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 September 30, 2015

OR

¨ 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  ¨

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

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

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

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

The number of outstanding common units of the registrant on November 4, 2015 was 26,010,766.

ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

TABLE OF CONTENTS

		PAGE
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)	3
	Combined Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014	3
	Combined Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2015 and 2014	4
	Combined Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2015 and 2014	5
	Combined Consolidated Statement of Unitholders’/Owner’s Equity for the Nine Months Ended September 30, 2015	6
	Combined Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2015 and 2014	7
	Notes to Combined Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	80
Item 4.	Controls and Procedures	84
PART II. OTHER INFORMATION
Item 6.	Exhibits	84
SIGNATURES		89

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES

COMBINED CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

	September 30,			December 31,
	2015			2014
ASSETS
Current assets:
Cash and cash equivalents	$	54,950		$	58,358
Accounts receivable		91,706			115,290
Advances to affiliates		—			4,389
Current portion of derivative asset		147,021			144,259
Subscriptions receivable		23,054			32,398
Prepaid expenses and other		26,022			26,789
Total current assets		342,753			381,483
Property, plant and equipment, net		1,659,358			2,419,289
Goodwill and intangible assets, net		14,154			14,330
Long-term derivative asset		206,142			130,602
Other assets, net		83,454			80,611
Total assets	$	2,305,861		$	3,026,315
LIABILITIES AND UNITHOLDERS’/OWNER’S EQUITY
Current liabilities:
Current portion of long-term debt	$	—		$	1,500
Accounts payable		85,792			123,670
Liabilities associated with drilling contracts		—			40,611
Current portion of derivative payable to Drilling Partnerships		1,881			932
Accrued interest		11,428			26,479
Accrued well drilling and completion costs		65,629			92,910
Deferred acquisition purchase price		39,167			105,000
Accrued liabilities		46,224			64,854
Total current liabilities		250,121			455,956
Long-term debt, less current portion		1,587,747			1,541,085
Asset retirement obligations and other		122,982			114,059
Commitments and contingencies
Unitholders’/owner’s equity:
Common unitholders’ equity		(34,624	)		—
Series A preferred equity		38,393			—
Owner’s equity		—			147,308
Accumulated other comprehensive income		10,388			54,008
		14,157			201,316
Non-controlling interests		330,854			713,899
Total unitholders’/owner’s equity		345,011			915,215
Total liabilities and unitholders’/owner’s equity	$	2,305,861		$	3,026,315

See accompanying notes to combined consolidated financial statements.

3

ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES

COMBINED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Revenues:
Gas and oil production	$	94,612		$	130,937		$	300,249		$	342,456
Well construction and completion		23,054			61,204			63,665			126,917
Gathering and processing		1,685			3,061			6,046			11,287
Administration and oversight		5,495			6,177			7,301			12,072
Well services		5,842			6,597			18,568			18,441
Gain on mark-to-market derivatives		131,777			—			210,466			—
Other, net		369			613			585			1,167
Total revenues		262,834			208,589			606,880			512,340
Costs and expenses:
Gas and oil production		42,300			52,004			131,908			134,590
Well construction and completion		20,046			53,221			55,361			110,363
Gathering and processing		2,473			3,214			7,406			11,900
Well services		2,398			2,617			6,735			7,525
General and administrative		21,704			17,299			82,037			63,487
Depreciation, depletion and amortization		43,311			65,068			131,043			177,513
Asset impairment		679,537			—			679,537			—
Total costs and expenses		811,769			193,423			1,094,027			505,378
Operating income (loss)		(548,935	)		15,166			(487,147	)		6,962
Loss on asset sales and disposal		(362	)		(92	)		(276	)		(1,683	)
Interest expense		(28,290	)		(19,423	)		(96,228	)		(51,474	)
Loss on extinguishment of debt		(4,726	)		—			(4,726	)		—
Net loss		(582,313	)		(4,349	)		(588,377	)		(46,195	)
Preferred unitholders’ dividends		(1,009	)		—			(2,346	)		—
Loss attributable to non-controlling interests		439,969			5,137			420,411			33,828
Net income (loss) attributable to unitholders’/owner’s interests	$	(143,353	)	$	788		$	(170,312	)	$	(12,367	)
Allocation of net income (loss) attributable to unitholders’/owner’s interests:
Portion applicable to owner’s interest (period prior to the transfer of assets on February 27, 2015)	$	—		$	788		$	(10,475	)	$	(12,367	)
Portion applicable to unitholders’ interests (period subsequent to the transfer of assets on February 27, 2015)		(143,353	)		—			(159,837	)		—
Net income (loss) attributable to unitholders’/owner’s  interests	$	(143,353	)	$	788		$	(170,312	)	$	(12,367	)
Net loss attributable to unitholders per common unit:
Basic	$	(5.51	)	$	—		$	(6.15	)	$	—
Diluted	$	(5.51	)	$	—		$	(6.15	)	$	—
Weighted average common units outstanding:
Basic		26,011			—			26,011			—
Diluted		26,011			—			26,011			—

See accompanying notes to combined consolidated financial statements.

4

ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES

COMBINED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Net loss	$	(582,313	)	$	(4,349	)	$	(588,377	)	$	(46,195	)
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges		—			70,362			—			5,268
Reclassification adjustment for gains due to impairment		(68,021	)		—			(68,021	)		—
Less: reclassification adjustment for realized (gains) losses of cash flow hedges in net loss		(23,927	)		(1,388	)		(77,048	)		22,703
Total other comprehensive income (loss)		(91,948	)		68,974			(145,069	)		27,971
Comprehensive income (loss)		(674,261	)		64,625			(733,446	)		(18,224	)
Comprehensive (income) loss attributable to non-controlling interests		509,678			(44,776	)		521,860			11,263
Comprehensive income (loss) attributable to unitholders’/owner’s interest	$	(164,583	)	$	19,849		$	(211,586	)	$	(6,961	)

See accompanying notes to combined consolidated financial statements.

5

ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES

COMBINED CONSOLIDATED STATEMENT OF UNITHOLDERS’/OWNER’S EQUITY

(in thousands, except unit data)

(Unaudited)

	Series A Preferred Equity					Common Unitholders’ Equity								Accumulated Other			Non-
	Units		Amount			Units		Amount			Owner’s Equity			Comprehensive Income			Controlling Interest			TotalUnitholders’/ Owner’s Equity
Balance at December 31, 2014		—	$	—			—	$	—		$	147,308		$	54,008		$	713,899		$	915,215
Net loss attributable to owner’s interest prior to the transfer of assets on February 27, 2015		—		—			—		—			(10,475	)		—			—			(10,475	)
Net distribution to owner’s interest prior to the transfer of assets on February 27, 2015		—		—			—		—			(19,758	)		—			—			(19,758	)
Net assets contributed by owner to Atlas Energy Group, LLC		—		—			26,010,766		117,075			(117,075	)		—			—			—
Issuance of units		1,616,047		40,401			—		(401	)		—			—			226,330			266,330
Distributions to non-controlling interests		—		—			—		—			—			—			(91,750	)		(91,750	)
Net issued and unissued units under incentive plan		—		—			—		2,757			—			—			4,600			7,357
Distribution equivalent rights paid on unissued units under incentive plans		—		—			—		—			—			—			(516	)		(516	)
Distribution payable		—		(336	)		—		—			—			—			3,587			3,251
Gain on sale from subsidiary unit issuances		—		—			—		3,436			—			—			(3,436	)		—
Distributions paid to preferred equity unitholders		—		(1,672	)		—		—			—			—			—			(1,672	)
Other comprehensive loss		—		—			—		—			—			(43,620	)		(101,449	)		(145,069	)
Net loss		—		—			—		(157,491	)		—			—			(420,411	)		(577,902	)
Balance at September 30, 2015		1,616,047	$	38,393			26,010,766	$	(34,624	)	$	—		$	10,388		$	330,854		$	345,011

See accompanying notes to combined consolidated financial statements.

6

ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES

COMBINED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Nine Months Ended September 30,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(588,377	)	$	(46,195	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		131,043			177,513
Asset impairment		679,537			—
Loss on early extinguishment of debt		4,726			—
Unrealized gain on derivatives		(192,644	)		—
Amortization of deferred financing costs		19,270			7,039
Non-cash compensation expense		7,819			6,343
(Gain) loss on asset sales and disposal		(190	)		1,683
Distributions paid to non-controlling interests		(92,266	)		(105,278	)
Equity income in unconsolidated companies		(502	)		(833	)
Distributions received from unconsolidated companies		2,104			1,244
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other		152,425			(73,588	)
Accounts payable and accrued liabilities		(196,053	)		5,489
Net cash used in operating activities		(73,108	)		(26,583	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(123,067	)		(162,726	)
Net cash paid for acquisitions		(49,060	)		(507,093	)
Other		(1,060	)		(2,060	)
Net cash used in investing activities		(173,187	)		(671,879	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities		758,041			1,034,000
Repayments under credit facilities		(725,657	)		(794,125	)
Net proceeds from subsidiary long term debt		—			97,386
Net proceeds from issuance of Series A units		40,000			—
Net proceeds from issuance of subsidiary units to the public		206,331			470,151
Retirement of subsidiary common limited partner units		—			(637	)
Net distributions to preferred unitholders		(1,672	)		—
Net distributions paid to unitholders		(19,758	)		(52,905	)
Amortization of discount on subsidiary debt		8,052			188
Deferred financing costs, distribution equivalent rights and other		(22,450	)		(9,466	)
Net cash provided by financing activities		242,887			744,592
Net change in cash and cash equivalents		(3,408	)		46,130
Cash and cash equivalents, beginning of year		58,358			10,625
Cash and cash equivalents, end of period	$	54,950		$	56,755

See accompanying notes to combined consolidated financial statements.

7

ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES

NOTES TO COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1—BASIS OF PRESENTATION

Atlas Energy Group, LLC is a Delaware limited liability company formed in October 2011 (the “Company”). At September 30, 2015, the Company’s operations primarily consisted of its ownership interests in the following:

· 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 23.6% 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 (NYSE: ARP) 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;

· 80.0% general partner interest and a 2.1% limited partner interest in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership that currently conducts natural gas and oil operations in the mid-continent region of the United States. 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, the Company purchased $5.0 million common limited partner units; and

· 15.9% general partner interest and 12.0% limited partner interest in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, its general partner, which incubate new MLPs and invest in existing MLPs.  

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

The accompanying combined consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2014 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and 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. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014. The results of operations for the three and nine months ended September 30, 2015 may not necessarily be indicative of the results of operations for the full year ending December 31, 2015.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Combination

The consolidated balance sheet at September 30, 2015 and the related combined consolidated statements of operations for the three and nine months ended September 30, 2015, subsequent to the transfer of assets on February 27, 2015, include the accounts of the Company and its subsidiaries. The Company’s combined consolidated balance sheet at December 31, 2014, the combined consolidated statement of operations for the portion of 2015 which is prior to the transfer of assets on February 27, 2015, and the combined consolidated statement of operations for the three and nine months ended September 30, 2014 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 the Company had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various entities comprising the Company, Atlas Energy’s net investment in the Company is shown as equity in the 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 combined consolidated balance sheets and related combined consolidated statements of operations. Such estimates included allocations made from the historical accounting records of Atlas Energy, based on management’s

8

best estimates, in order to derive the financial statements of the Company. Actual balances and results could be different from those estimates. Transactions between the Company and other Atlas Energy operations have been identified in the combined consolidated financial statements as transactions between affiliates.

In connection with Atlas Energy’s merger with Targa and the concurrent Separation, the Company was 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 generally accepted accounting principles, the Company included $150.0 million of Atlas Energy’s original term loan at the time of issuance, and the related interest expense, within its historical financial statements. Atlas Energy’s other historical borrowings were allocated to the Company’s historical financial statements in the same ratio. The Company used proceeds from the issuance of its Series A preferred units (see Note 12) and borrowings under its term loan credit facilities (see Note 7) to fund the $150.0 million payment.

The Company combines the financial statements of ARP and AGP into its combined consolidated financial statements rather than presenting its ownership interest as equity investments, as the Company controls these entities through its general partnership interests therein. As such, the non-controlling interests in ARP and AGP are reflected as (income) loss attributable to non-controlling interests in the combined consolidated statements of operations and as a component of unitholders’ equity on the combined consolidated balance sheets. All material intercompany transactions have been eliminated.

In accordance with established practice in the oil and gas industry, the Company’s combined consolidated financial statements include its 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%. The Company’s 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 (see “Property, Plant and Equipment”).

Use of Estimates

The preparation of the Company’s 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 the Company’s combined consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Company’s combined consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired and liabilities assumed. Such estimates included estimated allocations made from the historical accounting records of Atlas Energy in order to derive the historical financial statements of the Company. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three and nine months ended September 30, 2015 and 2014 represent actual results in all material respects (see “Revenue Recognition”).

Receivables

Accounts receivable on the combined consolidated balance sheets consist primarily of the trade accounts receivable associated with the Company and its subsidiaries. In evaluating the realizability of accounts receivable, management performs ongoing credit evaluations of customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness, as determined by management’s review of customers’ credit information. The Company and its subsidiaries extend credit on sales on an unsecured basis to many of their customers. At September 30, 2015 and December 31, 2014, the Company had recorded no allowance for uncollectible accounts receivable on its combined consolidated balance sheets.

Inventory

The Company had $8.7 million and $8.9 million of inventory at September 30, 2015 and December 31, 2014, respectively, which were included within prepaid expenses and other current assets on its combined consolidated balance

9

sheets. The Company values inventories at the lower of cost or market. The Company’s inventories, which consist primarily of ARP’s materials, pipes, supplies and other inventories, were principally determined using the average cost method.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Company’s results of operations.

The Company’s subsidiaries follow the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. “Mcf” is defined as one thousand cubic feet.

The Company’s subsidiaries’ depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include ARP’s costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by ARP for its interests, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s combined consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s combined consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s combined consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Impairment of Long-Lived Assets

The Company and its subsidiaries review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s subsidiaries’ plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. The Company’s subsidiaries estimate prices based upon current contracts in place, adjusted for basis differentials and market-related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, ARP’s reserve

10

estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include ARP’s actual capital contributions and a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

ARP’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to ARP operating and administrative fees in addition to their proportionate share of external operating expenses. These assumptions could result in ARP’s calculation of depletion and impairment being different than its proportionate share of the Drilling Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Company and ARP cannot predict what reserve revisions may be required in future periods.

ARP’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships, which ARP sponsors and owns an interest in but does not control. ARP’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which ARP may be unable to recover due to the Drilling Partnerships’ legal structure. ARP may have to pay additional consideration in the future as a Drilling Partnership’s wells become uneconomic to the Drilling Partnership under the terms of the Drilling Partnership’s drilling and operating agreement in order to recover these excess reserves, in addition to ARP becoming responsible for paying associated future operating, development and plugging costs of the well interests acquired, and to acquire any additional residual interests in the wells held by the Drilling Partnership’s limited partners. The acquisition of any such uneconomic well interest from the Drilling Partnership by ARP is governed under the Drilling Partnership’s limited partnership agreement. In general, ARP will seek consent from the Drilling Partnership’s limited partners to acquire the well interests from the Drilling Partnership based upon ARP’s determination of fair market value.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate that the Company’s subsidiaries will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. There were no impairments of unproved gas and oil properties recorded on the Company’s combined consolidated statements of operations for the three and nine months ended September 30, 2015 and 2014.

Capitalized Interest

ARP capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP were 6.5% and 5.4% for the three months ended September 30, 2015 and 2014, respectively, and 6.4% and 5.7% for the nine months ended September 30, 2015 and 2014, respectively. The amounts of interest capitalized by ARP were $4.0 million and $3.7 million for the three months ended September 30, 2015 and 2014, respectively, and $12.0 million and $9.4 million for the nine months ended September 30, 2015 and 2014, respectively.

Intangible Assets

ARP has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. ARP amortizes contracts acquired on a declining balance method over their respective estimated useful lives.

The following table reflects the components of intangible assets being amortized at September 30, 2015 and December 31, 2014 (in thousands):

	September 30,			December 31,			Estimated Useful Lives
	2015			2014			In Years
Gross Carrying Amount	$	14,344		$	14,344			13
Accumulated Amortization		(13,829	)		(13,653	)
Net Carrying Amount	$	515		$	691

Amortization expense on intangible assets was $0.1 million for both the three months ended September 30, 2015 and 2014. Amortization expense on intangible assets was $0.2 million for both the nine months ended September 30, 2015 and 2014. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending

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December 31 is as follows: 2015 - $0.2million; 2016 - $0.1million; 2017 - $0.1 million; 2018 - $0.1 million; and 2019 - $0.1 million.

Goodwill

At September 30, 2015 and December 31, 2014, the Company had $13.6 million of goodwill recorded in connection with ARP’s prior consummated acquisitions. No changes in the carrying amount of goodwill were recorded for the three and nine months ended September 30, 2015 and 2014.

ARP tests goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units. ARP’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including ARP’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, ARP also considers the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ARP’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in ARP’s industry to determine whether those valuations appear reasonable in management’s judgment. ARP’s management will continue to evaluate goodwill at least annually or when impairment indicators arise.

As a result of its goodwill impairment evaluation at December 31, 2014, ARP recognized an $18.1 million non-cash impairment charge within asset impairments on the Company’s combined consolidated statement of operations for the year ended December 31, 2014. The goodwill impairment resulted from the reduction in ARP’s estimated fair value of its gas and oil production reporting unit in comparison to its carrying amount at December 31, 2014. ARP’s estimated fair value of its gas and oil production reporting unit was impacted by a decline in overall commodity prices during the fourth quarter of 2014.

Derivative Instruments

ARP and AGP enter into certain financial contracts to manage their exposure to movement in commodity prices and interest rates (see Note 8). The derivative instruments recorded in the combined consolidated balance sheets are measured as either an asset or liability at fair value. Changes in the fair value of derivative instruments are recognized currently in the Company’s combined consolidated statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Company and ARP discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s combined consolidated statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 will be reclassified to the combined consolidated statements of operations in the periods in which those respective derivative contracts settle. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within unitholders’ equity on the Company’s consolidated balance sheets and reclassified to the Company’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings.

Asset Retirement Obligations

The Company’s subsidiaries recognize an estimated liability for the plugging and abandonment of gas and oil wells and related facilities (see Note 6). The Company’s subsidiaries also recognize a liability for future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Company‘s subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

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ARP Preferred Units

In connection with ARP’s acquisition of certain proved reserves and associated assets from Titan Operating, L.L.C. in July 2012, ARP issued 3.8 million newly created convertible Class B ARP preferred units (“Class B ARP Preferred Units”). While outstanding, the Class B ARP Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. On December 23, 2014, 3,796,900 of Class B ARP Preferred Units were converted into common units, while the remaining 39,654 Class B ARP Preferred Units were converted into common units on July 25, 2015. In connection with ARP’s acquisition of certain proved reserves and associated assets from EP Energy, Inc. in July 2013, ARP issued 3.7 million newly created convertible Class C ARP preferred units to Atlas Energy (“Class C ARP Preferred Units”). While outstanding, the Class C ARP Preferred Units will receive regular quarterly cash distributions equal to the greater of (i) $0.51 and (ii) the quarterly common unit distribution. In October 2014, in connection with ARP’s acquisition of assets in the Eagle Ford Shale (see Note 3), ARP issued 3.2 million of its 8.625% Class D cumulative redeemable perpetual preferred units (“Class D ARP Preferred Units”) and in March 2015, issued an additional 800,000 Class D ARP Preferred Units (see Note 12). The initial quarterly distribution on the Class D ARP Preferred Units was $0.616927 per unit, representing the distribution for the period from October 2, 2014 through January 14, 2015. Subsequent to January 14, 2015, ARP pays quarterly distributions on the Class D ARP Preferred Units at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference. In April 2015, ARP issued 255,000 of its newly created 10.75% Class E Cumulative Redeemable Perpetual ARP preferred units (“Class E ARP Preferred Units”). The initial quarterly distribution on the Class E ARP Preferred Units was $0.6793 per unit, representing the distribution for the period from April 14, 2015 through July 15, 2015. Subsequent to July 15, 2015, ARP will pay future quarterly distributions on the Class E Preferred Units at an annual rate of $2.6875 per unit, or 10.75% of the liquidation preference. At September 30, 2015 and December 31, 2014, $103.5 million and $78.0 million, respectively, related to ARP’s preferred units, are included within non-controlling interests on the Company’s combined consolidated statements of unitholders’ equity.

Income Taxes

The Company, ARP, AGP, Lightfoot and the respective subsidiaries thereof are not subject to U.S. federal and most state income taxes. The partners of these entities are liable for income tax in regard to their distributive share of the entities’ taxable income. Such taxable income may vary substantially from net income (loss) reported in the accompanying combined consolidated financial statements. Certain corporate subsidiaries of ARP are subject to federal and state income tax. The federal and state income taxes related to the Company and these corporate subsidiaries were immaterial to the combined consolidated financial statements as of September 30, 2015 and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for these corporate subsidiaries in the accompanying combined consolidated financial statements.

Each of the entities which comprise the Company evaluates tax positions taken or expected to be taken in the course of preparing their respective tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Company’s management does not believe it has any tax positions taken within its combined consolidated financial statements that would not meet this threshold. The Company’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Company has not recognized any such potential interest or penalties in its combined consolidated financial statements for the three and nine months ended September 30, 2015 and 2014.

The entities comprising the Company file Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the entities comprising the Company are no longer subject to income tax examinations by major tax authorities for years prior to 2011 and are not currently being examined by any jurisdiction and are not aware of any potential examinations as of September 30, 2015.

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 share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. A portion of the Company’s phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plans and incentive compensation agreements (see Note 14), contain non-forfeitable rights to distribution

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equivalents of the Company. The participation rights result in a non-contingent transfer of value each time the Company declares 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 loss allocated to the common unitholders for purposes of calculating net loss attributable to common unitholders per unit (in thousands, except unit data):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Net loss	$	(582,313	)	$	(4,349	)	$	(588,377	)	$	(46,195	)
Preferred unitholder dividends		(1,009	)		—			(2,346	)		—
Loss attributable to non-controlling interests		439,969			5,137			420,411			33,828
(Income) loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015)		—			(788	)		10,475			12,367
Net loss utilized in the calculation of net loss attributable to common unitholders per unit – basic and diluted(1)	$	(143,353	)	$	—		$	(159,837	)	$	—

(1) Net loss attributable to common unitholders per unit is calculated by dividing net income (loss) attributable to common unitholders, less income allocable to participating securities, by the sum of the weighted average number of common unitholder 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. For the three months ended September 30, 2015, net loss attributable common unitholders per unit is not allocated to approximately 69,000 phantom units, 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 nine months ended September 30, 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 68,000 phantom units, 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 three and nine months ended September 30, 2015, distributions on the Company’s Series A preferred units were excluded, because the inclusion of such preferred distributions would have been anti-dilutive.

The following table sets forth the reconciliation of the Company’s 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 September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Weighted average number of common unitholders per unit—basic		26,011		—		26,011		—
Add effect of dilutive incentive awards(1)		—		—		—		—
Add effect of dilutive convertible preferred units(1)		—		—		—		—
Weighted average number of common unitholders per unit—diluted		26,011		—		26,011		—

(1) For the three months ended September 30, 2015, 2,737,000 phantom units 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 nine months ended September 30, 2015, 1,492,000 phantom units 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 three and nine months ended September 30, 2015, potential common units issuable upon conversion of the Company’s 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.

Revenue Recognition

Natural gas and oil production. The Company’s subsidiaries’ gas and oil production operations generally sell natural gas, crude oil and NGLs at prevailing market prices. Typically, sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer

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point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which the Company’s subsidiaries have an interest with other producers, are recognized on the basis of the entity’s percentage ownership of the working interest and/or overriding royalty.

ARP’s Drilling Partnerships. Certain energy activities are conducted by ARP through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by ARP is deployed to drill and complete wells included within the partnership. As ARP deploys Drilling Partnership investor capital, it recognizes certain management fees it is entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if ARP has Drilling Partnership investor capital that has not yet been deployed, it will recognize a current liability titled “Liabilities Associated with Drilling Contracts” on the Company’s combined consolidated balance sheets. After the Drilling Partnership well is completed and turned in line, ARP is entitled to receive additional operating and management fees, which are included within well services and administration and oversight revenue, respectively, on a monthly basis while the well is operating. In addition to the management fees it is entitled to receive for services provided, ARP is also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which generally approximate 30%. ARP recognizes its Drilling Partnership management fees in the following manner:

· Well construction and completion. For each well that is drilled by a Drilling Partnership, ARP receives a 15% mark-up on those costs incurred to drill and complete wells included within the partnership. Such fees are earned, in accordance with the partnership agreement, and recognized as the services are performed, typically between 60 and 270 days.

· Administration and oversight. For each well drilled by a Drilling Partnership, ARP receives a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which is earned, in accordance with the partnership agreement, and recognized at the initiation of the well. Additionally, the Drilling Partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. The well administrative fee is earned on a monthly basis as the services are performed.

· Well services. Each Drilling Partnership pays ARP a monthly per well operating fee, currently $1,000 to $2,000, depending on the type of well, for the life of the well. Such fees are earned on a monthly basis as the services are performed.

While the 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.

ARP’s gathering and processing revenue. Gathering and processing revenue includes gathering fees ARP charges to the Drilling Partnership wells for ARP’s processing plants in the New Albany and the Chattanooga shales. Generally, ARP charges a gathering fee to the Drilling Partnership wells equivalent to the fees ARP remits. In Appalachia, a majority of the 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 the Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%.

The Company’s subsidiaries’ gas and oil production operations accrue unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data and management estimates of the related commodity sales and transportation and

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compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” for further description). The Company had unbilled revenues at September 30, 2015 and December 31, 2014 of $48.5 million and $85.5 million, respectively, which were included in accounts receivable within its combined consolidated balance sheets.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Company’s combined consolidated financial statements, and for all periods presented, only include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges (see Note 8). The Company does not have any other type of transaction which would be included within other comprehensive income (loss).

Recently Issued Accounting Standards

In September 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-16, Business Combinations (Subtopic 805) (“Update 2015-16”) which eliminates the need to retrospectively adjust previously issued financial statements for changes in provisional amounts recognized at the date on which a business was acquired and later revised based on new information about facts and circumstances that existed at the acquisition date.  Subsequent to the effective date of this accounting standard, such adjustments will be applied prospectively and the nature of, and reason for, the change in accounting principle will be disclosed.  The Company will adopt the requirements of Update 2015-16 upon its effective date of January 1, 2016, and the Company does not anticipate it having a material impact on its financial position, results of operations or related disclosures.  

In August 2015, the FASB issued ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements which was a clarification of its previously issued ASU 2015-03, Interest—Imputation of Interest (“Update 2015-15”) requiring entities to present debt issuance costs related to a recognized debt liability as a direct deduction from the carrying amount of that debt liability. Given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to line-of-credit arrangements, ASU 2015-15 effectively allows an entity to defer line-of-credit issuance costs and present such costs as an asset.  These deferred debt issuance costs may be amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Company will adopt the requirements of Update 2015-15 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In April 2015, the FASB issued ASU 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (“Update 2015-06”). Under Topic 260, Earnings per Share, master limited partnerships (“MLPs”) apply the two-class method to calculate earnings per unit (“EPU”) because the general partner, limited partners, and incentive distribution rights holders each participate differently in the distribution of available cash. When a general partner transfers (or “drops down”) net assets to an MLP and that transaction is accounted for as a transaction between entities under common control, the statements of operations of the MLP are adjusted retrospectively to reflect the drop down transaction as if it occurred on the earliest date during which the entities were under common control. The amendments in Update 2015-06 specify that for purposes of calculating historical EPU under the two-class method, the earnings (losses) of a transferred business before the date of a drop down transaction should be allocated entirely to the general partner interest, and previously reported EPU of the limited partners would not change as a result of a drop down transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the drop down transaction occurs also are required. The amendments in Update 2015-06 are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted and amendments in Update 2015-06 should be applied retrospectively for all financial statements presented. The Company will adopt the requirements of Update 2015-06 upon its effective date of January 1, 2016, and the Company does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In March 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30) (“Update 2015-03”). The amendments in Update 2015-03 are intended to simplify presentation of debt issuance costs and require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs would not be affected by the amendments in Update 2015-03. The amendments in Update 2015-03 are effective for periods beginning after December 15, 2015, and interim periods within those periods. Early adoption is permitted, including adoption in an interim period, and an entity should apply the new guidance on a retrospective basis. The Company will adopt the requirements of Update 2015-03

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upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“Update 2015-02”). The amendments in Update 2015-02 are intended to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures.  The amendments simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The amendments in Update 2015-02 are effective for periods beginning after December 31, 2015. Early adoption is permitted, including adoption in an interim period. The Company will adopt the requirements of Update 2015-02 upon its effective date of January 1, 2016, and is evaluating the impact of adoption on its financial position, results of operations or related disclosures.

In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The Company will adopt the requirements of Update 2015-01 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815) – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity (“Update 2014-16”). Certain classes of shares include features that entitle the holders to preferences and rights (such as conversion rights, redemption rights, voting powers, and liquidation and dividend payment preferences) over the other shareholders. Shares that include embedded derivative features are referred to as hybrid financial instruments, which must be separated from the host contract and accounted for as a derivative if certain criteria are met under Subtopic 815-10.One criterion requires evaluating whether the nature of the host contract is more akin to debt or to equity and whether the economic characteristics and risks of the embedded derivative feature are “clearly and closely related” to the host contract. In making that evaluation, an issuer or investor may consider all terms and features in a hybrid financial instrument including the embedded derivative feature that is being evaluated for separate accounting or may consider all terms and features in the hybrid financial instrument except for the embedded derivative feature that is being evaluated for separate accounting. The use of different methods can result in different accounting outcomes for economically similar hybrid financial instruments.Additionally, there is diversity in practice with respect to the consideration of redemption features in relation to other features when determining whether the nature of a host contract is more akin to debt or to equity. The amendments in Update 2014-16 clarify how current U.S. GAAP should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. The effects of initially adopting the amendments in Update 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in the form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. The amendments in Update 2014-16 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The Company will adopt the requirements of Update 2014-16 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early adoption is permitted. The Company will adopt the requirements of Update 2014-15 upon its effective date in 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In June 2014, the FASB issued ASU 2014-12, Compensation—Stock Compensation (Topic 718) (“Update 2014-12”). The amendments in Update 2014-12 require that a performance target that affects vesting and that could be achieved after the

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requisite service period be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in Update 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. The Company will adopt the requirements of Update 2014-12 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles—Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is not permitted. The Company will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2018, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

NOTE 3—ACQUISITIONS

ARP’s Rangely Acquisition

On June 30, 2014, ARP completed an acquisition of a 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado from Merit Management Partners I, L.P., Merit Energy Partners III, L.P. and Merit Energy Company, LLC (collectively, “Merit Energy”) for approximately $408.9 million in cash, net of purchase price adjustments (the “Rangely Acquisition”). The purchase price was funded through borrowings under ARP’s revolving credit facility, the issuance of an additional $100.0 million of ARP’s 7.75% senior notes due 2021 (“7.75% ARP Senior Notes”) (see Note 7) and the issuance of 15,525,000 of ARP’s common limited partner units (see Note 12). The Rangely Acquisition had an effective date of April 1, 2014. The Company’s combined consolidated financial statements reflected the operating results of the acquired business commencing June 30, 2014 with the transaction closing.

ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9). In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $11.6 million of transaction fees which were included within non-controlling interests at December 31, 2014 on the Company’s combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred.

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The following table presents the values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

Assets:
Prepaid expenses and other	$	4,041
Property, plant and equipment		405,416
Other assets, net		2,888
Total assets acquired	$	412,345
Liabilities:
Accrued liabilities		2,117
Asset retirement obligation		1,305
Total liabilities assumed		3,422
Net assets acquired	$	408,923

Other Acquisitions

ARP’s Arkoma Acquisition

On June 5, 2015, ARP completed the acquisition of the Company’s coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma for approximately $31.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). ARP funded the purchase price through the issuance of 6,500,000 common limited partner units (see Note 12). 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.

ARP’s and AGP’s Eagle Ford Acquisition

On November 5, 2014, ARP and AGP completed an acquisition of oil and natural gas liquid interests in the Eagle Ford Shale in Atascosa County, Texas from Cima Resources, LLC and Cinco Resources, Inc. (together “Cinco”) for $342.0 million, net of purchase price adjustments (the “Eagle Ford Acquisition”). Approximately $183.1 million was paid in cash by ARP and $19.9 million was paid by AGP at closing, and approximately $139.0 million was to be paid in four quarterly installments beginning December 31, 2014. On December 31, 2014, AGP made its first installment payment of $35.0 million related to its Eagle Ford Acquisition. Prior to the March 31, 2015 installment, ARP, AGP, and Cinco amended the purchase and sale agreement to alter the timing and amount of the quarterly payments beginning with the March 31, 2015 payment and ending December 31, 2015, with no change to the overall purchase price. On March 31, 2015, AGP paid $28.3 million and ARP issued $20.0 million of its Class D ARP Preferred Units (see Note 12) to satisfy the second installment related to the Eagle Ford Acquisition. On June 30, 2015, AGP paid $16.0 million and ARP paid $0.6 million to satisfy the third installment related to the Eagle Ford Acquisition. In September 2015, ARP agreed with AGP to have AGP transfer its remaining $36.3 million of deferred purchase obligation, along with the related undeveloped natural gas and oil properties, to ARP.  On September 30, 2015, ARP paid $17.5 million to satisfy the fourth installment related to the Eagle Ford Acquisition.  At September 30, 2015, ARP’s remaining deferred portion of the purchase price was $21.6 million, payable on December 31, 2015. The Eagle Ford Acquisition had an effective date of July 1, 2014. ARP’s issuance of Class D ARP Preferred Units represents a non-cash transaction for statement of cash flow purposes during the nine months ended September 30, 2015.

ARP’s GeoMet Acquisition

On May 12, 2014, ARP completed the acquisition of certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $97.9 million in cash, net of purchase price adjustments (the “GeoMet Acquisition”), with an effective date of January 1, 2014. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia.

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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):

	September 30,			December 31,			Estimated Useful Lives
	2015			2014			in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	469,684		$	455,401
Pre-development costs		8,664			7,378
Wells and related equipment		3,158,769			3,082,429
Total proved properties		3,637,117			3,545,208
Unproved properties		316,924			311,946
Support equipment		44,274			37,359
Total natural gas and oil properties		3,998,315			3,894,513
Pipelines, processing and compression facilities		59,598			49,547			2 – 40
Rights of way		829			830			20 – 40
Land, buildings and improvements		9,202			9,160			3 – 40
Other		18,318			17,936			3 – 10
		4,086,262			3,971,986
Less – accumulated depreciation, depletion and amortization		(2,426,904	)		(1,552,697	)
	$	1,659,358		$	2,419,289

During the three and nine months ended September 30, 2015, the Company recognized $0.4 million and $0.3 million of gains on asset sales and disposals, respectively. During the three and nine months ended September 30, 2014, the Company recognized $0.1 million and $1.7 million, respectively, of losses on asset sales and disposals. The $1.7 million loss during the nine months ended September 30, 2014 was primarily related to ARP’s sale of producing wells in the Niobrara Shale in connection with the settlement of a third party farm out agreement.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate the Company’s subsidiaries will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. There were no impairments of unproved gas and oil properties recorded by the Company’s subsidiaries for the three and nine months ended September 30, 2015 and 2014.

Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. For the three and nine months ended September 30, 2015, the Company recognized $747.5 million of asset impairment primarily related to ARP’s oil and gas properties in the Barnett, Coal-bed Methane, Southern Appalachia, Marcellus and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices, reduced by $68.0 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairment and the related hedge gains are included in asset impairment expense in the Company’s combined consolidated results of operations for the three and nine months ended September 30, 2015. There were no asset impairments of proved gas and oil properties for the three and nine months ended September 30, 2014.

During the nine months ended September 30, 2015 and 2014, the Company recognized $12.0 million and $42.6 million, respectively, of non-cash property, plant and equipment additions, which were included within the changes in accounts payable and accrued liabilities on the Company’s combined consolidated statement of cash flows.

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NOTE 5—OTHER ASSETS

The following is a summary of other assets at the dates indicated (in thousands):

		September 30,	December 31,
	2015		2014
Deferred financing costs, net of accumulated amortization of $39,945 and $20,675 at September 30, 2015 and December 31, 2014, respectively	$	49,299	$	46,120
Investment in Lightfoot		19,521		21,123
Rabbi Trust		5,378		3,925
Security deposits		231		229
ARP notes receivable		3,871		3,866
Other		5,154		5,348
	$	83,454	$	80,611

Deferred financing costs. Deferred financing costs are recorded at cost and amortized over the terms of the respective debt agreements (see Note 7). Amortization expense of the Company’s and its subsidiaries’ deferred financing costs was $3.6 million and $2.7 million for the three months ended September 30, 2015 and 2014, respectively, and $9.8 million and $7.0 million for the nine months ended September 30, 2015 and 2014, respectively, which was recorded within interest expense on the Company’s combined consolidated statements of operations. During the nine months ended September 30, 2015, the Company recognized $5.2 million for accelerated amortization of deferred financing costs associated with Atlas Energy, L.P.’s credit facility and term loan. There was no accelerated amortization of deferred financing costs for the Company during the three months ended September 30, 2015 and the nine months ended September 30, 2014.

During the nine months ended September 30, 2015, ARP recognized $4.3 million for accelerated amortization of deferred financing costs associated with a reduction of the borrowing base under its revolving credit facility. There was no accelerated amortization of deferred financing costs for ARP during the three months ended September 30, 2015 and 2014 and during the nine months ended September 30, 2014.

ARP notes receivable. At September 30, 2015 and December 31, 2014, ARP had notes receivable with certain investors of its Drilling Partnerships, which were included within other assets, net on the Company’s combined consolidated balance sheets. The notes have a maturity date of March 31, 2022, and a 2.25% per annum interest rate. The maturity date of the notes can be extended to March 31, 2027, subject to certain closing conditions, including an extension fee of 1.0% of the outstanding principal balance. The Company recognized interest income within other, net on the Company’s combined consolidated statements of operations of approximately $21,000 and $22,000, respectively, for the three months ended September 30, 2015 and 2014, and approximately $64,000 and $68,000 for the nine months ended September 30, 2015 and 2014, respectively. At September 30, 2015 and December 31, 2014, ARP recorded no allowance for credit losses within the Company’s combined consolidated balance sheets based upon payment history and ongoing credit evaluations associated with the ARP notes receivable.

Investment in Lightfoot. At September 30, 2015, the Company had an approximate 12.0% interest in Lightfoot L.P. and an approximate 15.9% interest in Lightfoot G.P., 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. The Company accounts for its investment in Lightfoot under the equity method of accounting. During the three months ended September 30, 2015 and 2014, the Company recognized equity income of approximately $0.3 million and $0.4 million, respectively, within other, net on the Company’s combined consolidated statements of operations. During the nine months ended September 30, 2015 and 2014, the Company recognized equity income of approximately $0.5 million and $0.8 million, respectively, within other, net on the Company’s combined consolidated statements of operations. During the three months ended September 30, 2015 and 2014, the Company received net cash distributions of approximately $1.4 million and $0.5 million, respectively. During the nine months ended September 30, 2015 and 2014, the Company received net cash distributions of approximately $2.2 million and $1.2 million, respectively.

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NOTE 6—ASSET RETIREMENT OBLIGATIONS

The Company’s subsidiaries recognize an estimated liability for the plugging and abandonment of their respective gas and oil wells and related facilities. The Company’s subsidiaries also recognize a liability for their respective future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Company’s subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability for asset retirement obligations was based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The Company’s subsidiaries have no assets legally restricted for purposes of settling asset retirement obligations. Except for the Company’s subsidiaries’ gas and oil properties, there were no other material retirement obligations associated with tangible long-lived assets.

ARP proportionately consolidates its ownership interest of the asset retirement obligations of its Drilling Partnerships. At September 30, 2015, the Drilling Partnerships had $45.6 million of aggregate asset retirement obligation liabilities recognized on their combined balance sheets allocable to the limited partners, exclusive of ARP’s proportional interest in such liabilities. Under the terms of the respective partnership agreements, ARP maintains the right to retain a portion or all of the distributions to the limited partners of its Drilling Partnerships to cover the limited partners’ share of the plugging and abandonment costs up to a specified amount per month. As of September 30, 2015, ARP has withheld approximately $4.3 million of limited partner distributions related to the asset retirement obligations of certain Drilling Partnerships. ARP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within each Drilling Partnership near the end of their useful life. On a partnership-by-partnership basis, ARP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors, including commodity price trends, the natural decline in the production of the wells, and current and future costs. Generally, ARP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon ARP’s decision to retain all future distributions to the limited partners of its Drilling Partnerships, ARP will assume the related asset retirement obligations of the limited partners.

A reconciliation of the Company’s subsidiaries’ liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Asset retirement obligations, beginning of period	$	110,937		$	101,455		$	108,101		$	91,214
Liabilities incurred		80			336			296			8,283
Liabilities settled		(1	)		(271	)		(547	)		(820	)
Accretion expense		1,584			1,471			4,750			4,314
Asset retirement obligations, end of period	$	112,600		$	102,991		$	112,600		$	102,991

The above accretion expense was included in depreciation, depletion and amortization in the Company’s combined consolidated statements of operations and the asset retirement obligation liabilities were included within asset retirement obligations and other in the Company’s combined consolidated balance sheets. During the year ended December 31, 2014, AGP incurred $0.1 million of future plugging and abandonment liabilities within purchase accounting related to the acquisition it consummated during the period. During the year ended December 31, 2014, ARP incurred $7.0 million of future plugging and abandonment liabilities within purchase accounting related to the acquisitions it consummated during the period (see Note 3). During the nine months ended September 30, 2014, ARP incurred $6.6 million of future plugging and abandonment liabilities within purchase accounting for the Rangely and GeoMet acquisitions it consummated during the period (see Note 3). No future plugging and abandonment liabilities related to consummated acquisitions were incurred during the three and nine months ended September 30, 2015.

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NOTE 7—DEBT

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

		September 30,		December 31,
		2015		2014
Term loan facilities	$	82,700	$	148,125
ARP revolving credit facility		563,000		696,000
ARP term loan facility		243,408		—
ARP 7.75% Senior Notes—due 2021		374,601		374,544
ARP 9.25% Senior Notes—due 2021		324,038		323,916
Total debt		1,587,747		1,542,585
Less current maturities		—		(1,500	)
Total long-term debt	$	1,587,747	$	1,541,085

Term Loan Facilities

On August 10, 2015, the Company entered into a credit agreement (the “Riverstone Credit Agreement”) with Riverstone Credit Partners, L.P., as administrative agent, and the lenders party thereto, for a new term loan facility (the “Riverstone Term Loan Facility”) in an aggregate principal amount of $82.7 million maturing in August 2020.The borrowings under the Riverstone Term Loan Facility were used to repay in full outstanding borrowings under the Company’s existing term loan facility.

The Company’s obligations under the Riverstone Term Loan Facility are secured on a first priority basis by security interests in substantially all of the assets of the Company and each of New Atlas Holdings, LLC, the Company’s direct wholly owned subsidiary, Atlas Lightfoot, LLC and any other material subsidiary of the Company that later guarantees indebtedness under the Riverstone Term Loan Facility, including all equity interests directly held by New Atlas Holdings, LLC or any guarantor and all tangible and intangible property of the Company and the guarantors (subject to certain customary exclusions and exceptions).

Borrowings under the Riverstone Term Loan Facility bear interest, at the Company’s option, at either (i) LIBOR plus 7.0% (as used with respect to the Riverstone Term Loan Facility, “Eurodollar Loans”) or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 6.0% (as used with respect to the Riverstone Term Loan Facility, an “ABR Loan”). Interest is generally payable at interest payment periods selected by the Company for Eurodollar Loans and quarterly for ABR Loans. At September 30, 2015, $82.7 million was outstanding under the Riverstone Term Loan Facility. At September 30, 2015, the weighted average interest rate on outstanding borrowings under the Riverstone Term Loan Facility was 8.0%.

The Riverstone Credit Agreement contains customary covenants that limit the Company’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. The Company was in compliance with these covenants as of September 30, 2015. The Riverstone Credit Agreement also requires that (a) the Total Leverage Ratio (as defined in the Riverstone Credit Agreement) not be greater than 4.00 to 1.00, beginning with the fiscal quarter ending March 31, 2016; (b) the full repayment of Company have liquidity of not less than $5 million at the end of each fiscal quarter, beginning with the fiscal quarter ending December 31, 2015; and (c) the Asset Coverage Ratio (as defined in the Riverstone Credit Agreement) not be less than 1.75 to 1.00 during the period from September 30, 2015 to June 30, 2016. Based on the definitions contained in the Credit Agreement, at September 30, 2015, the Company’s Total Leverage Ratio was 2.6 to 1.0 and the Company’s Asset Coverage Ratio was 2.9 to 1.0.

The Company has the right at any time to prepay any borrowings outstanding under the Riverstone Term Loan Facility, subject to the payment of a prepayment premium specified therein. Subject to certain exceptions, the Company may also be required to prepay all or a portion of the Riverstone Term Loan Facility in certain instances, including the following:

· at the end of each fiscal quarter, the Company must repay the Riverstone Term Loan Facility in an amount equal to: (i) if the Total Leverage Ratio is equal to or greater than 3.50 to 1.00, 100% of Distributable Cash (as defined in the Riverstone Credit Agreement), (ii) if the Total Leverage Ratio is equal to or greater than 3.00 to 1.00 but less than 3.25 to 1.00, 75% of Distributable Cash, (iii) if the Total Leverage Ratio is equal to or

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greater than 2.75 to 1.00 but less than 3.00 to1.00, 50% of Distributable Cash, (iv) if the Total Leverage Ratio is equal to or greater than 2.50 to 1.00 but less than 2.75 to1.00, 25% of Distributable Cash, and (v) if the Total Leverage Ratio is less than 2.50 to 1.00, 0% of Distributable Cash. 

· if, at any time after June 30, 2016, the Asset Coverage Ratio is less than 2.00 to 1.00, the Company must prepay the Riverstone Term Loan Facility in an aggregate principal amount necessary to achieve an Asset Coverage Ratio of greater than 2.00 to 1.00; the Asset Coverage Ratio is equal to the ratio of the Asset Value (the sum of the discounted net present values of the loan parties’ oil and gas properties, cash and cash equivalents, and the values of certain equity interests of ARP, Atlas Lightfoot, LLC, AGP and certain other midstream and upstream companies, determined as set forth in the Riverstone Credit Agreement) to Total Funded Debt (as defined in the Riverstone Credit Agreement);

· if the Company or any restricted subsidiary of the Company disposes of property or assets (including equity interests) to a person other than a loan party or receives insurance or condemnation proceeds following a casualty event, the Company must repay the Riverstone Term Loan Facility in an aggregate principal amount equal to 100% of the net cash proceeds from such disposition or casualty event; and

· if the Company or any restricted subsidiary of the Company issues or incurs any debt or issues any equity, the Company must repay the Riverstone Term Loan Facility in an aggregate principal amount equal to 100% of the net cash proceeds of such issuances or incurrences of debt or issuances of equity.

On February 27, 2015, the Company entered into a credit agreement with Deutsche Bank AG New York Branch, as administrative agent, and the lenders party thereto (the “Credit Agreement”). The Credit Agreement provided for a Secured Senior Interim Term Loan Facility in an aggregate principal amount of $30.0 million (the “Interim Term Loan Facility”) and a Secured Senior Term Loan A Facility in an aggregate principal amount of approximately $97.8 million (the “Term Loan A Facility” and together with the Interim Term Loan Facility, the “Term Loan Facilities”). In June 2015, the Company prepaid $33.1 million on the Term Loan Facilities in connection with the Arkoma Acquisition (see Note 3). On August 10, 2015, the Company repaid in full the remaining $82.7 million outstanding under the Term Loan Facilities.

The proceeds from the issuance of the Term Loan Facilities were used to fund a portion of the Company’s $150.0 million payment to Atlas Energy in connection with the repayment of Atlas Energy’s term loan (see Note 2). The Interim Term Loan Facility matured on August 27, 2015 and the Term Loan A Facility was to mature on February 26, 2016. The Company’s obligations under the Term Loan Facilities were secured on a first priority basis by security interests in substantially all of the assets of the Company and its material subsidiaries, including all equity interests directly held by the Company, New Atlas Holdings, LLC, or any other guarantor, and all tangible and intangible property. Borrowings under the Term Loan Facilities bore interest, at the Company’s option, at either (i) LIBOR plus 7.5% (as used with respect to the Term Loan Facilities, “Eurodollar Loans”) or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, in each case plus 6.5% (as was used with the Term Loan Facilities, an “ABR Loan”). Interest was generally payable at interest payment periods selected by the Company for Eurodollar Loans and quarterly for ABR Loans.

The Company had the right at any time to prepay any borrowings outstanding under the Term Loan Facilities, without premium or penalty, provided the Interim Term Loan Facility was repaid prior to the Term Loan A Facility. Subject to certain exceptions, the Company may also have been required to prepay all or a portion of the Term Loan Facilities in certain instances, including the following:

· if, at any time, the Recognized Value Ratio (as defined in the Credit Agreement) was less than 2.00 to 1.00, the Company must have prepaid the Term Loan Facilities and any revolving loans outstanding in an aggregate principal amount necessary to achieve a Recognized Value Ratio of greater than 2.00 to 1.00; the Recognized Value Ratio was equal to the ratio of the Recognized Value (the sum of the discounted net present values of the Loan Parties’ oil and gas properties and the values of the common units, Class A Units and Class C Units of ARP, determined as set forth in the Credit Agreement) to Total Funded Debt (as defined in the Credit Agreement);

· if the Company disposed of all or any portion of the Arkoma Assets (as defined in the Credit Agreement), the Company must have prepaid the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds resulting from such disposition;

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· if the Company or any of its restricted subsidiaries disposed of property or assets (including equity interests), the Company must have repaid the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds from such disposition or casualty event; and; 

· if the Company incurred any debt or issues any equity, it must have repaid the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds of such issuances or incurrences of debt or issuances of equity.

The Credit Agreement contained customary covenants that limited the Company’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. The Credit Agreement also required that the Total Leverage Ratio (as defined in the Credit Agreement) not be greater than (i) as of the last day of any fiscal quarter prior to the full repayment of the Interim Term Loan Facility, 3.75 to 1.00, and (ii) as of the last day of any quarter thereafter, 3.50 to 1.00.

Atlas Energy Term Loan Facility

On July 31, 2013, Atlas Energy entered into a $240.0 million secured term loan facility with a group of outside investors (the “Term Facility”). At December 31, 2014, $148.1 million of the Term Facility was attributable to the Company. The Term Facility had a maturity date of July 31, 2019. Borrowings under the Term Facility bore interest, at Atlas Energy’s election, at either an adjusted LIBOR rate plus an applicable margin of 5.50% per annum or the alternate base rate (as defined in the Term Facility) (“ABR”) plus an applicable margin of 4.50% per annum. Interest was generally payable quarterly for ABR loans and, for LIBOR loans at the interest periods selected by Atlas Energy. Atlas Energy was required to repay principal at the rate of $0.6 million per quarter commencing December 31, 2013 and continuing until the maturity date when the remaining balance was due. At December 31, 2014, the weighted average interest rate on outstanding borrowings under the Term Facility was 6.5%.  

In connection with Atlas Energy’s merger with Targa, the Term Facility was repaid in full on February 27, 2015.

ARP Credit Facility

ARP is a party to a Second Amended and Restated Credit Agreement dated July 31, 2013, as amended, with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (the “ARP Credit Agreement”), which provides for a senior secured revolving credit facility with a borrowing base of $750.0 million as of September 30, 2015.  

ARP’s borrowing base is scheduled for semi-annual redeterminations on November 1, 2015 and thereafter on May 1 and November 1 of each year. In July 2015, the determination by the lenders reaffirmed ARP’s $750.0 million borrowing base. The ARP Credit Agreement also provides that ARP’s borrowing base will be reduced by 25% of the stated amount of any senior notes issued, or additional second lien debt incurred, after July 1, 2015. At September 30, 2015, $563.0 million was outstanding under the credit facility. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which $4.3 million was outstanding at September 30, 2015. ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. Borrowings under the credit facility bear interest, at ARP’s election, at either an adjusted LIBOR rate plus an applicable margin between 1.50% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.50% and1.75% per annum. If the borrowing base utilization (as defined in the ARP Credit Agreement) is less than 90%, the applicable margin on Eurodollar Loans and ABR Loans (each as defined in the ARP Credit Agreement) will be increased by 0.25%. ARP is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.375% per annum if less than 50% of the borrowing base is utilized and 0.5% if 50% or more of the borrowing base is utilized, which is included within interest expense on the Company’s combined consolidated statements of operations. At September 30, 2015, the weighted average interest rate on outstanding borrowings under the credit facility was 2.75%.

The ARP Credit Agreement contains customary covenants that limit ARP’s ability to incur additional indebtedness (excluding second lien debt in an aggregate principal amount of up to $300.0 million), grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or

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consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. ARP was in compliancewith these covenants as of September 30, 2015. The ARP Credit Agreement also requires that ARP maintain a ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than (i) 5.25 to 1.0 as of the last day of the quarters ending on March 31, 2015, June 30, 2015, September 30, 2015, December 31, 2015 and March 31, 2016, (ii) 5.00 to 1.0 as of the last day of the quarters ending on June 30, 2016, September 30, 2016 and December 31, 2016, (iii) 4.50 to 1.0 as of the last day of the quarter ending on March 31, 2017 and (iv) 4.00 to 1.0 as of the last day of each quarter thereafter, and a ratio of current assets (as defined in the ARP Credit Agreement) to current liabilities (as defined in the ARP Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. Based on the definitions contained in the ARP Credit Agreement, at September 30, 2015, ARP’s ratio of current assets to current liabilities was 1.4 to 1.0, and its ratio of Total Funded Debt to EBITDA was 5.2 to 1.0.

ARP Term Loan Facility

On February 23, 2015, ARP entered into a Second Lien Credit Agreement with certain lenders and Wilmington Trust, National Association, as administrative agent. The Second Lien Credit Agreement provides for a second lien term loan in an original principal amount of $250.0 million (the “ARP Term Loan Facility”). The ARP Term Loan Facility matures on February 23, 2020. The ARP Term Loan Facility is presented net of unamortized discount of $6.6 million at September 30, 2015.

ARP has the option to prepay the ARP Term Loan Facility at any time, and is required to offer to prepay the ARP Term Loan Facility with 100% of the net cash proceeds from the issuance or incurrence of any debt and 100% of the excess net cash proceeds from certain asset sales and condemnation recoveries. ARP is also required to offer to prepay the ARP Term Loan Facility upon the occurrence of a change of control. All prepayments are subject to the following premiums, plus accrued and unpaid interest:

· the make-whole premium (plus an additional amount if such prepayment is optional and funded with proceeds from the issuance of equity) for prepayments made during the first 12 months after the closing date;

· 4.5% of the principal amount prepaid for prepayments made between 12 months and 24 months after the closing date;

· 2.25% of the principal amount prepaid for prepayments made between 24 months and 36 months after the closing date; and

· no premium for prepayments made following 36 months after the closing date.

ARP’s obligations under the ARP Term Loan Facility are secured on a second priority basis by security interests in all of its assets and those of its restricted subsidiaries (the “Loan Parties”) that guarantee ARP’s existing first lien revolving credit facility. In addition, the obligations under the ARP Term Loan Facility are guaranteed by ARP’s material restricted subsidiaries. Borrowings under the ARP Term Loan Facility bear interest, at ARP’s option, at either (i) LIBOR plus 9.0% or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 8.0% (an “ABR Loan”). Interest is generally payable at the applicable maturity date for Eurodollar loans and quarterly for ABR loans. At September 30, 2015, the weighted average interest rate on outstanding borrowings under the term loan facility was 10.0%.

The Second Lien Credit Agreement contains customary covenants that limit ARP’s ability to make restricted payments, take on indebtedness, issue preferred stock, grant liens, conduct sales of assets and subsidiary stock, make distributions from restricted subsidiaries, conduct affiliate transactions and engage in other business activities. In addition, the Second Lien Credit Agreement contains covenants substantially similar to those in ARP’s existing first lien revolving 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 in compliance with these covenants as of September 30, 2015.

Under the Second Lien Credit Agreement, ARP may elect to add one or more incremental term loan tranches to the ARP Term Loan Facility so long as the aggregate outstanding principal amount of the ARP Term Loan Facility plus the principal amount of any incremental term loan does not exceed $300.0 million and certain other conditions are adhered to.  Any such incremental term loans may not mature on a date earlier than February 23, 2020.

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Senior Notes

At September 30, 2015, ARP had $374.6 million outstanding of its 7.75% senior unsecured notes due 2021 (“7.75% ARP Senior Notes”). The 7.75% ARP Senior Notes were presented net of a $0.4 million unamortized discount as of September 30, 2015. Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable for up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, ARP may redeem the 7.75% ARP Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (as defined in the governing indenture), plus accrued and unpaid interest, if any. On and after January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 7.75% ARP Senior Notes.

At September 30, 2015, ARP had $324.0 million outstanding of its 9.25% senior unsecured notes due 2021 (“9.25% ARP Senior Notes”). The 9.25% ARP Senior Notes were presented net of a $1.0 million unamortized discount as of September 30, 2015. Interest on the 9.25% ARP Senior Notes is payable semi-annually on February 15 and August 15. At any time prior to August 15, 2017, ARP may redeem the 9.25% ARP Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (as defined in the governing indenture), plus accrued and unpaid interest, if any. At any time on or after August 15, 2017, ARP may redeem some or all of the 9.25% ARP Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 100.0%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 9.25% ARP Senior Notes.

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 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 limitations of 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 September 30, 2015.

Cash payments for interest by the Company and its subsidiaries on their respective borrowings were $93.7 million and $62.5 million for the nine months ended September 30, 2015 and 2014, respectively.

NOTE 8—DERIVATIVE INSTRUMENTS

AGP and ARP use a number of different derivative instruments, principally swaps, collars, and options, in connection with their commodity and interest rate price risk management activities. AGP and ARP enter into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold or interest payments on the underlying debt instrument are due. Under commodity-based swap agreements, AGP and ARP receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.  

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On January 1, 2015, ARP discontinued hedge accounting for its qualified commodity derivatives. As such, changes in fair value of these derivatives after December 31, 2014 are recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s combined consolidated statements of operations. The fair values of these commodity derivative instruments at December 31, 2014, which were recognized in accumulated other comprehensive income within unitholders’ equity on the Company’s combined consolidated balance sheet, are being reclassified to the Company’s combined consolidated statements of operations at the time the originally hedged physical transactions settle.

AGP and ARP enter into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Company’s combined consolidated balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Company’s combined consolidated balance sheets as the initial value of the options.

AGP and ARP enter into commodity future option and collar 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 other natural gas liquids contracts are based on an OPIS Mt. Belvieu index.

Derivatives are recorded on the Company’s combined consolidated balance sheets as assets or liabilities at fair value. The Company reflected net derivative assets on its combined consolidated balance sheets of $353.2 million and $274.9 million at September 30, 2015 and December 31, 2014, respectively. Of the $10.4 million of net gain in accumulated other comprehensive income within unitholders’ equity on the Company’s combined consolidated balance sheet related to derivatives at September 30, 2015, the Company will reclassify $8.0 million of gains to its combined consolidated statement of operations over the next twelve-month period as these contracts expire with the remaining $2.4 million of gains being reclassified to the Company’s combined consolidated statements of operations in later periods as the remaining contracts expire. During the three and nine months ended September 30, 2014, $0.3 million and $0.8 million were reclassified from other comprehensive income related to derivative instruments entered into during that same period.

The following table summarizes the commodity derivative activity for the three and nine months ended September 30, 2015 (in thousands):  

	Three Months EndedSeptember 30, 2015			Nine Months EndedSeptember 30, 2015
Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets(1)	$	(23,927	)	$	(77,048	)
Portion of settlements attributable to subsequent mark to market gains		(19,752	)		(49,877	)
Total cash settlements on commodity derivative contracts		(43,679	)		(126,925	)
2015 Unrealized gains prior to settlement(2)		10,989			17,822
Unrealized gain on open derivative contracts at September 30, 2015, net of amounts recognized in income in prior year(2)		120,788			192,644
Gains on mark-to-market derivatives	$	131,777		$	210,466

(1) Recognized in gas and oil production revenue.

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

The Company had cash settlement gains of $43.7 million and $1.4 million during the three months ended September 30, 2015 and 2014, respectively, and cash settlement gains of $126.9 million and cash settlement losses of $22.7 million during the nine months ended September 30, 2015 and 2014, respectively. As the underlying prices and terms in the Company’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three and nine months ended September 30, 2015 and 2014 for hedge ineffectiveness.

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Atlas Growth

At May 1, 2015, AGP entered into a secured credit facility agreement with a syndicate of banks. As of the date hereof, the lenders under the credit facility have no commitment to lend to 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. 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. AGP was in compliance with these covenants as of September 30, 2015. 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. AGP has elected not to utilize hedge accounting for its derivative instruments.  

