on April 29, 2016.
(6)	Previously filed as an exhibit to Atlas Growth Partners, L.P.’s registration statement on Form S-1 (File No. 333-207537) filed on October 21, 2015.
(7)	Previously filed as an exhibit to our current report on Form 8-K filed eon April 29, 2016.

70

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

SIGNATURES

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

	ATLAS ENERGY GROUP, LLC
Date:  August 8, 2016	By:	/s/ EDWARD E. COHEN
		Edward E. Cohen Chief Executive Officer
Date:  August 8, 2016	By:	/s/ JEFFREY M. SLOTTERBACK
		Jeffrey M. Slotterback Chief Financial Officer
Date:  August 8, 2016	By:	/s/ MATTHEW J. FINKBEINER
		Matthew J. Finkbeiner Chief Accounting Officer

71

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Edward E. Cohen, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2016 of Atlas Energy Group, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ EDWARD E. COHEN

Edward E. Cohen

Chief Executive Officer

August 8, 2016

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Jeffrey M. Slotterback, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2016 of Atlas Energy Group, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ JEFFREY M. SLOTTERBACK

Jeffrey M. Slotterback

Chief Financial Officer

August 8, 2016

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Atlas Energy Group, LLC (the “Company”) on Form 10-Q for the quarter ended June 30, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Edward E. Cohen, Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ EDWARD E. COHEN

Edward E. Cohen

Chief Executive Officer 

August 8, 2016

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Atlas Energy Group, LLC (the “Company”) on Form 10-Q for the quarter ended June 30, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jeffrey M. Slotterback, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ JEFFREY M. SLOTTERBACK

Jeffrey M. Slotterback

Chief Financial Officer

August 8, 2016

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Aug. 04, 2016
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2
Entity Registrant Name	Atlas Energy Group, LLC
Entity Central Index Key	0001623595
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Trading Symbol	ATLS
Entity Common Stock, Units Outstanding		26,037,992

XML

CONDENSED COMBINED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 43,502	$ 31,214
Accounts receivable	64,904	65,920
Current portion of derivative asset	99,654	159,763
Subscriptions receivable		19,877
Prepaid expenses and other	17,105	22,997
Current deferred financing costs	12,162
Total current assets	237,327	299,771
Property, plant and equipment, net	1,273,453	1,316,897
Goodwill and intangible assets, net	14,028	14,095
Long-term derivative asset	135,231	198,371
Other assets, net	37,261	54,112
Total assets	1,697,300	1,883,246
Current liabilities:
Accounts payable	40,421	52,550
Liabilities associated with drilling contracts		21,483
Current portion of derivative payable to Drilling Partnerships	956	2,574
Accrued interest	24,130	25,452
Accrued well drilling and completion costs	2,182	33,555
Accrued liabilities	29,711	42,440
Current portion of long-term debt	1,553,277	4,250
Total current liabilities	1,650,677	182,304
Long-term debt, net, less current portion	72,362	1,568,064
Asset retirement obligations and other	140,104	124,919
Commitments and contingencies (Note 9)
Unitholders’ equity (deficit):
Common unitholders’ equity (deficit)	(145,033)	(103,148)
Series A preferred equity	42,113	40,875
Warrants	1,868
Accumulated other comprehensive income	2,273	4,284
Unitholders'/owner's equity excluding non-controlling interests	(98,779)	(57,989)
Non-controlling interests	(67,064)	65,948
Total unitholders’ equity (deficit)	(165,843)	7,959
Total liabilities and unitholders’ equity (deficit)	$ 1,697,300	$ 1,883,246

XML

CONDENSED COMBINED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Revenues:
Gas and oil production		$ 54,782	$ 99,077	$ 106,375	$ 205,637
Well construction and completion		(1,326)	16,956	774	40,611
Gathering and processing		1,600	2,177	3,095	4,361
Administration and oversight		495	547	950	1,806
Well services		4,190	6,102	8,622	12,726
Gain (loss) on mark-to-market derivatives		(74,090)	(26,896)	(27,637)	78,689
Other, net		545	284	870	216
Total revenues	[1]	(13,804)	98,247	93,049	344,046
Costs and expenses:
Gas and oil production		31,570	43,619	68,226	89,608
Well construction and completion		(1,153)	14,745	673	35,315
Gathering and processing		2,191	2,516	4,470	4,933
Well services		1,474	2,139	3,652	4,337
General and administrative		27,995	18,405	49,915	60,333
Depreciation, depletion and amortization		32,307	43,276	66,579	87,732
Total costs and expenses		94,384	124,700	193,515	282,258
Operating income (loss)		(108,188)	(26,453)	(100,466)	61,788
Gain (loss) on asset sales and disposal		(502)	97	(493)	86
Interest expense		(35,844)	(33,187)	(65,292)	(67,938)
Gain (loss) on early extinguishment of debt, net		(27)		20,418	0
Other income (loss)		(6,156)	0	(6,156)	0
Net income (loss)		(150,717)	(59,543)	(151,989)	(6,064)
Preferred unitholders’ dividends			(1,004)	(339)	(1,337)
(Income) loss attributable to non-controlling interests		114,637	38,740	109,297	(19,558)
Net loss attributable to unitholders’/owner’s interests		(36,080)	(21,807)	(43,031)	(26,959)
Allocation of net loss attributable to unitholders’/owner’s interests:
Portion applicable to owner’s interest (period prior to the transfer of assets on February 27, 2015)					(10,475)
Portion applicable to unitholders’ interests (period subsequent to the transfer of assets on February 27, 2015)		(36,080)	(21,807)	(43,031)	(16,484)
Net loss attributable to unitholders’/owner’s interests		$ (36,080)	$ (21,807)	$ (43,031)	$ (26,959)
Net loss attributable to unitholders per common unit (Note 2):
Basic		$ (1.39)	$ (0.84)	$ (1.65)	$ (0.63)
Diluted		$ (1.39)	$ (0.84)	$ (1.65)	$ (0.63)
Weighted average common units outstanding (Note 2):
Basic		26,031	26,011	26,029	26,011
Diluted		26,031	26,011	26,029	26,011

[1] 1) Revenues include gains (losses) on mark to market derivatives. A $73.3 million loss on ARP’s mark-to-market derivatives is included for the three months ended June 30, 2016 related to increases in commodity future prices relative to ARP’s commodity fixed price swaps during the three months ended June 30, 2016 as compared to the prior year period.

XML

CONDENSED COMBINED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement Of Income And Comprehensive Income [Abstract]
Net loss	$ (150,717)	$ (59,543)	$ (151,989)	$ (6,064)
Other comprehensive loss:
Reclassification to mark-to-market gains	(5,555)	(25,778)	(9,070)	(53,121)
Total other comprehensive loss	(5,555)	(25,778)	(9,070)	(53,121)
Comprehensive loss	(156,272)	(85,321)	(161,059)	(59,185)
Comprehensive loss attributable to non-controlling interests	118,967	51,125	116,356	12,182
Comprehensive loss attributable to unitholders’ interest	$ (37,305)	$ (34,196)	$ (44,703)	$ (47,003)

XML

CONDENSED COMBINED CONSOLIDATED STATEMENT OF UNITHOLDERS' EQUITY (Unaudited) - 6 months ended Jun. 30, 2016 - USD ($) $ in Thousands	Total	Series A Preferred Equity	Common Unitholders' Equity (Deficit)	Warrants	Accumulated Other Comprehensive Income	Non-Controlling Interest
Balance at Dec. 31, 2015	$ 7,959	$ 40,875	$ (103,148)		$ 4,284	$ 65,948
Balance units at Dec. 31, 2015		1,621,427	26,010,766
Issuance of units and warrants	(853)	$ 1,576	$ (1,576)	$ 1,868		(2,721)
Issuance of units and warrants (units)		63,025		4,668,044
Distributions to non-controlling interests	(16,837)					(16,837)
Net issued and unissued units under incentive plan	2,243		$ 2,541			(298)
Net issued and unissued units under incentive plan (units)			27,226
Distribution equivalent rights paid on unissued units under incentive plans	(11)					(11)
Distribution payable	3,730	$ 338				3,392
Gain on sale from subsidiary unit issuances			$ 181			(181)
Dividends paid to preferred equity unitholders	(1,015)	(1,015)
Other comprehensive loss	(9,070)				(2,011)	(7,059)
Net income (loss)	(151,989)	339	(43,031)			(109,297)
Balance at Jun. 30, 2016	$ (165,843)	$ 42,113	$ (145,033)	$ 1,868	$ 2,273	$ (67,064)
Balance units at Jun. 30, 2016		1,684,452	26,037,992	4,668,044

XML

CONDENSED COMBINED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (151,989)	$ (6,064)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization	66,579	87,732
Gain on early extinguishment of debts, net	(20,418)	0
(Gain) loss on derivatives	38,303	(71,808)
Amortization of deferred financing costs and discount and premium on long-term debt	12,281	15,670
Non-cash compensation expense	2,235	5,083
Paid-in-kind interest	3,632	0
(Gain) loss on asset sales and disposal	493	(86)
Other (income) loss	6,156	0
Distributions paid to non-controlling interests	(16,848)	(62,831)
Equity income in unconsolidated companies	(715)	(154)
Distributions received from unconsolidated companies	863	838
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other	94,754	92,497
Accounts payable and accrued liabilities	(62,206)	(98,913)
Net cash used in operating activities	(26,880)	(38,036)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(25,147)	(82,609)
Net cash paid for acquisitions	0	(49,060)
Other	1,282	(2,079)
Net cash used in investing activities	(23,865)	(133,748)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under ARP’s revolving credit facility	135,000	231,000
Repayments under ARP’s revolving credit facility	(57,500)	(377,000)
ARP senior note repurchases	(5,528)	0
Net proceeds from issuance of Series A units	0	40,000
Net proceeds from issuance of ARP and AGP units to the public	(2,721)	123,885
Dividends to preferred unitholders	(1,015)	(667)
Net investment from (distributions to) Atlas Energy	0	(19,758)
Deferred financing costs, distribution equivalent rights and other	(953)	(9,102)
Net cash provided by financing activities	63,033	153,503
Net change in cash and cash equivalents	12,288	(18,281)
Cash and cash equivalents, beginning of year	31,214	58,358
Cash and cash equivalents, end of period	43,502	40,077
Atlas Energy | Term loan facilities
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under term loan facilities	0	115,848
Repayments under term loan facilities	(4,250)	(193,203)
ARP | Second lien term loan facility
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under term loan facilities	$ 0	$ 242,500

XML

Basis of Presentation

6 Months Ended

Jun. 30, 2016

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Basis of Presentation

NOTE 1—BASIS OF PRESENTATION

We are a publicly traded (OTC: 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 June 30, 2016, our operations primarily consisted of our ownership interests in the following:

· 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 23.3% limited partner interest (consisting of 20,962,485 common and 3,749,986 preferred limited partner units) in Atlas Resource Partners, L.P. (“ARP”), a publicly traded Delaware master limited partnership (“MLP”) (OTC: ARPJ) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”), with operations in basins across the United States. As part of its exploration and production activities, ARP sponsors and manages tax-advantaged investment partnerships (“Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas and oil production activities;

· all of the incentive distribution rights, an 80.0% general partner interest and a 2.1% limited partner interest in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations primarily focused in the Eagle Ford Shale in South Texas. On June 30, 2015, AGP concluded a private placement offering, during which it issued $233.0 million of its common limited partner units. Of the $233.0 million of gross funds raised, we purchased $5.0 million common limited partner units. AGP’s registration statement on Form S-1 (Registration Number: 333-207537) was declared effective by the Securities and Exchange Commission on April 5, 2016. AGP is offering in the aggregate up to 100,000,000 Class A common units and Class T common units, each representing limited partner interests in AGP, pursuant to a primary offering on a "best efforts" basis. AGP must receive minimum offering proceeds of $1.0 million to break escrow, and the maximum offering proceeds of the primary offering may not exceed $1.0 billion. The Class A common units will be sold for a cash purchase price of $10.00 and the Class T common units will be sold for a cash purchase price of $9.60, with the remaining $0.40 constituting the Class T common unitholders' deferred payment obligation to AGP. AGP is also offering up to 21,505,376 Class A common units at $9.30 per unit pursuant to a distribution reinvestment plan; and

· 12.0% limited partner interest in Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and a 15.4% general partner interest in Lightfoot Capital Partners GP, LLC (“Lightfoot G.P.” and together with Lightfoot L.P., “Lightfoot”), the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of the Company’s board of directors, is the Chairman of the Board. Lightfoot L.P. focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt. We account for our investment in Lightfoot under the equity method of accounting. During both the three months ended June 30, 2016 and 2015, we received net cash distributions of approximately $0.4 million. During both the six months ended June 30, 2016 and 2015, we received net cash distributions of approximately $0.8 million.

At June 30, 2016, we had 26,037,992 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 statements be read in conjunction with the financial statements and the notes thereto included in our latest Annual Report on 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 5). The results of operations for the interim periods presented may not necessarily be indicative of the results of operations for the full year.

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2016

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Combination

Our condensed combined consolidated financial statements for the six months ended June 30, 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 10) 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 each of their respective economic performance, and our ownership of each of their respective 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 12 – 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 $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.

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.

Ability for the Company and ARP to Continue as a Going Concern

On July 25, 2016, ARP and certain of its subsidiaries and us, solely with respect to certain sections thereof, entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with (i) lenders holding 100% of ARP’s senior secured revolving credit facility (the “First Lien Lenders”), (ii) lenders holding 100% of ARP’s second lien term loan (the “Second Lien Lenders”) and (iii) holders (the “Consenting Noteholders” and, collectively with the First Lien Lenders and the Second Lien Lenders, and their respective successors or permitted assigns that become party to the Restructuring Support Agreement, the “Restructuring Support Parties”) of approximately 80% of the aggregate principal amount outstanding of the 7.75% ARP Senior Notes due 2021 (the “7.75% ARP Senior Notes”) and the 9.25% ARP Senior Notes due 2021 (the “9.25% ARP Senior Notes” and, together with the 7.75% ARP Senior Notes, the “Notes”) of ARP’s subsidiaries, Atlas Resource Partners Holdings, LLC and Atlas Resource Finance Corporation (together, the “Issuers”). Under the Restructuring Support Agreement, the Restructuring Support Parties have agreed, subject to certain terms and conditions, to support ARP’s restructuring (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”). See Note 3, “ARP Restructuring Support Agreement,” for further information.

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

The Restructuring, including as a result of ARP monetizing certain hedges to pay down borrowings outstanding under ARP’s senior secured credit facility, will result in a reduction of ARP’s existing debt by approximately $900 million and elimination of approximately $80 million of ARP’s annual debt service obligations. Pursuant to the Plan, ARP’s business assets and operations will vest in a limited liability company, which will be classified as a corporation for U.S. federal income tax purposes (“New Holdco”). ARP expects to consummate the Plan and emerge from Chapter 11 before the end of the third quarter of 2016. Interested parties should refer to the information and the limitations and qualifications discussed in ARP’s disclosure statement related to ARP’s Restructuring (the “ARP Disclosure Statement”) which was filed as Exhibit 99.1 to ARP’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 25, 2016.

ARP intends to continue to operate its businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, it is contemplated that all of ARP’s suppliers, vendors, employees, royalty owners, trade partners and landlords will be unimpaired by the Plan and will be satisfied in full in the ordinary course of business, and ARP’s existing trade contracts and terms will be maintained. To assure ordinary course operations, ARP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to ARP, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.

The Chapter 11 Filings constituted an event of default that accelerated all of ARP’s outstanding debt obligations under the ARP First Lien Credit Facility (as defined below), the ARP Second Lien Term Loan (as defined below) and the indenture governing the ARP Notes. Any efforts to enforce such payments are automatically stayed as a result of ARP’s Chapter 11 Filings, and the holders’ rights of enforcement are subject to the applicable provisions of Chapter 11.  Accordingly, we classified all of ARP’s outstanding debt obligations as a current liability on our condensed combined consolidated balance sheet as of June 30, 2016. See Note 5, Debt, for further information.

ARP’s Restructuring is not expected to materially impact us or our ownership interest in AGP or Lightfoot. We are not a party to ARP’s Restructuring. We remain controlled by the same ownership group and management team and thus, we expect that ARP’s Restructuring will not have a material impact on the ability of management to operate us or the other businesses.

The significant risks and uncertainties related to ARP’s Chapter 11 Filings raise substantial doubt about ARP’s and our ability to continue as a going concern. Our condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. Our condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we and ARP cannot continue as a going concern, adjustments to the carrying values and classification of our and ARP’s assets and liabilities and the reported amounts of income and expenses could be required and could be material.

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 private placement offering completed in 2015. 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.

AGP is not a party to the Restructuring Support Agreement, and ARP’s Restructuring is not expected to materially impact AGP.

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 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, fair value of derivative and other financial instruments and fair value of certain gas and oil properties and asset retirement obligations. 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.