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

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Combined Consolidated Balance Sheets		Net Amount ofAssets Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Assets
As of September 30, 2015
Current portion of derivative assets	$	399	$	—	$	399
Long-term portion of derivative assets		163		—		163
Total derivative assets	$	562	$	—	$	562
As of December 31, 2014
Current portion of derivative assets	$	—	$	—	$	—
Long-term portion of derivative assets		—		—		—
Total derivative assets	$	—	$	—	$	—

	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Combined Consolidated Balance Sheets		Net Amount of Liabilities Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Liabilities
As of September 30, 2015
Current portion of derivative liabilities	$	—	$	—	$	—
Long-term portion of derivative liabilities		—		—		—
Total derivative liabilities	$	—	$	—	$	—
As of December 31, 2014
Current portion of derivative liabilities	$	—	$	—	$	—
Long-term portion of derivative liabilities		—		—		—
Total derivative liabilities	$	—	$	—	$	—

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At September 30, 2015, AGP had the following commodity derivatives:

Crude Oil – Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Bbl)(1)		(per Bbl)(1)		(in thousands)(2)
2015		13,500	$	61.000	$	205
2016		18,000	$	63.150		249
2017		9,000	$	65.000		108
	AGP’s net assets				$	562

⁽¹⁾ “Bbl” represents barrels.

⁽²⁾ Fair value based on forward WTI crude oil prices, as applicable.

Atlas Resource

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

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Combined Consolidated Balance Sheets			Net Amount ofAssets Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Assets
As of September 30, 2015
Current portion of derivative assets	$	146,629	$	(7	)	$	146,622
Long-term portion of derivative assets		205,979		—			205,979
Total derivative assets	$	352,608	$	(7	)	$	352,601
As of December 31, 2014
Current portion of derivative assets	$	144,357	$	(98	)	$	144,259
Long-term portion of derivative assets		130,972		(370	)		130,602
Total derivative assets	$	275,329	$	(468	)	$	274,861

	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Combined Consolidated Balance Sheets		Net Amount of Liabilities Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Liabilities
As of September 30, 2015
Current portion of derivative liabilities	$	(7	)	$	7	$	—
Long-term portion of derivative liabilities		—			—		—
Total derivative liabilities	$	(7	)	$	7	$	—
As of December 31, 2014
Current portion of derivative liabilities	$	(98	)	$	98	$	—
Long-term portion of derivative liabilities		(370	)		370		—
Total derivative liabilities	$	(468	)	$	468	$	—

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AtSeptember 30, 2015, ARP had the following commodity derivatives:

Natural Gas – Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(MMBtu)(1)		(per MMBtu)(1)		(in thousands)(2)
2015		13,611,100	$	4.193	$	21,734
2016		53,546,300	$	4.229		75,852
2017		49,920,000	$	4.219		60,364
2018		40,800,000	$	4.170		44,298
2019		15,960,000	$	4.017		13,785
					$	216,033

Natural Gas – Costless Collars

Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap		Fair Value Asset
		(MMBtu)(1)		(per MMBtu)(1)		(in thousands)(2)
2015	Puts purchased		600,000	$	3.934	$	803
2015	Calls sold		600,000	$	4.634		—
						$	803

Natural Gas – Put Options – Drilling Partnerships

Production Period Ending December 31,	Option Type	Volumes		Average Fixed Price		Fair Value Asset
		(MMBtu)(1)		(per MMBtu)(1)		(in thousands)(2)
2015	Puts purchased		360,000	$	4.000	$	505
2016	Puts purchased		1,440,000	$	4.150		1,952
						$	2,457

Natural Gas – WAHA Basis Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price			Fair Value Asset
	(MMBtu)(1)		(per MMBtu)(1)			(in thousands)(7)
2015		1,200,000	$	(0.090	)	$	41
						$	41

Natural Gas Liquids – Natural Gasoline Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Gal)(1)		(per Gal)(1)		(in thousands)(8)
2015		1,260,000	$	1.923	$	1,225
					$	1,225

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Natural Gas Liquids – Propane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Gal)(1)		(per Gal)(1)		(in thousands)(4)
2015		2,016,000	$	1.016	$	1,096
					$	1,096

Natural Gas Liquids – Butane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Gal)(1)		(per Gal)(1)		(in thousands)(5)
2015		378,000	$	1.248	$	237
					$	237

Natural Gas Liquids – Iso Butane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Gal)(1)		(per Gal)(1)		(in thousands)(6)
2015		378,000	$	1.263	$	238
					$	238

Natural Gas Liquids – Crude Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Bbl)(1)		(per Bbl)(1)		(in thousands)(3)
2016		84,000	$	85.651	$	3,038
2017		60,000	$	83.780		1,828
					$	4,866

Crude Oil – Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Bbl)(1)		(per Bbl)(1)		(in thousands)(3)
2015		487,500	$	87.592	$	20,377
2016		1,557,000	$	81.471		49,856
2017		1,140,000	$	77.285		27,462
2018		1,080,000	$	76.281		22,073
2019		540,000	$	68.371		5,837
					$	125,605
		ARP’s net assets			$	352,601

⁽¹⁾ “MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons.

⁽²⁾ Fair value based on forward NYMEX natural gas prices, as applicable.

⁽³⁾ Fair value based on forward WTI crude oil prices, as applicable.

⁽⁴⁾ Fair value based on forward Mt. Belvieu propane prices, as applicable.

⁽⁵⁾ Fair value based on forward Mt. Belvieu butane prices, as applicable.

⁽⁶⁾ Fair value based on forward Mt. Belvieu iso butane prices, as applicable.

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⁽⁷⁾ Fair value based on forward WAHA natural gas prices, as applicable 

⁽⁸⁾ Fair value based on forward Mt. Belvieu natural gasoline prices, as applicable.

In June 2012, ARP entered into natural gas put option contracts which related to future natural gas production of the Drilling Partnerships. Therefore, a portion of any unrealized derivative gain or loss is allocable to the limited partners of the Drilling Partnerships based on their share of estimated gas production related to the derivatives not yet settled. At September 30, 2015, net unrealized derivative assets of $2.5 million were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts.

During the nine months ended September 30, 2015, the Company received approximately $4.9 million in net proceeds from the early termination of its 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 the Company’s Term Loan Facilities (see Note 7).

At September 30, 2015, 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 its revolving credit facility (see Note 7), 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. Each participating Drilling Partnership’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets and by a guarantee of the general partner of the Drilling Partnership. ARP, as the ultimate general partner of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnerships’ 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.

NOTE 9—FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company and its subsidiaries have established a hierarchy to measure their financial instruments at fair value which requires them to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect the Company’s and its subsidiaries’ own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Company and its subsidiaries use a market approach fair value methodology to value the assets and liabilities for their outstanding derivative contracts (see Note 8) and the Company’s rabbi trust assets (see Note 14). ARP and AGP manage and report derivative assets and liabilities on the basis of their exposure to market risks and credit risks by counterparty. ARP’s and AGP’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument. Investments held in the Company’s rabbi trust are publicly traded equity and debt securities and are therefore defined as Level 1 fair value measurements.

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Information for the Company and its subsidiaries’ assets and liabilities measured at fair value at September 30, 2015 and December 31, 2014 was as follows (in thousands):

	Level 1		Level 2			Level 3		Total
As of September 30, 2015
Assets, gross
Rabbi trust	$	5,378	$	—		$	—	$	5,378
ARP Commodity swaps		—		349,348			—		349,348
ARP Commodity puts		—		2,457			—		2,457
ARP Commodity options		—		803			—		803
AGP Commodity swaps		—		562			—		562
Total assets, gross		5,378		353,170			—		358,548
Liabilities, gross
ARP Commodity swaps		—		(7	)		—		(7	)
ARP Commodity options		—		—			—		—
AGP Commodity swaps		—		—			—		—
Total derivative liabilities, gross		—		(7	)		—		(7	)
Total assets, fair value, net	$	5,378	$	353,163		$	—	$	358,541
As of December 31, 2014
Assets, gross
Rabbi trust	$	3,925	$	—		$	—	$	3,925
ARP Commodity swaps		—		267,242			—		267,242
ARP Commodity puts		—		2,767			—		2,767
ARP Commodity options		—		5,320			—		5,320
Total assets, gross		3,925		275,329			—		279,254
Liabilities, gross
ARP Commodity swaps		—		(401	)		—		(401	)
ARP Commodity options		—		(67	)		—		(67	)
Total derivative liabilities, gross		—		(468	)		—		(468	)
Total assets, fair value, net	$	3,925	$	274,861		$	—	$	278,786

Other Financial Instruments

The estimated fair values of the Company’s and its subsidiaries’ other financial instruments have been determined based upon their assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Company and its subsidiaries could realize upon the sale or refinancing of such financial instruments.

The Company’s and its subsidiaries’ other current assets and liabilities on its 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 the Company’s and ARP’s debt at September 30, 2015 and December 31, 2014, which consist principally of ARP’s senior notes, borrowings under the Company’s term loan facilities, and borrowings under ARP’s term loan and revolving credit facilities, were $1,077.2 million and $1,363.4 million, respectively, compared with the carrying amounts of $1,587.7 million and $1,542.6 million, respectively. The carrying values of outstanding borrowings under the respective revolving and term loan credit facilities, which bear interest at variable interest rates, approximated their estimated fair values. The estimated fair values of the ARP senior notes were based upon the market approach and calculated using the yields of the ARP senior notes 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

The Company’s subsidiaries estimate the fair value of their respective asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Company’s subsidiaries and estimated inflation rates (see Note 6).

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Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the three and nine months ended September 30, 2015 and 2014 was as follows (in thousands):

	Three Months Ended September 30,
	2015				2014
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	80	$	80	$	336	$	336
Total	$	80	$	80	$	336	$	336

	Nine Months Ended September 30,
	2015				2014
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	296	$	296	$	8,283	$	8,283
Total	$	296	$	296	$	8,283	$	8,283

The Company’s subsidiaries estimate the fair value of their long-lived assets in connection with reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances. See Note 4 for a discussion of current year impairments. No impairments were recognized during the three and nine months ended September 30, 2014.

During the year ended December 31, 2014, ARP completed the Eagle Ford, Rangely and GeoMet acquisitions and AGP completed the Eagle Ford Acquisition (see Note 3). The fair value measurements of assets acquired and liabilities assumed for each of these acquisitions are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The estimated fair values of the assets acquired and liabilities assumed in the Eagle Ford Acquisition as of the acquisition date, which are reflected in the Company’s combined consolidated balance sheet as of September 30, 2015 are subject to change as the final valuations have not yet been completed, and such changes could be material. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under the Company’s subsidiaries’ existing methodology for recognizing an estimated liability for the plugging and abandonment of their gas and oil wells (see Note 6). These inputs require significant judgments and estimates by the Company’s subsidiaries’ management at the time of the valuation and are subject to change.

NOTE 10—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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.

NOTE 11—COMMITMENTS AND CONTINGENCIES

General Commitments

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 September

35

30, 2015, 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 the three months ended September 30, 2015 and 2014, $0.4 million and $0.9 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. For the nine months ended September 30, 2015 and 2014, $1.5 million and $4.7 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.

In connection with the Eagle Ford Acquisition (see Note 3), ARP guaranteed the timely payment of the deferred portion of the purchase price that is to be paid by AGP. Pursuant to the agreement between ARP and AGP, ARP will have the right to receive some or all of the assets acquired by AGP in the event of its failure to contribute its portion of any deferred payments. In September 2015, ARP agreed with AGP to have AGP transfer its remaining $36.3 million of deferred purchase obligation, along with the related undeveloped natural gas and oil properties, to ARP. ARP’s deferred purchase obligation is included within deferred acquisition purchase price on the Company’s combined consolidated balance sheets at September 30, 2015 and December 31, 2014 (see Note 3). AGP’s deferred purchase obligation was included within deferred acquisition purchase price on the Company’s combined consolidated balance sheet at December 31, 2014 (see Note 3).

In connection with ARP’s GeoMet Acquisition (see Note 3), ARP acquired certain long-term annual firm transportation obligations. Estimated fixed and determinable portions of ARP’s firm transportation obligations as of September 30, 2015 were as follows: 2015— $0.9 million; 2016— $3.6 million; 2017— $2.5 million; 2018— $1.8 million; 2019— $1.8 million; thereafter— $6.5 million.

In connection with ARP’s acquisition of assets from EP Energy E&P Company, L.P. on July 31, 2013 (the “EP Energy Acquisition”), ARP acquired certain long-term annual firm transportation obligations. Estimated fixed and determinable portions of ARP’s firm transportation obligations as of September 30, 2015 were as follows: 2015— $2.2 million; 2016— $2.2 million; and 2017 to 2019— none.

As of September 30, 2015, the Company’s subsidiaries are committed to expend approximately $45.0 million on drilling and completion expenditures.

Legal Proceedings

The Company and its subsidiaries are parties to various routine legal proceedings arising out of the ordinary course of its business. Management of the Company and its subsidiaries believe that none of these actions, individually or in the aggregate, will have a material adverse effect on the Company’s financial condition or results of operations.

NOTE 12—ISSUANCES OF UNITS

The Company recognizes gains or losses on ARP’s and AGP’s equity transactions as credits or debits, respectively, to unitholders’ equity on its combined consolidated balance sheets rather than as income or loss on its combined consolidated statements of operations. These gains or losses represent the Company’s portion of the excess or the shortage of the net

36

offering price per unit of each of ARP’s and AGP’s common units as compared to the book carrying amount per unit (see Note 2).

On February 27, 2015 the Company issued and sold an aggregate of 1.6 million of its 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 the Company’s 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 the Company to holders of the Company’s 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 the Company’s 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 of the Company; and (ii) the lower of (a) 110.0% of the volume weighted average price for the Company’s common units on the NYSE over the 30 trading days following the distribution date; and (b) $16.00 per common unit of the Company. The Company sold the Series A Preferred Units in a private transaction exempt from registration under Section 4(2) of the Securities Act. The Series A Preferred Units resulted in proceeds to the Company of $40.0 million. The Company used the proceeds to fund a portion of the $150.0 million payment by the Company 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 the unitholders of the Company, 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.

Atlas Resource Partners

In August 2015, ARP entered into a distribution agreement with MLV & Co. LLC (“MLV”). Pursuant to the distribution agreement, ARP may sell from time to time through MLV ARP’s 8.625% Class D ARP Cumulative Redeemable Perpetual Preferred Units (“Class D ARP Preferred Units”) and Class E ARP Cumulative Redeemable Perpetual Preferred Units (“Class E ARP Preferred Units”) having a maximum aggregate offering price of up to $100 million. Sales of Class D and Class E ARP Preferred 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 of 1933, as amended, including sales made directly on the NYSE, the existing trading market for the Units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP will pay MLV a commission, which shall not be more than 3.0% of the gross sales price of Class D and Class E ARP Preferred Units. ARP has agreed to reimburse MLV for certain expenses incurred in connection with entering into the distribution agreement. Under the terms of the distribution agreement, ARP may also sell Class D and Class E ARP Preferred Units from time to time to MLV as principal for its own account at a price to be agreed upon at the time of sale. Any sale of Class D and Class E ARP Preferred Units to MLV as principal would be pursuant to the terms of a separate terms agreement between ARP and MLV. During the three and nine months ended September 30, 2015, ARP issued 90,328 Class D ARP Preferred Units and 1,083 Class E ARP Preferred Units under the preferred equity distribution program for net proceeds of $1.0 million, net of $0.2 million in commissions and offering expenses paid.

In May 2015, in connection with the Arkoma Acquisition (see Note 3), 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 approximately $49.7 million. ARP used a portion of the net proceeds to fund the Arkoma Acquisition and to reduce borrowings outstanding under ARP’s revolving 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 approximately $6.0 million.  ARP pays distributions on the Class E ARP Preferred Units at a rate of 10.75% per annum of the stated liquidation preference of $25.00.

In October 2014, in connection with the Eagle Ford Acquisition (see Note 3), ARP issued 3,200,000 8.625% Class D Preferred Units at a public offering price of $25.00 per unit, yielding net proceeds of approximately $77.3 million from the offering, after deducting underwriting discounts and estimated offering expenses. ARP used the net proceeds from the offering to fund a portion of the Eagle Ford Acquisition. 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. ARP pays cumulative distributions on a quarterly basis, at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference.

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The Class D and Class E ARP Preferred Units rank senior to ARP’s common units and Class C ARP Preferred Units with respect to the payment of distributions and distributions upon a liquidation event. The Class D and Class E ARP Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by ARP or converted into its common units in connection with a change in control. At any time on or after October 15, 2019 for the Class D ARP Preferred Units and April 15, 2020 for the ARP Class E Preferred Units, ARP may, at its option, redeem the such preferred units in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, ARP may redeem such preferred units following certain changes of control, as described in the respective Certificates of Designation. If ARP does not exercise this redemption option upon a change of control, then holders of such preferred units will have the option to convert the preferred units into a number of ARP common units as set forth in the respective Certificates of Designation. If ARP exercises any of its redemption rights relating to such preferred units, the holders will not have the conversion right described above with respect to the preferred units called for redemption.

In August 2014, ARP entered into 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 terms agreement between ARP and such Agent. During the three months ended September 30, 2015, ARP issued 5,519,110 common limited partner units under the equity distribution program for net proceeds of $18.6 million, net of $0.4 million in commissions and offering expenses paid. During the nine months ended September 30, 2015, ARP issued 8,404,934 common limited partner units under the equity distribution program for net proceeds of $40.0 million, net of $1.0 million in commissions and offering expenses paid.

In May 2014, in connection with the Rangely Acquisition (see Note 3), ARP issued 15,525,000 of its common limited partner units (including 2,025,000 units pursuant to an over-allotment option) in a public offering at a price of $19.90 per unit, yielding net proceeds of approximately $297.3 million.

In March 2014, in connection with the GeoMet Acquisition (see Note 3), ARP issued 6,325,000 of its common limited partner units (including 825,000 units pursuant to an over-allotment option) in a public offering at a price of $21.18 per unit, yielding net proceeds of approximately $129.0 million.

Atlas Growth Partners

AGP has issued approximately $233.0 million of its common limited partner units through a private placement offering that expired on June 30, 2015. Of the $233.0 million of gross funds raised, we purchased $5.0 million common limited partner units during the offering.

In connection with the issuance of ARP’s and AGP’s unit offerings during the nine months ended September 30, 2015, the Company recorded gains of $3.4 million within unitholders’ equity and a corresponding decrease in non-controlling interests on its combined consolidated balance sheet and combined consolidated statement of unitholders’/owner’s equity. For the year ended December 31, 2014, the Company recorded gains of $45.0 million within equity and a corresponding decrease in non-controlling interests on its combined consolidated balance sheets and combined consolidated statement of equity.

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NOTE 13—CASH DISTRIBUTIONS

The Company’s Cash Distributions. The Company has a cash distribution policy under which it distributes, within 50 days following the end of each calendar quarter, all of its available cash (as defined in its limited liability company agreement) for that quarter to its unitholders. Distributions declared by the Company related to its Class A preferred units were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	For MonthEnded	Total Cash DistributionTo CommonUnitholders		Total Cash Distribution To PreferredUnitholders
May 15, 2015	March 31, 2015	$	—	$	333
June 12, 2015	April 30, 2015	$	—	$	334
July 15, 2015	May 31, 2015	$	—	$	334
August 14, 2015	June 30, 2015	$	—	$	335
September 14, 2015	July 31, 2015	$	—	$	336
October 15, 2015	August 31, 2015	$	—	$	336

On October 28, 2015, the Company declared a monthly distribution of $0.3 million for the month ended September 30, 2015 related to its Series A Preferred Units. The distribution will be paid on November 13, 2015 to unitholders of record at the close of business on November 9, 2015.

ARP Cash Distributions. In January 2014, ARP’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program whereby it distributes all of its available cash (as defined in ARP’s partnership agreement) for that month to its unitholders within 45 days from the month end. Prior to that, ARP paid quarterly cash distributions within 45 days from the end of each calendar quarter. If ARP’s common unit distributions in any quarter exceed specified target levels, the Company will receive between 13% and 48% of such distributions in excess of the specified target levels. While outstanding, the Class B ARP Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.40 (or $0.1333 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. While outstanding, the Class C ARP Preferred Units will receive regular quarterly cash distributions equal to the greater of (i) $0.51 (or $0.17 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. The initial quarterly distribution on the Class D ARP Preferred Units was $0.616927 per unit, representing the distribution for the period from October 2, 2014 through January 14, 2015. ARP pays quarterly distributions on the Class D ARP Preferred Units at an annual rate of $2.15625 per unit, $0.5390625 per unit paid on a quarterly basis, or 8.625% of the liquidation preference. ARP pays distributions on the Class E ARP Preferred Units at an annual rate of $2.6875 per unit, or $0.671875 per unit on a quarterly basis, or 10.75% of the $25.00 liquidation preference.

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Distributions declared by ARP from January 1, 2014 through September 30, 2015 were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	For Month Ended	Cash Distribution per CommonLimited Partner Unit		Total Cash Distribution to Common Limited Partners		Total Cash Distribution To Preferred Limited Partners(1)			Total Cash Distribution to the GeneralPartner’s Class A Units
March 17, 2014	January 31, 2014	$	0.1933	$	12,718	$	1,467		$	1,055
April 14, 2014	February 28, 2014	$	0.1933	$	12,719	$	1,466		$	1,055
May 15, 2014	March 31, 2014	$	0.1933	$	12,719	$	1,466		$	1,054
June 13, 2014	April 30, 2014	$	0.1933	$	15,752	$	1,466		$	1,279
July 15, 2014	May 31, 2014	$	0.1933	$	15,752	$	1,466		$	1,279
August 14, 2014	June 30, 2014	$	0.1966	$	16,029	$	1,492		$	1,377
September 12, 2014	July 31, 2014	$	0.1966	$	16,028	$	1,493		$	1,378
October 15, 2014	August 31, 2014	$	0.1966	$	16,032	$	1,491		$	1,378
November 14, 2014	September 30, 2014	$	0.1966	$	16,032	$	1,492		$	1,378
December 15, 2014	October 31, 2014	$	0.1966	$	16,033	$	1,491		$	1,378
January 14, 2015	November 30, 2014	$	0.1966	$	16,779	$	745	(1)	$	1,378
February 13, 2015	December 31, 2014	$	0.1966	$	16,782	$	745	(1)	$	1,378
March 17, 2015	January 31, 2015	$	0.1083	$	9,284	$	643	(1)	$	203
April 14, 2015	February 28, 2015	$	0.1083	$	9,347	$	643	(1)	$	204
May 15, 2015	March 31, 2015	$	0.1083	$	9,444	$	643	(1)	$	206
June 12, 2015	April 30, 2015	$	0.1083	$	10,179	$	642	(1)	$	221
July 15, 2015	May 31, 2015	$	0.1083	$	10,304	$	643	(1)	$	223
August 14, 2015	June 30, 2015	$	0.1083	$	10,309	$	637	(2)	$	223
September 14, 2015	July 31, 2015	$	0.1083	$	10,571	$	638	(2)	$	229
October 15, 2015	August 31, 2015	$	0.1083	$	10,949	$	637	(2)	$	236

(1) Includes payments for the Class B and Class C preferred unit monthly distributions.

(2) Includes payments for the Class C preferred unit monthly distributions. The remaining Class B Preferred Units were converted on July 25, 2015, and the Class B Preferred Unitholders received additional ARP common units upon conversion in lieu of the June distribution. No Class B Preferred Units were outstanding at September 30, 2015.  

Date Cash Distribution Paid	For the Period	Cash Distribution per Class D PreferredLimited Partner Unit		Total Cash DistributionTo Class D Preferred Limited Partners
January 15, 2015	October 2, 2014 – January 14, 2015	$	0.6169270	$	1,974
April 15, 2015	January 15, 2015 – April 14, 2015	$	0.5390630	$	2,156
July 15, 2015	April 15, 2015 – July 14, 2015	$	0.5390625	$	2,157
October 15, 2015	July 15, 2015 – October 14, 2015	$	0.5390625	$	2,205

Date Cash Distribution Paid	For the Period	Cash Distribution per Class E PreferredLimited Partner Unit		Total Cash DistributionTo Class E Preferred Limited Partners
July 15, 2015	April 14, 2015 – July 14, 2015	$	0.6793	$	173
October 15, 2015	July 15, 2015 – October 14, 2015	$	0.6718750	$	172

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On October 28, 2015, ARP declared a monthly distribution of $0.1083 per common unit for the month of September 30, 2015. The $11.9 million distribution, including $0.2 million and $0.6 million to the general partner and preferred limited partners, respectively, will be paid on November13, 2015 to unitholders of record at the close of business on November9, 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 target 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 declared by AGP from January 1, 2014 through September 30, 2015 were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	For the Quarter Ended	Cash Distribution per CommonLimited Partner Unit		Total Cash Distribution to Common Limited Partners		Total Cash Distribution to the GeneralPartner’s Class A Units
February 14, 2014(1)	December 31, 2013	$	0.1167	$	120	$	2
May 15, 2014	March 31, 2014	$	0.1750	$	223	$	6
August 14, 2014	June 30, 2014	$	0.1750	$	342	$	7
November 14, 2014	September 30, 2014	$	0.1750	$	841	$	16
February 13, 2015	December 31, 2014	$	0.1750	$	1,636	$	33
May 15, 2015	March 31, 2015	$	0.1750	$	2,180	$	45
August 14, 2015	June 30, 2015	$	0.1750	$	2,646	$	54

(1) Represents a pro-rated cash distribution of $0.1750 per common limited partner unit and general partner unit for the period from November 1, 2013, the date AGP commenced operations.

On November 5, 2015, AGP declared a quarterly distribution of $0.1750 per common unit for the quarter ended September 30, 2015. The $4.2 million distribution, including $0.1 million to the general partner, will be paid on November 13, 2015 to unitholders of record at the close of business on September 30, 2015.

NOTE 14—BENEFIT PLANS

2015 Long-Term Incentive Plan

The Board of Directors of the Company approved and adopted the Company’s 2015 Long-Term Incentive Plan (“2015 LTIP”) effective February 2015. The 2015 LTIP provides equity incentive awards to officers, employees and managing board members of the Company and its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for the Company. The 2015 LTIP is administered by a committee consisting of the Board or committee of the Board or board of an affiliate appointed by the Board (the “LTIP Committee”). Under the 2015 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 5,250,000 units. At September 30, 2015, the Company had 2,581,510 phantom units and unit options outstanding under the 2015 LTIP, with 2,668,490 phantom units and unit options available for grant.

In the case of awards held by eligible employees, following a “change in control”, as defined in the 2015 LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the 2015 LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment,

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but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full.

In connection with a change in control, the LTIP Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any Participant, subject to the terms of any award agreements and employment agreements to which the Company (or any affiliate) and any Participant are party, may take one or more of the following actions (with discretion to differentiate between individual Participants and awards for any reason):

· cause awards to be assumed or substituted by the surviving entity (or a parent, subsidiary or affiliate of such surviving entity);

· accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards shall vest (and, with respect to options, become exercisable) as to the units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction;

· provide for the payment of cash or other consideration to Participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards);

· terminate all or some awards upon the consummation of the change-in-control transaction, but only if the LTIP Committee provides for full vesting of awards immediately prior to the consummation of such transaction; and

· make such other modifications, adjustments or amendments to outstanding awards as the LTIP Committee deems necessary or appropriate.

2015 Phantom Units. A phantom unit entitles a Participant to receive a Company common unit or its then-Fair Market Value in cash or other securities or property, upon vesting of the phantom unit. In tandem with phantom unit grants, the LTIP Committee may grant Distribution Equivalent Rights (“DERs”), which are the right to receive cash, securities, or property per phantom unit in an amount equal to, and at the same time as, the cash distributions or other distributions of securities or property the Company makes on a common unit during the period such phantom unit is outstanding. Generally, phantom units to be granted to employees under the 2015 LTIP will vest over a designated period of time and phantom units granted to non-employee directors generally vest over a four year period, 25% per year. Of the phantom units outstanding under the 2015 LTIP at September 30, 2015, there are 846,372 units that will vest within the following twelve months. The director phantom units outstanding under the 2015 LTIP at September 30, 2015 include DERs. No amounts were paid during the three and nine months ended September 30, 2015 and 2014 with respect to DERs.

The following table sets forth the 2015 LTIP phantom unit activity for the periods indicated:

	Three Months Ended September 30,
	2015					2014
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value
Outstanding, beginning of period		2,764,210		$	6.50		—	$	—
Granted		10,500			4.20		—		—
Vested(1)		—			—		—		—
Forfeited		(193,200	)		6.43		—		—
Outstanding, end of period(2)(3)(4)		2,581,510		$	6.49		—	$	—
Non-cash compensation expense recognized (in thousands)				$	2,375			$	—

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	Nine Months Ended September 30,
	2015					2014
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		—		$	—		—	$	—
Granted		2,774,710			6.49		—		—
Vested(1)		—			—		—		—
Forfeited		(193,200	)		6.43		—		—
Outstanding, end of period(2)(3)(4)		2,581,510		$	6.49		—	$	—
Non-cash compensation expense recognized (in thousands)				$	3,322			$	—

(1) No phantom unit awards vested during the three and nine months ended September 30, 2015 and 2014.

(2) The aggregate intrinsic value of phantom unit awards outstanding at September 30, 2015 was approximately $5.8 million.

(3) There was $0.1 million recognized as liabilities on the Company’s consolidated balance sheet at September 30, 2015 representing 68,910 units, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair value for these units was $9.07at September 30, 2015.

At September 30, 2015, the Company had approximately $13.0 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2015 LTIP based upon the fair value of the awardswhich is expected to be recognized over a weighted average period of 1.8 years.  

2015 Unit Options. A unit option entitles a Participant to receive a common unit of the Company upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option shall not be less than the fair market value of the Company’s common unit on the date of grant of the option. The LTIP Committee also determines how the exercise price may be paid by the Participant. The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Generally, unit options to be granted under the 2015 LTIP will vest over a designated period of time. There are no unit options outstanding under the 2015 LTIP at September 30, 2015. No cash was received from the exercise of options for the three and nine months ended September 30, 2015 and 2014, respectively.

Restricted Units

Restricted units are actual common units issued to a participant that are subject to vesting restrictions and evidenced in such manner as the LTIP Committee may deem appropriate, including book-entry registration or issuance of one or more unit certificates. Prior to or upon the grant of an award of restricted units, the LTIP Committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both. A holder of restricted units will have certain rights of holders of common units in general, including the right to vote the restricted units. However, during the period in which the restricted units are subject to vesting restrictions, the holder will not be permitted to sell, assign, transfer, pledge or otherwise encumber the restricted units. There were no restricted units granted, issued or outstanding through September 30, 2015.