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):

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Net loss	$	(150,717	)	$	(59,543	)	$	(151,989	)	$	(6,064	)
Preferred unitholders’ dividends		—			(1,004	)		(339	)		(1,337	)
(Income) loss attributable to non-controlling interests		114,637			38,740			109,297			(19,558	)
Loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015)		—			—			—			10,475
Net loss attributable to common unitholders		(36,080	)		(21,807	)		(43,031	)		(16,484	)
Less: Net income attributable to participating securities – phantom units(1)		—			—			—			—
Net loss utilized in the calculation of net loss attributable to common unitholders per unit – diluted(1)	$	(36,080	)	$	(21,807	)	$	(43,031	)	$	(16,484	)

(1) Net income (loss) attributable to common unitholders for the net income (loss) attributable to common unitholders per unit calculation is net income (loss) attributable to common unitholders, less income allocable to participating securities. For the three months ended June 30, 2016, and 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 352,000 and 69,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the six months ended June 30, 2016 and 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 307,000 and 67,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.

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):

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Weighted average number of common unitholders per unit—basic		26,031		26,011		26,029		26,011
Add effect of dilutive incentive awards(1)		—		—		—		—
Add effect of dilutive convertible preferred units(2)		—		—		—		—
Weighted average number of common unitholders per unit—diluted		26,031		26,011		26,029		26,011

(1) For the three months ended June 30, 2016 and 2015, approximately 2,692,000 and 750,000 phantom units, respectively, were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive. For the six months ended June 30, 2016, and 2015, approximately 2,691,000 and 567,000 phantom units, respectively, were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive.

(2) For each of the three months and six months ended June 30, 2016 and 2015, potential common units issuable upon conversion of our Series A preferred units were excluded from the computation of diluted earnings attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive.

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 June 30, 2016 and December 31, 2015, we reflected $4.1 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 $4.1 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 six months ended June 30, 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 six months ended June 30, 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.

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.

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Restructuring and Related Activities

6 Months Ended

Jun. 30, 2016

Restructuring And Related Activities [Abstract]

Restructuring Support Agreement

NOTE 3—RESTRUCTURING SUPPORT AGREEMENT

As disclosed in Note 2, on July 25, 2016, ARP and certain of its subsidiaries and us, solely with respect to certain sections thereof, entered into the Restructuring Support Agreement with the Restructuring Support Parties.  On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. Under the Restructuring Support Agreement, the Restructuring Support Parties have agreed, subject to certain terms and conditions, to support ARP’s Restructuring pursuant to the Plan.

In particular, under the Plan, on the Plan’s effective date (the “Plan Effective Date”), the First Lien Lenders will receive cash payment of all obligations owed to them by ARP pursuant to the senior secured revolving credit facility (other than $440 million of principal and face amount of letters of credit) and become lenders under an exit facility credit agreement (the “First Lien Exit Facility”), composed of a $410 million conforming reserve-based tranche and a $30 million non-conforming tranche. The non-conforming tranche will mature on May 1, 2017 and the conforming reserve-based tranche will mature on August 23, 2019. In addition, ARP will enter into a new second lien credit agreement (the “Second Lien Exit Facility” and, together with the First Lien Exit Facility, the “Exit Facilities”). The Second Lien Lenders will receive a pro rata share of the Second Lien Exit Facility, which will have an aggregate principal amount of $250 million plus the amounts resulting from the accrual of paid in kind interest on the principal amount of $250 million from the commencement of ARP’s Chapter 11 Filings, with interest expense paid in cash to be reduced to 2% and the remainder to be paid-in-kind from the commencement date through May 1, 2017 at a rate equal to Adjusted LIBO Rate plus 9% per annum. During the next 15-month period, cash and in-kind interest will vary based on a pricing grid tied to ARP’s leverage ratio under the ARP revolving credit facility. After such 15-month period, interest will accrue at a rate equal to Adjusted LIBO Rate plus 9% per annum and will be payable in cash. In addition to the Second Lien Exit Facility, the Second Lien Lenders will receive a pro rata share of 10% of the common equity interests of New HoldCo, subject to dilution by a management incentive plan. Holders of the Notes, in exchange for 100% of the $668 million aggregate principal amount of Notes outstanding plus accrued but unpaid interest as of the commencement of the Chapter 11 cases, will receive, on the Plan Effective Date, 90% of the common equity interests of New HoldCo as of the Plan Effective Date, subject to dilution by a management incentive plan.

Under the Plan, holders of ARP’s limited partnership units will receive no recovery. On the Plan Effective Date, all of ARP’s preferred limited partnership units and common limited partnership units will be cancelled without the receipt of any consideration.

ARP intends to continue to operate its businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, all suppliers, vendors, employees, royalty owners, trade partners and landlords will be unimpaired by the Plan and will be satisfied in full in the ordinary course of business, and ARP’s existing trade contracts and terms will be maintained. To assure ordinary course operations, ARP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to ARP, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.

Under the Plan, on the Plan Effective Date, a wholly owned subsidiary of the Company (“ARP Mgt LLC”) will receive a preferred share of New HoldCo. The preferred share will entitle ARP Mgt LLC to receive 2% of the economics of New HoldCo (subject to dilution if catch-up contributions are not made with respect to future equity issuances, other than pursuant to the management incentive plan) and certain other rights as provided for in the Restructuring Support Agreement. Four of the seven initial members of the board of directors of New HoldCo are representatives of ARP Mgt LLC (the “New HoldCo Class A Directors”). For so long as ARP Mgt LLC holds such preferred share, the New HoldCo Class A Directors will be appointed by a majority of ARP’s Class A Directors then in office. New HoldCo will have a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in New HoldCo's limited liability company agreement), subject to the receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of New HoldCo unaffiliated with ARP Mgt LLC voting in favor of the exercise of the right to purchase the preferred share.

In accordance with, and subject to the terms and conditions of, the Restructuring Support Agreement, each of the Restructuring Support Parties has agreed, among other things, to: (i) support and take all commercially reasonable actions necessary or reasonably requested by ARP to facilitate consummation of the Restructuring in accordance with the Plan and the related term sheets, including without limitation, if applicable, to timely vote to accept the Plan; (ii) use commercially reasonable efforts to support the confirmation of the Plan and approval of the Disclosure Statement and the solicitation procedures; (iii) not object to, delay, interfere, impede, or take any other action to delay, interfere or impede, directly or indirectly, with the Restructuring, confirmation of the Plan, or approval of the Disclosure Statement or the solicitation procedures; and (iv) not object to our efforts to enter into the Exit Facilities, and not object to, or support the efforts of any other person to oppose or object to, the Exit Facilities.

In accordance with, and subject to the terms and conditions of, the Restructuring Support Agreement, ARP has agreed, subject to applicable fiduciary duties, among other things, to: (i) support and complete the Restructuring and all transactions set forth in the Plan and the Restructuring Support Agreement; (ii) complete the Restructuring and all transactions set forth or described in the Plan; (iii) take any and all necessary actions in furtherance of the Restructuring, the Restructuring Support Agreement and the Plan; (iv) make commercially reasonable efforts to obtain any and all required regulatory and/or third-party approvals for the Restructuring; and (v) operate the business in the ordinary course, taking into account the Restructuring.

The Restructuring Support Agreement may be terminated upon the occurrence of certain events, including the failure to meet specified milestones related to filing, confirmation and consummation of the Plan, among other requirements, and in the event of certain breaches by the parties under the Restructuring Support Agreement. There can be no assurance that the restructuring transactions will be consummated.

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Property, Plant and Equipment

6 Months Ended

Jun. 30, 2016

Property Plant And Equipment [Abstract]

Property, Plant and Equipment

NOTE 4—PROPERTY, PLANT AND EQUIPMENT

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

		June 30,		December 31,			Estimated Useful Lives
		2016		2015			in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	571,761		$	569,377
Pre-development costs		7,125			6,529
Wells and related equipment		3,173,064			3,157,708
Total proved properties		3,751,950			3,733,614
Unproved properties		213,047			213,047
Support equipment		44,264			44,921
Total natural gas and oil properties		4,009,261			3,991,582
Pipelines, processing and compression facilities		61,139			59,733		15 – 20
Rights of way		829			829		20 – 40
Land, buildings and improvements		9,798			9,798		3 – 40
Other		18,422			18,405		3 – 10
		4,099,449			4,080,347
Less – accumulated depreciation, depletion and amortization		(2,825,996	)		(2,763,450	)
	$	1,273,453		$	1,316,897

During the six months ended June 30, 2016 and 2015, we recognized $18.7 million and $29.0 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 was 6.6% for both the three months ended June 30, 2016 and 2015.  The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP were 6.7% and 6.4% for the six months ended June 30, 2016 and 2015, respectively. The amounts of interest capitalized by ARP were $2.4 million and $4.1 million for the three months ended June 30, 2016 and 2015, respectively. The amounts of interest capitalized by ARP were $4.8 million and $8.0 million for the six months ended June 30, 2016 and 2015, respectively.

For the three months ended June 30, 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 depreciation, depletion and amortization in our condensed combined consolidated statements of operations. For the six months ended June 30, 2016 and 2015, we recorded $3.3 million and $3.2 million, respectively, of accretion expense related to ARP and AGP’s asset retirement obligations within depreciation, depletion and amortization in our condensed combined consolidated statements of operations.  For the three months ended June 30, 2016 and 2015, ARP recorded liabilities of $9.9 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.  For the six months ended June 30, 2016 and 2015, ARP recorded liabilities of $12.9 million and $0.5 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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Debt

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Debt

NOTE 5—DEBT

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

	June 30,			December 31,
	2016			2015
Term loan facilities	$	72,619		$	72,700
Deferred financing costs	(257		)		(3,813	)
ARP First Lien Credit Facility	669,500				592,000
ARP Second Lien Term Loan	244,534				243,783
ARP 7.75% Senior Notes—due 2021	354,385				374,619
ARP 9.25% Senior Notes—due 2021	312,096				324,080
ARP deferred financing costs	(27,238		)		(31,055	)
Total debt, net	1,625,639				1,572,314
Less current maturities	(1,553,277		)		(4,250	)
Total long-term debt, net	$	72,362		$	1,568,064

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:

Condensed Combined Consolidated Balance Sheet	Previously Filed		Adjustment			Restated
December 31, 2015:
Other assets, net	$	88,980	$	(34,868	)	$	54,112
Long-term debt, less current portion	$	1,602,932	$	(34,868	)	$	1,568,064

Cash Interest.  Cash payments for interest by us and our subsidiaries on our/their respective borrowings were $16.4 million and $13.2 million for the three months ended June 30, 2016 and 2015, respectively, and $59.1 million and $51.7 million for the six months ended June 30, 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:

· provide the ability for us and the Borrower to enter into the new Second Lien Credit Agreement (defined below);

· shorten the maturity date of the First Lien Credit Agreement to September 30, 2017, subject to an optional extension to September 30, 2018 by the Borrower, assuming certain conditions are met, including a First Lien Leverage Ratio (as defined in the First Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee;

· modify the applicable cash interest rate margin for ABR Loans and Eurodollar Loans to 0.50% and 1.50%, respectively, and add a pay-in-kind interest payment of 11% of the principal balance per annum;

· allow the Borrower to make mandatory pre-payments under the First Lien Credit Agreement or the new Second Lien Credit Agreement, in its discretion, and add additional mandatory pre-payment events, including a monthly cash sweep for balances in excess of $4 million;

· provide that the First Lien Credit Agreement may be prepaid without premium;

· replace the existing financial covenants with (i) the requirement that we maintain a minimum of $2 million in EBITDA on a trailing twelve-month basis, beginning with the quarter ending June 30, 2016, and (ii) the incorporation into the First Lien Credit Agreement of the financial covenants included in ARP’s credit agreement, beginning with the quarter ending June 30, 2016;

· prohibit the payment of cash distributions on our common and preferred units;

· require the receipt of quarterly distributions from AGP and Lightfoot; and

· add a cross-default provision for defaults by ARP.

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 is presented in the table above net of an unamortized discount of $1.9 million as of June 30, 2016, related to the 4,668,044 warrants issued in connection with the Second Lien Credit Agreement (see Note 10).

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.

As a result of the cross-default, on July 11, 2016, we entered into waiver agreements (the “Waivers”) with Riverstone and the Lenders in connection with the First Lien Credit Agreement and the Second Lien Credit Agreement. Pursuant to the Waivers, Riverstone and the Lenders agreed to waive under the First Lien Credit Agreement and the Second Lien Credit Agreement:

· the cross-defaults relating to ARP’s default, for so long as the forbearing parties continue to forbear from exercising their rights and remedies; and

· the potential default relating to ARP’s ongoing negotiations with its lenders and noteholders to the extent any resulting restructuring is completed prior to October 31, 2016

We and ARP’s future debt maturities, excluding any future payment-in-kind interest payments, are as follows: $1,580.5 million, $35.0 million and $35.8 million, respectively, for the years ending December 31, 2016, 2017 and 2019, 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 a 5% or more unitholder participated in approximately 12% of the loan syndication.

ARP First Lien Credit Facility

ARP is party to a Second Amended and Restated Credit Agreement, dated as of July 31, 2013 by and among ARP, the lenders from time to time party thereto, and Wells Fargo Bank, National Association, as administrative agent, as amended, supplemented or modified from time to time (the “ARP First Lien Credit Facility”), which provides for a senior secured revolving credit facility with a maximum borrowing base of $1.5 billion scheduled to mature in July 2018.

On June 8, 2016, ARP received notice from Wells Fargo Bank, National Association, as administrative agent under the ARP First Lien Credit Facility that its borrowing base had been redetermined in accordance with the ARP First Lien Credit Facility and reduced from $700.0 million to $530.0 million. As of June 30, 2016, $669.5 million in borrowings were outstanding (which includes $4.2 million in letters of credit) under the ARP First Lien Credit Facility, resulting in a borrowing base deficiency of $143.7 million. The ARP First Lien Credit Facility provides that within 30 days after ARP’s receipt of a notification of a borrowing base deficiency, ARP must elect to cure the borrowing base deficiency through any combination of the following actions: (i) repay amounts outstanding under the ARP First Lien Credit Facility sufficient to cure the borrowing base deficiency, either within 30 days after receipt of the borrowing base deficiency notice or in four equal monthly installments beginning on July 11, 2016; or (ii) pledge as collateral additional oil and gas properties acceptable to the administrative agent and lenders sufficient to cure the borrowing base deficiency within 60 days after receipt of the borrowing base deficiency notice. As part of the discussions with ARP’s lenders and noteholders (see Notes 1 and 3), ARP determined not to make the first installment payment that was due on July 11, 2016.

In connection therewith and in support of negotiations with ARP’s First Lien Lenders, Second Lien Lenders, and Consenting Noteholders, on July 11, 2016, ARP and certain of its subsidiaries entered into two forbearance agreements: (i) with Wells Fargo Bank, National Association, as administrative agent, and the other lenders under the ARP First Lien Credit Facility (the “ARP First Lien Credit Forbearance”) and (ii) with the Consenting Noteholders of the 7.75% ARP Senior Notes and the 9.25% ARP Senior Notes (the “ARP Notes Forbearance”).

Pursuant to the ARP First Lien Credit Forbearance, the administrative agent and the lenders representing approximately 81% of the outstanding indebtedness under the ARP First Lien Credit Facility agreed to forbear from exercising their rights and remedies arising from non-payment of the first installment of the borrowing base deficiency cure due on July 11, 2016 and related cross-defaults (the “ARP Specified Default”) until the earliest to occur of (i) July 27, 2016, (ii) the occurrence of an event of default under the ARP First Lien Credit Facility (unrelated to the ARP Specified Default) or (iii) the exercise by any holder of indebtedness outstanding under the ARP Second Lien Term Loan, the ARP Notes or any other material indebtedness of ours of rights or remedies against us or the other loan parties or their respective property.

Pursuant to the ARP Notes Forbearance, the holders of approximately 78% of the aggregate outstanding principal amount of the 7.75% ARP Senior Notes and approximately 82% of the 9.25% ARP Senior Notes agreed to forbear from exercising their rights and remedies arising from the cross-default that resulted from the ARP Specified Default until the earliest to occur of (i) July 27, 2016, (ii) another event of default under the 7.75% ARP Senior Notes indenture or the 9.25% ARP Senior Notes indenture or (iii) any other holder of the ARP Notes commences a legal proceeding against us or the other loan parties or their respective property. The holders of a majority of the Second Lien Term Loan were supportive of the forbearance.

ARP’s borrowing base is scheduled for semi-annual redeterminations in May and November of each year. Up to $20.0 million of the ARP First Lien Credit Facility may be in the form of standby letters of credit, of which $4.2 million was outstanding at June 30, 2016. ARP’s obligations under the ARP First Lien Credit Facility are secured by mortgages on ARP’s oil and gas properties and first priority security interests in substantially all of ARP’s assets. Additionally, obligations under the ARP First Lien Credit Facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. At June 30, 2016, the weighted average interest rate on outstanding borrowings under the ARP First Lien Credit Facility was 4.0%.

The ARP First Lien Credit Facility 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 First Lien Credit Facility also requires that ARP maintain a ratio of First Lien Debt to EBITDA (ratio as defined in the ARP First Lien Credit Facility) of not greater than 2.75 to 1.00, and a ratio of current assets to current liabilities (ratio as defined in the ARP First Lien Credit Facility) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. ARP was not in compliance with these covenants as of June 30, 2016.  

ARP’s Chapter 11 Filings constituted an event of default that accelerated ARP’s obligations under the ARP First Lien Credit Facility and as a result, we classified $669.5 million of ARP’s outstanding amounts under the ARP First Lien Credit Facility as current portion of long-term debt and $12.2 million of deferred financing costs related to the ARP First Lien Credit Facility as current assets within our condensed combined consolidated balance sheet as of June 30, 2016.Any efforts to enforce such payments are automatically stayed as a result of the Chapter 11 Filings, and the holders’ rights of enforcement are subject to the applicable provisions of Chapter 11.

Pursuant to the ARP Restructuring Support Agreement, ARP completed the sale of substantially all of its commodity hedge positions on July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under the ARP First Lien Credit Facility. Accordingly, approximately $440 million remained outstanding under the ARP First Lien Credit Facility as of July 27, 2016, the date of ARP’s Chapter 11 Filings.

On the Plan Effective Date, ARP expect to enter into the new ARP First Lien Exit Facility, which will replace the ARP First Lien Credit Facility (see Note 3).

ARP Second Lien Term Loan

ARP is party to a Second Lien Credit Agreement, dated as of February 23, 2015 by and among ARP, the lenders from time to time party thereto, and Wilmington Trust, National Association, as administrative agent, as amended, supplemented or modified from time to time (the “ARP Second Lien Term Loan”), which provides for a second lien term loan in an original principal amount of $250.0 million. The ARP Second Lien Term Loan matures on February 23, 2020. The Second Lien Term Loan is presented in the table above net of unamortized discount of $5.5 million as of June 30, 2016.

ARP’s obligations under the ARP Second Lien Term Loan are secured on a second priority basis by security interests in all of ARP’s assets and those of its restricted subsidiaries that guarantee the ARP First Lien Credit Facility. In addition, the obligations under the ARP Second Lien Term Loan are guaranteed by ARP’s material restricted subsidiaries. At June 30, 2016, the weighted average interest rate on outstanding borrowings under the ARP Second Lien Term Loan was 10.0%.

The ARP Second Lien Term Loan contains customary covenants including, without limitation, covenants that limit ARP’s ability to make restricted payments, take on indebtedness, issue preferred units, 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 Second Lien Term Loan contains covenants substantially similar to those in the ARP First Lien Credit Facility, including, among others, restrictions on swap agreements, debt of unrestricted subsidiaries, drilling and operating agreements and the sale or discount of receivables. ARP was not in compliance with the financial covenants as of June 30, 2016.  

ARP’s Chapter 11 Filings constituted an event of default that accelerated ARP’s obligations under the ARP Second Lien Term Loan and as a result, we classified $244.5 million of ARP’s outstanding amounts under the ARP Second Lien Term Loan, which is net of $5.5 million unamortized discount and $9.4 million deferred financing costs, as current portion of long-term debt within our condensed combined consolidated balance sheet as of June 30, 2016.  Any efforts to enforce such payments are automatically stayed as a result of the Chapter 11 Filings, and the holders’ rights of enforcement are subject to the applicable provisions of Chapter 11.

On the Plan Effective Date, ARP expects to enter into the new ARP Second Lien Exit Facility, which will replace the ARP Second Lien Term Loan (see Note 3).

ARP Senior Notes

At June 30, 2016, ARP had $354.4 million outstanding of its 7.75% ARP Senior Notes due 2021. The 7.75% ARP Senior Notes were presented net of a $0.3 million unamortized discount as of June 30, 2016.

At June 30, 2016, ARP had $312.1 million outstanding of its 9.25% ARP Senior Notes due 2021. The 9.25% ARP Senior Notes were presented net of a $0.8 million unamortized discount as of June 30, 2016.

In January and February 2016, ARP executed transactions to repurchase $20.3 million of its 7.75% Senior Notes and $12.1 million of its 9.25% Senior Notes for $5.5 million, which included $0.6 million of interest. As a result of these transactions, we recognized $26.5 million as gain on early extinguishment of debt, net of accelerated amortization of deferred financing costs of $0.9 million, in our condensed combined consolidated statement of operations for the six months ended June 30, 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 June 30, 2016.

On June 6, 2016, ARP and certain of its subsidiaries, Wells Fargo Bank, National Association, as resigning trustee (“Wells Fargo”) and U.S. Bank National Association, as successor trustee (“U.S. Bank”), entered into an Instrument of Resignation, Appointment and Acceptance (the “Instrument”). In connection with the Instrument, Wells Fargo resigned as trustee, note custodian, registrar and paying agent under the Indenture dated as of July 30, 2013, as supplemented and amended and ARP accepted such resignation and appointed U.S. Bank as the successor trustee, note custodian, registrar and paying agent under the such indenture.

ARP’s Chapter 11 Filings constituted an event of default that accelerated ARP’s obligations under the 7.75% ARP Senior Notes and the 9.25% ARP Senior Notes and as a result, we classified $354.4 million of ARP’s outstanding amounts under the 7.75% ARP Senior Notes, which is net of $0.3 million unamortized discount and $9.5 million deferred financing costs, and $312.1 million of ARP’s outstanding amounts under the 9.25% ARP Senior Notes, which is net of $0.8 million unamortized discount and $8.3 million deferred financing costs, as current portion of long-term debt within our condensed combined consolidated balance sheet as of June 30, 2016. Any efforts to enforce such payments are automatically stayed as a result of the Chapter 11 Filings, and the holders’ rights of enforcement are subject to the applicable provisions of Chapter 11.

On the Plan Effective Date, the 7.75% Senior Notes and the 9.25% Senior Notes (together with accrued but unpaid interest) will be cancelled and the holders will receive 90% of the common equity interests of New HoldCo (see Note 3).

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Derivative Instruments

6 Months Ended

Jun. 30, 2016

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Instruments

NOTE 6—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.

ARP and AGP 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 $234.6 million and $358.1 million at June 30, 2016 and December 31, 2015, respectively. Of the $2.3 million of net gain in accumulated other comprehensive income within unitholders’ equity on our condensed combined consolidated balance sheet related to derivatives at June 30, 2016, we expect to reclassify $1.5 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.

Pursuant to the ARP Restructuring Support Agreement, ARP completed the sale of certain of substantially all of its commodity hedge positions on July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under the ARP First Lien Credit Facility.

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

		Three Months Ended June 30,					Six Months Ended June 30,
	2016			2015			2016			2015
Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets(1)	$	5,555		$	25,778		$	9,070		$	53,121
Portion of settlements attributable to subsequent mark to market gains (losses)		39,835			14,922			85,265			30,125
Total cash settlements on commodity derivative contracts	$	45,390		$	40,700		$	94,335		$	83,246
Gains recognized on cash settlement(2)	$	4,732		$	3,678		$	10,666		$	6,881
Gains (losses) recognized on open derivative contracts(2)		(78,822	)		(30,574	)		(38,303	)		71,808
Gains (losses) on mark-to-market derivatives	$	(74,090	)	$	(26,896	)	$	(27,637	)	$	78,689

(1) Recognized in gas and oil production revenue.

(2) Recognized in gain on mark-to-market derivatives.

During the three and six months ended June 30, 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 June 30, 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 June 30, 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.

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):

Offsetting Derivatives as of June 30, 2016	Gross Amounts Recognized			Gross Amounts Offset			Net Amount Presented
Current portion of derivative assets	$	183		$	(183	)	$	—
Long-term portion of derivative assets		55			(55	)		—
Total derivative assets	$	238		$	(238	)	$	—
Current portion of derivative liabilities	$	(320	)	$	183		$	(137	)
Long-term portion of derivative liabilities		(218	)		55			(163	)
Total derivative liabilities	$	(538	)	$	238		$	(300	)
Offsetting Derivatives as of December 31, 2015
Current portion of derivative assets	$	399		$	(96	)	$	303
Long-term portion of derivative assets		162			(53	)		109
Total derivative assets	$	561		$	(149	)	$	412
Current portion of derivative liabilities	$	(96	)	$	96		$	—
Long-term portion of derivative liabilities		(53	)		53			—
Total derivative liabilities	$	(149	)	$	149		$	—

At June 30, 2016, AGP had the following commodity derivatives:

Type	Production Period Ending December 31,	Volumes(1)	Average Fixed Price(1)		Fair Value (Liability)			Total Type
					(in thousands)(2)			(in thousands)(2)
Crude Oil – Fixed Price Swaps	2016(3)	31,600	$	46.350	$	(95	)
	2017	37,100	$	49.968	$	(79	)
	2018	26,500	$	48.850	$	(126	)
						AGP’s net liabilities		$	(300)

(1) Volumes for crude oil are stated in barrels.

(2) Fair value of crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable.

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

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):

Offsetting Derivatives as of June 30, 2016	Gross Amounts Recognized		Gross Amounts Offset		Net Amount Presented
Current portion of derivative assets	$	99,654	$	—	$	99,654
Long-term portion of derivative assets		135,231		—		135,231
Total derivative assets	$	234,885	$	—	$	234,885
Current portion of derivative liabilities	$	—	$	—	$	—
Long-term portion of derivative liabilities		—		—		—
Total derivative liabilities	$	—	$	—	$	—
Offsetting Derivatives as of December 31, 2015
Current portion of derivative assets	$	159,460	$	—	$	159,460
Long-term portion of derivative assets		198,262		—		198,262
Total derivative assets	$	357,722	$	—	$	357,722
Current portion of derivative liabilities	$	—	$	—	$	—
Long-term portion of derivative liabilities		—		—		—
Total derivative liabilities	$	—	$	—	$	—

At June 30, 2016, ARP had the following commodity derivatives:

Type	Production Period Ending December 31,	Volumes(1)	Average Fixed Price(1)		Fair Value Asset		Total Type
					(in thousands)(2)		(in thousands)(2)
Natural Gas – Fixed Price Swaps	2016(3)	26,910,000	$	4.224	$	32,326
	2017	50,120,000	$	4.221	$	51,933
	2018	40,300,000	$	4.168	$	45,498
	2019	15,860,000	$	4.019	$	15,945
							$	145,702
Natural Gas – Put Options – Drilling Partnerships	2016(3)	720,000	$	4.150	$	814
							$	814
Crude Oil – Fixed Price Swaps	2016(3)	820,500	$	81.685	$	26,449
	2017	1,200,000	$	77.610	$	30,412
	2018	1,080,000	$	76.281	$	24,184
	2019	540,000	$	68.371	$	7,324
							$	88,369
					Total net ARP assets		$	234,885

(1) Volumes for natural gas are stated in million British Thermal Units. Volumes for crude oil are stated in barrels.

(2) Fair value for natural gas fixed price swaps and natural gas put options based on forward NYMEX natural gas prices, as applicable. Fair value for crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable.

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

Secured Hedge Facility

At June 30, 2016, ARP had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under ARP’s revolving credit facility, ARP is required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. ARP, as general partner of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility and guarantees their obligations under it. Before executing any hedge transaction, a participating Drilling Partnership is required to, among other things, provide mortgages on its oil and gas properties and first priority security interests in substantially all of its assets to the collateral agent for the benefit of the counterparties. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, 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.

An event of default occurred under the secured hedging facility agreement upon ARP’s filing of voluntary petitions for relief under Chapter 11.  The lenders under the secured hedge facility agreed to forbear from exercising remedies in respect of such event of default while the Chapter 11 Filings are pending and, upon occurrence of the effective date of the Plan contemplated by ARP’s Restructuring Support Agreement, such event of default will no longer be deemed to exist or to continue under the secured hedge facility.

In addition, it will be an event of default under ARP’s revolving credit facility if ARP, as general partner of the Drilling Partnerships, breaches an obligation governed by the secured hedge facility and the effect of such breach is to cause amounts owing under swap agreements governed by the secured hedge facility to become immediately due and payable.

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Fair Value of Financial Instruments

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

NOTE 7—FAIR VALUE OF FINANCIAL INSTRUMENTS

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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 June 30, 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 June 30, 2016 and December 31, 2015 were as follows (in thousands):

	Level 1		Level 2			Level 3		Total
As of June 30, 2016
Assets, gross
Rabbi trust	$	4,072	$	—		$	—	$	4,072
ARP Commodity swaps		—		234,071			—		234,071
ARP Commodity puts		—		814			—		814
AGP Commodity swaps		—		238			—		238
Total assets, gross		4,072		235,123			—		239,195
Liabilities, gross
AGP Commodity swaps		—		(538	)		—		(538	)
Total derivative liabilities, gross		—		(538	)		—		(538	)
Total assets, fair value, net	$	4,072	$	234,585		$	—	$	238,657
As of December 31, 2015
Assets, gross
Rabbi trust	$	5,584	$	—		$	—	$	5,584
ARP Commodity swaps		—		355,329			—		355,329
ARP Commodity puts		—		2,393			—		2,393
AGP Commodity swaps		—		561			—		561
Total assets, gross		5,584		358,283			—		363,867
Liabilities, gross
AGP Commodity swaps		—		(149	)		—		(149	)
Total derivative liabilities, gross	$	—	$	(149	)	$	—	$	(149	)
Total assets, fair value, net	$	5,584	$	358,134		$	—	$	363,718

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 June 30, 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 $1,020.7 million and $929.2 million, respectively, compared with the carrying amounts of $1,661.6 million and $1,614.7 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.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

Management estimated the fair values of ARP’s natural gas and oil properties transferred to ARP upon liquidations of certain Drilling Partnerships (see Note 8) based on discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, ARP’s future operating and development costs of the assets, the respective natural gas, oil and natural gas liquids forward price curves, and estimated salvage values using ARP’s historical experience and external estimates of recovery values. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs.

Management estimated the fair value of asset retirement obligations transferred to ARP upon liquidations of certain Drilling Partnerships (see Note 4) based on discounted cash flow projections using ARP’s historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future considering inflation rates, federal and state regulatory requirements, and ARP’s assumed credit-adjusted risk-free interest rate. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs.

Management estimated the fair value of the Warrants associated the Second Lien Credit Agreement (see Note 10) using a Black-Scholes pricing model which is based on Level 3 inputs including a unit price on the date of issuance of $0.50, exercise price of $0.20, risk free rate of 1.8%, a term of 10 years, and estimated volatility rate of 57%. The volatility rate used is consistent with that of ARP and similar sized entities within the industry. The estimated fair value per warrant was $0.40.

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Certain Relationships and Related Party Transactions

6 Months Ended

Jun. 30, 2016

Related Party Transactions [Abstract]

Certain Relationships And Related Party Transactions

NOTE 8—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 management fee in connection with its management of AGP equivalent to 1% of capital contributions per annum. During the three months ended June 30, 2016 and 2015, AGP paid approximately $0.6 million and $0.3 million related to AGP GP for this management fee. During the six months ended June 30, 2016 and 2015, AGP paid approximately $1.1 million and $0.6 million related to AGP GP for this management fee. We charge direct costs, such as salary and wages, and allocate indirect costs, such as rent for offices, 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 by ARP to the Atlas Eagle Ford 2015 L.P. private drilling partnership for activities directly related to their program. In June 2016, ARP transferred $5.2 million of funds to certain of the Drilling Partnerships that were projected to make monthly or quarterly distributions to their limited partners over the next several months and/or quarter to ensure accessible distribution funding coverage in accordance with the respective Drilling Partnerships’ operations and partnership agreements in the event ARP experiences a prolonged restructuring period as ARP performs all administrative and management functions for the Drilling Partnerships. On July 26, 2016, ARP adopted certain amendments to the Drilling Partnerships’ partnership agreements, in accordance with ARP’s ability to amend the Drilling Partnerships’ partnership agreements to cure an ambiguity in or correct or supplement any provision of the Drilling Partnerships’ partnership agreements as may be inconsistent with any other provision, to provide that bankruptcy and insolvency events, such as the Chapter 11 Filings, with respect to the managing general partner will not cause the managing general partner to cease to serve as the managing general partner of the Drilling Partnerships nor cause the termination of the Drilling Partnerships.

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. During the quarter ended June 30, 2016, ARP recorded $7.2 million and $12.4 million of gas and oil properties and asset retirement obligations, respectively, transferred to ARP as a result of certain Drilling Partnership liquidations. The gas and oil properties and asset retirement obligations were recorded at their fair values on the respective dates of the Drilling Partnerships’ liquidation and transfer to ARP (see Note 7) and resulted in a non-cash loss of $6.2 million, net of liquidation and transfer adjustments, for the three and six months ended June 30, 2016, which was recorded in other income/(loss) in the condensed consolidated statement of operations.