Rabbi Trust

In 2011, the Company established an excess 401(k) plan relating to certain executives. In connection with the plan, the Company established a “rabbi” trust for the contributed amounts. At September 30, 2015 and December 31, 2014, the Company reflected $5.4 million and $3.9 million, respectively, related to the value of the rabbi trust within other assets, net on its combined consolidated balance sheets, and recorded corresponding liabilities of $5.4 million and $3.9 million as of those same dates within asset retirement obligations and other on its combined consolidated balance sheets. During the three and nine months ended September 30, 2015 and 2014, no distributions were made to participants related to the rabbi trust.

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ARP Long-Term Incentive Plan

ARP’s 2012 Long-Term Incentive Plan (the “ARP LTIP”), effective March 2012, provides incentive awards to officers, employees and directors as well as employees of the Company and its affiliates, consultants and joint venture partners who perform services for ARP. The ARP LTIP is administered by the board of the Company, a committee of the board or the board (or committee of the board) of an affiliate (the “ARP LTIP Committee”). Under ARP’s 2012 LTIP, the ARP LTIP Committee may grant awards of phantom units, restricted units, or unit options for an aggregate of 2,900,000 common limited partner units of ARP. At September 30, 2015, ARP had 1,736,920 phantom units, restricted units and unit options outstanding under the ARP LTIP with 182,008 phantom units, restricted units and unit options available for grant. Share based payments to non-employee directors, which have a cash settlement option, are recognized within liabilities in the consolidated financial statements based upon their current fair market value.

In the case of awards held by eligible employees, following a “change in control”, as defined in the ARP LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the ARP LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full.

In connection with a change in control, the ARP LTIP Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which the Company, as general partner, (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason):

· cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity);

· accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to ARP’s common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction;

· provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards);

· terminate all or some awards upon the consummation of the change-in-control transaction, but only if the ARP LTIP Committee provides for full vesting of awards immediately prior to the consummation of such transaction; and

· make such other modifications, adjustments or amendments to outstanding awards or the new equity plan as the ARP LTIP Committee deems necessary or appropriate.

ARP Phantom Units. Phantom units represent rights to receive a common unit, an amount of cash or other securities or property based on the value of a common unit, or a combination of common units and cash or other securities or property upon vesting. Phantom units are subject to terms and conditions determined by the ARP LTIP Committee, which may include vesting restrictions. In tandem with phantom unit grants, the ARP LTIP Committee may grant DERs, which are the right to receive an amount in cash, securities, or other property equal to, and at the same time as, the cash distributions or other distributions of securities or other property made by ARP with respect to a common unit during the period that the underlying phantom unit is outstanding. Phantom units granted under the ARP LTIP generally will vest 25% of the original granted amount on each of the four anniversaries of the date of grant. Of the phantom units outstanding under the ARP LTIP at September 30, 2015, 162,496 units will vest within the following twelve months. All phantom units outstanding under the ARP LTIP at September 30, 2015 include DERs. During the three months ended September 30, 2015 and 2014, ARP paid $0.1 million and $0.5 million, respectively, with respect to the ARP LTIP’s DERs. During the nine months ended September 30, 2015 and 2014, ARP paid $0.6 million and $1.5 million, respectively, with respect to the ARP LTIP’s DERs. These amounts were recorded as reductions of equity on the Company’s combined consolidated balance sheets.

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The following table sets forth the ARP LTIP phantom unit activity for the periods indicated:

	Three Months Ended September 30,
	2015					2014
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of period		411,257		$	21.10		901,207		$	23.29
Granted		—			—		9,400			19.85
Vested and issued(1)		(68,187	)		22.15		(115,797	)		24.54
Forfeited		(23,914	)		23.00		—			—
Outstanding, end of period(2)(3)		319,156		$	20.74		794,810		$	23.07
Vested and not yet issued(4)		3,125		$	21.02		5,412		$	25.25
Non-cash compensation expense recognized (in thousands)				$	375				$	1,647

	Nine Months Ended September 30,
	2015					2014
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		799,192		$	22.70		839,808		$	24.31
Granted		9,730			8.50		236,423			20.28
Vested and issued(1)		(457,727	)		23.75		(262,671	)		24.51
Forfeited		(32,039	)		23.01		(18,750	)		23.00
Outstanding, end of period(2)(3)		319,156		$	20.74		794,810		$	23.07
Vested and not yet issued(4)		3,125		$	21.02		5,412		$	25.25
Non-cash compensation expense recognized (in thousands)				$	3,692				$	4,968

(1) The intrinsic values of phantom unit awards vested and issued during the three months ended September 30, 2015 and 2014 were $0.3 million and $2.3 million, respectively, and $3.9 million and $5.2 million during the nine months ended September 30, 2015 and 2014, respectively.

(2) The aggregate intrinsic value for phantom unit awards outstanding at September 30, 2015was $0.9 million.

(3) There were approximately $16,000 and $0.1 million recognized as liabilities on the Company’s consolidated balance sheets at September 30, 2015 and December 31, 2014, respectively, representing 14,005 and 26,579units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were $13.39 and $21.16at September 30, 2015 and December 31, 2014, respectively. There was $0.2 million recognized as liabilities on the Company’s consolidated balance sheet at the period ended September 30, 2014 representing 29,035 units that participants may opt to settle in cash instead of units. The weighted average grant date fair value for these units was $21.09 at September 30, 2014.

(4) The intrinsic values of phantom unit awards vested, but not yet issued at September 30, 2015 and 2014 were approximately $2,000 and $0.1 million, respectively.

At September 30, 2015, ARP had approximately $2.3 million in unrecognized compensation expense related to unvested phantom units outstanding under the ARP LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 1.6 years.

ARP Unit Options. A unit option is the right to purchase an ARP common unit in the future at a predetermined price (the exercise price). The exercise price of each ARP unit option is determined by the ARP LTIP Committee and may be equal to or greater than the fair market value of ARP’s common unit on the date of grant of the option. The ARP LTIP Committee will determine the vesting and exercise restrictions applicable to an ARP award of options, if any, and the method by which the exercise price may be paid by the participant. Unit option awards expire 10 years from the date of grant. Unit options granted under the ARP LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. There were 83,163 unit options outstanding under the ARP LTIP at September 30, 2015 that will vest within the following twelve months. No cash was received from the exercise of options for the three and nine months ended September 30, 2015 and 2014.

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The following table sets forth the ARP LTIP unit option activity for the periods indicated:

	Three Months Ended September 30,
	2015						2014
	Number of Unit Options			Weighted Average Exercise Price			Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of period		1,452,800		$	24.66			1,468,925		$	24.66
Granted		—			—			—			—
Exercised (1)		—			—			—			—
Forfeited		(35,036	)		24.67			(3,750	)		24.67
Outstanding, end of period(2)(3)		1,417,764		$	24.66			1,465,175		$	24.66
Options exercisable, end of period(4)		1,332,976		$	24.67			732,025		$	24.67
Non-cash compensation expense recognized (in thousands)				$	(87	)				$	342

	Nine Months Ended September 30,
	2015					2014
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of year		1,458,300		$	24.66		1,482,675		$	24.66
Granted		—			—		—			—
Exercised (1)		—			—		—			—
Forfeited		(40,536	)		24.68		(17,500	)		24.46
Outstanding, end of period(2)(3)		1,417,764		$	24.66		1,465,175		$	24.66
Options exercisable, end of period(4)		1,332,976		$	24.67		732,025		$	24.67
Non-cash compensation expense recognized (in thousands)				$	805				$	1,374

(1) No options were exercised during the three and nine months ended September 30, 2015 and 2014.

(2) The weighted average remaining contractual life for outstanding options at September 30, 2015 was 6.6 years.

(3) There were no aggregate intrinsic values of options outstanding at September 30, 2015 and 2014.

(4) The weighted average remaining contractual life for exercisable options at September 30, 2015 was 6.6 years. There were no intrinsic values for options exercisable at September 30, 2015 and 2014.

At September 30, 2015, ARP had approximately $0.1 million in unrecognized compensation expense related to unvested unit options outstanding under the ARP LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 0.6 years. ARP used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted.

Restricted Units

Restricted units are actual common units issued to a participant that are subject to vesting restrictions and evidenced in such manner as the ARP LTIP Committee may deem appropriate, including book-entry registration or issuance of one or more unit certificates. Prior to or upon the grant of an award of restricted units, the ARP LTIP Committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both. A holder of restricted units will have certain rights of holders of common units in general, including the right to vote the restricted units. However, during the period in which the restricted units are subject to vesting restrictions, the holder will not be permitted to sell, assign, transfer, pledge or otherwise encumber the restricted units. There were no restricted units granted, issued or outstanding through September 30, 2015.

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NOTE 15—OPERATING SEGMENT INFORMATION

The Company’s operations include three reportable operating segments: ARP, AGP, and corporate and other. These operating segments reflect the way the Company manages its operations and makes business decisions. Corporate and other includes the Company’s equity investment in Lightfoot (see Note 1), as well as its general and administrative and interest expenses. Operating segment data for the periods indicated were as follows (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Atlas Resource:
Revenues	$	257,895		$	206,699		$	597,609		$	506,953
Operating costs and expenses		(80,486	)		(123,567	)		(244,126	)		(313,720	)
Depreciation, depletion and amortization expense		(40,463	)		(64,578	)		(125,948	)		(176,077	)
Asset impairment		(672,246	)		—			(672,246	)		—
Loss on asset sales and disposal		(362	)		(92	)		(276	)		(1,686	)
Interest expense		(25,192	)		(16,577	)		(75,105	)		(43,028	)
Segment income (loss)	$	(560,854	)	$	1,885		$	(520,092	)	$	(27,558	)
Atlas Growth:
Revenues	$	4,591		$	1,538		$	8,767		$	4,563
Operating costs and expenses		(3,385	)		(3,885	)		(11,697	)		(8,622	)
Asset impairment		(7,291	)		—			(7,291	)		—
Depreciation, depletion and amortization expense		(2,848	)		(490	)		(5,095	)		(1,436	)
Interest expense		(14	)		—			(14	)		—
Segment loss	$	(8,947	)	$	(2,837	)	$	(15,330	)	$	(5,495	)
Corporate and other:
Revenues	$	348		$	352		$	504		$	824
General and administrative		(5,050	)		(903	)		(27,624	)		(5,523	)
Gain on asset sales and disposal		—			—			—			3
Interest expense		(3,084	)		(2,846	)		(21,109	)		(8,446	)
Loss on early extinguishment of debt		(4,726	)		—			(4,726	)		—
Segment loss	$	(12,512	)	$	(3,397	)	$	(52,955	)	$	(13,142	)
Reconciliation of segment income (loss) to net loss:
Segment income (loss):
Atlas Resource	$	(560,854	)	$	1,885		$	(520,092	)	$	(27,558	)
Atlas Growth		(8,947	)		(2,837	)		(15,330	)	$	(5,495	)
Corporate and other		(12,512	)	$	(3,397	)	$	(52,955	)	$	(13,142	)
Net loss	$	(582,313	)	$	(4,349	)	$	(588,377	)	$	(46,195	)
Reconciliation of segment revenues to total revenues:
Segment revenues:
Atlas Resource	$	257,895		$	206,699		$	597,609		$	506,953
Atlas Growth		4,591			1,538			8,767		$	4,563
Corporate and other		348			352			504		$	824
Total revenues	$	262,834		$	208,589		$	606,880		$	512,340
Capital expenditures:
Atlas Resource	$	32,799		$	55,930		$	102,290		$	150,579
Atlas Growth		7,659			567			20,777			12,147
Corporate and other		—			—			—			—
Total capital expenditures	$	40,458		$	56,497		$	123,067		$	162,726

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	September 30,		December 31,
	2015		2014
Balance sheet:
Goodwill:
Atlas Resource	$	13,639	$	13,639
Atlas Growth		—		—
Corporate and other		—		—
	$	13,639	$	13,639
Total assets:
Atlas Resource	$	2,096,758	$	2,791,553
Atlas Growth		171,522		190,161
Corporate and other		37,581		44,601
	$	2,305,861	$	3,026,315

NOTE 16—SUBSEQUENT EVENTS

The Company

On October 28, 2015, the Company declared a monthly cash distribution of $0.3 million for the month ended September 30, 2015 related to its Series A Preferred Units. The distribution will be paid on November 13, 2015 to unitholders of record at the close of business on November 9, 2015.

Atlas Resource

Cash Distributions. On October 28, 2015, ARP declared a monthly distribution of $0.1083 per common unit for the month of September 30, 2015. The $11.9 million distribution, including $0.2 million and $0.6 million to the general partner and preferred limited partners, respectively, will be paid on November 13, 2015 to unitholders of record at the close of business on November 9, 2015.

On October 15, 2015, ARP paid a quarterly distribution of $0.5390625 per Class D ARP Preferred Unit, or $2.2 million, for the period from July 15, 2015 through October 14, 2015 to Class D ARP Preferred Unitholders of record as of October 1, 2015.

On October 15, 2015, ARP paid a quarterly distribution of $0.6791875 per Class E ARP Preferred Unit, or $0.2 million, for the period from July 15, 2015 through October 14, 2015 to Class E ARP Preferred Unitholders of record as of October 1, 2015.

Atlas Growth

On November 5, 2015, AGP declared a quarterly distribution of $0.1750 per common unit for the quarter ended September 30, 2015. The $4.2 million distribution, including $0.1 million to the general partner, will be paid on November 13, 2015 to unitholders of record at the close of business on September 30, 2015.

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

Forward-Looking Statements

When used in this Form 10-Q, the words “believes,” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties more particularly described in “Item 1A. Risk Factors” in our annual report on Form 10-K for the year ended December 31, 2014, as supplemented by this Form 10-Q. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

We believe the assumptions underlying the 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, L.P. (“Atlas Energy”), on February 27, 2015. However, our historical 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. References in this 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 Delaware limited liability company formed in October 2011. At September 30, 2015, 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 23.6% 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 (NYSE: ARP) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”), with operations in basins across the United States. 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;

· 80.0% general partner interest and a 2.1% limited partner interest in Atlas Growth Partners, L.P., a Delaware limited partnership that currently conducts natural gas and oil operations in the mid-continent region of the United States (“AGP”); and

· 15.9% general partner interest and 12.0% limited partner interest in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, its general partner, which incubate new MLPs and invest in existing MLPs;

On February 27, 2015, our former owner, 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. In connection with the Separation, we paid $150.0 million to Atlas Energy related to the repayment of Atlas Energy’s term loan credit facility. We used proceeds from the issuance of our Series A preferred units (see “Issuance of Units”) and the issuance of our term loan credit facilities (see “Credit Facilities”) to fund the payment.

FINANCIAL PRESENTATION

Our 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 combined consolidated financial statements, Atlas Energy’s net investment in us is shown as equity in the 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 combined

49

consolidated balance sheets and related 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. Actual balances and results could be different from those estimates.

In connection with Atlas Energy’s merger with Targa and our concurrent unit distribution, 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 generally accepted accounting principles, 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. In addition, all of Atlas Energy’s other historical borrowings were allocated to our historical financial statements in the same ratio.  

Our combined consolidated financial statements contain our accounts and those of our combined consolidated subsidiaries, all of which are wholly-owned at September 30, 2015, except for ARP and AGP, which we control. Due to the structure of our ownership interests in ARP and AGP, in accordance with generally accepted accounting principles, we consolidate the financial statements of ARP and AGP into our combined consolidated financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in ARP and AGP are reflected as income (loss) attributable to non-controlling interests in our combined consolidated statements of operations and as a component of unitholders’ equity on our combined consolidated balance sheets. Throughout this section, when we refer to “our” combined consolidated financial statements, we are referring to the 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. All significant intercompany transactions and balances have been eliminated in the combination of the financial statements. Certain amounts in the prior year’s consolidated financial statements have been reclassified to conform to the current year presentation.

SUBSEQUENT EVENTS

Cash Distributions. On October 28, 2015, we declared a monthly cash distribution of $0.3 millionfor the month ended September 30, 2015 related to our Series A convertible preferred units (“Series A Preferred Units”). The distribution will be paid on November 13, 2015 to unitholders of record at the close of business on November 9, 2015.

Atlas Resource

Cash Distributions. On October 28, 2015, ARP declared a monthly distribution of $0.1083 per common unit for the month of September 30, 2015. The $11.9 million distribution, including $0.2 million and $0.6 million to the general partner and the preferred limited partners, respectively, will be paid on November 13, 2015 to unitholders of record at the close of business on November 9, 2015.

On October 15, 2015, ARP paid a quarterly distribution of $0.5390625 per 8.625% Class D cumulative redeemable perpetual preferred unit (“Class D ARP Preferred Units”), or $2.2 million, for the period from July 15, 2015 through October 14, 2015 to Class D Preferred Unitholders of record as of October 1, 2015.

On October 15, 2015, ARP paid an initial quarterly distribution of $0.6718750 per 10.75% Class E cumulative redeemable perpetual preferred unit (“Class E ARP Preferred Units”), or $0.2 million, for the period from July 15, 2015 through October 14, 2015 to Class E ARP Preferred Unitholders of record as of October 1, 2015.

Atlas Growth

On November 5, 2015, AGP declared a quarterly distribution of $0.1750 per common unit for the quarter ended September 30, 2015. The $4.2 million distribution, including $0.1 million to the general partner, will be paid on November 13, 2015 to unitholders of record at the close of business on September 30, 2015.

RECENT DEVELOPMENTS

Term Loan Credit Facilities. On August 10, 2015, we entered into a credit agreement (the “Riverstone Credit Agreement”) with Riverstone Credit Partners, L.P., as administrative agent, and the lenders party thereto, for a new term loan facility (the “Riverstone Term Loan Facility”) in an aggregate principal amount of $82.7 million maturing in August 2020.  The borrowings under the Riverstone Term Loan Facility were used to repay in full outstanding borrowings under our existing term loan facility.  At September 30, 2015, $82.7 million was outstanding under the Riverstone Term Loan Facility.

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Our obligations under the Riverstone Term Loan Facility are secured on a first priority basis by security interests in substantially all of our assets and the assets of each of New Atlas Holdings, LLC, our direct wholly owned subsidiary, Atlas Lightfoot, LLC and any of our other material subsidiaries that later guarantee indebtedness under the Riverstone Term Loan Facility, including all equity interests directly held by New Atlas Holdings, LLC or any guarantor and all tangible and intangible property of us and the guarantors (subject to certain customary exclusions and exceptions).  Borrowings under the Riverstone Term Loan Facility bear interest, at our option, at either (i) LIBOR plus 7.0% (as used with respect to the Riverstone Term Loan Facility, “Eurodollar Loans”) or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 6.0% (as used with respect to the Riverstone Term Loan Facility, an “ABR Loan”). Interest is generally payable at interest payment periods selected by us for Eurodollar Loans and quarterly for ABR Loans (see “Credit Facilities”).

On February 27, 2015, we entered into a Credit Agreement with Deutsche Bank AG New York Branch, as administrative agent, and the lenders from time to time party thereto (the “Credit Agreement”). The Credit Agreement provided for a Secured Senior Interim Term Loan Facility in an aggregate principal amount of $30.0 million (the “Interim Term Loan Facility”) and a Secured Senior Term Loan A Facility in an aggregate principal amount of approximately $97.8 million (the “Term Loan A Facility” and together with the Interim Term Loan Facility, the “Term Loan Facilities”). The Interim Term Loan Facility matured on August 27, 2015 and the Term Loan A Facility was to mature on February 26, 2016. In June 2015, we prepaid $33.1 million on the Term Loan Facilities in connection with the Arkoma Acquisition (see “Recent Developments”).  In August 2015, we repaid in full the remaining $82.7 outstanding under the Term Loan Facilities (see “Credit Facilities”).

Preferred Unit Purchase Agreement. On February 27, 2015, weissued and sold an aggregate of 1.6 million of our newly created Series A Preferred Units, with a liquidation preference of $25.00 per unit, at a purchase price of $25.00 per unit to certain members of our management, two management members of the Board, and outside investors. We sold the Series A Preferred Units in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”). The private placement resulted in proceeds to us of $40.0 million. We used the proceeds to fund a portion of the $150.0 million payment 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 (see “Issuances of Units”). 

On August 26, 2015, at a special meeting of the unitholders of the Company, 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

Atlas Resource

Arkoma Acquisition. On June 5, 2015, ARP completed the acquisition of our coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma for approximately $31.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). The Arkoma Acquisition had an effective date of January 1, 2015, however, as the acquisition constituted a transaction between entities under common control, we retrospectively adjusted our consolidated financial statements for any date prior to the date of acquisition to reflect our results on a consolidated basis with the results of the Arkoma assets as of or at the beginning of the respective period.

Issuance of ARP Common Units. 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 approximately $49.7 million. ARP used a portion of the net proceeds to fund the Arkoma Acquisition and to reduce borrowings outstanding under its revolving credit facility (see “Issuance of Units”).

Issuance of ARP Preferred Units. 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 Class E Unit for net proceeds of approximately $6.0 million. Distributions are payable on the Class E ARP Preferred Units at a rate of 10.75% per annum of the stated liquidation preference of $25.00.

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Credit Facility Amendment. On February 23, 2015, ARP entered into a Sixth Amendment to the Second Amended and Restated Credit Agreement (the “Sixth Amendment”) with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, which amendment amends the Second Amended and Restated Credit Agreement (the “ARP Credit Agreement”), dated July 31, 2013. Among other things, the Sixth Amendment:

· reduced the borrowing base under the ARP Credit Agreement from $900.0 million to $750.0 million;

· permitted the incurrence of second lien debt in an aggregate principal amount up to $300.0 million;

· rescheduled the May 1, 2015 borrowing base redetermination for July 1, 2015;

· if the borrowing base utilization (as defined in the ARP Credit Agreement) is less than 90%, increased the applicable margin on Eurodollar loans and ABR loans by 0.25% from previous levels,

· following the next scheduled redetermination of the borrowing base, upon the issuance of senior notes or the incurrence of second lien debt, reduces the borrowing base by 25% of the stated amount of such senior notes or additional second lien debt; and

· revised the maximum ratio of Total Funded Debt to EBITDA to be (i) 5.25 to 1.0 as of the last day of the quarters ending on March 31, 2015, June 30, 2015, September 30, 2015, December 31, 2015 and March 31, 2016, (ii) 5.00 to 1.0 as of the last day of the quarters ending on June 30, 2016, September 30, 2016 and December 31, 2016, (iii) 4.50 to 1.0 as of the last day of the quarter ending on March 31, 2017 and (iv) 4.00 to 1.0 as of the last day of each quarter thereafter.

Second Lien Term Loan Facility. On February 23, 2015, ARP entered into a Second Lien Credit Agreement (the “Second Lien Credit Agreement”) with certain lenders and Wilmington Trust, National Association, as administrative agent. The Second Lien Credit Agreement provides for a second lien term loan in an original principal amount of $250.0 million (the “Term Loan Facility”). The Term Loan Facility matures on February 23, 2020.

ARP’s obligations under the Term Loan Facility are secured on a second priority basis by security interests in all of its assets and those of its restricted subsidiaries (the “Loan Parties”) that guarantee ARP’s existing first lien revolving credit facility. In addition, the obligations under the Term Loan Facility are guaranteed by ARP’s material restricted subsidiaries.  Borrowings under the Term Loan Facility bear interest, at ARP’s option, at either (i) LIBOR plus 9.0% or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, in each case plus 8.0% (an “ABR Loan”). Interest is generally payable at the applicable maturity date for Eurodollar loans and quarterly for ABR loans (see “Credit Facilities”).

Atlas Growth

Private Placement Fundraising. 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 during the offering.

CONTRACTUAL REVENUE ARRANGEMENTS

Natural Gas and Oil Production

Natural Gas. Our subsidiaries market the majority of their natural gas production to gas marketers directly or to third party plant operators who process and market our subsidiaries’ gas. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The pricing indices for the majority of our subsidiaries’ production areas are as follows:

· Appalachian Basin - Dominion South Point, Tennessee Gas Pipeline Zone 4 (200 Leg), Transco Leidy Line, Columbia Appalachia, NYMEX and Transco Zone 5;

· Mississippi Lime - Southern Star;

· Barnett Shale and Marble Falls- primarily Waha;

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· Raton – ANR, Panhandle, and NGPL;  

· Black Warrior Basin – Southern Natural;

· Eagle Ford – Transco Zone 1;

· Arkoma – Enable Gas; and

· Other regions - primarily the Texas Gas Zone SL spot market (New Albany Shale) and the Cheyenne Hub spot market (Niobrara).

Our subsidiaries attempt to sell the majority of natural gas produced at monthly, fixed index prices and a smaller portion at index daily prices.

ARP holds firm transportation obligations on Colorado Interstate Gas for the benefit of production from the Raton Basin in the New Mexico/Colorado Area. The total of firm transportation obligations held is approximately 82,500 dth/d under contracts expiring in 2016. ARP also holds firm transportation obligations on East Tennessee Natural Gas (25,000 dth/d), Columbia Gas Transmission (14,500 dth/d) and Equitrans (12,300 dth/d) for the benefit of production from the central Appalachian Basin under contracts expiring between the years 2015 and 2024 (“dth” represents dekatherm, each, of which is equivalent to 1MMBtu.).

Crude Oil. Crude oil produced from our subsidiaries’ wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. The crude oil is typically sold at the prevailing spot market price for each region, less appropriate trucking/pipeline charges. The oil and natural gas liquids production of ARP’s Rangely assets flows into a common carrier pipeline and is sold at prevailing market prices, less applicable transportation and oil quality differentials. Our subsidiaries do not have delivery commitments for fixed and determinable quantities of crude oil in any future periods under existing contracts or agreements.

Natural Gas Liquids. NGLs are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas to meet pipeline specifications for transport or sale to end users or marketers operating on the receiving pipeline. The resulting plant residue natural gas is sold as indicated above and our subsidiaries’ NGLs are generally priced and sold using the Mont Belvieu (TX) or Conway (KS) regional processing indices. The cost to process and fractionate the NGLs from the gas stream is typically either a volumetric fee for the gas and liquids processed or a percentage retention by the processing and fractionation facility. Our subsidiaries do not have delivery commitments for fixed and determinable quantities of NGLs in any future periods under existing contracts or agreements.

Atlas Resources’ Drilling Partnerships

Certain energy activities are conducted by ARP through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by ARP is deployed to drill and complete wells included within the partnership. As it deploys Drilling Partnership investor capital, ARP recognizes certain management fees it is entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if ARP has Drilling Partnership investor capital that has not yet been deployed, we will recognize a current liability titled “Liabilities Associated with Drilling Contracts” on our consolidated balance sheets. After the Drilling Partnership well is completed and turned in line, ARP is entitled to receive additional operating and management fees, which are included within well services and administration and oversight revenue, respectively, on a monthly basis while the well is operating. In addition to the management fees it is entitled to receive for services provided, ARP is also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which generally approximates 30%.

As the ultimate managing general partner of our Drilling Partnerships, ARP receives the following Drilling Partnership management fees:

· Well construction and completion. For each well that is drilled by a Drilling Partnership, ARP receives a 15% mark-up on those costs incurred to drill and complete wells included within the partnership. Such fees are earned, in accordance with each Drilling Partnership’s partnership agreement, and recognized as the services are performed, typically between 60 and 270 days.

· Administration and oversight. For each well drilled by a Drilling Partnership, ARP currently receives a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which is earned in accordance with each

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Drilling Partnership’spartnership agreement and recognized at the initiation of a well. Additionally, the Drilling Partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. The well administrative fee is earned on a monthly basis as the services are performed; and 

· Well services. Each Drilling Partnership pays ARP a monthly per well operating fee, currently $1,000 to $2,000, depending on the type of well, for the life of the well. Such fees are earned on a monthly basis as the services are performed.

Gathering and processing revenue includes gathering fees ARP charges to the Drilling Partnership wells for its processing plants in the New Albany and the Chattanooga Shales. Generally, ARP charges a gathering fee to the 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 it remits a gathering fee of 16%. However, based on the respective Drilling Partnership partnership agreements, ARP charges its Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses within its partnership management segment, specifically those in the Appalachian Basin, will generally exceed the revenues collected from Drilling Partnerships by approximately 3%.

While the 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.

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.

Natural Gas and Oil Production

The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines during the fourth quarter of 2014 and the first three quarters of 2015. The causes of these declines are based on a number of factors, including, but not limited to, a significant increase in natural gas, oil and NGL production. While we anticipate continued high levels of exploration and production activities for our subsidiaries over the long-term in the areas in which they operate, fluctuations in energy prices can greatly affect production rates and investments in the development of new natural gas, oil and NGL reserves.

Our and our subsidiaries’ future gas and oil reserves, production, cash flow, the ability to make payments on debt and the ability to make distributions to unitholders, including ARP’s and AGP’s ability to make distributions to us, depend on our subsidiaries’ success in producing current reserves efficiently, developing existing acreage and acquiring additional proved reserves economically. Our subsidiaries face the challenge of natural production declines and volatile natural gas, oil and NGL prices. As initial reservoir pressures are depleted, natural gas and oil production from particular wells decrease. Our subsidiaries attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than produced.

RESULTS OF OPERATIONS

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Gas and Oil Production

Production Profile. At September 30, 2015, 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 September 30, 2015, 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 the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming, as well as the Cedar Bluff area of West Virginia and Virginia, where ARP established a position following its acquisition of assets from GeoMet Inc. in May 2014, and the Arkoma Basin in eastern Oklahoma, where ARP established a position following the Arkoma Acquisition (“see Recent Developments”);

· 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 ARP’s acquisition on June 30, 2014 (“Rangely Acquisition”);

· 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;

· AGP’s and ARP’s Mississippi Lime and Hunton plays in northwestern Oklahoma, an oil and NGL-rich area; and

· ARP’s other operating areas, including the Chattanooga Shale in northeastern Tennessee, which enables us to access other formations in that region such as the Monteagle and Ft. Payne Limestone; the New Albany Shale in southwestern Indiana, a biogenic shale play with a long-lived and shallow decline profile; and the Niobrara Shale 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 nine months ended September 30, 2015 and 2014:

	Three Months Ended  September 30,				Nine Months Ended  September 30,
	2015		2014		2015		2014
Atlas Growth:
Gross wells drilled		—		1		—		11
Our share of gross wells drilled		—		1		—		11
Gross wells turned in line(1)		2		—		4		10
Net wells turned in line(1)		2		—		4		10

	Three Months Ended  September 30,				Nine Months Ended  September 30,
	2015		2014		2015		2014
Atlas Resource:
Gross wells drilled		13		30		20		98
Our share of gross wells drilled(2)		4		9		9		52
Gross wells turned in line(1)		3		30		34		90
Net wells turned in line(1) (2)		3		12		13		53

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

(2) 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.