As of June 30, 2016 and December 31, 2015, ARP had trade receivables of $8.9 million and $6.6 million, respectively, from certain of the Drilling Partnerships, which were recorded in accounts receivable in the condensed consolidated balance sheets.  As of June 30, 2016 and December 31, 2015, ARP had trade payables of $1.5 million and $3.0 million, respectively, to certain of the Drilling Partnerships, which were 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 5), our Series A preferred units (Note 10) and our general partner and limited partner interest in Lightfoot (see Note 1).

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2016

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

NOTE 9—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 June 30, 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 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 both the three months ended June 30, 2016 and 2015, $0.5 million 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.  For the six months ended June 30, 2016 and 2015, $0.6 million and $1.1 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 June 30, 2016, we and our subsidiaries are committed to expend approximately $4.6 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.

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Issuances of Units

6 Months Ended

Jun. 30, 2016

Proceeds From Issuance Or Sale Of Equity [Abstract]

Issuances of Units

NOTE 10—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.

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. The Warrants include a cashless exercise provision entitling the Lenders to surrender a portion of the underlying common units that has a value equal to the aggregate exercise price in lieu of paying cash upon exercise of a warrant. As a result of issuance of the Warrants, we recognized a $1.9 million debt discount on the Second Lien Credit Agreement, which will be amortized over the term of the debt, and a corresponding $1.9 million increase to unitholders’ equity – warrants on our condensed combined balance sheet as of June 30, 2016.

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.

On May 12, 2016, due to the income tax ramifications of potential options we were 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. The delayed vesting schedule did not have a significant impact on the compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the three and six months ended June 30, 2016 or our remaining unrecognized compensation expense related to such awards.

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 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 June 30, 2016, ARP did not issue any common limited partner units under the equity distribution program. During the three months ended June 30, 2015, ARP issued 2,403,288 common limited partner units under the equity distribution agreement for net proceeds of $17.5 million, net of $0.5 million in commissions and offering expenses paid.  During the six months ended June 30, 2016, ARP issued 245,175 common limited partner units under the equity distribution program for net proceeds of $0.2 million, net of $4,000 in commissions and offering expenses paid. During the six months ended June 30, 2015, ARP issued 2,885,824 common limited partner units under the equity distribution agreement for net proceeds of $21.4 million, net of $0.6 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 and six months ended June 30, 2016 and 2015.

In May 2015, in connection with the Arkoma Acquisition, ARP issued 6,500,000 of its common limited partner units in a public offering at a price of $7.97 per unit, yielding net proceeds of $49.7 million. ARP used a portion of the net proceeds to fund the Arkoma Acquisition and to reduce borrowings outstanding under ARP’s First Lien Credit Facility.

In April 2015, ARP issued 255,000 of its 10.75% Class E ARP Preferred Units at a public offering price of $25.00 per unit for net proceeds of $6.0 million.

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 ARP Preferred Units to the seller at a value of $25.00 per unit.

On May 12, 2016, due to the income tax ramifications of the potential options ARP was 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 August 31 ,2016. The delayed vesting schedule did not have a significant impact on ARP’s compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the three and six months ended June 30, 2016 or our remaining unrecognized compensation expense related to such awards.

On July 12, 2016, ARP received notification from the New York Stock Exchange that the NYSE commenced proceedings to delist ARP’s common units as a result of ARP’s failure to comply with the continued listed standards set forth in Section 802.01C of the NYSE Listed Company Manual to maintain an average closing price of $1.00 per unit over a consecutive 30 day period. The Class D ARP Preferred Units and Class E ARP Preferred Units were also delisted from the NYSE. ARP’s common units, Class D ARP Preferred Units, and Class E ARP Preferred Units began trading on the OTC market on July 13, 2016 with the ticker symbol “ARPJ” for ARP’s common units, “ARPJP” for Class D ARP Preferred Units, and “ARPJN” for Class E ARP Preferred Units.

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 $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 six months ended June 30, 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 six months ended June 30, 2015, we recorded gains of $2.9 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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Cash Distributions

6 Months Ended

Jun. 30, 2016

Distributions Made To Members Or Limited Partners [Abstract]

Cash Distributions

NOTE 11—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 entered into on March 30, 2016 (see Note 5), we are prohibited from paying future cash distributions on our common and preferred units.

During the six months ended June 30, 2016, we paid a distribution of $1.0 million to Class A preferred unitholders. During the six months ended June 30, 2015, we paid a distribution of $0.7 million to Class A preferred unitholders.

ARP Cash Distributions. ARP has a monthly cash distribution program whereby ARP distributes all of its available cash (as defined in the 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. In July 2015, the remaining 39,654 Class B Preferred Units were converted into ARP common limited partner units.

The Class C ARP Preferred Units received 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. 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.

ARP pays quarterly distributions on its 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 quarterly distributions on its 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 June 16, 2016, the Board of Directors elected to suspend the distributions on the Class D ARP Preferred Units and the Class E ARP Preferred Units, beginning with the second quarter 2016 distribution, due to the continued lower commodity price environment.  The Class D ARP Preferred Units and Class E ARP Preferred Units accrued distributions of $1.9 million and $0.1 million, respectively, from April 15, 2016 through June 30, 2016.  However, due to the distribution suspension and ARP’s recent Chapter 11 filings, these amounts were not earned as the preferred units will be cancelled without receipt of any consideration on the Plan Effective Date.

During the six months ended June 30, 2016, ARP paid four monthly cash distributions totaling $5.1 million to common limited partners ($0.0125 per unit per month); $2.5 million to Preferred Class C limited partners ($0.0125 per unit per month); and $0.2 million to the General Partner Class A holder ($0.0125 per unit per month). During the six months ended June 30, 2015, ARP paid six monthly cash distributions totaling $71.2 million to common limited partners ($0.1966 per unit in both January and February 2015 and $0.1083 per unit in March through June 2015); $4.0 million to Preferred Class C limited partners ($0.1966 per unit in both January and February 2015 and $0.17 per unit in March through June 2015); and $3.6 million to the General Partner Class A holder ($0.1966 per unit in both January and February 2015 and $0.1083 per unit in March through June 2015).

During the six months ended June 30, 2016, ARP paid two distributions totaling $4.4 million to Class D Preferred units ($0.5390625 per unit) for the period October 15, 2016 through April 14, 2016. During the six months ended June 30, 2015, ARP paid two distributions totaling $4.1 million to Class D Preferred units ($0.6169270 per unit for the period October 2, 2014 through January 14, 2015 and $0.539063 per unit for the period January 15, 2015 through April 14, 2015).

During the six months ended June 30, 2016, ARP paid two distributions totaling $0.3 million to Class E Preferred units ($0.671875 per unit) for the period October 15, 2015 through April 14, 2016.  No distributions were paid to Class E Preferred units during the six months ended June 30, 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 six months ended June 30, 2016, AGP paid a distribution of $8.2 million to common limited partners ($0.1750 per unit per quarter) and $0.2 million to the general partner’s Class A units ($0.1750 per unit per quarter). During the six months ended June 30, 2015, AGP paid a distribution of $3.8 million to common limited partners ($0.1750 per unit per quarter) and $0.1 million to the general partner’s Class A units ($0.1750 per unit per quarter).

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Operating Segment Information

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

Operating Segment Information

NOTE 12—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 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):

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Atlas Resource Partners:
Revenues(1)	$	(16,824	)	$	96,125		$	86,384		$	339,714
Operating costs and expenses	(57,125		)		(75,822	)	(116,327		)		(163,640	)
Depreciation, depletion and amortization expense	(29,008		)		(42,494	)	(59,053		)		(85,485	)
Gain (loss) on asset sales and disposal	(502		)		97		(493		)		86
Interest expense	(31,954		)		(24,716	)	(59,659		)		(49,913	)
Gain on early extinguishment of debt	—				—		26,498				—
Other income (loss)		(6,156	)		—			(6,156	)		—
Segment income (loss)	$	(141,569	)	$	(46,810	)	$	(128,806	)	$	40,762
Atlas Growth Partners:
Revenues	$	2,559		$	1,865		$	5,993		$	4,176
Operating costs and expenses	(3,421		)		(3,243	)	(6,924		)		(8,312	)
Depreciation, depletion and amortization expense	(3,299		)		(782	)	(7,526		)		(2,247	)
Segment loss	$	(4,161	)	$	(2,160	)	$	(8,457	)	$	(6,383	)
Corporate and other:
Revenues	$	461		$	257		$	672		$	156
General and administrative	(1,531		)		(2,359	)	(3,685		)		(22,574	)
Interest expense	(3,890		)		(8,471	)	(5,633		)		(18,025	)
Loss on early extinguishment of debt	(27		)		—		(6,080		)		—
Segment loss	$	(4,987	)	$	(10,573	)	$	(14,726	)	$	(40,443	)
Reconciliation of segment loss to net loss:
Segment income (loss):
Atlas Resource Partners	$	(141,569	)	$	(46,810	)	$	(128,806	)	$	40,762
Atlas Growth Partners	(4,161		)		(2,160	)	(8,457		)		(6,383	)
Corporate and other		(4,987	)		(10,573	)		(14,726	)		(40,443	)
Net loss	$	(150,717	)	$	(59,543	)	$	(151,989	)	$	(6,064	)
Reconciliation of segment revenues to total revenues:
Segment revenues:
Atlas Resource Partners(1)	$	(16,824	)	$	96,125		$	86,384		$	339,714
Atlas Growth Partners	2,559				1,865		5,993				4,176
Corporate and other	461				257		672				156
Total revenues(1)	$	(13,804	)	$	98,247		$	93,049		$	344,046
Capital expenditures:
Atlas Resource Partners	$	5,650		$	26,993		$	18,820		$	69,491
Atlas Growth Partners	778				3,175		6,327				13,118
Corporate and other	—				—		—				—
Total capital expenditures	$	6,428		$	30,168		$	25,147		$	82,609

	June 30,		December 31,
	2016		2015
Balance sheet:
Goodwill:
Atlas Resource Partners	$	13,639	$	13,639
Atlas Growth Partners	—			—
Corporate and other	—			—
Total goodwill	$	13,639	$	13,639
Total assets:
Atlas Resource Partners	$	1,540,386	$	1,699,949
Atlas Growth Partners	135,721			159,622
Corporate and other	21,193			23,675
Total assets	$	1,697,300	$	1,883,246

1) Revenues include gains (losses) on mark to market derivatives. A $73.3 million loss on ARP’s mark-to-market derivatives is included for the three months ended June 30, 2016 related to increases in commodity future prices relative to ARP’s commodity fixed price swaps during the three months ended June 30, 2016 as compared to the prior year period.

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Subsequent Events

6 Months Ended

Jun. 30, 2016

Subsequent Events [Abstract]

Subsequent Events

NOTE 13—SUBSEQUENT EVENTS

Atlas Resource Partners

First Lien Credit Facility Installment Payment. As part of the ongoing discussions with ARP’s lenders and noteholders, ARP determined not to make the first installment payment that was due under the ARP First Lien Credit Facility on July 11, 2016 (see Note 5).

NYSE Compliance.On July 12, 2016, ARP received notification from the New York Stock Exchange that the NYSE commenced proceedings to delist ARP’s common units (see Note 10).

Restructuring Support Agreement. On July 25, 2016, ARP and certain of their subsidiaries and us, solely with respect to certain sections thereof, entered into the Restructuring Support Agreement with the Restructuring Support Parties.  On July 27, 2016, ARP and certain of their subsidiaries filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court (see Note 3).

Sale of ARP’s Commodity Hedge Positions. Pursuant to the ARP Restructuring Support Agreement, ARP completed the sale of substantially all of its commodity hedge positions on July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under the ARP First Lien Credit Facility (See Note 5).

Conversion of Preferred Units and Warrants. On July 31, the 3,749,986 Class C ARP Preferred Units that were issued to us on July 31, 2013, were converted into 3,749,986 common units and the associated warrant issued to us to purchase 562,497 of ARP’s common units expired.

Atlas Growth Partners

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

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2016

Accounting Policies [Abstract]

Principles of Consolidation and Combination

Principles of Consolidation and Combination

Our condensed combined consolidated financial statements for the six months ended June 30, 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 10) 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 each of their respective economic performance, and our ownership of each of their respective 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 12 – 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 $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.

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.

Liquidity and Capital Resources

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.

Ability to Continue as a Going Concern

Ability for the Company and ARP to Continue as a Going Concern

On July 25, 2016, ARP and certain of its subsidiaries and us, solely with respect to certain sections thereof, entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with (i) lenders holding 100% of ARP’s senior secured revolving credit facility (the “First Lien Lenders”), (ii) lenders holding 100% of ARP’s second lien term loan (the “Second Lien Lenders”) and (iii) holders (the “Consenting Noteholders” and, collectively with the First Lien Lenders and the Second Lien Lenders, and their respective successors or permitted assigns that become party to the Restructuring Support Agreement, the “Restructuring Support Parties”) of approximately 80% of the aggregate principal amount outstanding of the 7.75% ARP Senior Notes due 2021 (the “7.75% ARP Senior Notes”) and the 9.25% ARP Senior Notes due 2021 (the “9.25% ARP Senior Notes” and, together with the 7.75% ARP Senior Notes, the “Notes”) of ARP’s subsidiaries, Atlas Resource Partners Holdings, LLC and Atlas Resource Finance Corporation (together, the “Issuers”). Under the Restructuring Support Agreement, the Restructuring Support Parties have agreed, subject to certain terms and conditions, to support ARP’s restructuring (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”). See Note 3, “ARP Restructuring Support Agreement,” for further information.

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

The Restructuring, including as a result of ARP monetizing certain hedges to pay down borrowings outstanding under ARP’s senior secured credit facility, will result in a reduction of ARP’s existing debt by approximately $900 million and elimination of approximately $80 million of ARP’s annual debt service obligations. Pursuant to the Plan, ARP’s business assets and operations will vest in a limited liability company, which will be classified as a corporation for U.S. federal income tax purposes (“New Holdco”). ARP expects to consummate the Plan and emerge from Chapter 11 before the end of the third quarter of 2016. Interested parties should refer to the information and the limitations and qualifications discussed in ARP’s disclosure statement related to ARP’s Restructuring (the “ARP Disclosure Statement”) which was filed as Exhibit 99.1 to ARP’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 25, 2016.

ARP intends to continue to operate its businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, it is contemplated that all of ARP’s suppliers, vendors, employees, royalty owners, trade partners and landlords will be unimpaired by the Plan and will be satisfied in full in the ordinary course of business, and ARP’s existing trade contracts and terms will be maintained. To assure ordinary course operations, ARP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to ARP, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.

The Chapter 11 Filings constituted an event of default that accelerated all of ARP’s outstanding debt obligations under the ARP First Lien Credit Facility (as defined below), the ARP Second Lien Term Loan (as defined below) and the indenture governing the ARP Notes. Any efforts to enforce such payments are automatically stayed as a result of ARP’s Chapter 11 Filings, and the holders’ rights of enforcement are subject to the applicable provisions of Chapter 11.  Accordingly, we classified all of ARP’s outstanding debt obligations as a current liability on our condensed combined consolidated balance sheet as of June 30, 2016. See Note 5, Debt, for further information.

ARP’s Restructuring is not expected to materially impact us or our ownership interest in AGP or Lightfoot. We are not a party to ARP’s Restructuring. We remain controlled by the same ownership group and management team and thus, we expect that ARP’s Restructuring will not have a material impact on the ability of management to operate us or the other businesses.

The significant risks and uncertainties related to ARP’s Chapter 11 Filings raise substantial doubt about ARP’s and our ability to continue as a going concern. Our condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. Our condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we and ARP cannot continue as a going concern, adjustments to the carrying values and classification of our and ARP’s assets and liabilities and the reported amounts of income and expenses could be required and could be material.

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 private placement offering completed in 2015. 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.

AGP is not a party to the Restructuring Support Agreement, and ARP’s Restructuring is not expected to materially impact AGP.

Use of Estimates

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 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, fair value of derivative and other financial instruments and fair value of certain gas and oil properties and asset retirement obligations. 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.

Net Income (Loss) Per Common Unit

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):

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Net loss	$	(150,717	)	$	(59,543	)	$	(151,989	)	$	(6,064	)
Preferred unitholders’ dividends		—			(1,004	)		(339	)		(1,337	)
(Income) loss attributable to non-controlling interests		114,637			38,740			109,297			(19,558	)
Loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015)		—			—			—			10,475
Net loss attributable to common unitholders		(36,080	)		(21,807	)		(43,031	)		(16,484	)
Less: Net income attributable to participating securities – phantom units(1)		—			—			—			—
Net loss utilized in the calculation of net loss attributable to common unitholders per unit – diluted(1)	$	(36,080	)	$	(21,807	)	$	(43,031	)	$	(16,484	)

(1) Net income (loss) attributable to common unitholders for the net income (loss) attributable to common unitholders per unit calculation is net income (loss) attributable to common unitholders, less income allocable to participating securities. For the three months ended June 30, 2016, and 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 352,000 and 69,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the six months ended June 30, 2016 and 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 307,000 and 67,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.