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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 nine months ended September 30, 2015 and 2014:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Production:(1)(2)
Atlas Resource:(3)
Appalachia:
Natural gas (MMcf)		3,123		3,516		8,879		10,670
Oil (000’s Bbls)		30		34		94		106
NGLs (000’s Bbls)		3		4		9		11
Total (MMcfe)		3,320		3,744		9,495		11,373
Coal-bed Methane:
Natural gas (MMcf)		11,828		12,896		35,849		35,597
Oil (000’s Bbls)		—		—		—		—
NGLs (000’s Bbls)		—		—		—		—
Total (MMcfe)		11,828		12,896		35,849		35,597
Barnett/Marble Falls:
Natural gas (MMcf)		4,019		5,311		12,795		15,955
Oil (000’s Bbls)		46		117		171		304
NGLs (000’s Bbls)		175		263		570		746
Total (MMcfe)		5,340		7,593		17,238		22,256
Rangely/Eagle Ford(4):
Natural gas (MMcf)		29		—		92		—
Oil (000’s Bbls)		329		236		1,035		236
NGLs (000’s Bbls)		29		24		89		24
Total (MMcfe)		2,174		1,562		6,832		1,562
Mississippi Lime/Hunton:
Natural gas (MMcf)		622		614		1,889		1,719
Oil (000’s Bbls)		40		34		121		101
NGLs (000’s Bbls)		52		50		156		143
Total (MMcfe)		1,175		1,117		3,553		3,181
Other operating areas:
Natural gas (MMcf)		289		294		873		897
Oil (000’s Bbls)		1		2		5		6
NGLs (000’s Bbls)		29		31		68		92
Total (MMcfe)		470		492		1,310		1,489
Total Atlas Resource:
Natural gas (MMcf)		19,910		22,632		60,376		64,838
Oil (000’s Bbls)		446		423		1,425		754
NGLs (000’s Bbls)		287		372		892		1,016
Total (MMcfe)		24,306		27,405		74,277		75,458
Atlas Growth:
Natural gas (MMcf)		53		71		162		179
Oil (000’s Bbls)		81		10		155		33
NGLs (000’s Bbls)		8		10		23		23
Total (MMcfe)		591		189		1,228		515
Total production:
Natural gas (MMcf)		19,963		22,702		60,539		65,017
Oil (000’s Bbls)		527		433		1,580		787
NGLs (000’s Bbls)		295		382		915		1,039
Total (MMcfe)		24,897		27,594		75,505		75,973
Production per day:(1)(2)

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Atlas Resource:(3)
Appalachia:
Natural gas (Mcfd)		33,950		38,218		32,522		39,083
Oil (Bpd)		326		367		343		390
NGLs (Bpd)		30		46		34		40
Total (Mcfed)		36,087		40,693		34,782		41,661
Coal-bed Methane:
Natural gas (Mcfd)		128,560		140,177		131,314		130,393
Oil (Bpd)		—		—		—		—
NGLs (Bpd)		—		—		—		—
Total (Mcfed)		128,560		140,177		131,314		130,393
Barnett/Marble Falls:
Natural gas (Mcfd)		43,685		57,726		46,868		58,445
Oil (Bpd)		495		1,273		625		1,114
NGLs (Bpd)		1,898		2,861		2,088		2,732
Total (Mcfed)		58,043		82,535		63,144		81,523
Rangely/Eagle Ford(4):
Natural gas (Mcfd)		313		—		337		—
Oil (Bpd)		3,573		2,567		3,790		865
NGLs (Bpd)		313		263		324		89
Total (Mcfed)		23,631		16,978		25,024		5,721
Mississippi Lime/Hunton:
Natural gas (Mcfd)		6,763		6,679		6,921		6,295
Oil (Bpd)		433		366		443		368
NGLs (Bpd)		569		545		572		524
Total (Mcfed)		12,771		12,145		13,014		11,651
Other operating areas:
Natural gas (Mcfd)		3,143		3,195		3,197		3,287
Oil (Bpd)		16		25		19		24
NGLs (Bpd)		311		334		248		337
Total (Mcfed)		5,104		5,349		4,799		5,453
Total Atlas Resource:
Natural gas (Mcfd)		216,414		245,996		221,159		237,503
Oil (Bpd)		4,842		4,598		5,220		2,761
NGLs (Bpd)		3,121		4,048		3,266		3,722
Total (Mcfed)		264,196		297,876		272,077		276,403
Atlas Growth:
Natural gas (Mcfd)		574		770		594		656
Oil (Bpd)		885		111		566		121
NGLs (Bpd)		91		104		84		85
Total (Mcfed)		6,426		2,058		4,497		1,887
Total production per day:
Natural gas (Mcfd)		216,988		246,766		221,753		238,158
Oil (Bpd)		5,727		4,710		5,786		2,882
NGLs (Bpd)		3,212		4,152		3,350		3,807
Total (Mcfed)		270,623		299,934		276,574		278,290

⁽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.

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⁽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 and West Virginia (excluding the Cedar Bluff area); 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, the Arkoma Basin in eastern Oklahoma and the County Line area of Wyoming; Rangely/Eagle Ford includes ARP’s 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado and AGP’s and ARP’s production located in southern Texas; Other operating areas include ARP’s production located in the Chattanooga, New Albany and Niobrara Shales.

⁽⁴⁾ Production volumes and production volumes per day related to the Rangely field reflect only volumes during the three and nine months ended September 30, 2014. Production volumes and volumes per day for Eagle Ford were included effective November 5, 2014, the date of its acquisition.

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 nine months ended September 30, 2015 and 2014, 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 September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Production revenues (in thousands):
Atlas Resource:
Natural gas revenue	$	57,919	$	79,251	$	181,008	$	239,233
Oil revenue		28,854		38,151		97,100		67,626
NGLs revenue		3,961		11,997		14,135		31,034
Total revenues	$	90,734	$	129,399	$	292,243	$	337,893
Atlas Growth:
Natural gas revenue	$	139	$	278	$	430	$	756
Oil revenue		3,640		951		7,286		3,081
NGLs revenue		99		309		290		726
Total revenues	$	3,878	$	1,538	$	8,006	$	4,563
Total production revenues:
Natural gas revenue	$	58,058	$	79,529	$	181,438	$	239,989
Oil revenue		32,494		39,102		104,386		70,707
NGLs revenue		4,060		12,306		14,425		31,760
Total revenues	$	94,612	$	130,937	$	300,249	$	342,456
Average sales price:
Atlas Resource:
Natural gas (per Mcf):(1)
Total realized price, after hedge(2)(3)	$	3.30	$	3.56	$	3.41	$	3.79
Total realized price, before hedge(2)	$	2.28	$	3.48	$	2.32	$	4.07
Oil (per Bbl):(1)
Total realized price, after hedge(3)	$	88.42	$	90.18	$	83.99	$	89.71
Total realized price, before hedge	$	43.25	$	91.08	$	46.74	$	93.45
NGLs (per Bbl):(1)
Total realized price, after hedge(3)	$	21.42	$	32.21	$	22.17	$	30.54
Total realized price, before hedge	$	11.01	$	32.18	$	13.00	$	32.16
Atlas Growth:
Natural gas (per Mcf):(1)
Total realized price, after hedge	$	2.63	$	3.92	$	2.65	$	4.22
Total realized price, before hedge	$	2.63	$	3.92	$	2.65	$	4.22
Oil (per Bbl):(1)
Total realized price, after hedge	$	47.14	$	92.96	$	48.39	$	93.52
Total realized price, before hedge	$	44.72	$	92.96	$	47.09	$	93.52
NGLs (per Bbl):(1)
Total realized price, after hedge	$	11.88	$	32.44	$	12.63	$	31.45

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Total realized price, before hedge	$	11.88	$	32.44	$	12.63	$	31.45
Production costs (per Mcfe):(1)
Atlas Resource:
Lease operating expenses(4)	$	1.30	$	1.37	$	1.34	$	1.26
Production taxes		0.19		0.30		0.20		0.27
Transportation and compression		0.24		0.23		0.24		0.26
	$	1.74	$	1.89	$	1.78	$	1.79
Atlas Growth:
Lease operating expenses(4)	$	0.81	$	2.71	$	0.99	$	2.51
Production taxes		0.31		0.52		0.32		0.50
Transportation and compression		0.07		—		0.06		—
	$	1.20	$	3.24	$	1.37	$	3.01
Total production costs:
Lease operating expenses(4)	$	1.29	$	1.37	$	1.33	$	1.26
Production taxes		0.19		0.30		0.20		0.27
Transportation and compression		0.24		0.23		0.23		0.26
	$	1.72	$	1.90	$	1.77	$	1.80

⁽¹⁾ “Mcf” represents thousand cubic feet; “Mcfe” represents thousand cubic feet equivalents; and “Bbl” represents barrels.

⁽²⁾ Excludes the impact of subordination of ARP’s production revenue to investor partners within its Drilling Partnerships for the three months ended September 30, 2015 and 2014. Including the effect of this subordination, ARP’s average realized gas sales price was $3.25 per Mcf ($2.23 per Mcf before the effects of financial hedging) and $3.50 per Mcf ($3.43 per Mcf before the effects of financial hedging) for three months ended September 30, 2015 and 2014, respectively, and $3.35 per Mcf ($2.27 per Mcf before the effects of financial hedging) and $3.69 per Mcf ($3.97 per Mcf before the effects of financial hedging) for nine months ended September 30, 2015 and 2014, respectively.

⁽³⁾ Includes the impact of $0.2 million of cash settlements, for both the three and nine months ended September 30, 2015, on AGP’s oil derivative contracts which were entered into subsequent to the Company’s decision to discontinue hedge accounting beginning on January 1, 2015. 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, consisting of $6.8 million associated with natural gas derivative contracts, $10.5 million associated with crude oil derivative contracts, and $2.2 million associated with natural gas liquids derivative contracts for the three months ended September 30, 2015, and $21.4 million associated with natural gas derivative contracts, $22.6 million associated with crude oil derivative contracts, and $5.6 million associated with natural gas liquids derivative contracts for the nine months ended September 30, 2015 (see “Item 1. Financial Statements – Note 8”).

⁽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 the three and nine months ended September 30, 2015 and 2014. Including the effects of these costs, ARP’s total lease operating expenses per Mcfe were $1.28 per Mcfe ($1.71 per Mcfe for total production costs) and $1.35 per Mcfe ($1.88 per Mcfe for total production costs) for the three months ended September 30, 2015 and 2014, respectively, and $1.32 per Mcfe ($1.75 per Mcfe for total production costs) and $1.23 per Mcfe ($1.76 per Mcfe for total production costs) for the nine months ended September 30, 2015 and 2014, respectively. Including the effects of these costs, total lease operating expenses per Mcfe were $1.27 per Mcfe ($1.70 per Mcfe for total production costs) and $1.36 per Mcfe ($1.88 per Mcfe for total production costs) for the three months ended September 30, 2015 and 2014, respectively, and $1.31 per Mcfe ($1.75 per Mcfe for total production costs) and $1.24 per Mcfe ($1.77 per Mcfe for total production costs) for the nine months ended September 30, 2015 and 2014, respectively.

Three Months Ended September 30, 2015 Compared with the Three Months Ended September 30, 2014. Total production revenues were $94.6 million for the three months ended September 30, 2015, a decrease of $36.3 million from $130.9 million for the three months ended September 30, 2014. This decrease consisted of a $22.7 million decrease attributable to AGP’s and ARP’s Barnett Shale/Marble Falls operations, a $9.1 million decrease attributable to ARP’s coal-bed methane assets, a $6.0 million decrease attributable to ARP’s Appalachia assets, a $4.7 million decrease attributable to ARP’s Mississippi Lime/Hunton assets, and a $1.0 million decrease associated with ARP’s other operating areas, partially offset by a $3.6 million increase attributable to AGP’s Eagle Ford assets, and a $3.6 million increase attributable to ARP’s Rangely and Eagle Ford assets.

Total production costs were $42.3 million for the three months ended September 30, 2015, a decrease of $9.7 million from $52.0 million for the three months ended September 30, 2014. This decrease primarily consisted of a $4.7 million decrease attributable to AGP’s and ARP’s Barnett Shale/Marble Falls assets, a $4.3 million decrease attributable to ARP’s coal-bed methane assets, a $1.7 million decrease attributable to ARP’s Appalachia operations, a $0.4 million decrease attributable to ARP’s Mississippi Lime/Hunton assets, a $0.2 million decrease associated with ARP’s other operating areas, and a $0.2 million increase in the credit received against lease operating expenses pertaining to the subordination of ARP’s revenue within its Drilling Partnerships, partially offset by a $1.3 million increase attributable to ARP’s Rangely/Eagle Ford assets, and a $0.5 million increase attributable to AGP’s Eagle Ford assets. Total production costs per Mcfe decreased to $1.72 per Mcfe

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for the three months ended September 30, 2015 from $1.90 per Mcfe for the comparable prior year period primarily as a result of continued efforts to reduce operating costs in each of our areas of production.

Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014. Total production revenues were $300.2 million for the nine months ended September 30, 2015, a decrease of $42.3 million from $342.5 million for the nine months ended September 30, 2014. This decrease consisted of a $56.2 million decrease attributable to AGP’s and ARP’s Barnett Shale/Marble Falls operations, a $24.4 million decrease attributable to ARP’s Appalachia assets, a $15.5 million decrease attributable to ARP’s coal-bed methane assets, an $11.9 million decrease attributable to ARP’s Mississippi Lime/Hunton assets, and a $3.1 million decrease associated with ARP’s other operating areas, partially offset by a $62.0 million increase attributable to ARP’s Rangely and Eagle Ford assets, and a $6.8 million increase attributable to AGP’s Eagle Ford assets.

Total production costs were $131.9 million for the nine months ended September 30, 2015, a decrease of $2.7 million from $134.6 million for the nine months ended September 30, 2014. This decrease primarily consisted of a $12.9 million decrease attributable to AGP’s and ARP’s Barnett Shale/Marble Falls assets, a $5.3 million decrease attributable to ARP’s Appalachia operations, a $4.5 million decrease attributable to production costs associated with ARP’s coal-bed methane assets, a $0.4 million decrease associated with ARP’s other operating areas, and a $0.1 million decrease attributable to AGP’s and ARP’s Mississippi Lime/Hunton assets, partially offset by a $19.2 million increase attributable to ARP’s Rangely/Eagle Ford assets, a $0.9 million increase attributable to AGP’s Eagle Ford assets, and a $0.4 million decrease in the credit received against ARP’s lease operating expenses pertaining to the subordination of its revenue within its Drilling Partnerships. Total production costs per Mcfe decreased to $1.77 per Mcfe for the nine months ended September 30, 2015 from $1.80 per Mcfe for the comparable prior year period primarily as a result of continued efforts to reduce operating costs in each of our areas of production.

Well Construction and Completion

Drilling Program Results. At September 30, 2015, 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. The following table presents the amounts of Drilling Partnership investor capital raised and deployed (in thousands), 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 September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Drilling partnership investor capital:
Raised	$	24,954	$	18,055	$	24,954	$	19,610
Deployed	$	23,054	$	61,204	$	63,665	$	126,917
Average construction and completion:
Revenue per well	$	7,204	$	2,121	$	3,942	$	2,476
Cost per well		6,264		1,845		3,428		2,153
Gross profit per well	$	940	$	276	$	514	$	323
Gross profit margin	$	3,008	$	7,983	$	8,304	$	16,554
Partnership net wells associated with revenue recognized(1):
Appalachia - Utica		—		2		2		3
Barnett/Marble Falls		—		22		5		37
Rangely/Eagle Ford		3		—		4		—
Mississippi Lime/Hunton		—		5		5		11
Total		3		29		16		51

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

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Three Months Ended September 30, 2015 Compared with the Three Months Ended September 30, 2014. Well construction and completion margin was $3.0 million for the three months ended September 30, 2015, a decrease of $5.0 million from $8.0 million for the three months ended September 30, 2014. This decrease consisted of a $7.1 million decrease related to fewer wells recognized for revenue within ARP’s Drilling Partnerships, partially offset by a $2.1 million increase associated with ARP’s higher gross profit margin per well.  Average revenue and cost per well increased between periods due primarily to higher capital deployed for Eagle Ford Shale wells within ARP’s Drilling Partnerships during the three months ended September 30, 2015 compared with the prior year period. 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.

Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014. Well construction and completion margin was $8.3 million for the nine months ended September 30, 2015, a decrease of $8.3 million from $16.6 million for the nine months ended September 30, 2014. This decrease consisted of an $11.4 million decrease related to fewer wells recognized for revenue within ARP’s Drilling Partnerships, partially offset by a $3.1 million increase associated with ARP’s higher gross profit margin per well. Average revenue and cost per well increased between periods due primarily to higher capital deployed for Eagle Ford Shale wells within ARP’s Drilling Partnerships during the nine months ended September 30, 2015 compared with the prior year period.

Administration and Oversight

At September 30, 2015, 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 and Niobrara Shale, 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 nine months ended September 30, 2015 and 2014. There were no exploratory wells drilled during the three and nine months ended September 30, 2015 and 2014.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Gross partnership wells drilled:
Appalachia - Utica		—		4		—		4
Barnett/Marble Falls		—		20		2		52
Eagle Ford		10		—		10		—
Mississippi Lime/Hunton		—		6		2		17
Total		10		30		14		73
Net partnership wells drilled:
Appalachia - Utica		—		4		—		4
Barnett/Marble Falls		—		20		2		40
Eagle Ford		10		—		10		—
Mississippi Lime/Hunton		—		6		1		17
Total		10		30		13		61

Three Months Ended September 30, 2015 Compared with the Three Months Ended September 30, 2014. Administration and oversight fee revenues were $5.5 million for the three months ended September 30, 2015, a decrease of $0.7 million from $6.2 million for the three months ended September 30, 2014. This decrease was due to a decrease in the number of wells spud within the current year period compared with the prior year period, particularly within the Marble Falls and the Mississippi Lime plays.

Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014. Administration and oversight fee revenues were $7.3 million for the nine months ended September 30, 2015, a decrease of $4.8 million from $12.1 million for the nine months ended September 30, 2014. This decrease was due to a decrease in the number of wells spud within the current year period compared with the prior year period, particularly within the Marble Falls and the Mississippi Lime plays.

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Well Services

At September 30, 2015, 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.

Three Months Ended September 30, 2015 Compared with the Three Months Ended September 30, 2014. Well services revenues were $5.8 million for the three months ended September 30, 2015, a decrease of $0.8 million from $6.6 million for the three months ended September 30, 2014. Well services expenses were $2.4 million for the three months ended September 30, 2015, a decrease of $0.2 million from $2.6 million for the three months ended September 30, 2014. The decrease in well services revenue is primarily related to ARP’s continued efforts to increase production through intermittent operation of certain legacy wells. The decrease in well services expense is primarily related to lower labor and other employee costs.

Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014. Well services revenues were $18.6 million for the nine months ended September 30, 2015, an increase of $0.2 million from $18.4 million for the nine months ended September 30, 2014. Well services expenses were $6.7 million for the nine months ended September 30, 2015, a decrease of $0.8 million from $7.5 million for the nine months ended September 30, 2014. The increase in well services revenue is primarily related to the increased utilization of ARP’s salt water gathering and disposal systems within the Mississippi Lime and Marble Falls plays by ARP’s Drilling Partnership wells, partially offset by a decrease in revenue pertaining to ARP’s continued efforts to increase production through intermittent operation of certain legacy wells. The decrease in well services expense is primarily related to lower labor and other employee costs.

Gathering and Processing

At September 30, 2015, 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 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%.

Three Months Ended September 30, 2015 Compared with the Three Months Ended September 30, 2014. Our net gathering and processing expense for the three months ended September 30, 2015 was net expense of $0.8 million, an unfavorable movement of $0.6 million compared with net expense of $0.2 million for the three months ended September 30, 2014. This unfavorable movement was principally due to decreases in ARP’s production volume and average realized natural gas price on its production volume within the Appalachian Basin between the periods, and lower gathering fees from ARP’s Marcellus Shale Drilling Partnership wells in Northeastern Pennsylvania, which are utilizing ARP’s gathering pipeline, as compared to the prior year period.

Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014. Our net gathering and processing expense for the nine months ended September 30, 2015 was net expense of $1.4 million, an unfavorable movement of $0.8 million compared with net expense of $0.6 million for the nine months ended September 30, 2014. This unfavorable movement was principally due to lower gathering fees from ARP’s Marcellus Shale Drilling Partnership wells in Northeastern Pennsylvania, which are utilizing ARP’s gathering pipeline, as compared to the prior year period.

Gain on Mark-to-Market Derivatives

On January 1, 2015, ARP discontinued hedge accounting for its qualified commodity derivatives. As such, subsequent changes in fair value of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives on our combined consolidated statements of operations. The fair values of these commodity derivative instruments at December 31, 2014, which were recognized in accumulated other comprehensive income within unitholders’ equity on our combined consolidated balance sheet, will be reclassified to our combined consolidated statements of operations in the future at the time the originally hedged physical transactions settle.

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Three Months Ended September 30, 2015 Compared with the Three Months Ended September 30, 2014. We recognized a gain on mark-to-market derivatives of $131.8 million for the three months ended September 30, 2015. This gain was due primarily to mark-to-market gains in the current quarter primarily related to the change in ARP’s and AGP’s natural gas and oil prices during the period. There were no gains or losses on mark-to-market derivatives during the three months ended September 30, 2014.

Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014. We recognized a gain on mark-to-market derivatives of $210.5 million for the nine months ended September 30, 2015. This gain was due primarily to mark-to-market gains in the current year primarily related to the change in ARP’s and AGP’s natural gas and oil prices during the year. There were no gains or losses on mark-to-market derivatives during the nine months ended September 30, 2014.

Other, Net

Three Months Ended September 30, 2015 Compared with the Three Months Ended September 30, 2014. Other, net for the three months ended September 30, 2015 was income of $0.4 million, as compared with income of $0.6 million for the comparable prior year period.

Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014. Other, net for the nine months ended September 30, 2015 was income of $0.6 million as compared with income of $1.2 million for the comparable prior year period. This $0.6 million unfavorable movement was primarily due to a $0.3 million decrease in income from our equity investment in Lightfoot.

Other Costs and Expenses

General and Administrative Expenses

The following table presents our and our subsidiaries’ general and administrative expenses for each of the respective periods (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
General and Administrative expenses:
Atlas Energy	$	5,050	$	903	$	27,624	$	5,523
Atlas Growth		2,676		3,272		10,013		7,070
Atlas Resource		13,978		13,124		44,400		50,894
Total	$	21,704	$	17,299	$	82,037	$	63,487

Three Months Ended September 30, 2015 Compared with the Three Months Ended September 30, 2014. Total general and administrative expenses increased to $21.7 million for the three months ended September 30, 2015 from $17.3 million for the three months ended September 30, 2014. Our $5.1 million of general and administrative expenses for the three months ended September 30, 2015 represents a $4.2 million increase from the comparable prior year period, due to a $2.4 million increasein stock compensation expense, a $0.7 million increasein non-recurring transaction costs due to our spin-off from Atlas Energy, and a $1.1 million increase in other corporate activities. AGP’s $2.7 million of general and administrative expenses for the three months ended September 30, 2015 represents a $0.6 million decrease from the comparable prior year period related to a decrease in salaries, wages, and other corporate activities. ARP’s $14.0 million of general and administrative expenses for the three months ended September 30, 2015 represents a $0.9 million increase from the comparable prior year period, which was primarily due to a $1.8 million increase related to the timing of the initiation of our 2015 Drilling Partnership program and a $1.2 million increase in other corporate activities during the current year period, partially offset by a $1.7 million decrease in non-cash compensation expense, and a $0.4 million decrease in non-recurring transaction costs related to the acquisitions of assets in the current and prior year periods.

Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014. Total general and administrative expenses increased to $82.0 million for the nine months ended September 30, 2015 from $63.5 million for the nine months ended September 30, 2014. Our $27.6 million of general and administrative expenses for the nine months ended September 30, 2015 represents a $22.1 million increase from the comparable prior year period, due to a $17.8 million increasein non-recurring transaction costs due to our spin-off from Atlas Energy, a $3.3 million increasein stock compensation expense, and a $1.0 million increase in other corporate activities. AGP’s $10.0 million of general and

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administrative expenses for the nine months ended September 30, 2015 represents a $2.9 million increase from the comparable prior year period related to an increase in salaries, wages, and other corporate activities due to the growth of its business. ARP’s $44.4 million of general and administrative expenses for the nine months ended September 30, 2015 represents a $6.5 million decrease from the comparable prior year period, which was primarily due to adecrease in non-recurring transaction costs related to the acquisitions of assets in the current and prior year periods.

Depreciation, Depletion and Amortization

The following table presents our subsidiaries’ depreciation, depletion and amortization expense for each of the respective periods (dollars in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Depreciation, depletion and amortization:
Atlas Growth	$	2,848	$	490	$	5,095	$	1,436
Atlas Resource		40,463		64,578		125,948		176,077
Total	$	43,311	$	65,068	$	131,043	$	177,513

Total depreciation, depletion and amortization decreased to $43.3 million for the three months ended September 30, 2015 compared with $65.1 million for the comparable prior year period, which was primarily due to a $22.5 million decrease in depletion expense.

Total depreciation, depletion and amortization decreased to $131.0 million for the nine months ended September 30, 2015 compared with $177.5 million for the comparable prior year period, which was primarily due to a $48.5 million decrease in depletion expense.

The following table presents our subsidiaries’ depletion expense per Mcfe for AGP’s and ARP’s operations for the respective periods (in thousands, except per Mcfe data):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Depletion expense:
Total	$	39,792		$	62,301		$	121,517		$	170,036
Depletion expense as a percentage of gas and oil production revenue		42	%		48	%		40	%		50	%
Depletion per Mcfe	$	1.60		$	2.26		$	1.61		$	2.24

Three Months Ended September 30, 2015 Compared with the Three Months Ended September 30, 2014. Depletion expense was $39.8 million for the three months ended September 30, 2015, a decrease of $22.5 million compared with $62.3 million for the three months ended September 30, 2014. Depletion expense of gas and oil properties as a percentage of gas and oil revenues decreased to 42% for the three months ended September 30, 2015 from 48% for the comparable prior year period. Depletion expense per Mcfe was $1.60 for the three months ended September 30, 2015, a decrease of $0.66 per Mcfe from $2.26 per Mcfe for the three months ended September 30, 2014. The decreases in depletion expense, depletion expense as a percentage of gas and oil revenues, and depletion expense per Mcfe when compared with the comparable prior year period are the result of the asset impairment recognized at December 31, 2014.  

Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014. Depletion expense was $121.5 million for the nine months ended September 30, 2015, a decrease of $48.5 million compared with $170.0 million for the nine months ended September 30, 2014. Depletion expense of gas and oil properties as a percentage of gas and oil revenues decreased to 40% for the nine months ended September 30, 2015 from 50% for the comparable prior year period. Depletion expense per Mcfe was $1.61 for the nine months ended September 30, 2015, a decrease of $0.63 per Mcfe from $2.24 per Mcfe for the nine months ended September 30, 2014. The decreases in depletion expense, depletion expense as a percentage of gas and oil revenues, and depletion expense per Mcfe when compared with the comparable prior year period are the result of the asset impairment recognized at December 31, 2014.

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Loss on Asset Sales and Disposal

Three Months Ended September 30, 2015 Compared with the Three Months Ended September 30, 2014. During the three months ended September 30, 2015 and 2014, we recognized losses on asset sales and disposal of $0.4 million and $0.1 million, respectively.  The $0.4 million loss on asset sales and disposal for the three months ended September 30, 2015 was primarily related to ARP’s $0.4 million of plugging and abandonment costs for certain wells in the New Albany Shale, partially offset by ARP’s $0.1 million insurance reimbursement for the Mossy Oak plant fire in Indiana in 2014.

Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014. During the nine months ended September 30, 2015 and 2014, we recognized losses on asset sales and disposal of $0.3 million and $1.7 million, respectively. The $0.4 million loss on asset sales and disposal for the nine months ended September 30, 2015 was primarily related to ARP’s $0.4 million of plugging and abandonment costs for certain wells in the New Albany Shale, partially offset by ARP’s $0.1 million insurance reimbursement for the Mossy Oak plant fire in Indiana in 2014. The $1.7 million loss on asset sales and disposal for nine months ended September 30, 2014 was primarily related to ARP’s sale of producing wells in its Niobrara Shale in connection with the settlement of a third party farm-out agreement.

Asset Impairment

Three Months Ended September 30, 2015 Compared with the Three Months Ended September 30, 2014. Asset impairment for the three months ended September 30, 2015 was $747.5 million as compared with no impairment for the comparable prior year period.  The $747.5 million of asset impairment primarily related to ARP’s oil and gas properties in the Barnett, Coal-bed Methane, Southern Appalachia, Marcellus and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices, reduced by $68.0 million of future hedge gains reclassified from accumulated other comprehensive income.  

Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014. Asset impairment for the nine months ended September 30, 2015 was $747.5 million as compared with no impairment for the comparable prior year period.  The $747.5 million of asset impairment primarily related to ARP’s oil and gas properties in the Barnett, Coal-bed Methane, Southern Appalachia, Marcellus and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices, reduced by $68.0 million of future hedge gains reclassified from accumulated other comprehensive income.  

Interest Expense

The following table presents our interest expense and that which was attributable to ARP for each of the respective periods:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Interest Expense:
Atlas Energy	$	3,098	$	2,846	$	21,123	$	8,446
Atlas Resource		25,192		16,577		75,105		43,028
Total	$	28,290	$	19,423	$	96,228	$	51,474

Three Months Ended September 30, 2015 Compared with the Three Months Ended September 30, 2014. Total interest expense increased to $28.3 million for the three months ended September 30, 2015, compared with $19.4 million for the three months ended September 30, 2014. This $8.9 million increase was due to our $0.3 million increase and an $8.6 million increase related to ARP. The $0.3 million increase in our interest expense was primarily related to $1.0 million of discount amortization for our Term Loan Facilities, partially offset by a $0.7 million decrease in interest expense on our outstanding borrowings. The $8.6 million increase in ARP’s interest expense consisted of a $6.8 million increase associated with ARP’s Term Loan Facility, a $1.7 million increase associated with interest expense on ARP’s Senior Notes, and a $0.8 million increase associated with amortization of ARP’s deferred financing costs, partially offset by a $0.7 million decrease associated with lower weighted-average outstanding borrowings under ARP’s revolving credit facility. The increase associated with ARP’s Senior Notes is primarily due to the issuance in October 2014 of an additional $75.0 million of ARP’s 9.25% Senior Notes due 2021. The increase in interest expense for ARP’s Term Loan Facility related to ARP’s entry into its Term Loan Facility in February 2015.

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Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014. Total interest expense increased to $96.2 million for the nine months ended September 30, 2015, compared with $51.5 million for thenine months ended September 30, 2014. This $44.7 million increase was primarily due to our $12.6 million increase and a$32.1 million increase related to ARP. The $12.6 million increase in our interest expense was primarily related to $5.2 million of accelerated amortization of the deferred financing costs associated with the portion of Atlas Energy’s Term Loan Facility allocated to us, $5.5 million of discount amortization for our Term Loan Facilities, and $2.9 million of accelerated amortization of the discount of our Term Loan Facilities resulting from repayments made to reduce the outstanding balance prior to paying off the loan through refinancing, partially offset by a $0.7 million decrease in interest expense related to outstanding borrowings. The $32.1 million increase in ARP’s interest expense consisted of a $16.3 million increase associated with ARP’s Term Loan Facility, an $8.5 million increase associated with interest expense on ARP’s Senior Notes, a $4.3 million accelerated amortization charge related to ARP’s reduced credit facility borrowing base, a $2.6 million increase associated with amortization of ARP’s deferred financing costs, and a $0.3 million increase associated with higher weighted-average outstanding borrowings under ARP’s revolving credit facility. The increase associated with ARP’s Senior Notes is primarily due to the issuance of an additional $100.0 million of ARP’s 7.75% Senior Notes due 2021 in June 2014 and an additional $75.0 million of ARP’s 9.25% Senior Notes due 2021 in October 2014. The increase in interest expense for ARP’s Term Loan Facility related to ARP’s entry into its Term Loan Facility in February 2015.

Loss on Early Extinguishment of Debt

Loss on early extinguishment of debt of $4.7 million for the three and nine months ended September 30, 2015 represents $4.4 million of accelerated amortization of the discount and $0.3 million of accelerated deferred financing costs related to the early retirement of our Term Loan Facilities with Deutsche Bank.

Loss Attributable to Non-Controlling Interests

Three Months Ended September 30, 2015 Compared with the Three Months Ended September 30, 2014. Loss attributable to non-controlling interests was $440.0 million for the three months ended September 30, 2015, compared with a loss of $5.1 million for the comparable prior year period. Loss attributable to non-controlling interests includes an allocation of ARP’s and AGP’s net losses to non-controlling interest holders. The increase in loss attributable to non-controlling interests between the three months ended September 30, 2015, and the prior year comparable period was primarily due to an increase in ARP’s net loss between periods primarily related to the $679.5 million impairment primarily for ARP’s oil and gas properties in the Barnett, Coal-bed Methane, Southern Appalachia, Marcellus and Mississippi Lime operating areas, partially offset by the $131.8 million gain on mark-to-market derivatives during the three months ended September 30, 2015.

Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014. Loss attributable to non-controlling interests was $420.4 million for the nine months ended September 30, 2015, compared with a loss of $33.8 million for the comparable prior year period. Loss attributable to non-controlling interests includes an allocation of ARP’s and AGP’s net losses to non-controlling interest holders. The movement in loss attributable to non-controlling interests between the nine months ended September 30, 2015, and the prior year comparable period was primarily due to an increase in ARP’s net loss between periods primarily related to the $679.5 million impairment primarily for ARP’s oil and gas properties in the Barnett, Coal-bed Methane, Southern Appalachia, Marcellus and Mississippi Lime operating areas, partially offset by the $210.5 million gain on mark-to-market derivatives during the three months ended September 30, 2015.

Liquidity and Capital Resources

General

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 our unitholders, which we expect to fund through operating cash flow, and cash distributions received.

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Atlas Resource. ARP’s primary sources of liquidity are cash generated from operations, capital raised through Drilling Partnerships, and borrowings under its revolving credit facility (see “Credit Facilities”). ARP’s primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures and distributions to its unitholders and us, as general partner. In general, ARP expects to fund:

· cash distributions and maintenance capital expenditures through existing cash and cash flows from operating activities;

· expansion capital expenditures and working capital deficits through cash generated from operations, additional borrowings and capital raised through Drilling Partnerships; and

· debt principal payments through additional borrowings as they become due or by the issuance of additional limited partner units or asset sales.

ARP relies on cash flow from operations and its credit facilities to execute its growth strategy and to meet its financial commitments and other short-term liquidity needs. ARP cannot be certain that additional capital will be available to the extent required and on acceptable terms.

Atlas Growth.  AGP’s primary sources of liquidity are cash generated from operations and financing activities. AGP’s primary cash requirements, in addition to normal operating expenses, are for capital expenditures, and quarterly distributions to its unitholders, which it expects to fund through operating cash flow.

We and our subsidiaries believe that we will have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve-month period. However, we and our subsidiaries are subject to business, operational and other risks that could adversely affect our cash flow. We and our subsidiaries may supplement our cash generation with proceeds from financing activities, including borrowings under our term loan credit facilities, ARP’s credit facilities and other borrowings, the issuance of additional limited partner units, the sale of assets and other transactions.

Cash Flows—Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014

Net cash used in operating activities of $73.1 million for the nine months ended September 30, 2015 represented an unfavorable movement of $46.5 million from net cash used in operating activities of $26.6 million for the comparable prior year period. The $46.5 million unfavorable movement was derived principally from an $85.2 million unfavorable movement in net loss, excluding non-cash items, partially offset by a $24.5 million favorable movement in working capital, a $13.0 million favorable movement in distributions paid to non-controlling interests and a $1.2 million favorable movement in equity earnings and distributions from unconsolidated subsidiaries. The non-cash charges, which impacted the $542.2 million unfavorable movement in net loss, primarily included a $679.5 million asset impairment charge, a $12.2 million favorable movement in amortization of deferred financing costs, a $4.7 million loss on early extinguishment of debt, and a $1.5 million favorable movement in non-cash compensation, partially offset by a $192.6 million unfavorable movement in unrealized gain on derivatives, a $46.5 million unfavorable movement in depreciation, depletion and amortization expense, and a $1.9 million unfavorable movement in gain/loss on asset sales and disposal. The movement in working capital was due to a $226.0 million favorable movement in accounts receivable, prepaid expenses and other, primarily due to the timing of payments received between comparable periods, partially offset by a $201.5 million unfavorable movement in accounts payable and accrued liabilities, primarily due to the timing of ARP’s capital programs. The movement in cash distributions to non-controlling interest holders was due principally to decreases in cash distributions of ARP.

Net cash used in investing activities of $173.2 million for the nine months ended September 30, 2015 represented a favorable movement of $498.7 million from net cash used in investing activities of $671.9 million for the comparable prior year period. This favorable movement was principally due to a $458.0 million decrease in net cash paid for acquisitions, a decrease in capital expenditures of $39.7 million and a $1.0 million favorable movement in proceeds from asset sales and other changes. See further discussion of capital expenditures under “Capital Requirements.”

Net cash provided by financing activities of $242.9 million for the nine months ended September 30, 2015 represented an unfavorable movement of $501.7 million from net cash provided by financing activities of $744.6 million for the comparable prior year period. This unfavorable movement was principally due to a decrease of $276.0 million for our and ARP’s borrowings under our and ARP’s term loans and ARP’s revolving credit facility, a decrease of $263.8 million in ARP’s and AGP’s equity offerings, a decrease of $97.4 million in net proceeds from issuances of ARP’s senior notes, a $12.3 million unfavorable movement in deferred financing costs, distribution equivalent rights and other and a $1.7 million

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unfavorable movement in net distributions to our preferred unitholders, partially offset by a decrease of $68.5 million in repayments of our term loan facilities and ARP’s revolving credit facility, an increase of $40.0 million for our proceeds from the issuance of our Series A Preferred Units, a $33.1 million favorable movement in distributions paid to unitholders,and a $7.9 million favorable movement of amortization of discount on our and ARP’s debt,. The gross amount of borrowings and repayments under the revolving credit facilities included within net cash provided by financing activities in the combined consolidated statements of cash flows, which are generally in excess of net borrowings or repayments during the period or at period end, reflect the timing of cash receipts, which generally occur at specific intervals during the period and are utilized to reduce borrowings under the revolving credit facilities, and payments, which generally occur throughout the period and increase borrowings under the revolving credit facilities for us and ARP, which is generally common practice for our business and industries.

ARP’s issuance of additional Class D Preferred Units as partial payment for the Eagle Ford Acquisition and our payment-in-kind of distributions on our preferred units represented non-cash transactions during the nine months ended September 30, 2015.

Capital Requirements

At September 30, 2015, the capital requirements of our subsidiaries’ natural gas and oil production consist primarily of:

· maintenance capital expenditures—oil and gas assets naturally decline in future periods and, as such, ARP recognizes the estimated capitalized cost of stemming such decline in production margin for the purpose of stabilizing ARP’s distributable cash flow and cash distributions, which we refer to as maintenance capital expenditures. ARP calculates the estimate of maintenance capital expenditures by first multiplying forecasted future full year production margin by expected aggregate production decline of proved developed producing wells. Maintenance capital expenditures are then the estimated capitalized cost of wells that will generate an estimated first-year margin equivalent to the production margin decline, assuming such wells are connected on the first day of the calendar year. ARP does not incur specific capital expenditures expressly for the purpose of maintaining or increasing production margin, but such amounts are a subset of hypothetical wells ARP expects to drill in future periods, including Marcellus Shale, Utica Shale, Mississippi Lime and Marble Falls wells, on undeveloped acreage already leased. Estimated capitalized cost of wells included within maintenance capital expenditures are also based upon relevant factors, including historical costs of similar wells and characteristics of each individual well. First-year margin from wells included within maintenance capital are also based upon relevant factors, including utilization of public forward commodity exchange prices, current estimates for regional pricing differentials, estimated labor and material rates and other production costs. Estimates for maintenance capital expenditures in the current year are the sum of the estimate calculated in the prior year plus estimates for the decline in production margin from wells connected during the current year and production acquired through acquisitions; and

· expansion capital expenditures— our subsidiaries consider expansion capital expenditures to be any capital expenditure costs expended that are not maintenance capital expenditures—generally, this will include expenditures to increase, rather than maintain, production margin in future periods, as well as land, gathering and processing, and other non-drilling capital expenditures.

The following table summarizes consolidated maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Atlas Resource:
Maintenance capital expenditures	$	13,456	$	22,400	$	42,788	$	46,300
Expansion capital expenditures		19,343		33,530		59,502		104,279
Total	$	32,799	$	55,930	$	102,290	$	150,579
Atlas Growth:
Expansion capital expenditures	$	7,659	$	567	$	20,777	$	12,147
Total	$	7,659	$	567	$	20,777	$	12,147
Consolidated:
Maintenance capital expenditures	$	13,456	$	22,400	$	42,788	$	46,300

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Expansion capital expenditures		27,002		34,097		80,279		116,426
Total	$	40,458	$	56,497	$	123,067	$	162,726

Atlas Resource Partners. During the three months ended September 30, 2015, ARP’s $32.8 million of total capital expenditures consisted primarily of $14.4 million for wells drilled exclusively for ARP’s own account compared with $23.1 million for the comparable prior year period, $7.3 million of investments in its Drilling Partnerships compared with $16.8 million for the prior year comparable period, $6.1 million of leasehold acquisition costs compared with $7.0 million for the prior year comparable period and $5.0 million of corporate and other costs compared with $9.0 million for the prior year comparable period, which primarily related to decreases in corporate salt water disposal well costs and gathering and processing costs.

During the nine months ended September 30, 2015, ARP’s $102.3 million of total capital expenditures consisted primarily of $40.1 million for wells drilled exclusively for ARP’s own account compared with $64.9 million for the comparable prior year period, $26.0 million of investments in its Drilling Partnerships compared with $41.8 million for the prior year comparable period, $9.9 million of leasehold acquisition costs compared with $18.3 million for the prior year comparable period and $26.3 million of corporate and other costs compared with $25.6 million for the prior year comparable period.

Atlas Growth. During the three months ended September 30, 2015, AGP’s $7.7 million of total capital expenditures consisted primarily of its wells drilled and leasehold acquisition costs.

During the nine months ended September 30, 2015, AGP’s $20.8 million of total capital expenditures consisted primarily of its wells drilled and leasehold acquisition costs.

Our subsidiaries continuously evaluate acquisitions of gas and oil assets. In order to make any acquisitions in the future, our subsidiaries believe they 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 our subsidiaries will be successful in their efforts to obtain outside capital.

As of September 30, 2015, our subsidiaries are committed to expending approximately $45.0 million on drilling and completion and other capital expenditures.

Off-Balance Sheet Arrangements

As of September 30, 2015, our subsidiaries’ off-balance sheet arrangements were limited to ARP’s letters of credit outstanding of $4.3 million, and commitments to spend $45.0 million related to capital expenditures.

ARP has certain long-term unconditional purchase obligations and commitments, primarily throughput contracts (see “Contractual Revenue Arrangements”).

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 September 30, 2015, management believes that any such estimated liability for redemptions of limited partner interests in Drilling Partnerships which allow such transactions would not be material.

Cash Distributions

Our board of directors adopted a cash distribution policy that requires, pursuant to our amended and restated limited liability company agreement, that we distribute all of our available cash quarterly to our unitholders within 50 days following

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the end of each calendar quarter in accordance with their respective percentage interests. As a result, we expect that we will rely upon external financing sources, including commercial borrowings and other debt and common unit issuances, to fund our acquisition and expansion capital expenditures, as well as our working capital needs.

Atlas Resource Partners’ Cash Distribution Policy. ARP’s partnership agreement requires that it distribute 100% of available cash to its common and preferred unitholders and to us, as ARP’s general partner, within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of ARP’s cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments. We, as ARP’s general partner, are granted discretion under ARP’s partnership agreement to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated.

On January 29, 2014, the Board of Directors approved a modification to ARP’s cash distribution payment practice to a monthly cash distribution program. Monthly cash distributions are paid approximately 45 days following the end of each respective monthly period.

Available cash will generally be distributed: first, 98% to ARP’s Class D and E preferred unitholders and 2% to us as general partner until the distribution payable to each of ARP’s Class D and Class E Preferred Units is an amount equal to its fixed quarterly distribution; second, 98% to ARP’s Class C preferred unitholders and 2% to us as general partner until there has been distributed to each outstanding ARP Class C Preferred Unit the greater of $0.51 and the distribution payable to common unitholders; thereafter, 98% to ARP’s common unitholders and 2% to us as general partner. These distribution percentages are modified to provide for incentive distributions to be paid to us, as ARP’s general partner, if quarterly distributions exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to ARP’s general partner that are in excess of 2% of the aggregate amount of cash being distributed. The incentive distribution rights will entitle us to receive an increasing percentage of cash distributed by ARP as it reaches specified targets.

CREDIT FACILITIES

As of September 30, 2015, we had not guaranteed any of ARP’s or AGP’s obligations or debt instruments.

Term Loan Credit Facilities

On August 10, 2015, we entered into a credit agreement (the “Riverstone Credit Agreement”) with Riverstone Credit Partners, L.P., as administrative agent, and the lenders party thereto, for a new term loan facility (the “Riverstone Term Loan Facility”) in an aggregate principal amount of $82.7 million maturing in August 2020. The borrowings under the Riverstone Term Loan Facility were used to repay in full outstanding borrowings under our existing term loan facility.

Our obligations under the Riverstone Term Loan Facility are secured on a first priority basis by security interests in substantially all of our assets and the asset of each of New Atlas Holdings, LLC, our direct wholly owned subsidiary, Atlas Lightfoot, LLC and any of our other material subsidiaries that later guarantees indebtedness under the Riverstone Term Loan Facility, including all equity interests directly held by New Atlas Holdings, LLC or any guarantor and all tangible and intangible property of us and the guarantors (subject to certain customary exclusions and exceptions).  

Borrowings under the Riverstone Term Loan Facility bear interest, at our option, at either (i) LIBOR plus 7.0% (as used with respect to the Riverstone Term Loan Facility, “Eurodollar Loans”) or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 6.0% (as used with respect to the Riverstone Term Loan Facility, an “ABR Loan”). Interest is generally payable at interest payment periods selected by us for Eurodollar Loans and quarterly for ABR Loans.  At September 30, 2015, $82.7 million was outstanding under the Riverstone Term Loan Facility. At September 30, 2015, the weighted average interest rate on outstanding borrowings under the Riverstone Term Loan Facility was 8.0%.

The Riverstone Credit Agreement contains customary covenants that limit our 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. The Riverstone Credit Agreement also requires that (a) the Total Leverage Ratio (as defined in the Riverstone Credit Agreement) not be greater than 4.00 to 1.00, beginning with the fiscal quarter ending March 31, 2016; (b) the Company have liquidity of not less than $5 million at the end of each fiscal quarter, beginning with the fiscal quarter ending December 31, 2015; and (c) the Asset Coverage Ratio (as defined in the Riverstone

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Credit Agreement) not be less than 1.75to 1.00 during the period from September 30, 2015 to June 30, 2016.Wewere in compliance with these covenants as of September 30, 2015.

We have the right at any time to prepay any borrowings outstanding under the Riverstone Term Loan Facility, subject to the payment of a prepayment premium specified therein. Subject to certain exceptions, we may also be required to prepay all or a portion of the Riverstone Term Loan Facility in certain instances, including the following:

· at the end of each fiscal quarter, we must repay the Riverstone Term Loan Facility in an amount equal to: (i) if the Total Leverage Ratio is equal to or greater than 3.50 to 1.00, 100% of Distributable Cash (as defined in the Riverstone Credit Agreement), (ii) if the Total Leverage Ratio is equal to or greater than 3.00 to 1.00 but less than 3.25 to 1.00, 75% of Distributable Cash, (iii) if the Total Leverage Ratio is equal to or greater than 2.75 to 1.00 but less than 3.00 to 1.00, 50% of Distributable Cash, (iv) if the Total Leverage Ratio is equal to or greater than 2.50:1.00 but less than 2.75 to 1.00, 25% of Distributable Cash, and (v) if the Total Leverage Ratio is less than 2.50:1.00, 0% of Distributable Cash.

· if, at any time after June 30, 2016, the Asset Coverage Ratio is less than 2.00 to 1.00, we must prepay the Riverstone Term Loan Facility in an aggregate principal amount necessary to achieve an Asset Coverage Ratio of greater than 2.00 to 1.00; the Asset Coverage Ratio is equal to the ratio of the Asset Value (the sum of the discounted net present values of the loan parties’ oil and gas properties, cash and cash equivalents, and the values of certain equity interests of ARP, Atlas Lightfoot, LLC, AGP and certain other midstream and upstream companies, determined as set forth in the Riverstone Credit Agreement) to Total Funded Debt (as defined in the Riverstone Credit Agreement);

· if we or any of our restricted subsidiaries disposes of property or assets (including equity interests) to a person other than a loan party or receives insurance or condemnation proceeds following a casualty event, we must repay the Riverstone Term Loan Facility in an aggregate principal amount equal to 100% of the net cash proceeds from such disposition or casualty event; and

· if we or any of our restricted subsidiaries issues or incurs any debt or issues any equity, we must repay the Riverstone Term Loan Facility in an aggregate principal amount equal to 100% of the net cash proceeds of such issuances or incurrences of debt or issuances of equity.

On February 27, 2015, we entered into a Credit Agreement with Deutsche Bank AG New York Branch, as administrative agent, and the lenders from time to time party thereto. The Credit Agreement provided for a Secured Senior Interim Term Loan Facility in an aggregate principal amount of $30.0 million and a Secured Senior Term Loan A Facility in an aggregate principal amount of approximately $97.8 million. In June 2015, we prepaid $33.1 million on the Term Loan Facilities in connection with the Arkoma Acquisition (see “Recent Developments”).  On August 10, 2015, we repaid in full the remaining $82.7 outstanding under the Term Loan Facilities.

The proceeds from the issuance of the Term Loan Facilities were used to fund a portion of our $150.0 million payment to Atlas Energy in connection with the repayment of Atlas Energy’s term loan. The Interim Term Loan Facility matured on August 27, 2015 and the Term Loan A Facility was to mature on February 26, 2016. Our obligations under the Term Loan Facilities were secured on a first priority basis by security interests in substantially all of our assets and our material subsidiaries, including all equity interests directly held by us, New Atlas Holdings, LLC, or any other guarantor subsidiary, and all tangible and intangible property. Borrowings under the Term Loan Facilities bore interest, at our option, at either (i) LIBOR plus 7.5% (as used with respect to the Term Loan Facilities, “Eurodollar Loans”) or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, in each case plus 6.5% (as used with respect to the Term Loan Facilities, an “ABR Loan”). Interest was generally payable at interest payment periods selected by us for Eurodollar Loans and quarterly for ABR Loans.

We had the right at any time to prepay any borrowings outstanding under the Term Loan Facilities, without premium or penalty, provided the Interim Term Loan Facility was repaid prior to the Term Loan A Facility. Subject to certain exceptions, we may also have been required to prepay all or a portion of the Term Loan Facilities in certain instances, including the following:

● if, at any time, the Recognized Value Ratio (as defined in the Credit Agreement) was less than 2.00 to 1.00, we must have prepaid the Term Loan Facilities and any revolving loans outstanding in an aggregate principal amount necessary to achieve a Recognized Value Ratio of greater than 2.00 to 1.00; the Recognized Value Ratio was equal to the ratio of the Recognized Value (the sum of the discounted net present values of the Loan Parties’

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oil and gas properties and the values of the common units, Class A Units and Class C Units of ARP, determined as set forth in the Credit Agreement) to Total Funded Debt (as defined in the Credit Agreement); 

● if we disposed of all or any portion of the Arkoma assets (as defined in the Credit Agreement), we must have prepaid the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds resulting from such disposition;

● if we or any of our restricted subsidiaries disposed of property or assets (including equity interests), we must have repaid the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds from such disposition or casualty event; and

● if we incurred any debt or issue any equity, we must have repaid the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds of such issuances or incurrences of debt or issuances of equity.

The Credit Agreement contained customary covenants that limited our 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. The Credit Agreement also required that the Total Leverage Ratio (as defined in the Credit Agreement) not be greater than (i) as of the last day of any fiscal quarter prior to the full repayment of the Interim Term Loan Facility, 3.75 to 1.00, and (ii) as of the last day of any quarter thereafter, 3.50 to 1.00.

ARP Revolving Credit Facility

ARP is a party to its Second Amended and Restated Credit Agreement dated July 31, 2013, as amended, with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (the “ARP Credit Agreement”), which provides for a senior secured revolving credit facility with a borrowing base of $750.0 million as of September 30, 2015.

ARP’s borrowing base is scheduled for semi-annual redeterminations on November 1, 2015 and thereafter on May 1 and November 1 of each year. In July 2015, the redetermination by the lenders reaffirmed ARP’s $750.0 million borrowing base. The ARP Credit Agreement also provides that its borrowing base will be reduced by 25% of the stated amount of any senior notes issued, or additional second lien debt incurred, after July 1, 2015. At September 30, 2015, $563.0 million was outstanding under the credit facility. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which $4.3 million was outstanding at September 30, 2015. ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. Borrowings under the credit facility bear interest, at ARP’s election, at either an adjusted LIBOR rate plus an applicable margin between 1.50% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.50% and1.75% per annum. If the borrowing base utilization (as defined in the ARP Credit Agreement) is less than 90%, the applicable margin on Eurodollar Loans and ABR Loans (each as defined in the ARP Credit Agreement) will be increased by 0.25%. ARP is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.375% per annum if less than 50% of the borrowing base is utilized and 0.5% if 50% or more of the borrowing base is utilized, which is included within interest expense on the Company’s combined consolidated statements of operations.

The ARP Credit Agreement contains customary covenants that limit ARP’s ability to incur additional indebtedness (excluding second lien debt in an aggregate principal amount of up to $300.0 million), grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. The ARP Credit Agreement also requires that ARP maintain a ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than (i) 5.25 to 1.0 as of the last day of the quarters ending on March 31, 2015, June 30, 2015, September 30, 2015, December 31, 2015 and March 31, 2016, (ii) 5.00 to 1.0 as of the last day of the quarters ending on June 30, 2016, September 30, 2016 and December 31, 2016, (iii) 4.50 to 1.0 as of the last day of the quarter ending on March 31, 2017 and (iv) 4.00 to 1.0 as of the last day of each quarter thereafter, and a ratio of current assets (as defined in the ARP Credit Agreement) to current liabilities (as defined in the ARP Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.  ARP was in compliance with these covenants as of September 30, 2015.

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ARP Term Loan Facility

On February 23, 2015, ARP entered into a Second Lien Credit Agreement with certain lenders and Wilmington Trust, National Association, as administrative agent. The Second Lien Credit Agreement provides for a second lien term loan in an original principal amount of $250.0 million (the “ARP Term Loan Facility”), and is presented net of $6.6 million of unamortized discount at September 30, 2015. The ARP Term Loan Facility matures on February 23, 2020.

ARP has the option to prepay the ARP Term Loan Facility at any time, and is required to offer to prepay the ARP Term Loan Facility with 100% of the net cash proceeds from the issuance or incurrence of any debt and 100% of the excess net cash proceeds from certain asset sales and condemnation recoveries. ARP is also required to offer to prepay the ARP Term Loan Facility upon the occurrence of a change of control. All prepayments are subject to the following premiums, plus accrued and unpaid interest:

· the make-whole premium (plus an additional amount if such prepayment is optional and funded with proceeds from the issuance of equity) for prepayments made during the first 12 months after the closing date;

· 4.5% of the principal amount prepaid for prepayments made between 12 months and 24 months after the closing date;

· 2.25% of the principal amount prepaid for prepayments made between 24 months and 36 months after the closing date; and

· no premium for prepayments made following 36 months after the closing date.

ARP’s obligations under the ARP Term Loan Facility are secured on a second priority basis by security interests in all of its assets and those of its restricted subsidiaries (the “Loan Parties”) that guarantee ARP’s existing first lien revolving credit facility. In addition, the obligations under the ARP Term Loan Facility are guaranteed by ARP’s material restricted subsidiaries. Borrowings under the ARP Term Loan Facility bear interest, at ARP’s option, at either (i) LIBOR plus 9.0% or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 8.0% (an “ABR Loan”). Interest is generally payable at the applicable maturity date for Eurodollar loans and quarterly for ABR loans.

The Second Lien Credit Agreement contains customary covenants that limit ARP’s ability to make restricted payments, take on indebtedness, issue preferred stock, grant liens, conduct sales of assets and subsidiary stock, make distributions from restricted subsidiaries, conduct affiliate transactions and engage in other business activities.  In addition, the Second Lien Credit Agreement contains covenants substantially similar to those in ARP’s existing first lien revolving 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 in compliance with these covenants as of September 30, 2015.

Under the Second Lien Credit Agreement, ARP may elect to add one or more incremental term loan tranches to the ARP Term Loan Facility so long as the aggregate outstanding principal amount of the ARP Term Loan Facility plus the principal amount of any incremental term loan does not exceed $300.0 million and certain other conditions are adhered to. Any such incremental term loans may not mature on a date earlier than February 23, 2020.

ATLAS RESOURCE SECURED HEDGE FACILITY

At September 30, 2015, 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

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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.

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 the date hereof, 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. 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.

ATLAS RESOURCE SENIOR NOTES

At September 30, 2015, ARP had $374.6 million outstanding of its 7.75% senior unsecured notes due 2021 (“7.75% ARP Senior Notes”). The 7.75% ARP Senior Notes were presented net of a $0.4 million unamortized discount as of September 30, 2015. Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable for up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, ARP may redeem the 7.75% ARP Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (as defined in the governing indenture), plus accrued and unpaid interest, if any. On and after January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 7.75% ARP Senior Notes.

At September 30, 2015, ARP had $324.0 million outstanding of its 9.25% senior unsecured notes due 2021 (“9.25% ARP Senior Notes”). The 9.25% ARP Senior Notes were presented net of a $1.0 million unamortized discount as of September 30, 2015. Interest on the 9.25% Senior Notes is payable semi-annually on February 15 and August 15. At any time prior to August 15, 2017, ARP may redeem the 9.25% ARP Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (as defined in the governing indenture), plus accrued and unpaid interest, if any. At any time on or after August 15, 2017, ARP may redeem some or all of the 9.25% ARP Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, ARP may redeem some or all of its 9.25% ARP Senior Notes at the redemption price of 102.313%, and on or after August 15, 2019, ARP may redeem some or all of its 9.25% ARP Senior Notes at the redemption price of 100.0%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase its 9.25% ARP Senior Notes.

In connection with the issuance of the $75.0 million of 9.25% ARP Senior Notes on October 14, 2014, ARP entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by July 11, 2015. On April 15, 2015, the registration statement relating to the exchange offer for the 9.25% ARP Senior Notes was declared effective, and the exchange offer was subsequently launched on April 15, 2014 and expired on May 13, 2015.

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

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several, and any of ARP’s subsidiaries, 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 limitations on 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 September 30, 2015.

ISSUANCE OF UNITS

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

On February 27, 2015 we issued and sold an aggregate of 1.6 million of our newly created Series A convertible preferred units, with a liquidation preference of $25.00 per unit (the “Series A Preferred Units”), at a purchase price of $25.00 per unit to certain members of our management, two management members of the Board, and outside investors. Holders of the Series A Preferred Units are entitled to monthly distributions of cash at a rate equal to the greater of (i) 10% of the liquidation preference per annum, increasing to 12% per annum, 14% per annum and 16% per annum on the first, second and third anniversaries of the private placement, respectively or (ii) the monthly equivalent of any cash distribution declared by the Company to holders of the Company’s 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 on the NYSE 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(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. 

Atlas Resource Equity Offerings

In August 2015, ARP entered into a distribution agreement with MLV & Co. LLC (“MLV”). Pursuant to the distribution agreement, ARP may sell from time to time through MLV ARP’s 8.625% Class D ARP Cumulative Redeemable Perpetual Preferred Units (“Class D ARP Preferred Units”) and Class E ARP Cumulative Redeemable Perpetual Preferred Units (“Class E ARP Preferred Units”) having a maximum aggregate offering price of up to $100 million. Sales of Class D and Class E ARP Preferred 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 of 1933, as amended, including sales made directly on the NYSE, the existing trading market for the Units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP will pay MLV a commission, which shall not be more than 3.0% of the gross sales price of Class D and Class E ARP Preferred Units. ARP has agreed to reimburse MLV for certain expenses incurred in connection with entering into the distribution agreement. Under the terms of the distribution agreement, ARP may also sell Class D and Class E ARP Preferred Units from time to time to MLV as principal for its own account at a price to be agreed upon at the time of sale. Any sale of Class D and Class E ARP Preferred Units to MLV as principal would be pursuant to the terms of a separate terms agreement between ARP and MLV. During the three and nine months ended September 30, 2015, ARP issued 90,328 Class D ARP Preferred Units and 1,083 Class E ARP Preferred Units under the preferred equity distribution program for net proceeds of $1.0 million, net of $0.2 million in commissions and offering expenses paid.

In May 2015, in connection with the Arkoma Acquisition (see “Note 3”), 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 approximately $49.7 million. ARP used a portion of the net proceeds to fund the Arkoma Acquisition and to reduce borrowings outstanding under ARP’s revolving 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 approximately $6.0 million.  ARP pays distributions on the Class E ARP Preferred Units at a rate of 10.75% per annum of the stated liquidation preference of $25.00.