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):

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Weighted average number of common unitholders per unit—basic		26,031		26,011		26,029		26,011
Add effect of dilutive incentive awards(1)		—		—		—		—
Add effect of dilutive convertible preferred units(2)		—		—		—		—
Weighted average number of common unitholders per unit—diluted		26,031		26,011		26,029		26,011

(1) For the three months ended June 30, 2016 and 2015, approximately 2,692,000 and 750,000 phantom units, respectively, were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive. For the six months ended June 30, 2016, and 2015, approximately 2,691,000 and 567,000 phantom units, respectively, were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive.

(2) For each of the three months and six months ended June 30, 2016 and 2015, potential common units issuable upon conversion of our Series A preferred units were excluded from the computation of diluted earnings attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive.

Rabbi Trust

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 June 30, 2016 and December 31, 2015, we reflected $4.1 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 $4.1 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 six months ended June 30, 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 six months ended June 30, 2015.

Recently Issued Accounting Standards

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.

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.

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Summary of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2016

Accounting Policies [Abstract]

Schedule of Net Income (Loss) Reconciliation

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):

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Net loss	$	(150,717	)	$	(59,543	)	$	(151,989	)	$	(6,064	)
Preferred unitholders’ dividends		—			(1,004	)		(339	)		(1,337	)
(Income) loss attributable to non-controlling interests		114,637			38,740			109,297			(19,558	)
Loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015)		—			—			—			10,475
Net loss attributable to common unitholders		(36,080	)		(21,807	)		(43,031	)		(16,484	)
Less: Net income attributable to participating securities – phantom units(1)		—			—			—			—
Net loss utilized in the calculation of net loss attributable to common unitholders per unit – diluted(1)	$	(36,080	)	$	(21,807	)	$	(43,031	)	$	(16,484	)

(1) Net income (loss) attributable to common unitholders for the net income (loss) attributable to common unitholders per unit calculation is net income (loss) attributable to common unitholders, less income allocable to participating securities. For the three months ended June 30, 2016, and 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 352,000 and 69,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the six months ended June 30, 2016 and 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 307,000 and 67,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.

Reconciliation of Weighted Average Number of Common Unit holder Units

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):

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Weighted average number of common unitholders per unit—basic		26,031		26,011		26,029		26,011
Add effect of dilutive incentive awards(1)		—		—		—		—
Add effect of dilutive convertible preferred units(2)		—		—		—		—
Weighted average number of common unitholders per unit—diluted		26,031		26,011		26,029		26,011

(1) For the three months ended June 30, 2016 and 2015, approximately 2,692,000 and 750,000 phantom units, respectively, were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive. For the six months ended June 30, 2016, and 2015, approximately 2,691,000 and 567,000 phantom units, respectively, were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive.

(2) For each of the three months and six months ended June 30, 2016 and 2015, potential common units issuable upon conversion of our Series A preferred units were excluded from the computation of diluted earnings attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive.

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Property, Plant and Equipment (Tables)

6 Months Ended

Jun. 30, 2016

Property Plant And Equipment [Abstract]

Summary of Property, Plant and Equipment

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

		June 30,		December 31,			Estimated Useful Lives
		2016		2015			in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	571,761		$	569,377
Pre-development costs		7,125			6,529
Wells and related equipment		3,173,064			3,157,708
Total proved properties		3,751,950			3,733,614
Unproved properties		213,047			213,047
Support equipment		44,264			44,921
Total natural gas and oil properties		4,009,261			3,991,582
Pipelines, processing and compression facilities		61,139			59,733		15 – 20
Rights of way		829			829		20 – 40
Land, buildings and improvements		9,798			9,798		3 – 40
Other		18,422			18,405		3 – 10
		4,099,449			4,080,347
Less – accumulated depreciation, depletion and amortization		(2,825,996	)		(2,763,450	)
	$	1,273,453		$	1,316,897

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Debt (Tables)

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Schedule of Total Long-term Debt Instruments

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

	June 30,			December 31,
	2016			2015
Term loan facilities	$	72,619		$	72,700
Deferred financing costs	(257		)		(3,813	)
ARP First Lien Credit Facility	669,500				592,000
ARP Second Lien Term Loan	244,534				243,783
ARP 7.75% Senior Notes—due 2021	354,385				374,619
ARP 9.25% Senior Notes—due 2021	312,096				324,080
ARP deferred financing costs	(27,238		)		(31,055	)
Total debt, net	1,625,639				1,572,314
Less current maturities	(1,553,277		)		(4,250	)
Total long-term debt, net	$	72,362		$	1,568,064

Schedule of Retrospective Effect of Debt Issuance Cost Reclassification

The retrospective effect of the reclassification resulted in the following changes:

Condensed Combined Consolidated Balance Sheet	Previously Filed		Adjustment			Restated
December 31, 2015:
Other assets, net	$	88,980	$	(34,868	)	$	54,112
Long-term debt, less current portion	$	1,602,932	$	(34,868	)	$	1,568,064

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Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2016

Derivatives Fair Value [Line Items]

Summary of Commodity Derivative Activity Presentation in Statement of Operations

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

		Three Months Ended June 30,					Six Months Ended June 30,
	2016			2015			2016			2015
Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets(1)	$	5,555		$	25,778		$	9,070		$	53,121
Portion of settlements attributable to subsequent mark to market gains (losses)		39,835			14,922			85,265			30,125
Total cash settlements on commodity derivative contracts	$	45,390		$	40,700		$	94,335		$	83,246
Gains recognized on cash settlement(2)	$	4,732		$	3,678		$	10,666		$	6,881
Gains (losses) recognized on open derivative contracts(2)		(78,822	)		(30,574	)		(38,303	)		71,808
Gains (losses) on mark-to-market derivatives	$	(74,090	)	$	(26,896	)	$	(27,637	)	$	78,689

(1) Recognized in gas and oil production revenue.

(2) Recognized in gain on mark-to-market derivatives.

Fair Value of Derivative Instruments Table

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):

Offsetting Derivatives as of June 30, 2016	Gross Amounts Recognized			Gross Amounts Offset			Net Amount Presented
Current portion of derivative assets	$	183		$	(183	)	$	—
Long-term portion of derivative assets		55			(55	)		—
Total derivative assets	$	238		$	(238	)	$	—
Current portion of derivative liabilities	$	(320	)	$	183		$	(137	)
Long-term portion of derivative liabilities		(218	)		55			(163	)
Total derivative liabilities	$	(538	)	$	238		$	(300	)
Offsetting Derivatives as of December 31, 2015
Current portion of derivative assets	$	399		$	(96	)	$	303
Long-term portion of derivative assets		162			(53	)		109
Total derivative assets	$	561		$	(149	)	$	412
Current portion of derivative liabilities	$	(96	)	$	96		$	—
Long-term portion of derivative liabilities		(53	)		53			—
Total derivative liabilities	$	(149	)	$	149		$	—

Commodity Derivative Instruments by Type Table

At June 30, 2016, AGP had the following commodity derivatives:

Type	Production Period Ending December 31,	Volumes(1)	Average Fixed Price(1)		Fair Value (Liability)			Total Type
					(in thousands)(2)			(in thousands)(2)
Crude Oil – Fixed Price Swaps	2016(3)	31,600	$	46.350	$	(95	)
	2017	37,100	$	49.968	$	(79	)
	2018	26,500	$	48.850	$	(126	)
						AGP’s net liabilities		$	(300)

(1) Volumes for crude oil are stated in barrels.

(2) Fair value of crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable.

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

Atlas Resource Partners, L.P.

Derivatives Fair Value [Line Items]

Fair Value of Derivative Instruments Table

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):

Offsetting Derivatives as of June 30, 2016	Gross Amounts Recognized		Gross Amounts Offset		Net Amount Presented
Current portion of derivative assets	$	99,654	$	—	$	99,654
Long-term portion of derivative assets		135,231		—		135,231
Total derivative assets	$	234,885	$	—	$	234,885
Current portion of derivative liabilities	$	—	$	—	$	—
Long-term portion of derivative liabilities		—		—		—
Total derivative liabilities	$	—	$	—	$	—
Offsetting Derivatives as of December 31, 2015
Current portion of derivative assets	$	159,460	$	—	$	159,460
Long-term portion of derivative assets		198,262		—		198,262
Total derivative assets	$	357,722	$	—	$	357,722
Current portion of derivative liabilities	$	—	$	—	$	—
Long-term portion of derivative liabilities		—		—		—
Total derivative liabilities	$	—	$	—	$	—

Commodity Derivative Instruments by Type Table

At June 30, 2016, ARP had the following commodity derivatives:

Type	Production Period Ending December 31,	Volumes(1)	Average Fixed Price(1)		Fair Value Asset		Total Type
					(in thousands)(2)		(in thousands)(2)
Natural Gas – Fixed Price Swaps	2016(3)	26,910,000	$	4.224	$	32,326
	2017	50,120,000	$	4.221	$	51,933
	2018	40,300,000	$	4.168	$	45,498
	2019	15,860,000	$	4.019	$	15,945
							$	145,702
Natural Gas – Put Options – Drilling Partnerships	2016(3)	720,000	$	4.150	$	814
							$	814
Crude Oil – Fixed Price Swaps	2016(3)	820,500	$	81.685	$	26,449
	2017	1,200,000	$	77.610	$	30,412
	2018	1,080,000	$	76.281	$	24,184
	2019	540,000	$	68.371	$	7,324
							$	88,369
					Total net ARP assets		$	234,885

(1) Volumes for natural gas are stated in million British Thermal Units. Volumes for crude oil are stated in barrels.

(2) Fair value for natural gas fixed price swaps and natural gas put options based on forward NYMEX natural gas prices, as applicable. Fair value for crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable.

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

Secured Hedge Facility

At June 30, 2016, ARP had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under ARP’s revolving credit facility, ARP is required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. ARP, as general partner of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility and guarantees their obligations under it. Before executing any hedge transaction, a participating Drilling Partnership is required to, among other things, provide mortgages on its oil and gas properties and first priority security interests in substantially all of its assets to the collateral agent for the benefit of the counterparties. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, 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.

An event of default occurred under the secured hedging facility agreement upon ARP’s filing of voluntary petitions for relief under Chapter 11.  The lenders under the secured hedge facility agreed to forbear from exercising remedies in respect of such event of default while the Chapter 11 Filings are pending and, upon occurrence of the effective date of the Plan contemplated by ARP’s Restructuring Support Agreement, such event of default will no longer be deemed to exist or to continue under the secured hedge facility.

In addition, it will be an event of default under ARP’s revolving credit facility if ARP, as general partner of the Drilling Partnerships, breaches an obligation governed by the secured hedge facility and the effect of such breach is to cause amounts owing under swap agreements governed by the secured hedge facility to become immediately due and payable.

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Fair Value of Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Company, ARP Financial Instruments Measured at Fair Value

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

	Level 1		Level 2			Level 3		Total
As of June 30, 2016
Assets, gross
Rabbi trust	$	4,072	$	—		$	—	$	4,072
ARP Commodity swaps		—		234,071			—		234,071
ARP Commodity puts		—		814			—		814
AGP Commodity swaps		—		238			—		238
Total assets, gross		4,072		235,123			—		239,195
Liabilities, gross
AGP Commodity swaps		—		(538	)		—		(538	)
Total derivative liabilities, gross		—		(538	)		—		(538	)
Total assets, fair value, net	$	4,072	$	234,585		$	—	$	238,657
As of December 31, 2015
Assets, gross
Rabbi trust	$	5,584	$	—		$	—	$	5,584
ARP Commodity swaps		—		355,329			—		355,329
ARP Commodity puts		—		2,393			—		2,393
AGP Commodity swaps		—		561			—		561
Total assets, gross		5,584		358,283			—		363,867
Liabilities, gross
AGP Commodity swaps		—		(149	)		—		(149	)
Total derivative liabilities, gross	$	—	$	(149	)	$	—	$	(149	)
Total assets, fair value, net	$	5,584	$	358,134		$	—	$	363,718

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Operating Segment Information (Tables)

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

Operating Segment Data

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 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):

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Atlas Resource Partners:
Revenues(1)	$	(16,824	)	$	96,125		$	86,384		$	339,714
Operating costs and expenses	(57,125		)		(75,822	)	(116,327		)		(163,640	)
Depreciation, depletion and amortization expense	(29,008		)		(42,494	)	(59,053		)		(85,485	)
Gain (loss) on asset sales and disposal	(502		)		97		(493		)		86
Interest expense	(31,954		)		(24,716	)	(59,659		)		(49,913	)
Gain on early extinguishment of debt	—				—		26,498				—
Other income (loss)		(6,156	)		—			(6,156	)		—
Segment income (loss)	$	(141,569	)	$	(46,810	)	$	(128,806	)	$	40,762
Atlas Growth Partners:
Revenues	$	2,559		$	1,865		$	5,993		$	4,176
Operating costs and expenses	(3,421		)		(3,243	)	(6,924		)		(8,312	)
Depreciation, depletion and amortization expense	(3,299		)		(782	)	(7,526		)		(2,247	)
Segment loss	$	(4,161	)	$	(2,160	)	$	(8,457	)	$	(6,383	)
Corporate and other:
Revenues	$	461		$	257		$	672		$	156
General and administrative	(1,531		)		(2,359	)	(3,685		)		(22,574	)
Interest expense	(3,890		)		(8,471	)	(5,633		)		(18,025	)
Loss on early extinguishment of debt	(27		)		—		(6,080		)		—
Segment loss	$	(4,987	)	$	(10,573	)	$	(14,726	)	$	(40,443	)
Reconciliation of segment loss to net loss:
Segment income (loss):
Atlas Resource Partners	$	(141,569	)	$	(46,810	)	$	(128,806	)	$	40,762
Atlas Growth Partners	(4,161		)		(2,160	)	(8,457		)		(6,383	)
Corporate and other		(4,987	)		(10,573	)		(14,726	)		(40,443	)
Net loss	$	(150,717	)	$	(59,543	)	$	(151,989	)	$	(6,064	)
Reconciliation of segment revenues to total revenues:
Segment revenues:
Atlas Resource Partners(1)	$	(16,824	)	$	96,125		$	86,384		$	339,714
Atlas Growth Partners	2,559				1,865		5,993				4,176
Corporate and other	461				257		672				156
Total revenues(1)	$	(13,804	)	$	98,247		$	93,049		$	344,046
Capital expenditures:
Atlas Resource Partners	$	5,650		$	26,993		$	18,820		$	69,491
Atlas Growth Partners	778				3,175		6,327				13,118
Corporate and other	—				—		—				—
Total capital expenditures	$	6,428		$	30,168		$	25,147		$	82,609

	June 30,		December 31,
	2016		2015
Balance sheet:
Goodwill:
Atlas Resource Partners	$	13,639	$	13,639
Atlas Growth Partners	—			—
Corporate and other	—			—
Total goodwill	$	13,639	$	13,639
Total assets:
Atlas Resource Partners	$	1,540,386	$	1,699,949
Atlas Growth Partners	135,721			159,622
Corporate and other	21,193			23,675
Total assets	$	1,697,300	$	1,883,246

1) Revenues include gains (losses) on mark to market derivatives. A $73.3 million loss on ARP’s mark-to-market derivatives is included for the three months ended June 30, 2016 related to increases in commodity future prices relative to ARP’s commodity fixed price swaps during the three months ended June 30, 2016 as compared to the prior year period.