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In October 2014, in connection with the Eagle Ford Acquisition (see Note 3), ARP issued 3,200,000 8.625% Class D Preferred Units at a public offering price of $25.00 per unit, yielding net proceeds of approximately $77.3 million from the offering, after deducting underwriting discounts and estimated offering expenses. ARP used the net proceeds from the offering to fund a portion of the Eagle Ford Acquisition. 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. ARP pays cumulative distributions on a quarterly basis, at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference.

The Class D and Class E ARP Preferred Units rank senior to ARP’s common units and Class C ARP Preferred Units with respect to the payment of distributions and distributions upon a liquidation event. The Class D and Class E ARP Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by ARP or converted into its common units in connection with a change in control. At any time on or after October 15, 2019 for the Class D ARP Preferred Units and April 15, 2020 for the ARP Class E Preferred Units, ARP may, at its option, redeem the such preferred units in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, ARP may redeem such preferred units following certain changes of control, as described in the respective Certificates of Designation. If ARP does not exercise this redemption option upon a change of control, then holders of such preferred units will have the option to convert the preferred units into a number of ARP common units as set forth in the respective Certificates of Designation. If ARP exercises any of its redemption rights relating to such preferred units, the holders will not have the conversion right described above with respect to the preferred units called for redemption.

In August 2014, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of 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 terms agreement between ARP and such Agent. During the three months ended September 30, 2015, ARP issued 5,519,110 common limited partner units under the equity distribution program for net proceeds of $18.6 million, net of $0.4 million in commissions and offering expenses paid. During the nine months ended September 30, 2015, ARP issued 8,404,934 common limited partner units under the equity distribution program for net proceeds of $40.0 million, net of $1.0 million in commissions and offering expenses paid.

In May 2014, in connection with the Rangely Acquisition (see Note 3), ARP issued 15,525,000 of its common limited partner units (including 2,025,000 units pursuant to an over-allotment option) in a public offering at a price of $19.90 per unit, yielding net proceeds of approximately $297.3 million.

In March 2014, in connection with the GeoMet Acquisition (see Note 3), ARP issued 6,325,000 of its common limited partner units (including 825,000 units pursuant to an over-allotment option) in a public offering at a price of $21.18 per unit, yielding net proceeds of approximately $129.0 million.

For the nine months ended September 30, 2015 and the year ended December 31, 2014, in connection with the issuance of ARP’s common units, we recorded losses of $1.2 million and gains of $40.5 million, respectively, within equity and a corresponding increase and decrease, respectively, in non-controlling interests on our combined consolidated balance sheets and combined consolidated statements of unitholders’ / owner’s equity.

Atlas Growth Equity Offerings

AGP issued approximately $233.0 million of its common limited partner units through a private placement offering that expired on June 30, 2015. Of the $233.0 million of gross funds raised, we purchased $5.0 million common limited partner units during the offering. For the nine months ended September 30, 2015 and the year ended December 31, 2014, in connection with the issuance of AGP’s common units, we recorded gains of $4.6 million and $4.5 million, respectively, within equity and a corresponding decrease in non-controlling interests on our combined consolidated balance sheets and combined consolidated statements of unitholders’ / owner’s equity.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point in time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include revenue and expense accruals, depletion, depreciation and amortization, asset impairment, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. A discussion of the significant accounting policies we have adopted and followed in the preparation of our consolidated financial statements was included in our Annual Report on Form 10-K for the year ended December 31, 2014, and we summarize our significant accounting policies within our consolidated financial statements included in Note 2 under “Item 1: Financial Statements” included in this report. The critical accounting policies and estimates we have identified are discussed below.

Depreciation and Impairment of Long-Lived Assets and Goodwill

Long-Lived Assets. The cost of property, plant and equipment, less estimated salvage value, is generally depreciated on a straight-line basis over the estimated useful lives of the assets. Useful lives are based on historical experience and are adjusted when changes in planned use, technological advances or other factors indicate that a different life would be more appropriate. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively.

Long-lived assets, other than goodwill and intangibles with infinite lives, generally consist of natural gas and oil properties and pipeline, processing and compression facilities and are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. A long-lived asset, other than goodwill and intangibles with infinite lives, is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. The undiscounted net cash flows expected to be generated by the asset are based upon our estimates that rely on various assumptions, including natural gas and oil prices, and production and operating expenses. Any significant variance in these assumptions could materially affect the estimated net cash flows expected to be generated by the asset. As discussed in “General Trends and Outlook”, recent increases in natural gas and oil drilling have driven an increase in the supply of natural gas and oil and put a downward pressure on domestic prices. Further declines in natural gas prices may result in additional impairment charges in future periods. Declines in natural gas and oil prices may result in impairment charges in future periods.

There were no impairments of unproved gas and oil properties recorded for the three and nine months ended September 30, 2015 and 2014.

For the three and nine months ended September 30, 2015, we recognized $747.5 million of asset impairment primarily related to oil and gas properties in ARP’s Barnett, Coal-bed Methane, Marcellus and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices, reduced by $68.0 million of future hedge gains reclassified from accumulated other comprehensive income.  There were no impairments of proved gas and oil properties for the three and nine months ended September 30, 2014.

Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. Additional factors impacting the economic viability of long-lived assets are discussed under “Item 1A: Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014.

Goodwill and Intangibles with Infinite Lives. Goodwill and intangibles with infinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment loss should be recognized if the carrying value of an entity’s reporting units exceeds its estimated fair value.

There were no goodwill impairments recognized by ARP during the three and nine months ended September 30, 2015 and 2014. During the year ended December 31, 2014, ARP recorded an $18.1 million goodwill non-cash impairment loss

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within asset impairment on our combined consolidated statement of operations related to an impairment of goodwill in its gas and oil production reporting unit due to a decline in overall commodity prices.

Fair Value of Financial Instruments

We and our subsidiaries have established a hierarchy to measure our financial instruments at fair value, which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

We use a fair value methodology to value the assets and liabilities for our subsidiaries’ outstanding derivative contracts and our rabbi trust assets. ARP’s and AGP’s commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. Investments held in our rabbi trust are publicly traded equity and debt securities and are therefore defined as Level 1 fair value measurements.

Liabilities that are required to be measured at fair value on a nonrecurring basis include our asset retirement obligations that are defined as Level 3. Estimates of the fair value of asset retirement obligations are based on discounted cash flows using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our subsidiaries’ credit-adjusted risk-free rate and inflation rates.

During the year ended December 31, 2014, our subsidiaries completed several acquisitions of oil and gas properties and related assets. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under our subsidiaries’ existing methodology for recognizing an estimated liability for the plugging and abandonment of their gas and oil wells (see “Item 1: Financial Statements—Note 6”). These inputs require significant judgments and estimates by management at the time of the valuation and are subject to change.

Reserve Estimates

Estimates of proved natural gas, oil and natural gas liquids reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas, oil and natural gas liquids prices, drilling and operating expenses, capital expenditures and availability of funds. The accuracy of these reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. As discussed in “Item 2: Properties” of our Annual Report on Form 10-K for the year ended December 31, 2014, our subsidiaries engaged independent third-party reserve engineers, to prepare reports of proved reserves.

Any significant variance in the assumptions utilized in the calculation of reserve estimates could materially affect the estimated quantity of reserves. As a result, estimates of proved natural gas, oil and natural gas liquids reserves are inherently imprecise. Actual future production, natural gas, oil and natural gas liquids prices, revenues, development expenditures, operating expenses and quantities of recoverable natural gas, oil and natural gas liquids reserves may vary substantially from our estimates or estimates contained in the reserve reports and may affect our subsidiaries’ ability to pay amounts due under our subsidiaries’ credit facilities or cause a reduction in our subsidiaries’ credit facilities. In addition, proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas, oil and natural gas liquids prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our subsidiaries’ control. Reserves and their relation to estimated future net cash flows impact the

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calculation of impairment and depletion of oil and gas properties. Adjustments to quarterly depletion rates, which are based upon a units of production method, are made concurrently with changes to reserve estimates. Generally, an increase or decrease in reserves without a corresponding change in capitalized costs will have a corresponding inverse impact to depletion expense.

 Asset Retirement Obligations

Our subsidiaries estimate the cost of future dismantlement, restoration, reclamation and abandonment of their operating assets.

Our subsidiaries recognize an estimated liability for the plugging and abandonment of gas and oil wells and related facilities. Our subsidiaries also recognize a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Our subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Since there are many variables in estimating asset retirement obligations, our subsidiaries attempt to limit the impact of management’s judgment on certain of these variables by developing a standard cost estimate based on historical costs and industry quotes updated annually. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. Neither we nor our subsidiaries have any assets legally restricted for purposes of settling asset retirement obligations. Except for gas and oil properties, there are no other material retirement obligations associated with our subsidiaries’ tangible long-lived assets.

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 September 30, 2015. 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.

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

Interest Rate Risk. As of September 30, 2015, we had $82.7 million of outstanding borrowings under our term facility and ARP had $563.0 million of outstanding borrowings under its revolving credit facility and $243.4 million of outstanding

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borrowings under its term loan facility. Holdingall 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 September 30, 2016 by $9.0 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 September 30, 2016 of approximately $2.1 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 AGP’s and ARP’s exposure to changing natural gas, oil and natural gas liquids prices, Atlas Growth 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. These contracts have qualified and been designated as cash flow hedges and been recorded at their fair values.

As of September 30, 2015, AGP had the following commodity derivatives:

Crude Oil – Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Bbl)(1)		(per Bbl)(1)
2015		13,500	$	61.000
2016		18,000	$	63.150
2017		9,000	$	65.000

(1) “Bbl” represents barrels.

As of September 30, 2015, ARP had the following commodity derivatives:

Natural Gas – Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(MMBtu)(1)		(per MMBtu)(1)
2015		13,611,000	$	4.193
2016		53,546,300	$	4.229
2017		49,920,000	$	4.219
2018		40,800,000	$	4.170
2019		15,960,000	$	4.017

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Natural Gas – Costless Collars

Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap
		(MMBtu)(1)		(per MMBtu)(1)
2015	Puts purchased		600,000	$	3.934
2015	Calls sold		600,000	$	4.634

Natural Gas – Put Options – Drilling Partnerships

Production Period Ending December 31,	Option Type	Volumes		Average Fixed Price
		(MMBtu)(1)		(per MMBtu)(1)
2015	Puts purchased		360,000	$	4.000
2016	Puts purchased		1,440,000	$	4.150

Natural Gas – WAHA Basis Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(MMBtu)(1)		(per MMBtu)(1)
2015		1,200,000	$	(0.090	)

Natural Gas Liquids – Natural Gasoline Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Gal)(1)		(per Gal)(1)
2015		1,260,000	$	1.923

Natural Gas Liquids – Propane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Gal)(1)		(per Gal)(1)
2015		2,016,000	$	1.016

Natural Gas Liquids – Butane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Gal)(1)		(per Gal)(1)
2015		378,000	$	1.248

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Natural Gas Liquids – Iso Butane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Gal)(1)		(per Gal)(1)
2015		378,000	$	1.263

Natural Gas Liquids – Crude Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Bbl)(1)		(per Bbl)(1)
2016		84,000	$	85.651
2017		60,000	$	83.780

Crude Oil – Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Bbl)(1)		(per Bbl)(1)
2015		487,500	$	87.592
2016		1,557,000	$	81.471
2017		1,140,000	$	77.285
2018		1,080,000	$	76.281
2019		540,000	$	68.371

(1) “MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons.

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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 September 30, 2015, our disclosure controls and procedures were effective at the reasonable assurance level.

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

PART II. OTHER INFORMATION

ITEM 6: EXHIBITS

Exhibit Number	Exhibit Description
2.1	Separation and Distribution Agreement by and among Atlas Energy, L.P., Atlas Energy GP LLC and Atlas Energy Group, LLC(28)
2.2	Employee Matters Agreement by and among Atlas Energy, L.P., Atlas Energy GP LLC and Atlas Energy Group, LLC(28)
2.3	Purchase and Sale Agreement, dated May 18, 2015, by and between New Atlas Holdings, LLC and ARP Production Company, LLC. The schedules to the Purchase and Sale Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request.(19)
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(28)
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(28)
10.1(a)	Amended and Restated Limited Partnership Agreement of Atlas Resource Partners, L.P.(4)
10.1(b)	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Atlas Resource Partners, L.P., dated as of July 25, 2012(5)
10.1(c)	Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Atlas Resource Partners, L.P., dated as of July 31, 2013(6)

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10.1(d)	Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Atlas Resource Partners, L.P., dated as of October 2, 2014(7)
10.1(e)	Amendment No. 4 to Amended and Restated Agreement of Limited Partnership of Atlas Resource Partners, L.P., dated as of November 3, 2014(2)
10.1(f)	Amendment No. 5 to Amended and Restated Agreement of Limited Partnership of Atlas Resource Partners, L.P., dated as of February 27, 2015 (29)
10.1(g)	Amendment No. 6 to Amended and Restated Agreement of Limited Partnership of Atlas Resource Partners, L.P., dated as of April 14, 2015 (31)
10.2	Atlas Resource Partners, L.P. Certificate of Designation of the Powers, Preferences and Relative, Participating, Optional and Other Special Rights and Qualifications, Limitations and Restrictions thereof of Class B Preferred Units, dated as of June 25, 2012(5)
10.3	Atlas Resource Partners, L.P. Certificate of Designation of the Powers, Preferences and Relative, Participating, Optional and Other Special Rights and Qualifications, Limitations and Restrictions thereof of Class C Convertible Preferred Units, dated as of July 31, 2013(6)
10.4	Atlas Resource Partners, L.P. Certificate of Designation of the Powers, Preferences and Relative, Participating, Optional, and Other Special Rights and Qualifications, Limitations and Restrictions thereof of Class D Preferred Units, dated as of October 2, 2014(7)
10.5	Atlas Resource Partners, L.P. Certificate of Designation of the Powers, Preferences and Relative, Participating, Optional, and Other Special Rights and Qualifications, Limitations and Restrictions thereof of Class E Preferred Units, dated as of April 14, 2015(31)
10.6	Atlas Energy Group, LLC 2015 Long-Term Incentive Plan(28)
10.7	Form of Phantom Unit Grant under Atlas Energy Group, LLC 2015 Long-Term Incentive Plan(14)
10.8	Form of Phantom Unit Grant Agreement for Non-Employee Directors under Atlas Energy Group, LLC 2015 Long-Term Incentive Plan(14)
10.9	Form of Option Grant Agreement under Atlas Energy Group, LLC 2015 Long-Term Incentive Plan(14)
10.10	Atlas Energy Group, LLC Annual Incentive Plan for Senior Executives(28)
10.11(a)	Second Amended and Restated Credit Agreement dated July 31, 2013 among Atlas Resource Partners, L.P., the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the lenders(6)
10.11(b)	First Amendment to Second Amended and Restated Credit Agreement dated December 6, 2013 among Atlas Resource Partners, L.P., the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the lenders(9)
10.11(c)	Third Amendment to Second Amended and Restated Credit Agreement dated June 30, 2014 among Atlas Resource Partners, L.P., the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the lenders(10)
10.11(d)	Fourth Amendment to Second Amended and Restated Credit Agreement dated September 24, 2014 among Atlas Resource Partners, L.P., the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the lenders(11)
10.11(e)	Fifth Amendment to Second Amended and Restated Credit Agreement dated November 24, 2014 among Atlas Resource Partners, L.P., the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the lenders(12)
10.11(f)	Sixth Amendment to Second Amended and Restated Credit Agreement dated February 23, 2015 among Atlas Resource Partners, L.P., the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the lenders(30)
10.12	Secured Hedge Facility Agreement dated as of March 5, 2012 among Atlas Resources, LLC, the participating partnerships from time to time party thereto, the hedge providers from time to time party thereto and Wells Fargo Bank, N.A., as collateral agent for the hedge providers(13)

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10.13	Atlas Resource Partners, L.P. 2012 Long-Term Incentive Plan(3)
10.14	Warrant to Purchase Atlas Resource Partners, L.P. Common Units(6)
10.15(a)	Indenture dated as of July 30, 2013, by and between Atlas Resource Escrow Corporation and Wells Fargo Bank, National Association(20)
10.15(b)	Supplemental Indenture dated as of July 31, 2013, by and among Atlas Resource Partners, L.P., Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, the guarantors named therein and Wells Fargo Bank, National Association(20)
10.15(c)	Second Supplemental Indenture dated as of October 14, 2014, by and among Atlas Resource Partners, L.P., Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, the guarantors named therein and Wells Fargo Bank, National Association(22)
10.15(d)	Third Supplemental Indenture dated as of July 23, 2015, by and among Atlas Resource Partners, L.P., Atlas Resource Partners Holdings, LLC (f/k/a Atlas Energy Holdings Operating Company, LLC), Atlas Resource Finance Corporation, the guarantors named therein and Wells Fargo Bank, National Association(34)
10.16(a)	Indenture dated as of January 23, 2013 among Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, Atlas Resource Partners, L.P., the subsidiaries named therein and U.S. Bank National Association(18)
10.16(b)	Supplemental Indenture dated as of June 2, 2014, by and among Atlas Resource Partners, L.P., Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, the subsidiary guarantors named therein and U.S. Bank, National Association(21)
10.16(c)	Second Supplemental Indenture dated as of July 23, 2015, among Atlas Resource Partners Holdings, LLC (f/k/a Atlas Energy Holdings Operating Company, LLC), Atlas Resource Finance Corporation, Atlas Resource Partners, L.P., the subsidiaries named therein and U.S. Bank National Association(34)
10.17	Registration Rights Agreement dated as of July 31, 2013, by and among Atlas Resource Partners, L.P., Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, the guarantors named therein and Deutsche Bank Securities, Inc., for itself and on behalf of the Initial Purchasers(20)
10.18	Registration Rights Agreement dated as of June 2, 2014, by and among Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, the guarantors named therein and Wells Fargo Securities, LLC and Deutsche Bank Securities, Inc.(21)
10.19	Registration Rights Agreement dated as of July 31, 2013 by and among Atlas Energy, L.P. and Atlas Resource Partners(6)
10.20	Amended and Restated Registration Rights Agreement, dated as of July 31, 2013, between Atlas Resource Partners, L.P., Wells Fargo Bank, National Association and the lenders named in the Amended and Restated Credit Agreement dated July 31, 2013 by and among Atlas Energy, L.P. and the lenders named therein(29)
10.21	Registration Rights Agreement dated as of October 14, 2014, by and among Atlas Resource Partners, L.P., Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, the guarantors named therein and Wells Fargo Securities, LLC(23)
10.22	Purchase and Sale Agreement, dated as of May 6, 2014, by and among Merit Management Partners I, L.P., Merit Energy Partners III, L.P., Merit Energy Company, LLC, ARP Rangely Production, LLC and Atlas Resource Partners, L.P., as Guarantor. The exhibits and schedules to the Purchase and Sale Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted exhibits and schedules will be furnished to the U.S. Securities and Exchange Commission upon request.(24)
10.23	Purchase and Sale Agreement, dated as of September 24, 2014, by and among Cinco Resources, Inc., Cima Resources, LLC, ARP Eagle Ford, LLC, Atlas Growth Eagle Ford, LLC and Atlas Resource Partners, L.P. The schedules to the Purchase and Sale Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted exhibits and schedules will be furnished to the U.S. Securities and Exchange Commission upon request.(11)

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10.24	First Amendment to Purchase and Sale Agreement dated October 27, 2014, by and between Cinco Resources, Inc., Cima Resources, LLC, ARP Eagle Ford, LLC, Atlas Growth Eagle Ford, LLC and Atlas Resource Partners, L.P. (27)
10.25	Second Amendment to Purchase and Sale Agreement dated March 31, 2015, by and between Cinco Resources, Inc., Cima Resources, LLC, ARP Eagle Ford, LLC, Atlas Growth Eagle Ford, LLC and Atlas Resource Partners, L.P. (32)
10.26	Registration Rights Agreement dated March 31, 2015, by and between Cinco Resources, Inc. and Atlas Resource Partners, L.P. (32)
10.27(a)	Shared Acquisition and Operating Agreement, dated as of September 24, 2014, by and among ARP Eagle Ford, LLC and Atlas Growth Eagle Ford, LLC and Atlas Resource Partners, L.P. The schedules to the Shared Acquisition and Operating Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted exhibits and schedules will be furnished to the U.S. Securities and Exchange Commission upon request.(11)
10.27(b)	Amended and Restated Shared Acquisition and Operating Agreement, effective as of September 24, 2014, by and among ARP Eagle Ford, LLC, Atlas Growth Eagle Ford, LLC and Atlas Eagle Ford Operating Company, LLC. The schedules to the Amended and Restated Shared Acquisition and Operating Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request. (39)
10.27(c)	Addendum #2 to the Amended and Restated Shared Acquisition and Operating Agreement by and among ARP Eagle Ford, LLC, Atlas Growth Eagle Ford, LLC and Atlas Eagle Ford Operating Company, LLC, effective as of July 1, 2015.The schedules to Addendum #2 to the Amended and Restated Shared Acquisition and Operating Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request. (39)
10.27(d)	Addendum #3 to the Amended and Restated Shared Acquisition and Operating Agreement by and among ARP Eagle Ford, LLC, Atlas Growth Eagle Ford, LLC and Atlas Eagle Ford Operating Company, LLC, effective as of September 30, 2015.The schedules to Addendum #3 to the Amended and Restated Shared Acquisition and Operating Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request. (39)
10.28	Distribution Agreement dated as of August 29, 2014, between Atlas Resource Partners, L.P. and Deutsche Bank Securities Inc., as representative of the several agents.(25)
10.29	Second Lien Credit Agreement dated as of February 23, 2015, among Atlas Resource Partners, L.P., the lenders party thereto and Wilmington Trust, National Association, as administrative agent. (30)
10.30	Credit Agreement dated as of February 27, 2015 among Atlas Energy Group, LLC, New Atlas Holdings, LLC, Deutsche Bank AG New York Branch, as administrative agent, and the lenders party thereto. (28)
10.31	Series A Preferred Unit Purchase Agreement by and among Atlas Energy Group, LLC and the purchasers signatory thereto. (28)
10.32	Registration Rights Agreement by and among Atlas Energy Group, LLC and the purchasers signatory thereto. (28)
10.33	Credit Agreement, among Atlas Energy Group, LLC, New Atlas Holdings, LLC, the lenders party thereto and Riverstone Credit Partners, L.P., as administrative agent, dated as of August 10, 2015(36)
10.34	Employment Agreement among Atlas Energy Group, LLC, Atlas Resource Partners, L.P. and Edward E. Cohen, dated as of September 4, 2015(37)
10.35	Employment Agreement among Atlas Energy Group, LLC, Atlas Resource Partners, L.P. and Jonathan Z. Cohen, dated as of September 4, 2015(37)

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10.36	Employment Agreement among Atlas Energy Group, LLC, Atlas Resource Partners, L.P. and Daniel C. Herz, dated as of September 4, 2015(37)
10.37	Employment Agreement among Atlas Energy Group, LLC, Atlas Resource Partners, L.P. and Mark Schumacher, dated as of September 4, 2015(37)
10.38	Distribution Agreement, dated as of August 19, 2015, between Atlas Resource Partners, L.P. and MLV & Co. LLC(38)
99.1	Rangely Summary Reserve Report of Cawley, Gillespie, and Associates, Inc. (33)
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(35)
101.SCH	XBRL Schema Document(35)
101.CAL	XBRL Calculation Linkbase Document(35)
101.LAB	XBRL Label Linkbase Document(35)
101.PRE	XBRL Presentation Linkbase Document(35)
101.DEF	XBRL Definition Linkbase Document(35)

(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 Atlas Resource Partners, L.P.’s current report on Form 8-K filed on March 14, 2012.
(5)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on July 26, 2012.
(6)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on August 6, 2013.
(7)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s registration statement on Form 8-A filed on October 2, 2014.
(8)	Previously filed as an exhibit to Atlas Energy, L.P.’s quarterly report on Form 10-Q for the quarter ended March 31, 2011.
(9)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s annual report on Form 10-K for the year ended December 31, 2013.
(10)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on July 2, 2014.
(11)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on September 30, 2014.
(12)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on November 25, 2014.
(13)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on March 7, 2012.
(14)	Previously filed as an exhibit to our Registration Statement on Form 10, as amended (File No. 1-36725).
(15)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on December 26, 2012.
(16)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on January 11, 2013.
(17)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on May 31, 2013.
(18)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on January 25, 2013.
(19)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on May 22, 2015.
(20)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on August 2, 2013.
(21)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on June 3, 2014.
(22)	Previously filed as an exhibit to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2012.
(23)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on October 15, 2014.
(24)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on May 7, 2014.
(25)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on August 29, 2014.

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(26)	[Intentionally Omitted]
(27)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on November 6, 2014.
(28)	Previously filed as an exhibit to our current report on Form 8-K filed on March 2, 2015.
(29)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2014.
(30)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on February 23, 2015.
(31)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s registration statement on Form 8-A filed on April 14, 2015.
(32)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on April 6, 2015.
(33)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on June 2, 2015.
(34)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s quarterly report on the Form 10-Q for the quarter ended June 30, 2015.
(35) (36) (37)	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”. Previously filed as an exhibit to Atlas Energy Group, LLC’s current report on Form 8-K filed on August 14, 2015. Previously filed as an exhibit to Atlas Energy Group, LLC’s current report on Form 8-K filed on September 4, 2015.
(38)	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on August 19, 2015.

⁽³⁸⁾ Previously filed as an exhibit to Atlas Resource Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended September 30, 2015.

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:	November 9, 2015	By:	/s/ EDWARD E. COHEN
			Edward E. Cohen
			Chief Executive Officer
Date:	November 9, 2015	By:	/s/ JEFFREY M. SLOTTERBACK
			Jeffrey M. Slotterback
			Chief Financial Officer
Date:	November 9, 2015	By:	/s/ MATTHEW J. FINKBEINER
			Matthew J. Finkbeiner
			Chief Accounting Officer

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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 September 30, 2015 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

November 9, 2015

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 September 30, 2015 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

November 9, 2015

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 period ended September 30, 2015 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 

November 9, 2015

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 period ended September 30, 2015 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

November 9, 2015

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Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number of Common Unit Holder Units) (Details) - shares	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2015
Accounting Policies [Abstract]
Basic	26,011,000	26,011,000
Weighted average number of common unitholders per unit—diluted	26,011,000	26,011,000
Antidilutive Securities Excluded From Computation Of Diluted Net Income (Loss) Attributable To Common Limited Partners Outstanding Units	2,737,000	1,492,000

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Debt (ARP Term Loan Facility) (Details) - USD ($)		9 Months Ended
	Feb. 23, 2015	Sep. 30, 2015
Debt Instrument, Redemption, Period Two
Debt Instrument [Line Items]
Principal amount prepaid for repayments	4.50%
Debt Instrument, Redemption, Period Three
Debt Instrument [Line Items]
Principal amount prepaid for repayments	2.25%
Second Lien Credit Agreement
Debt Instrument [Line Items]
Line of Credit Facility interest rate description		Borrowings under the ARP Term Loan Facility bear interest, at ARP’s option, at either (i) LIBOR plus 9.0% or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 8.0% (an “ABR Loan”). Interest is generally payable at the applicable maturity date for Eurodollar loans and quarterly for ABR loans.
Line of Credit Facility, weighted average interest rate		10.00%
Principal amount of term loan facility	$ 300,000,000
Second Lien Credit Agreement | Incremental Term Loan
Debt Instrument [Line Items]
Line of Credit Facility, expiration date		Feb. 23, 2020
Second Lien Credit Agreement | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	9.00%
Second Lien Credit Agreement | Federal Funds Effective Swap Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	0.50%
Second Lien Credit Agreement | One Month L I B O R
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	1.00%
Second Lien Credit Agreement | Base Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	2.00%
Second Lien Credit Agreement | Alternate Base Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	8.00%
Second Lien Credit Agreement | Debt Instrument, Redemption, Period Four
Debt Instrument [Line Items]
Principal amount prepaid for repayments	0.00%
Atlas Resource Partners, L.P. | Second Lien Credit Agreement
Debt Instrument [Line Items]
Line of Credit Facility, aggregate principal amount	$ 250,000,000
Line of Credit Facility, expiration date		Feb. 23, 2020
Term Loan Facilities, unamortized discount		$ 6,600,000
Net cash proceeds from the issuance or incurrence of debt	100.00%
Excess net cash proceeds from certain asset sales and condemnation recoveries	100.00%

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Asset Retirement Obligations (Reconciliation of Liability for Well Plugging and Abandonment Costs) (Narrative) (Details) - USD ($)	3 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2013
Asset Retirement Obligations [Line Items]
Asset retirement obligations	$ 112,600,000	$ 112,600,000	$ 102,991,000	$ 108,101,000	$ 110,937,000	$ 101,455,000	$ 91,214,000
Limited Partner Interest | Series of Individually Immaterial Business Acquisitions
Asset Retirement Obligations [Line Items]
Oil and gas reclamation liabilities noncurrent	0	0
Relationship With Drilling Partnerships
Asset Retirement Obligations [Line Items]
Limited partner distributions withheld related to the asset retirement obligations of certain Drilling Partnerships		4,300,000
Relationship With Drilling Partnerships | Limited Partner Interest
Asset Retirement Obligations [Line Items]
Asset retirement obligations	$ 45,600,000	$ 45,600,000
Atlas Growth Partners, L.P | Series of Individually Immaterial Business Acquisitions
Asset Retirement Obligations [Line Items]
Oil and gas reclamation liabilities noncurrent				100,000
Atlas Resource Partners, L.P. | Series of Individually Immaterial Business Acquisitions
Asset Retirement Obligations [Line Items]
Oil and gas reclamation liabilities noncurrent			$ 6,600,000	$ 7,000,000

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Debt (Senior Notes) (Details) - USD ($)	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Debt Instrument [Line Items]
Debt instrument, restrictive covenants	The indentures governing the 7.75% ARP Senior Notes and 9.25% ARP Senior Notes contain covenants, including limitations of 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 September 30, 2015.
Cash paid on accrued interest on debt	$ 93,700,000	$ 62,500,000
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
9.25% Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount of second lien debt	$ 324,000,000
Senior Notes, maturity	2021
Debt instrument, interest rate, stated percentage	9.25%
Term Loan Facilities, unamortized discount	$ 1,000,000
Senior Notes interest payment dates and terms	Interest on the 9.25% ARP Senior Notes is payable semi-annually on February 15 and August 15.
Debt instrument, call feature	At any time prior to August 15, 2017, ARP may redeem the 9.25% ARP Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (as defined in the governing indenture), plus accrued and unpaid interest, if any. At any time on or after August 15, 2017, ARP may redeem some or all of the 9.25% ARP Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 100.0%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 9.25% ARP Senior Notes.
Atlas Resource Partners, L.P. | 7.75% Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount of second lien debt	$ 374,600,000
Senior Notes, maturity	2021
Debt instrument, interest rate, stated percentage	7.75%		7.75%
Term Loan Facilities, unamortized discount	$ 400,000
Senior Notes interest payment dates and terms	Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15.
Repurchase, make whole and redemption terms and description	At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable for up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, ARP may redeem the 7.75% ARP Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (as defined in the governing indenture), plus accrued and unpaid interest, if any. On and after January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019.
Atlas Resource Partners, L.P. | 9.25% Senior Notes
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	9.25%		9.25%

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Benefit Plans (ARP Unit Options Activity) (Details) - 2012 Long Term Incentive Plans - Phantom Units - USD ($)		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights				The ARP LTIP Committee will determine the vesting and exercise restrictions applicable to an ARP award of options, if any, and the method by which the exercise price may be paid by the participant. Unit option awards expire 10 years from the date of grant.
Years From Date Of Grant Unit Option Awards Expire				10 years
Share Based Compensation Arrangement By Share Based Payment Award Fair Value Assumptions Outstanding Options To Vest Within Next Twelve Months		83,163		83,163
Proceeds from Stock Options Exercised		$ 0	$ 0	$ 0	$ 0
Outstanding, beginning of year (Units)		1,452,800	1,468,925	1,458,300	1,482,675
Forfeited (Units)		(35,036)	(3,750)	(40,536)	(17,500)
Outstanding, end of period (Units)	[1],[2]	1,417,764	1,465,175	1,417,764	1,465,175
Options exercisable (Units)	[3]	1,332,976	732,025	1,332,976	732,025
Non-cash compensation expense recognized		$ (87,000)	$ 342,000	$ 805,000	$ 1,374,000
Outstanding, beginning of year		$ 24.66	$ 24.66	$ 24.66	$ 24.66
Forfeited		24.67	24.67	24.68	24.46
Outstanding, end of period	[1],[2]	24.66	24.66	24.66	24.66
Options exercisable, end of year	[3]	$ 24.67	$ 24.67	$ 24.67	$ 24.67
Share Based Compensation Arrangement By Share Based Payment Award Options Exercises In Period Total Intrinsic Value		$ 0	$ 0	$ 0	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term				6 years 7 months 6 days
Aggregate Intrinsic Value Of Options Outstanding		0	0	$ 0	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term				6 years 7 months 6 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value		0	$ 0	$ 0	$ 0
Unrecognized compensation expense related to unvested unit options		$ 100,000		$ 100,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition				7 months 6 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Method Used				ARP used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted.
Vesting Percentage On Each Of Next Four Anniversaries Of Date Of Grant
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share Based Compensation Arrangement By Share Based Payment Award Options Vesting Period Percentage				25.00%

[1] The weighted average remaining contractual life for outstanding options at September 30, 2015 was 6.6 years.