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Basis of Presentation (Narrative) (Details) - USD ($)			3 Months Ended		6 Months Ended
	Jun. 30, 2015	Feb. 27, 2015	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Basis Of Presentation [Line Items]
Percentage of interest represented by common units which is effected by pro rata distribution		100.00%
Distributions received from unconsolidated companies					$ 863,000	$ 838,000
Limited partners units issued			26,037,992		26,037,992
Limited partners units outstanding			26,037,992		26,037,992
Lightfoot Capital Partners, LP
Basis Of Presentation [Line Items]
General partner ownership interest					15.40%
Common limited partner ownership interest					12.00%
Distributions received from unconsolidated companies			$ 400,000	$ 400,000	$ 800,000	$ 800,000
Preferred Limited Partner Units
Basis Of Presentation [Line Items]
Common limited partner interest in ARP, units					3,749,986
Atlas Resource Partners, L.P.
Basis Of Presentation [Line Items]
General partner ownership interest					100.00%
Common limited partner ownership interest					23.30%
Common limited partner interest in ARP, units					20,962,485
Atlas Growth Partners, L.P
Basis Of Presentation [Line Items]
General partner ownership interest					80.00%
Common limited partner ownership interest					2.10%
Common limited partner units issued	$ 233,000,000
Common limited partner units purchased	$ 5,000,000
Minimum offering proceeds to break escrow					$ 1,000,000
Maximum offering proceeds of primary offering					$ 1,000,000,000
Atlas Growth Partners, L.P | Class A Common Units
Basis Of Presentation [Line Items]
Partners unit issue price per share			$ 10.00		$ 10.00
Partners unit issued, under distribution reinvestment plan					21,505,376
Partners unit issue price per share under distribution reinvestment plan			9.30		$ 9.30
Atlas Growth Partners, L.P | Class T Common Units
Basis Of Presentation [Line Items]
Common units aggregate offering					100,000,000
Partners unit issue price per share			9.60		$ 9.60
Deferred payment obligation price per share			$ 0.40		$ 0.40
Atlas Growth Partners, L.P | Maximum | Class A Common Units
Basis Of Presentation [Line Items]
Common units aggregate offering					100,000,000

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Summary of Significant Accounting Policies (Narrative) (Details) - USD ($)			1 Months Ended	3 Months Ended		6 Months Ended
	Jul. 25, 2016	Jun. 05, 2015	May 31, 2015	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Jul. 27, 2016	Jun. 08, 2016	Dec. 31, 2015	Jul. 31, 2013
Summary Of Significant Accounting Policies [Line Items]
Repayments under credit facilities						$ 57,500,000	$ 377,000,000
Pro-rata share in Drilling Partnerships						30.00%
Partners unit, issued				0	2,403,288	245,175	2,885,824
Rabbi Trust other assets				$ 37,261,000		$ 37,261,000				$ 54,112,000
Rabbi trust other liabilities recorded				140,104,000		140,104,000				124,919,000
Rabbi trust
Summary Of Significant Accounting Policies [Line Items]
Rabbi Trust other assets				4,100,000		4,100,000				5,600,000
Rabbi trust other liabilities recorded				4,100,000		4,100,000				$ 5,600,000
Partnership distributed to participants						2,300,000	$ 0
Subsequent Event
Summary Of Significant Accounting Policies [Line Items]
Credit facility	$ 900,000,000
Aggregate principal amount outstanding	80.00%
Reduction of borrowing base eliminated	$ 80,000,000
First Lien Lenders | Subsequent Event
Summary Of Significant Accounting Policies [Line Items]
Percentage of line of credit facility	100.00%
Arkoma Acquisition
Summary Of Significant Accounting Policies [Line Items]
Partners unit, issued			6,500,000
Atlas Resource Partners, L.P.
Summary Of Significant Accounting Policies [Line Items]
Credit facility				$ 250,000,000		250,000,000			$ 700,000,000
Atlas Resource Partners, L.P. | Arkoma Acquisition
Summary Of Significant Accounting Policies [Line Items]
Business acquisition, cost of acquired entity, cash paid		$ 31,500,000
Partners unit, issued		6,500,000
Business acquisition, effective date of acquisition		Jan. 01, 2015
Secured Term Facility
Summary Of Significant Accounting Policies [Line Items]
Repayments under credit facilities						150,000,000
Credit facility											$ 240,000,000
Secured Term Facility | Series A Preferred Units
Summary Of Significant Accounting Policies [Line Items]
Proceeds from Issuance of Convertible Preferred Stock						$ 150,000,000
Second Lien Term Loan | Subsequent Event
Summary Of Significant Accounting Policies [Line Items]
Credit facility								$ 250,000,000
Percentage of line of credit facility	100.00%
7.75% Senior Notes | Subsequent Event
Summary Of Significant Accounting Policies [Line Items]
Debt instrument interest rate stated percentage	7.75%
7.75% Senior Notes | Atlas Resource Partners, L.P.
Summary Of Significant Accounting Policies [Line Items]
Debt instrument interest rate stated percentage				7.75%		7.75%				7.75%
9.25% Senior Notes
Summary Of Significant Accounting Policies [Line Items]
Debt instrument interest rate stated percentage				9.25%		9.25%
9.25% Senior Notes | Subsequent Event
Summary Of Significant Accounting Policies [Line Items]
Debt instrument interest rate stated percentage	9.25%
9.25% Senior Notes | Atlas Resource Partners, L.P.
Summary Of Significant Accounting Policies [Line Items]
Debt instrument interest rate stated percentage				9.25%		9.25%				9.25%

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Summary of Significant Accounting Policies (Schedule of Net Income (Loss) Reconciliation) (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Reconciliation Of Net Income [Line Items]
Net loss		$ (150,717)	$ (59,543)	$ (151,989)	$ (6,064)
Preferred unitholders’ dividends			(1,004)	(339)	(1,337)
(Income) loss attributable to non-controlling interests		114,637	38,740	109,297	(19,558)
Loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015)					10,475
Net loss attributable to common unitholders		(36,080)	(21,807)	(43,031)	(16,484)
Net loss utilized in the calculation of net loss attributable to common unitholders per unit – diluted	[1]	$ (36,080)	$ (21,807)	$ (43,031)	$ (16,484)
Antidilutive Phantom Unit Securities Excluded from Computation of Diluted Earnings Attributable to Common Unit Holders Outstanding Units		352,000	69,000	307,000	67,000
Continuing Operations
Reconciliation Of Net Income [Line Items]
Preferred unitholders’ dividends			$ (1,004)	$ (339)	$ (1,337)

[1] Net income (loss) attributable to common unitholders for the net income (loss) attributable to common unitholders per unit calculation is net income (loss) attributable to common unitholders, less income allocable to participating securities. For the three months ended June 30, 2016, and 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 352,000 and 69,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the six months ended June 30, 2016 and 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 307,000 and 67,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity

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Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number of Common Unit Holder Units) (Details) - shares	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Accounting Policies [Abstract]
Weighted average number of common unitholders per unit—basic	26,031,000	26,011,000	26,029,000	26,011,000
Weighted average number of common unitholders per unit—diluted	26,031,000	26,011,000	26,029,000	26,011,000
Antidilutive Securities Excluded From Computation Of Diluted Net Income (Loss) Attributable To Common Limited Partners Outstanding Units	2,692,000	750,000	2,691,000	567,000

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Restructuring Support Agreement Narrative (Details) - USD ($)		6 Months Ended
	Jul. 27, 2016	Jun. 30, 2016	Jul. 25, 2016
Subsequent Event
Restructuring Cost And Reserve [Line Items]
Credit facility			$ 900,000,000
Subsequent Event | ARP Mgt LLC
Restructuring Cost And Reserve [Line Items]
Percentage of preferred share	2.00%
Subsequent Event | First Lien Lenders
Restructuring Cost And Reserve [Line Items]
Credit facility	$ 440,000,000
Subsequent Event | Second Lien Term Loan
Restructuring Cost And Reserve [Line Items]
Credit facility	$ 250,000,000
Percentage of interest expense paid in cash	2.00%
Percentage of common equity interest	10.00%
Subsequent Event | New Holdco
Restructuring Cost And Reserve [Line Items]
Percentage of common equity interest	90.00%
Senior Notes	$ 668,000,000
Percentage of notes outstanding	100.00%
Percentage of common stock voting rights	67.00%
Adjusted LIBO Rate | Subsequent Event | Second Lien Term Loan
Restructuring Cost And Reserve [Line Items]
Variable interest rate	9.00%
Revolving Credit Facility Conforming Tranche | First Lien Lenders
Restructuring Cost And Reserve [Line Items]
Line of Credit Facility, Expiration Date		May 01, 2017
Revolving Credit Facility Conforming Tranche | Subsequent Event | First Lien Lenders
Restructuring Cost And Reserve [Line Items]
Credit facility	$ 410,000,000
Revolving Credit Facility Nonconforming Tranche | First Lien Lenders
Restructuring Cost And Reserve [Line Items]
Line of Credit Facility, Expiration Date		Aug. 23, 2019
Revolving Credit Facility Nonconforming Tranche | Subsequent Event | First Lien Lenders
Restructuring Cost And Reserve [Line Items]
Credit facility	$ 30,000,000

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Property, Plant and Equipment (Summary of Property, Plant and Equipment) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Property Plant And Equipment [Abstract]
Proved properties: Leasehold interests	$ 571,761	$ 569,377
Proved properties: Pre-development costs	7,125	6,529
Proved properties: Wells and related equipment	3,173,064	3,157,708
Total proved properties	3,751,950	3,733,614
Unproved properties	213,047	213,047
Support equipment	44,264	44,921
Total natural gas and oil properties	4,009,261	3,991,582
Pipelines, processing and compression facilities	61,139	59,733
Rights of way	829	829
Land, buildings and improvements	9,798	9,798
Other	18,422	18,405
Total gross property, plant and equipment	4,099,449	4,080,347
Less – accumulated depreciation, depletion and amortization	(2,825,996)	(2,763,450)
Property, plant and equipment, Net, Total	$ 1,273,453	$ 1,316,897

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Property, Plant and Equipment (Useful Life Narrative) (Details)	6 Months Ended
	Jun. 30, 2016
Pipelines, processing and compression facilities | Minimum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	15 years
Pipelines, processing and compression facilities | Maximum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	20 years
Rights of way | Minimum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	20 years
Rights of way | Maximum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	40 years
Land, buildings and improvements | Minimum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	3 years
Land, buildings and improvements | Maximum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	40 years
Other | Minimum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	3 years
Other | Maximum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	10 years

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Property, Plant and Equipment (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Property Plant And Equipment [Line Items]
Non-cash property, plant and equipment additions			$ 18.7	$ 29.0
Atlas Resource Partners, L.P.
Property Plant And Equipment [Line Items]
Weighted average interest rate used to capitalize interest	6.60%	6.60%	6.70%	6.40%
Interest costs capitalized	$ 2.4	$ 4.1	$ 4.8	$ 8.0
Liabilities recorded in asset retirement obligations	9.9	0.2	12.9	0.5
Atlas Resource Partners, L.P. | Depreciation, depletion and amortization
Property Plant And Equipment [Line Items]
Accretion expense related to asset retirement obligations	$ 1.7	$ 1.6	$ 3.3	$ 3.2

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Debt (Schedule of Total Debt Outstanding) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Total debt, net	$ 1,625,639	$ 1,572,314
Less current maturities	(1,553,277)	(4,250)
Total long-term debt, net	$ 72,362	1,568,064
9.25% Senior Notes
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	9.25%
Atlas Energy
Debt Instrument [Line Items]
Deferred financing costs	$ (257)	(3,813)
Atlas Energy | Term loan facilities
Debt Instrument [Line Items]
Term loans	72,619	72,700
Atlas Resource Partners, L.P.
Debt Instrument [Line Items]
Deferred financing costs	(27,238)	(31,055)
Atlas Resource Partners, L.P. | First Lien Lenders
Debt Instrument [Line Items]
Deferred financing costs	(12,200)
First Lien Credit Facility	669,500	592,000
Atlas Resource Partners, L.P. | Second Lien Term Loan
Debt Instrument [Line Items]
Term loans	244,534	243,783
Atlas Resource Partners, L.P. | 7.75% Senior Notes
Debt Instrument [Line Items]
Term loans	354,400
Deferred financing costs	(9,500)
Senior Notes	$ 354,385	$ 374,619
Debt instrument, interest rate, stated percentage	7.75%	7.75%
Atlas Resource Partners, L.P. | 9.25% Senior Notes
Debt Instrument [Line Items]
Term loans	$ 312,100
Deferred financing costs	(8,300)
Senior Notes	$ 312,096	$ 324,080
Debt instrument, interest rate, stated percentage	9.25%	9.25%

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Debt (Schedule of Retrospective Effect of Debt Issuance Cost Reclassification) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Other assets, net	$ 37,261	$ 54,112
Long-term debt, net, less current portion	$ 72,362	1,568,064
Previously Filed
Debt Instrument [Line Items]
Other assets, net		88,980
Long-term debt, net, less current portion		1,602,932
Adjustment
Debt Instrument [Line Items]
Other assets, net		(34,868)
Long-term debt, net, less current portion		$ (34,868)

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Debt (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Debt Disclosure [Abstract]
Cash Payments For Interest On Debt	$ 16.4	$ 13.2	$ 59.1	$ 51.7

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Debt (Term Loan Facilities) (Details)		6 Months Ended
	Mar. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Sep. 30, 2017	Apr. 27, 2016 USD ($) shares
Debt Instrument [Line Items]
Debt maturities, excluding future payment-in-kind interest payments, 2016		$ 1,580,500,000
Debt maturities, excluding future payment-in-kind interest payments, 2017		35,000,000
Debt maturities, excluding future payment-in-kind interest payments, 2019		$ 35,800,000
Company's Current and Former Officers
Debt Instrument [Line Items]
Percentage of lenders participated in loan syndication		12.00%
Minimum | Unitholders
Debt Instrument [Line Items]
Percentage of lenders participated in loan syndication		5.00%
Term loan facilities
Debt Instrument [Line Items]
Deemed prepayment premium	$ 2,400,000
Term loan facilities | Maximum
Debt Instrument [Line Items]
Market Capitalization	75,000,000
Term loan facilities | Third Amendment
Debt Instrument [Line Items]
Prepayment of outstanding principal	4,250,000
Prepayment of interest	500,000
First Lien Credit Agreement | Term loan facilities
Debt Instrument [Line Items]
Term loans	$ 35,000,000
First Lien Credit Agreement | Term loan facilities | Third Amendment
Debt Instrument [Line Items]
Line of Credit Facility, Expiration Date	Sep. 30, 2017
Line of credit facility extended expiration date	Sep. 30, 2018
Restricted cash balance	$ 4,000,000
Minimum reserve balance in EBITDA on trailing twelve-months basis	$ 2,000,000
Line of credit facility covenant terms		Replace the existing financial covenants with (i) the requirement that we maintain a minimum of $2 million in EBITDA on a trailing twelve-month basis, beginning with the quarter ending June 30, 2016, and (ii) the incorporation into the First Lien Credit Agreement of the financial covenants included in ARP’s credit agreement, beginning with the quarter ending June 30, 2016.
First Lien Credit Agreement | Term loan facilities | Third Amendment | Alternative Base Rate
Debt Instrument [Line Items]
Cash interest rate margin	0.50%
Pay-in-kind interest payment percentage	11.00%
First Lien Credit Agreement | Term loan facilities | Third Amendment | Eurodollar Loans
Debt Instrument [Line Items]
Cash interest rate margin	1.50%
First Lien Credit Agreement | Term loan facilities | Third Amendment | Maximum
Debt Instrument [Line Items]
Leverage ratio	6
Extension fee percentage	5.00%
Second lien term loan facility
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount		$ 1,900,000		$ 1,900,000
Warrants issued | shares				4,668,044
Second lien term loan facility | Maximum
Debt Instrument [Line Items]
Warrants issued | shares				4,668,044
Second lien term loan facility | Minimum | Scenario Forecast
Debt Instrument [Line Items]
Asset coverage ratio			2
Second lien term loan facility | Term loan facilities
Debt Instrument [Line Items]
Term loans	$ 35,800,000
Line of Credit Facility, Expiration Date	Mar. 30, 2019
Line of credit facility extended expiration date	Mar. 30, 2020
Line of Credit Facility interest rate description		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.
Borrowings bearing interest rate	30.00%
Borrowings interest rate if First Lien Credit Agreement is fully repaid prior to March 30, 2018	20.00%
Borrowings interest rate if extension option is exercised	30.00%
Second lien term loan facility | Term loan facilities | Maximum
Debt Instrument [Line Items]
Leverage ratio	6
Extension fee percentage	5.00%

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Debt (ARP First Lien Credit Facility) (Details) - USD ($)		6 Months Ended
	Jul. 27, 2016	Jun. 30, 2016	Jun. 30, 2015	Jul. 25, 2016	Jul. 11, 2016	Jun. 08, 2016	Dec. 31, 2015
Line Of Credit Facility [Line Items]
Repayments under credit facilities		$ 57,500,000	$ 377,000,000
Subsequent Event
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity				$ 900,000,000
7.75% Senior Notes | Subsequent Event
Line Of Credit Facility [Line Items]
Debt instrument interest rate stated percentage				7.75%
9.25% Senior Notes
Line Of Credit Facility [Line Items]
Debt instrument interest rate stated percentage		9.25%
Aggregate principal amount		$ 312,100,000
9.25% Senior Notes | Subsequent Event
Line Of Credit Facility [Line Items]
Debt instrument interest rate stated percentage				9.25%
First Lien Lenders
Line Of Credit Facility [Line Items]
Required current assets to current liabilities ratio		1.00%
First Lien Lenders | Subsequent Event
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity	$ 440,000,000
Repayments under credit facilities	233,500,000
Atlas Resource Partners, L.P.
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity		$ 250,000,000				$ 700,000,000
Line of Credit Facility, Expiration Date		Feb. 23, 2020
Deferred financing costs		$ 27,238,000					$ 31,055,000
Atlas Resource Partners, L.P. | 7.75% Senior Notes
Line Of Credit Facility [Line Items]
Debt instrument interest rate stated percentage		7.75%					7.75%
Aggregate principal amount		$ 354,400,000
Deferred financing costs		$ 9,500,000
Atlas Resource Partners, L.P. | 9.25% Senior Notes
Line Of Credit Facility [Line Items]
Debt instrument interest rate stated percentage		9.25%					9.25%
Deferred financing costs		$ 8,300,000
Atlas Resource Partners, L.P. | First Lien Lenders
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity		$ 1,500,000,000				$ 530,000,000
Line of Credit Facility, Expiration Date		Jul. 01, 2018
First Lien Credit Facility		$ 669,500,000					$ 592,000,000
Letters of credit outstanding amount		4,200,000
Line of credit facility borrowing capacity deficiency		$ 143,700,000
Repayment of barrowing base beginning date		Jul. 11, 2016
Letters of credit outstanding maximum		$ 20,000,000
Line of Credit Facility collateral		ARP’s obligations under the ARP First Lien Credit Facility are secured by mortgages on ARP’s oil and gas properties and first priority security interests in substantially all of ARP’s assets. Additionally, obligations under the ARP First Lien Credit Facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor.
Line of Credit Facility interest rate description		At June 30, 2016, the weighted average interest rate on outstanding borrowings under the ARP First Lien Credit Facility was 4.0%.
Line of Credit Facility, weighted average interest rate		4.00%
Aggregate principal amount		$ 300,000,000
Line of credit facility covenant terms		The ARP First Lien Credit Facility 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 First Lien Credit Facility also requires that ARP maintain a ratio of First Lien Debt to EBITDA (ratio as defined in the ARP First Lien Credit Facility) of not greater than 2.75 to 1.00, and a ratio of current assets to current liabilities (ratio as defined in the ARP First Lien Credit Facility) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. ARP was not in compliance with these covenants as of June 30, 2016.
Deferred financing costs		$ 12,200,000
Atlas Resource Partners, L.P. | First Lien Lenders | Subsequent Event
Line Of Credit Facility [Line Items]
Repayments under credit facilities	233,500,000
Line of Credit Facility, Remaining Borrowing Capacity	$ 440,000,000
Atlas Resource Partners, L.P. | First Lien Lenders | Subsequent Event | Forbearance Agreements
Line Of Credit Facility [Line Items]
Percentage of outstanding indebtedness under facility lenders agreed to forbear from exercising rights					81.00%
Atlas Resource Partners, L.P. | First Lien Lenders | 7.75% Senior Notes | Subsequent Event | Forbearance Agreements
Line Of Credit Facility [Line Items]
Debt instrument interest rate stated percentage					7.75%
Percentage of outstanding principal senior notes, holders agreed to forbear from exercising rights					78.00%
Atlas Resource Partners, L.P. | First Lien Lenders | 9.25% Senior Notes | Subsequent Event | Forbearance Agreements
Line Of Credit Facility [Line Items]
Debt instrument interest rate stated percentage					9.25%
Percentage of outstanding principal senior notes, holders agreed to forbear from exercising rights					82.00%

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Debt (ARP Second Lien Term Loan) (Details) - Atlas Resource Partners, L.P. - USD ($)	6 Months Ended
	Jun. 30, 2016	Jun. 08, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Line of Credit Facility, aggregate principal amount	$ 250,000,000	$ 700,000,000
Line of Credit Facility, Expiration Date	Feb. 23, 2020
Debt Instrument, Unamortized Discount	$ 5,500,000
Deferred financing costs	$ 27,238,000		$ 31,055,000
Second Lien Term Loan
Debt Instrument [Line Items]
Line of Credit Facility, weighted average interest rate	10.00%
Term loans	$ 244,534,000		$ 243,783,000
Second Lien Term Loan | Current Portion Of Long Term Debt
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount	5,500,000
Term loans	244,500,000
Deferred financing costs	$ 9,400,000

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Debt (ARP Senior Notes) (Details) - USD ($)		3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Jul. 27, 2016	Jul. 25, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Cash Payments For Interest On Debt		$ 16,400,000	$ 13,200,000	$ 59,100,000	$ 51,700,000
Gain on early extinguishment of debt		(27,000)		$ 20,418,000	$ 0
Debt instrument, restrictive covenants				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.
Debt instrument, covenant compliance				ARP was in compliance with these covenants as of June 30, 2016.
New Holdco | Subsequent Event
Debt Instrument [Line Items]
Percentage of common equity interest						90.00%
7.75% Senior Notes
Debt Instrument [Line Items]
Restrictions as to the ability to obtain cash or any other distribution of funds from the guarantor				$ 0
7.75% Senior Notes | Subsequent Event
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage							7.75%
9.25% Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount	$ 312,100,000	$ 312,100,000		$ 312,100,000
Senior Notes, maturity				2021
Debt instrument interest rate stated percentage	9.25%	9.25%		9.25%
Term Loan Facilities, unamortized discount	$ 800,000	$ 800,000		$ 800,000
9.25% Senior Notes | Subsequent Event
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage							9.25%
Atlas Resource Partners, L.P.
Debt Instrument [Line Items]
Term Loan Facilities, unamortized discount	5,500,000	5,500,000		5,500,000
Repayment of debt	5,500,000
Cash Payments For Interest On Debt	600,000
Gain on early extinguishment of debt	26,500,000
Amortization of financing costs				900,000
Deferred financing costs	27,238,000	27,238,000		27,238,000				$ 31,055,000
Atlas Resource Partners, L.P. | 7.75% Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount	$ 354,400,000	$ 354,400,000		$ 354,400,000
Senior Notes, maturity				2021
Debt instrument interest rate stated percentage	7.75%	7.75%		7.75%				7.75%
Term Loan Facilities, unamortized discount	$ 300,000	$ 300,000		$ 300,000
Senior unsecured notes, repurchased	20,300,000	20,300,000		20,300,000
Loans Payable	354,400,000	354,400,000		354,400,000
Deferred financing costs	$ 9,500,000	$ 9,500,000		$ 9,500,000
Atlas Resource Partners, L.P. | 9.25% Senior Notes
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	9.25%	9.25%		9.25%				9.25%
Term Loan Facilities, unamortized discount	$ 800,000	$ 800,000		$ 800,000
Senior unsecured notes, repurchased	12,100,000	12,100,000		12,100,000
Loans Payable	312,100,000	312,100,000		312,100,000
Deferred financing costs	$ 8,300,000	$ 8,300,000		$ 8,300,000

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Derivative Instruments (Narrative) (Details) - USD ($)		3 Months Ended	6 Months Ended
	Jul. 27, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Derivative Instruments Gain Loss [Line Items]
Net derivative assets			$ 234,600,000		$ 358,100,000
Net gain in accumulated other comprehensive income			2,300,000
Cash flow hedge gain (losses) to be reclassified within twelve months			1,500,000
Cash flow hedge gain (loss) to be reclassified in later periods			800,000
Repayments under credit facilities			$ 57,500,000	$ 377,000,000
Atlas Resource Partners, L.P. | Crude Oil and Natural Gas
Derivative Instruments Gain Loss [Line Items]
Proceeds from early termination of commodity derivatives		$ 4,900,000		$ 4,900,000
First Lien Lenders | Subsequent Event
Derivative Instruments Gain Loss [Line Items]
Repayments under credit facilities	$ 233,500,000
First Lien Lenders | Subsequent Event | Atlas Resource Partners, L.P.
Derivative Instruments Gain Loss [Line Items]
Repayments under credit facilities	$ 233,500,000

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Derivative Instruments (Summary of Commodity Derivative Activity and Presentation in Partnership's Consolidated Statement of Operations) (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets	[1]	$ 5,555	$ 25,778	$ 9,070	$ 53,121
Portion of settlements attributable to subsequent mark to market gains (losses)		39,835	14,922	85,265	30,125
Total cash settlements on commodity derivative contracts		45,390	40,700	94,335	83,246
Gains recognized on cash settlement	[2]	4,732	3,678	10,666	6,881
Gains (losses) recognized on open derivative contracts	[2]	(78,822)	(30,574)	(38,303)	71,808
Gains (losses) on mark-to-market derivatives		$ (74,090)	$ (26,896)	$ (27,637)	$ 78,689

[1] Recognized in gas and oil production revenue.

[2] Recognized in gain on mark-to-market derivatives.

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Derivative Instruments (Fair Values of the Company's Derivative Instruments Table) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	$ 239,195	$ 363,867
Net Amount Presented, Assets	234,600	358,100
Gross Amounts Recognized, Liabilities	(538)	(149)
Atlas Growth Partners, L.P | Derivative Financial Instruments Current Liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities	(320)	(96)
Gross Amounts Offset, Liabilities	183	96
Net Amount Presented, Liabilities	(137)
Atlas Growth Partners, L.P | Derivative Financial Instruments Long Term Liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities	(218)	(53)
Gross Amounts Offset, Liabilities	55	53
Net Amount Presented, Liabilities	(163)
Atlas Growth Partners, L.P | Derivative Financial Instruments Liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities	(538)	(149)
Gross Amounts Offset, Liabilities	238	149
Net Amount Presented, Liabilities	(300)
Atlas Growth Partners, L.P | Current portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	183	399
Gross Amounts Offset, Assets	(183)	(96)
Net Amount Presented, Assets		303
Atlas Growth Partners, L.P | Long-term portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	55	162
Gross Amounts Offset, Assets	(55)	(53)
Net Amount Presented, Assets		109
Atlas Growth Partners, L.P | Total derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	238	561
Gross Amounts Offset, Assets	$ (238)	(149)
Net Amount Presented, Assets		$ 412

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Derivative Instruments (The Company's Commodity Derivative Instruments by Type Table) (Details) - Atlas Growth Partners, L.P - Natural Gas Liquids – Crude Oil Fixed Price Swaps $ in Thousands	Jun. 30, 2016 USD ($) bbl $ / bbl
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	$ (300)	[1]
Production Period Ending December 31 2016
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	31,600	[2],[3]
Derivative, Swap Type, Average Fixed Price | $ / bbl	46.350	[2],[3]
Fair Value Asset / (Liability)	$ (95)	[1],[2]
Production Period Ending December 31 2017
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	37,100	[3]
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.968	[3]
Fair Value Asset / (Liability)	$ (79)	[1]
Production Period Ending December 31 2018
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	26,500	[3]
Derivative, Swap Type, Average Fixed Price | $ / bbl	48.850	[3]
Fair Value Asset / (Liability)	$ (126)	[1]

[1] Fair value of crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable.

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

[3] Volumes for crude oil are stated in barrels.

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Derivative Instruments (Fair Value of ARP's Derivative Instruments Table) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	$ 239,195	$ 363,867
Net Amount Presented, Assets	234,600	358,100
Gross Amounts Recognized, Liabilities	538	149
Atlas Resource Partners, L.P. | Current portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	99,654	159,460
Net Amount Presented, Assets	99,654	159,460
Atlas Resource Partners, L.P. | Long-term portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	135,231	198,262
Net Amount Presented, Assets	135,231	198,262
Atlas Resource Partners, L.P. | Total derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	234,885	357,722
Net Amount Presented, Assets	$ 234,885	$ 357,722

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Derivative Instruments (ARP's Commodity Derivative Instruments by Type Table) (Details) - Atlas Resource Partners, L.P. $ in Thousands	Jun. 30, 2016 USD ($) bbl MMBTU $ / bbl $ / MMBTU
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	$ 234,885	[1]
Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	145,702	[1]
Natural Gas Put Options Drilling Partnership
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	814	[1]
Natural Gas Liquids – Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	$ 88,369	[1]
Production Period Ending December 31 2016 | Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	26,910,000	[2],[3]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	4.224	[2],[3]
Fair Value Asset / (Liability)	$ 32,326	[1],[2]
Production Period Ending December 31 2016 | Natural Gas Put Options Drilling Partnership
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	720,000	[2],[3]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	4.150	[2],[3]
Fair Value Asset / (Liability)	$ 814	[1],[2]
Production Period Ending December 31 2016 | Natural Gas Liquids – Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	820,500	[2],[3]
Derivative, Swap Type, Average Fixed Price | $ / bbl	81.685	[2],[3]
Fair Value Asset / (Liability)	$ 26,449	[1],[2]
Production Period Ending December 31 2017 | Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	50,120,000	[3]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	4.221	[3]
Fair Value Asset / (Liability)	$ 51,933	[1]
Production Period Ending December 31 2017 | Natural Gas Liquids – Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	1,200,000	[3]
Derivative, Swap Type, Average Fixed Price | $ / bbl	77.610	[3]
Fair Value Asset / (Liability)	$ 30,412	[1]
Production Period Ending December 31 2018 | Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	40,300,000	[3]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	4.168	[3]
Fair Value Asset / (Liability)	$ 45,498	[1]
Production Period Ending December 31 2018 | Natural Gas Liquids – Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	1,080,000	[3]
Derivative, Swap Type, Average Fixed Price | $ / bbl	76.281	[3]
Fair Value Asset / (Liability)	$ 24,184	[1]
Production Period Ending December 31 2019 | Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	15,860,000	[3]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	4.019	[3]
Fair Value Asset / (Liability)	$ 15,945	[1]
Production Period Ending December 31 2019 | Natural Gas Liquids – Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	540,000	[3]
Derivative, Swap Type, Average Fixed Price | $ / bbl	68.371	[3]
Fair Value Asset / (Liability)	$ 7,324	[1]

[1] Fair value for natural gas fixed price swaps and natural gas put options based on forward NYMEX natural gas prices, as applicable. Fair value for crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable.

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

[3] Volumes for natural gas are stated in million British Thermal Units. Volumes for crude oil are stated in barrels.

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Fair Value of Financial Instruments (Schedule of Financial Instruments at Fair Value) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	$ 239,195	$ 363,867
Liabilities, gross	(538)	(149)
Total assets, fair value, net	238,657	363,718
Rabbi trust
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Rabbi trust	4,072	5,584
Atlas Resource Partners, L.P. | Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	814	2,393
Atlas Resource Partners, L.P. | Swap | Commodity Contract
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	234,071	355,329
Atlas Growth Partners, L.P | Swap | Commodity Contract
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	238	561
Liabilities, gross	(538)	(149)
Level 1
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	4,072	5,584
Total assets, fair value, net	4,072	5,584
Level 1 | Rabbi trust
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Rabbi trust	4,072	5,584
Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	235,123	358,283
Liabilities, gross	(538)	(149)
Total assets, fair value, net	234,585	358,134
Level 2 | Atlas Resource Partners, L.P. | Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	814	2,393
Level 2 | Atlas Resource Partners, L.P. | Swap | Commodity Contract
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	234,071	355,329
Level 2 | Atlas Growth Partners, L.P | Swap | Commodity Contract
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	238	561
Liabilities, gross	$ (538)	$ (149)

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Fair Value of Financial Instruments (Narrative) (Details) - Level 3 - USD ($) $ / shares in Units, $ in Millions	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Long-term debt, fair value	$ 1,020.7	$ 929.2
Long-term debt	$ 1,661.6	$ 1,614.7
Warrants fair value unit price on the date of issuance	$ 0.50
Warrants fair value assumptions, exercise price	$ 0.20
Warrants fair value assumptions, risk free rate	1.80%
Warrants fair value assumptions, expected term	10 years
Warrants fair value assumptions, estimated volatility rate	57.00%
Estimated fair value per warrant	$ 0.40

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Certain Relationships and Related Party Transactions (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Mar. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Accrued well drilling and completion costs	$ 2,182		$ 2,182			$ 33,555
Other income (loss)	(6,156)	$ 0	$ (6,156)	$ 0
Relationship With Drilling Partnerships
Related Party Transaction [Line Items]
Related party transaction, description of transaction			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.
Capital raised from investors					$ 36,700
Accrued well drilling and completion costs					$ 13,300
Funds transferred to partners	5,200		$ 5,200
Oil and gas properties transferred	7,200		7,200
Asset retirement obligations	12,400		12,400
Other income (loss)	(6,200)		(6,200)
Accounts Receivable, Related Parties, Current	8,900		8,900			6,600
Accounts Payable, Related Parties, Current	$ 1,500		$ 1,500			$ 3,000
Relationship with AGP
Related Party Transaction [Line Items]
Percentage of capital contribution	1.00%		1.00%
Payment for management fee	$ 600	$ 300	$ 1,100	$ 600
Gross proceeds of private placement offering percentage	2.00%		2.00%

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Commitments and Contingencies (General Commitments) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Percentage of present value of future cash flows			10.00%
Net partnership revenues subordinated	$ 0.5	$ 0.5	$ 0.6	$ 1.1
Commitment to expend			$ 4.6
Minimum
Partnership obligations to purchase units from investor partners			5.00%
Investor partners return on investment			10.00%
Maximum
Partnership obligations to purchase units from investor partners			10.00%
Percentage on unhedged revenue			50.00%
Investor partners return on investment			12.00%

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Issuances of Units (Common Unit Purchase Agreement) (Details) - USD ($) $ / shares in Units, $ in Thousands		6 Months Ended
	Apr. 27, 2016	Jun. 30, 2016
Capital Unit [Line Items]
Warrants		$ 1,868
Second lien term loan facility
Capital Unit [Line Items]
Warrant to purchase common units	4,668,044
Investment warrants exercise price	$ 0.20
Warrants, expiration date		Mar. 30, 2026
Debt Instrument, Unamortized Discount	$ 1,900	$ 1,900
Warrants		$ 1,900
Second lien term loan facility | Maximum
Capital Unit [Line Items]
Warrant to purchase common units	4,668,044

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Issuances of Units (Preferred Unit Purchase Agreement) (Details) - USD ($)					3 Months Ended	6 Months Ended
	May 12, 2016	Mar. 18, 2016	Jan. 07, 2016	Feb. 27, 2015	Jun. 30, 2016	Jun. 30, 2016
Capital Unit [Line Items]
Percentage Of Common Unit Regular Quarterly Cash Distributions				2.00%
Consecutive trading days		30 days	30 days
Delayed recognition of non-cash compensation expense					$ 0	$ 0
Board of Directors
Capital Unit [Line Items]
Granted (in units)	110,000
Board of Directors | Phantom Units
Capital Unit [Line Items]
Granted (in units)	911,900
Maximum
Capital Unit [Line Items]
Average closing price of common unit			$ 1.00
Average market capitalization			$ 50,000,000
Stockholders’ equity			$ 50,000,000
Minimum
Capital Unit [Line Items]
Average market capitalization		$ 15,000,000
Series A Convertible Preferred Units
Capital Unit [Line Items]
Partners' Capital Account, Units, Sold in Private Placement				1,600,000
Redemption price per unit					$ 25.00	$ 25.00
Subsidiary or Equity Method Investee, Price-Per-Share					$ 25.00	$ 25.00
Partners' Capital Account, Private Placement of Units						$ 40,000,000
Cash consideration						$ 150,000,000
Percentage of Preferred Unit Regular Quarterly Cash Distributions				2.00%
Conversion price policy description						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.
Volume weighted average price				110.00%
Series A Convertible Preferred Units | Maximum
Capital Unit [Line Items]
Conversion per unit				$ 16.00
Series A Convertible Preferred Units | Minimum
Capital Unit [Line Items]
Conversion per unit				$ 8.00
Series A Convertible Preferred Units | Private Placement | Maximum
Capital Unit [Line Items]
Percentage of Preferred Unit Regular Quarterly Cash Distributions				10.00%
Series A Convertible Preferred Units | First Anniversary | Private Placement | Maximum
Capital Unit [Line Items]
Percentage of Preferred Unit Regular Quarterly Cash Distributions				12.00%
Series A Convertible Preferred Units | Second Anniversary | Private Placement | Maximum
Capital Unit [Line Items]
Percentage of Preferred Unit Regular Quarterly Cash Distributions				14.00%
Series A Convertible Preferred Units | Third Anniversary | Private Placement | Maximum
Capital Unit [Line Items]
Percentage of Preferred Unit Regular Quarterly Cash Distributions				16.00%

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Issuances of Units (Atlas Resource Partners) (Details) - USD ($)						1 Months Ended			3 Months Ended		6 Months Ended
	Jul. 12, 2016	May 12, 2016	Mar. 18, 2016	Jan. 07, 2016	Mar. 31, 2015	Aug. 31, 2015	May 31, 2015	Apr. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Capital Unit [Line Items]
Partners unit, issued									0	2,403,288	245,175	2,885,824
Aggregate Offering Price Of Common Units (Maximum)											$ 100,000,000
Agent commission, maximum percentage, of the gross sales price of common limited partner units sold.											2.00%
Net proceeds from issuance of common limited partner units										$ 17,500,000	$ 200,000	$ 21,400,000
Payments for commissions and offering expenses										$ 500,000	4,000	$ 600,000
Impact on compensation expense									$ 0		0
Consecutive trading days			30 days	30 days
Subsequent Event
Capital Unit [Line Items]
Average closing price of common unit	$ 1.00
Consecutive trading days	30 days
Minimum
Capital Unit [Line Items]
Vesting date		May 15, 2016
Maximum
Capital Unit [Line Items]
Vesting date		Aug. 31, 2016
Average closing price of common unit				$ 1.00
General and Administrative Expense
Capital Unit [Line Items]
Impact on compensation expense									$ 0		$ 0
Board of Directors
Capital Unit [Line Items]
Granted (in units)		110,000
Arkoma Acquisition
Capital Unit [Line Items]
Partners unit, issued							6,500,000
Partners Capital Account Units Date Of Sale											May 2015
Subsidiary or Equity Method Investee, Price-Per-Share							$ 7.97
Partners Capital Account Sale Of Units							$ 49,700,000
Class E Preferred Units
Capital Unit [Line Items]
Partners unit, issued								255,000
Partners' Capital Account, Units, Percentage								10.75%
Partners Capital Account Units Date Of Sale											April 2015
Partners Capital Account Sale Of Units								$ 6,000,000
Public offer price per share								$ 25.00
Class D Preferred Units
Capital Unit [Line Items]
Partners unit, issued					800,000
Subsidiary or Equity Method Investee, Price-Per-Share					$ 25.00
Equity Distribution Agreement with MLV & Co. LLC | Class D Preferred Units
Capital Unit [Line Items]
Partners unit, issued									0	0	0	0
Partners' Capital Account, Units, Percentage						8.625%
Equity Distribution Agreement with MLV & Co. LLC | Class E Preferred Units
Capital Unit [Line Items]
Partners unit, issued									0	0	0	0
Partners' Capital Account, Units, Percentage						10.75%

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Issuances of Units (Atlas Growth Partners) (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Capital Unit [Line Items]
Partners unit, issued		0	2,403,288	245,175	2,885,824
Gain on sale of subsidiary unit issuances				$ 0.2	$ 2.9
Atlas Growth Partners, L.P
Capital Unit [Line Items]
Common limited partner units issued	$ 233.0
Percentage of warrants to purchase additional common units in amount equal to				10.00%
Warrants, exercise price				$ 10.00
Common limited partner units purchased	$ 5.0
Partners unit, issued				2,330,041
Private Placement | Atlas Growth Partners, L.P
Capital Unit [Line Items]
Common limited partner units issued				$ 500.0
Number of days extension private placement offering				two 90 day
Stock issued during period, shares				23,300,410
Fees and commission and expenses				$ 203.4
Common limited partner number of units purchased				500,010
Common limited partner units purchased				$ 5.0

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Cash Distributions - Additional Information (Details) - USD ($)	1 Months Ended						3 Months Ended	6 Months Ended
	Jun. 30, 2015	May 31, 2015	Apr. 30, 2015	Mar. 31, 2015	Feb. 28, 2015	Jan. 31, 2015	Jun. 30, 2016	Jun. 30, 2016	Jun. 30, 2015
Common Limited Partners
Distribution Made To Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid								$ 5,100,000	$ 71,200,000
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit	$ 0.1083	$ 0.1083	$ 0.1083	$ 0.1083	$ 0.1966	$ 0.1966		$ 0.0125
Class C Preferred Limited Partners
Distribution Made To Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid								$ 2,500,000	4,000,000
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit	0.17	0.17	0.17	0.17	0.1966	0.1966		$ 0.0125
Class A General Partner
Distribution Made To Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid								$ 200,000	3,600,000
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit	$ 0.1083	$ 0.1083	$ 0.1083	$ 0.1083	$ 0.1966	$ 0.1966		$ 0.0125
Class A Preferred Units
Distribution Made To Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid								$ 1,000,000	700,000
Atlas Energy
Distribution Made To Limited Partner [Line Items]
Distribution Policy, Members or Limited Partners, Description								We have a cash distribution policy under which we distributed, within 50 days following the end of each calendar quarter, all of our available cash (as defined in its limited liability company agreement) for that quarter to our unitholders.
Atlas Resource Partners, L.P.
Distribution Made To Limited Partner [Line Items]
Distribution Policy, Members or Limited Partners, Description								ARP has a monthly cash distribution program whereby ARP distributes all of its available cash (as defined in the partnership agreement) for that month to its unitholders within 45 days from the month end.
Atlas Resource Partners, L.P. | Class D Preferred Limited Partners | October 15, 2016 – April 14, 2016
Distribution Made To Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid								$ 4,400,000
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit								$ 0.5390625
Atlas Resource Partners, L.P. | Class D Preferred Limited Partners | October 02, 2014 – January 14, 2015
Distribution Made To Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid									$ 4,100,000
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit									$ 0.6169270
Atlas Resource Partners, L.P. | Class D Preferred Limited Partners | January 15, 2015 – April 14, 2015
Distribution Made To Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid									$ 4,100,000
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit									$ 0.539063
Atlas Resource Partners, L.P. | Class E Preferred Limited Partners
Distribution Made To Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid									$ 0
Atlas Resource Partners, L.P. | Class E Preferred Limited Partners | October 15, 2015 – April 14, 2016
Distribution Made To Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid								$ 300,000
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit								$ 0.671875
Atlas Resource Partners, L.P. | Preferred Class B
Distribution Made To Limited Partner [Line Items]
Preferred Unit Regular Monthly Cash Distributions Per Unit								$ 0.1333
Conversion of Class B preferred units (units)								39,654
Atlas Resource Partners, L.P. | Class C Preferred Units
Distribution Made To Limited Partner [Line Items]
Preferred Unit Regular Monthly Cash Distributions Per Unit								$ 0.17
Atlas Resource Partners, L.P. | Preferred class D
Distribution Made To Limited Partner [Line Items]
Preferred Unit Regular Quarterly Cash Distributions Per Unit								0.5390625
Preferred Unit Regular Cash Distributions Per Unit								$ 2.15625
Partners' Capital Account, Units, Percentage								8.625%
Preferred Stock Liquidation Preference							$ 25.00	$ 25.00
Preferred stock units accrued distributions							$ 1,900,000
Atlas Resource Partners, L.P. | Preferred class E
Distribution Made To Limited Partner [Line Items]
Preferred Unit Regular Quarterly Cash Distributions Per Unit								0.671875
Preferred Unit Regular Cash Distributions Per Unit								$ 2.6875
Partners' Capital Account, Units, Percentage								10.75%
Preferred Stock Liquidation Preference							$ 25.00	$ 25.00
Preferred stock units accrued distributions							$ 100,000
Atlas Resource Partners, L.P. | Minimum
Distribution Made To Limited Partner [Line Items]
Percentage Of Distributions In Excess Of Targets								13.00%
Atlas Resource Partners, L.P. | Minimum | Preferred Class B
Distribution Made To Limited Partner [Line Items]
Preferred Unit Regular Quarterly Cash Distributions Per Unit								$ 0.40
Atlas Resource Partners, L.P. | Minimum | Class C Preferred Units
Distribution Made To Limited Partner [Line Items]
Preferred Unit Regular Quarterly Cash Distributions Per Unit								$ 0.51
Atlas Resource Partners, L.P. | Maximum
Distribution Made To Limited Partner [Line Items]
Percentage Of Distributions In Excess Of Targets								48.00%
Atlas Growth Partners, L.P
Distribution Made To Limited Partner [Line Items]
Quarterly cash distribution target								$ 0.175
Yearly cash distribution target								$ 0.70
Atlas Growth Partners, L.P | Common Limited Partners
Distribution Made To Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid								$ 8,200,000	$ 3,800,000
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit								$ 0.1750	$ 0.1750
Atlas Growth Partners, L.P | Class A General Partner
Distribution Made To Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid								$ 200,000	$ 100,000
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit								$ 0.1750	$ 0.1750

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Operating Segment Information (Narrative) (Details)	6 Months Ended
	Jun. 30, 2016 Segment
Segment Reporting [Abstract]
Number of reportable operating segments	3

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Operating Segment Information (Operating Segment Data) (Details) - USD ($) $ in Thousands			3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Segment Reporting Information [Line Items]
Revenues	[1]		$ (13,804)	$ 98,247	$ 93,049	$ 344,046
Depreciation, depletion and amortization expense			(32,307)	(43,276)	(66,579)	(87,732)
Gain (loss) on asset sales and disposal			(502)	97	(493)	86
General and administrative			(27,995)	(18,405)	(49,915)	(60,333)
Interest expense			(35,844)	(33,187)	(65,292)	(67,938)
Gain (loss) on early extinguishment of debt			(27)		20,418	0
Other income (loss)			(6,156)	0	(6,156)	0
Gains (losses) on mark to market derivatives			(74,090)	(26,896)	(27,637)	78,689
Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Gain (loss) on early extinguishment of debt		$ 26,500
Gains (losses) on mark to market derivatives			73,300
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Revenues	[1]		(16,824)	96,125	86,384	339,714
Operating costs and expenses			(57,125)	(75,822)	(116,327)	(163,640)
Depreciation, depletion and amortization expense			(29,008)	(42,494)	(59,053)	(85,485)
Gain (loss) on asset sales and disposal			(502)	97	(493)	86
Interest expense			(31,954)	(24,716)	(59,659)	(49,913)
Gain (loss) on early extinguishment of debt					26,498
Other income (loss)			(6,156)		(6,156)
Segment income (loss)			(141,569)	(46,810)	(128,806)	40,762
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Revenues	[1]		2,559	1,865	5,993	4,176
Operating costs and expenses			(3,421)	(3,243)	(6,924)	(8,312)
Depreciation, depletion and amortization expense			(3,299)	(782)	(7,526)	(2,247)
Segment income (loss)			(4,161)	(2,160)	(8,457)	(6,383)
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Revenues			461	257	672	156
General and administrative			(1,531)	(2,359)	(3,685)	(22,574)
Interest expense			(3,890)	(8,471)	(5,633)	(18,025)
Gain (loss) on early extinguishment of debt			(27)		(6,080)
Segment income (loss)			$ (4,987)	$ (10,573)	$ (14,726)	$ (40,443)

[1] 1) Revenues include gains (losses) on mark to market derivatives. A $73.3 million loss on ARP’s mark-to-market derivatives is included for the three months ended June 30, 2016 related to increases in commodity future prices relative to ARP’s commodity fixed price swaps during the three months ended June 30, 2016 as compared to the prior year period.

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Operating Segment Information (Reconciliation of Segment Income (Loss) to Net Loss) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Segment Reporting Information [Line Items]
Net loss	$ (150,717)	$ (59,543)	$ (151,989)	$ (6,064)
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Net loss	(141,569)	(46,810)	(128,806)	40,762
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Net loss	(4,161)	(2,160)	(8,457)	(6,383)
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Net loss	$ (4,987)	$ (10,573)	$ (14,726)	$ (40,443)

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Operating Segment Information (Reconciliation of Segment Revenues to Total Revenues) (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Segment Reporting Information [Line Items]
Total revenues	[1]	$ (13,804)	$ 98,247	$ 93,049	$ 344,046
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Total revenues	[1]	(16,824)	96,125	86,384	339,714
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Total revenues	[1]	2,559	1,865	5,993	4,176
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Total revenues		$ 461	$ 257	$ 672	$ 156

[1] 1) Revenues include gains (losses) on mark to market derivatives. A $73.3 million loss on ARP’s mark-to-market derivatives is included for the three months ended June 30, 2016 related to increases in commodity future prices relative to ARP’s commodity fixed price swaps during the three months ended June 30, 2016 as compared to the prior year period.

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Operating Segment Information (Capital Expenditures) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Segment Reporting Information [Line Items]
Capital expenditures	$ 6,428	$ 30,168	$ 25,147	$ 82,609
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Capital expenditures	5,650	26,993	18,820	69,491
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Capital expenditures	$ 778	$ 3,175	$ 6,327	$ 13,118

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Operating Segment Information (Balance Sheet) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Goodwill	$ 13,639	$ 13,639
Total assets	1,697,300	1,883,246
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Goodwill	13,639	13,639
Total assets	1,540,386	1,699,949
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Total assets	135,721	159,622
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Total assets	$ 21,193	$ 23,675

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Subsequent Events (Atlas Growth Cash Distribution) (Details) - USD ($)				6 Months Ended
	Aug. 09, 2016	Jul. 31, 2016	Jul. 27, 2016	Jun. 30, 2016	Jun. 30, 2015	Jul. 31, 2013
Subsequent Event [Line Items]
Repayments under credit facilities				$ 57,500,000	$ 377,000,000
Class C Preferred Stock | Atlas Resource Partners, L.P.
Subsequent Event [Line Items]
Preferred units, issued						3,749,986
Subsequent Event | Atlas Resource Partners, L.P.
Subsequent Event [Line Items]
Warrant issued to purchase common units		562,497
Subsequent Event | Atlas Growth Partners, L.P | Cash Distribution Declared
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Declaration Date	Aug. 03, 2016
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit	$ 0.1750
Subsequent Event | Atlas Growth Partners, L.P | Cash Distribution Paid
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 4,200,000
Distribution Made to Member or Limited Partner, Distribution Date	Aug. 12, 2016
Distribution Made to Member or Limited Partner, Date of Record	Jun. 30, 2016
Subsequent Event | Atlas Growth Partners, L.P | Cash Distribution Paid | General Partner
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 100,000
Subsequent Event | Class C Preferred Stock | Atlas Resource Partners, L.P.
Subsequent Event [Line Items]
Convertible preferred units, issued upon conversion		3,749,986
Subsequent Event | First Lien Lenders
Subsequent Event [Line Items]
Repayments under credit facilities			$ 233,500,000
Subsequent Event | First Lien Lenders | Atlas Resource Partners, L.P.
Subsequent Event [Line Items]
Repayments under credit facilities			$ 233,500,000