[2] There were no aggregate intrinsic values of options outstanding at September 30, 2015 and 2014.

[3] The weighted average remaining contractual life for exercisable options at September 30, 2015 was 6.6 years. There were no intrinsic values for options exercisable at September 30, 2015 and 2014.

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Other Assets (Summary of Other Assets) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Other Assets [Line Items]
Deferred financing costs, net of accumulated amortization of $39,945 and $20,675 at September 30, 2015 and December 31, 2014, respectively	$ 49,299	$ 46,120
Rabbi Trust	5,378	3,925
Security deposits	231	229
Other	5,154	5,348
Total Other Assets	83,454	80,611
Lightfoot
Other Assets [Line Items]
Investment in Lightfoot	19,521	21,123
Atlas Resource Partners, L.P.
Other Assets [Line Items]
ARP notes receivable	$ 3,871	$ 3,866

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Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2015

2015 Long Term Incentive Plan

Defined Benefit Plan Disclosure [Line Items]

Phantom Unit Activity

The following table sets forth the 2015 LTIP phantom unit activity for the periods indicated:

	Three Months Ended September 30,
	2015					2014
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value
Outstanding, beginning of period		2,764,210		$	6.50		—	$	—
Granted		10,500			4.20		—		—
Vested(1)		—			—		—		—
Forfeited		(193,200	)		6.43		—		—
Outstanding, end of period(2)(3)(4)		2,581,510		$	6.49		—	$	—
Non-cash compensation expense recognized (in thousands)				$	2,375			$	—

	Nine Months Ended September 30,
	2015					2014
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		—		$	—		—	$	—
Granted		2,774,710			6.49		—		—
Vested(1)		—			—		—		—
Forfeited		(193,200	)		6.43		—		—
Outstanding, end of period(2)(3)(4)		2,581,510		$	6.49		—	$	—
Non-cash compensation expense recognized (in thousands)				$	3,322			$	—

(1) No phantom unit awards vested during the three and nine months ended September 30, 2015 and 2014.

(2) The aggregate intrinsic value of phantom unit awards outstanding at September 30, 2015 was approximately $5.8 million.

(3) There was $0.1 million recognized as liabilities on the Company’s consolidated balance sheet at September 30, 2015 representing 68,910 units, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair value for these units was $9.07at September 30, 2015.

ARP Long Term Incentive Plan

Defined Benefit Plan Disclosure [Line Items]

Phantom Unit Activity

The following table sets forth the ARP LTIP phantom unit activity for the periods indicated:

	Three Months Ended September 30,
	2015					2014
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of period		411,257		$	21.10		901,207		$	23.29
Granted		—			—		9,400			19.85
Vested and issued(1)		(68,187	)		22.15		(115,797	)		24.54
Forfeited		(23,914	)		23.00		—			—
Outstanding, end of period(2)(3)		319,156		$	20.74		794,810		$	23.07
Vested and not yet issued(4)		3,125		$	21.02		5,412		$	25.25
Non-cash compensation expense recognized (in thousands)				$	375				$	1,647

	Nine Months Ended September 30,
	2015					2014
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		799,192		$	22.70		839,808		$	24.31
Granted		9,730			8.50		236,423			20.28
Vested and issued(1)		(457,727	)		23.75		(262,671	)		24.51
Forfeited		(32,039	)		23.01		(18,750	)		23.00
Outstanding, end of period(2)(3)		319,156		$	20.74		794,810		$	23.07
Vested and not yet issued(4)		3,125		$	21.02		5,412		$	25.25
Non-cash compensation expense recognized (in thousands)				$	3,692				$	4,968

(1) The intrinsic values of phantom unit awards vested and issued during the three months ended September 30, 2015 and 2014 were $0.3 million and $2.3 million, respectively, and $3.9 million and $5.2 million during the nine months ended September 30, 2015 and 2014, respectively.

(2) The aggregate intrinsic value for phantom unit awards outstanding at September 30, 2015was $0.9 million.

(3) There were approximately $16,000 and $0.1 million recognized as liabilities on the Company’s consolidated balance sheets at September 30, 2015 and December 31, 2014, respectively, representing 14,005 and 26,579units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were $13.39 and $21.16at September 30, 2015 and December 31, 2014, respectively. There was $0.2 million recognized as liabilities on the Company’s consolidated balance sheet at the period ended September 30, 2014 representing 29,035 units that participants may opt to settle in cash instead of units. The weighted average grant date fair value for these units was $21.09 at September 30, 2014.

(4) The intrinsic values of phantom unit awards vested, but not yet issued at September 30, 2015 and 2014 were approximately $2,000 and $0.1 million, respectively.

Unit Option Activity

The following table sets forth the ARP LTIP unit option activity for the periods indicated:

	Three Months Ended September 30,
	2015						2014
	Number of Unit Options			Weighted Average Exercise Price			Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of period		1,452,800		$	24.66			1,468,925		$	24.66
Granted		—			—			—			—
Exercised (1)		—			—			—			—
Forfeited		(35,036	)		24.67			(3,750	)		24.67
Outstanding, end of period(2)(3)		1,417,764		$	24.66			1,465,175		$	24.66
Options exercisable, end of period(4)		1,332,976		$	24.67			732,025		$	24.67
Non-cash compensation expense recognized (in thousands)				$	(87	)				$	342

	Nine Months Ended September 30,
	2015					2014
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of year		1,458,300		$	24.66		1,482,675		$	24.66
Granted		—			—		—			—
Exercised (1)		—			—		—			—
Forfeited		(40,536	)		24.68		(17,500	)		24.46
Outstanding, end of period(2)(3)		1,417,764		$	24.66		1,465,175		$	24.66
Options exercisable, end of period(4)		1,332,976		$	24.67		732,025		$	24.67
Non-cash compensation expense recognized (in thousands)				$	805				$	1,374

(1) No options were exercised during the three and nine months ended September 30, 2015 and 2014.

(2) The weighted average remaining contractual life for outstanding options at September 30, 2015 was 6.6 years.

(3) There were no aggregate intrinsic values of options outstanding at September 30, 2015 and 2014.

(4) The weighted average remaining contractual life for exercisable options at September 30, 2015 was 6.6 years. There were no intrinsic values for options exercisable at September 30, 2015 and 2014.

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Benefit Plan (Restricted Units Narrative) (Details) - Restricted Stock - shares	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares, Issued	0	0
Shares, Granted	0	0
Shares, Outstanding	0	0

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Benefit Plans (2015 LTIP Phantom Unit Activity) (Details) - 2015 Phantom Units - USD ($)		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights				Generally, phantom units to be granted to employees under the 2015 LTIP will vest over a designated period of time
Share Based Compensation Arrangement By Share Based Payment Award Award Other Than Options Vesting Period Percentage				25.00%
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months		846,372		846,372
Distribution Equivalent Rights Paid On Unissued Units Under Incentive Plans		$ 0	$ 0	$ 0	$ 0
Outstanding, beginning of year (Units)		2,764,210
Granted (Units)		10,500		2,774,710
Forfeited (Units)		(193,200)		(193,200)
Outstanding, end of period (Units)	[1],[2]	2,581,510		2,581,510
Non-cash compensation expense recognized		$ 2,375,000		$ 3,322,000
Outstanding, beginning of year		$ 6.50
Granted		4.20		$ 6.49
Forfeited		6.43		6.43
Outstanding, end of period	[1],[2]	$ 6.49		$ 6.49
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value		$ 0	$ 0	$ 0	$ 0
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value		5,800,000		5,800,000
Liabilities Related to Outstanding Phantom Units		$ 100,000		$ 100,000
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Units Classified Within Liabilities		68,910		68,910
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Weighted Average Grant Date Fair Value Units Classified Within Liabilities		$ 9.07		$ 9.07
Unrecognized compensation expense related to unvested phantom units		$ 13,000,000		$ 13,000,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition				1 year 9 months 18 days
Non Employees
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period				4 years

[1] The aggregate intrinsic value of phantom unit awards outstanding at September 30, 2015 was approximately $5.8 million.

[2] There was $0.1 million recognized as liabilities on the Company’s consolidated balance sheet at September 30, 2015 representing 68,910 units, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair value for these units was $9.07 at September 30, 2015.

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Derivative Instruments (Summary of Commodity Derivative Activity) (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
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]	$ (23,927)		$ (77,048)
Portion of settlements attributable to subsequent mark to market gains		(19,752)		(49,877)
Total cash settlements on commodity derivative contracts		(43,679)	$ (1,400)	(126,925)	$ 22,700
2015 Unrealized gains prior to settlement	[2]	10,989		17,822
Unrealized gain on open derivative contracts at September 30, 2015, net of amounts recognized in income in prior year	[2]	120,788		192,644
Gains on mark-to-market derivatives		$ 131,777		$ 210,466

[1] Recognized in gas and oil production revenue.

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

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Benefit Plans (ARP Long Term Incentive Plan Narrative) (Details) - ARP Long Term Incentive Plan	9 Months Ended
	Sep. 30, 2015 shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Description	ARP’s 2012 Long-Term Incentive Plan (the “ARP LTIP”), effective March 2012, provides incentive awards to officers, employees and directors as well as employees of the Company and its affiliates, consultants and joint venture partners who perform services for ARP. The ARP LTIP is administered by the board of the Company, a committee of the board or the board (or committee of the board) of an affiliate (the “ARP LTIP Committee”).
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	2,900,000
Phantom Units, Restricted Units and Unit Options Outstanding	1,736,920
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	182,008

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Subsequent Events (The Company) (Details) - Subsequent Event $ in Millions	Oct. 28, 2015 USD ($)
Cash Distribution Declared
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Declaration Date	Oct. 28, 2015
Cash Distribution Paid
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 11.9
Distribution Made to Member or Limited Partner, Distribution Date	Nov. 13, 2015
Distribution Made to Member or Limited Partner, Date of Record	Nov. 09, 2015
Series A Preferred Units | Cash Distribution Declared
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Declaration Date	Oct. 28, 2015
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 0.3
Series A Preferred Units | Cash Distribution Paid
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Distribution Date	Nov. 13, 2015
Distribution Made to Member or Limited Partner, Date of Record	Nov. 09, 2015

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Operating Segment Information (Operating Segment Data) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Segment Reporting Information [Line Items]
Revenues	$ 262,834	$ 208,589	$ 606,880	$ 512,340
General And Administrative Expense	(21,704)	(17,299)	(82,037)	(63,487)
Depreciation, depletion and amortization expense	(43,311)	(65,068)	(131,043)	(177,513)
Asset impairment			(679,537)
Gain (loss) on asset sales and disposal			190	(1,683)
Interest expense	(28,290)	(19,423)	(96,228)	(51,474)
Loss on early extinguishment of debt	(4,726)		(4,726)
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Revenues	257,895	206,699	597,609	506,953
Operating costs and expenses	(80,486)	(123,567)	(244,126)	(313,720)
Depreciation, depletion and amortization expense	(40,463)	(64,578)	(125,948)	(176,077)
Asset impairment	(672,246)		(672,246)
Gain (loss) on asset sales and disposal	(362)	(92)	(276)	(1,686)
Interest expense	(25,192)	(16,577)	(75,105)	(43,028)
Segment income (loss)	(560,854)	1,885	(520,092)	(27,558)
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Revenues	4,591	1,538	8,767	4,563
Operating costs and expenses	(3,385)	(3,885)	(11,697)	(8,622)
Depreciation, depletion and amortization expense	(2,848)	(490)	(5,095)	(1,436)
Asset impairment	(7,291)		(7,291)
Interest expense	(14)		(14)
Segment income (loss)	(8,947)	(2,837)	(15,330)	(5,495)
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Revenues	348	352	504	824
General And Administrative Expense	(5,050)	(903)	(27,624)	(5,523)
Gain (loss) on asset sales and disposal				3
Interest expense	(3,084)	(2,846)	(21,109)	(8,446)
Loss on early extinguishment of debt	(4,726)		(4,726)
Segment income (loss)	$ (12,512)	$ (3,397)	$ (52,955)	$ (13,142)

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Subsequent Events (Atlas Resource Cash Distribution) (Details) - USD ($)			1 Months Ended																				2 Months Ended
	Oct. 28, 2015	Oct. 15, 2015	Aug. 31, 2015	Jul. 31, 2015	Jun. 30, 2015	May. 31, 2015	Apr. 30, 2015	Mar. 31, 2015	Feb. 28, 2015	Jan. 31, 2015	Dec. 31, 2014	Nov. 30, 2014	Oct. 31, 2014	Sep. 30, 2014	Aug. 31, 2014	Jul. 31, 2014	Jun. 30, 2014	May. 31, 2014	Apr. 30, 2014	Mar. 31, 2014	Feb. 28, 2014	Jan. 31, 2014	Jul. 15, 2015
Class E Preferred Units
Subsequent Event [Line Items]
Preferred Unit Regular Quarterly Cash Distributions Per Unit																							$ 0.6793
Atlas Resource Partners, L.P.
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit			$ 0.1083	$ 0.1083	$ 0.1083	$ 0.1083	$ 0.1083	$ 0.1083	$ 0.1083	$ 0.1083	$ 0.1966	$ 0.1966	$ 0.1966	$ 0.1966	$ 0.1966	$ 0.1966	$ 0.1966	$ 0.1933	$ 0.1933	$ 0.1933	$ 0.1933	$ 0.1933
General Partner | Atlas Resource Partners, L.P.
Subsequent Event [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid			$ 236,000	$ 229,000	$ 223,000	$ 223,000	$ 221,000	$ 206,000	$ 204,000	$ 203,000	$ 1,378,000	$ 1,378,000	$ 1,378,000	$ 1,378,000	$ 1,378,000	$ 1,378,000	$ 1,377,000	$ 1,279,000	$ 1,279,000	$ 1,054,000	$ 1,055,000	$ 1,055,000
Subsequent Event | Atlas Resource Partners, L.P. | Class D Preferred Units
Subsequent Event [Line Items]
Preferred Unit Regular Quarterly Cash Distributions Per Unit		$ 0.5390625
Distribution Made to Limited Partner, Cash Distributions Paid		$ 2,200,000
Subsequent Event | Atlas Resource Partners, L.P. | Class E Preferred Units
Subsequent Event [Line Items]
Preferred Unit Regular Quarterly Cash Distributions Per Unit		$ 0.6791875
Distribution Made to Limited Partner, Cash Distributions Paid		$ 200,000
Subsequent Event | Cash Distribution Declared
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Declaration Date	Oct. 28, 2015
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit	$ 0.1083
Subsequent Event | Cash Distribution Declared | Atlas Resource Partners, L.P.
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Declaration Date	Oct. 28, 2015
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit	$ 0.1083
Subsequent Event | Cash Distribution Paid
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 11,900,000
Distribution Made to Member or Limited Partner, Distribution Date	Nov. 13, 2015
Distribution Made to Member or Limited Partner, Date of Record	Nov. 09, 2015
Subsequent Event | Cash Distribution Paid | Atlas Resource Partners, L.P.
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 11,900,000
Distribution Made to Member or Limited Partner, Distribution Date	Nov. 13, 2015
Distribution Made to Member or Limited Partner, Date of Record	Nov. 09, 2015
Subsequent Event | Cash Distribution Paid | General Partner
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 200,000
Subsequent Event | Cash Distribution Paid | General Partner | Atlas Resource Partners, L.P.
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid	200,000
Subsequent Event | Cash Distribution Paid | Preferred Limited Partner Units
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 600,000

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Benefit Plans (ARP LTIP Phantom Unit Activity) (Details) - ARP Phantom Units - USD ($)		3 Months Ended				9 Months Ended
		Sep. 30, 2015		Sep. 30, 2014		Sep. 30, 2015		Sep. 30, 2014		Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, beginning of year (Units)		411,257		901,207		799,192		839,808
Granted (Units)				9,400		9,730		236,423
Vested and issued (Units)	[1]	(68,187)		(115,797)		(457,727)		(262,671)
Forfeited (Units)		(23,914)				(32,039)		(18,750)
Outstanding, end of period (Units)	[2],[3]	319,156		794,810		319,156		794,810
Vested and not yet issued (Units)	[4]	3,125		5,412		3,125		5,412
Non-cash compensation expense recognized		$ 375,000		$ 1,647,000		$ 3,692,000	[4]	$ 4,968,000	[4]
Outstanding, beginning of year		$ 21.10		$ 23.29		$ 22.70		$ 24.31
Granted				19.85		8.50		20.28
Vested and issued	[1]	22.15		24.54		23.75		24.51
Forfeited		23.00				23.01		23.00
Outstanding, end of period	[2],[3]	20.74		23.07		20.74		23.07
Vested and not yet issued		$ 21.02	[4]	$ 25.25	[4]	$ 21.02	[2],[3]	$ 25.25	[2],[3]
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value		$ 300,000		$ 2,300,000		$ 3,900,000		$ 5,200,000
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value		900,000				900,000
Liabilities Related to Outstanding Phantom Units		$ 16,000		$ 200,000		$ 16,000		$ 200,000		$ 100,000
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Units Classified Within Liabilities		14,005		29,035		14,005		29,035		26,579
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Weighted Average Grant Date Fair Value Units Classified Within Liabilities		$ 13.39		$ 21.09		$ 13.39		$ 21.09		$ 21.16
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested But Not Yet Been Issued In Period Intrinsic Value						$ 2,000		$ 100,000
Unrecognized compensation expense related to unvested phantom units		$ 2,300,000				$ 2,300,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition						1 year 7 months 6 days
Atlas Resource Partners, L.P.
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights						Phantom units granted under the ARP LTIP generally will vest 25% of the original granted amount on each of the four anniversaries of the date of grant.
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months		162,496				162,496
Distribution Equivalent Rights Paid On Unissued Units Under Incentive Plans		$ 100,000		$ 500,000		$ 600,000		$ 1,500,000
Atlas Resource Partners, L.P. | Vesting Percentage On Each Of Next Four Anniversaries Of Date Of Grant
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share Based Compensation Arrangement By Share Based Payment Award Award Other Than Options Vesting Period Percentage						25.00%

[1] The intrinsic values of phantom unit awards vested and issued during the three months ended September 30, 2015 and 2014 were $0.3 million and $2.3 million, respectively, and $3.9 million and $5.2 million during the nine months ended September 30, 2015 and 2014, respectively.

[2] The aggregate intrinsic value for phantom unit awards outstanding at September 30, 2015 was $0.9 million.

[3] There were approximately $16,000 and $0.1 million recognized as liabilities on the Company’s consolidated balance sheets at September 30, 2015 and December 31, 2014, respectively, representing 14,005 and 26,579 units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were $13.39 and $21.16 at September 30, 2015 and December 31, 2014, respectively. There was $0.2 million recognized as liabilities on the Company’s consolidated balance sheet at the period ended September 30, 2014 representing 29,035 units that participants may opt to settle in cash instead of units. The weighted average grant date fair value for these units was $21.09 at September 30, 2014.

[4] The intrinsic values of phantom unit awards vested, but not yet issued at September 30, 2015 and 2014 were approximately $2,000 and $0.1 million, respectively.

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Cash Distributions (Schedule of Distributions Declared by Partnership) (Parenthetical) (Details)	2 Months Ended
	Dec. 31, 2013 $ / shares
Distribution Policy Members Or Limited Partners [Abstract]
Pro-rated Cash Distributions	$ 0.1750

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Acquisitions (Tables)

9 Months Ended

Sep. 30, 2015

Rangely Acquisition

Assets Acquired and Liabilities Assumed in Acquisition

The following table presents the values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

Assets:
Prepaid expenses and other	$	4,041
Property, plant and equipment		405,416
Other assets, net		2,888
Total assets acquired	$	412,345
Liabilities:
Accrued liabilities		2,117
Asset retirement obligation		1,305
Total liabilities assumed		3,422
Net assets acquired	$	408,923

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Debt (Schedule of Total Debt Outstanding) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Total debt	$ 1,587,747	$ 1,542,585
Less current maturities		(1,500)
Total long-term debt	$ 1,587,747	1,541,085
9.25% Senior Notes
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	9.25%
Atlas Energy
Debt Instrument [Line Items]
Term loan facilities		148,100
Atlas Energy | Term loan facilities
Debt Instrument [Line Items]
Term loan facilities	$ 82,700	148,125
Atlas Resource Partners, L.P.
Debt Instrument [Line Items]
Term loan facilities	243,408
Revolving credit facility	563,000	696,000
Atlas Resource Partners, L.P. | 7.75% Senior Notes
Debt Instrument [Line Items]
Senior Notes	$ 374,601	$ 374,544
Debt instrument, interest rate, stated percentage	7.75%	7.75%
Atlas Resource Partners, L.P. | 9.25% Senior Notes
Debt Instrument [Line Items]
Senior Notes	$ 324,038	$ 323,916
Debt instrument, interest rate, stated percentage	9.25%	9.25%

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Acquisitions (Other Acquisition) (Narrative) (Details) - USD ($) $ in Millions								1 Months Ended		3 Months Ended	9 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Jun. 05, 2015	Mar. 31, 2015	Dec. 31, 2014	Nov. 05, 2014	May. 12, 2014	May. 31, 2015	Mar. 31, 2014	Sep. 30, 2015	Sep. 30, 2015
Business Acquisition [Line Items]
Partners unit, issued										5,519,110	8,404,934
Arkoma Acquisition
Business Acquisition [Line Items]
Partners unit, issued								6,500,000
ARP’s and AGP’s Eagle Ford Acquisition
Business Acquisition [Line Items]
Business acquisition, effective date of acquisition						Jul. 01, 2014
Business acquisition, date of acquisition agreement											Nov. 05, 2014
Net cash acquired						$ 342.0
Deferred portion of purchase price						139.0
Deferred portion of purchase price payable in quarterly installments, beginning date											Dec. 31, 2014
Purchase price represent non-cash transaction	$ 21.6
ARP’s Geomet Acquisition
Business Acquisition [Line Items]
Partners unit, issued									6,325,000
Business acquisition, effective date of acquisition							Jan. 01, 2014
Cash consideration							$ 97.9
Business acquisition, description of acquired entity							The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia.
Atlas Resource Partners, L.P. | Arkoma Acquisition
Business Acquisition [Line Items]
Business acquisition, cost of acquired entity, cash paid			$ 31.5
Partners unit, issued											6,500,000
Business acquisition, effective date of acquisition											Jan. 01, 2015
Atlas Resource Partners, L.P. | ARP’s and AGP’s Eagle Ford Acquisition
Business Acquisition [Line Items]
Cash consideration	17.5	$ 0.6				183.1
Atlas Resource Partners, L.P. | ARP’s and AGP’s Eagle Ford Acquisition | Class D Preferred Units
Business Acquisition [Line Items]
Business acquisition, cost of acquired entity, equity interests issued and issuable				$ 20.0
Atlas Growth Partners, L.P | ARP’s and AGP’s Eagle Ford Acquisition
Business Acquisition [Line Items]
Cash consideration		$ 16.0		$ 28.3		$ 19.9
Deferred portion of purchase price					$ 35.0
Purchase price represent non-cash transaction	$ 36.3

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Benefit Plans (Rabbi Trust Narrative) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Rabbi Trust	$ 5,378,000		$ 5,378,000		$ 3,925,000
Rabbi trust liabilities recorded	5,400,000		5,400,000		$ 3,900,000
Partnership distributed to participants			1,672,000
Rabbi trust
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Partnership distributed to participants	$ 0	$ 0	$ 0	$ 0

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Summary of Significant Accounting Policies (Schedule of the Components of Intangible Assets Being Amortized) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Gross Carrying Amount	$ 14,344	$ 14,344
Accumulated Amortization	(13,829)	(13,653)
Net Carrying Amount	$ 515	$ 691
Estimated Useful Lives In Years	13 years

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Debt (Atlas Energy Term Loan Facility) (Details) - USD ($)	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014	Jul. 31, 2013
Debt Instrument [Line Items]
Line of Credit Facility, initiation date	Feb. 27, 2015
Atlas Energy
Debt Instrument [Line Items]
Line of Credit Facility, initiation date	Jul. 31, 2013
Credit facility			$ 240,000,000
Term loan facilities		$ 148,100,000
Line of Credit Facility, expiration date	Jul. 31, 2019
Senior Notes interest payment dates and terms	Borrowings under the Term Facility bore interest, at Atlas Energy’s election, at either an adjusted LIBOR rate plus an applicable margin of 5.50% per annum or the alternate base rate (as defined in the Term Facility) (“ABR”) plus an applicable margin of 4.50% per annum. Interest was generally payable quarterly for ABR loans and, for LIBOR loans at the interest periods selected by Atlas Energy. Atlas Energy was required to repay principal at the rate of $0.6 million per quarter commencing December 31, 2013 and continuing until the maturity date when the remaining balance was due.
Line of Credit Facility, additional margin rates in excess of LIBOR	5.50%
Line of Credit Facility, borrowing base additional rate	4.50%
Line of Credit Facility, principal repayment rate per quarter	$ 600,000
Outstanding Term Facility, weighted average interest rate	6.50%

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Issuances of Units (Preferred Unit Purchase Agreement) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		9 Months Ended
	Feb. 27, 2015	Sep. 30, 2015
Capital Unit [Line Items]
Percentage of Preferred Unit Regular Quarterly Cash Distributions		10.75%
Percentage Of Common Unit Regular Quarterly Cash Distributions	2.00%
Series A Convertible Preferred Units
Capital Unit [Line Items]
Partners Capital Account Units Date Of Sale		February 27, 2015
Partners' Capital Account, Units, Sold in Private Placement	1.6
Redemption price per unit		$ 25.00
Subsidiary or Equity Method Investee, Price-Per-Share		$ 25.00
Partners' Capital Account, Private Placement of Units		$ 40.0
Cash consideration		$ 150.0
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 of the Company; and (ii) the lower of (a) 110.0% of the volume weighted average price for the Company’s common units on the NYSE over the 30 trading days following the distribution date; and (b) $16.00 per common unit of the Company.
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 | Private Placement | First Anniversary | Maximum
Capital Unit [Line Items]
Percentage of Preferred Unit Regular Quarterly Cash Distributions	12.00%
Series A Convertible Preferred Units | Private Placement | Second Anniversary | Maximum
Capital Unit [Line Items]
Percentage of Preferred Unit Regular Quarterly Cash Distributions	14.00%
Series A Convertible Preferred Units | Private Placement | Third Anniversary | Maximum
Capital Unit [Line Items]
Percentage of Preferred Unit Regular Quarterly Cash Distributions	16.00%

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Derivative Instruments (ARP's Commodity Derivative Instruments by Type Table) (Details) - Atlas Resource Partners, L.P. $ in Thousands	Sep. 30, 2015 USD ($) bbl MMBTU gal $ / bbl $ / MMBTU $ / gal
Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	$ 216,033	[1]
Natural Gas Costless Collars
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	803	[1]
Natural Gas Put Options Drilling Partnership
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	2,457	[1]
Natural Gas - WAHA Basis Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	41	[2]
Natural Gas Liquids Natural Gasoline Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	1,225	[3]
Natural Gas Liquids Propane Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	1,096	[4]
Natural Gas Liquids - Butane Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	237	[5]
Natural Gas Liquids Iso Butane Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	238	[6]
Natural Gas Liquids Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	4,866	[7]
Natural Gas Liquids – Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	125,605	[7]
Total ARP Net Liability
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	$ 352,601	[7]
Production Period Ending December 31 2015 | Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	13,611,100	[8]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	4.193	[8]
Fair Value Asset / (Liability)	$ 21,734	[1]
Production Period Ending December 31 2015 | Natural Gas Costless Collars | Puts Purchased
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	600,000	[8]
Fair Value Asset / (Liability)	$ 803	[1]
Average Floor and Cap | $ / MMBTU	3.934	[8]
Production Period Ending December 31 2015 | Natural Gas Costless Collars | Calls Sold
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	600,000	[8]
Average Floor and Cap | $ / MMBTU	4.634	[8]
Production Period Ending December 31 2015 | Natural Gas Put Options Drilling Partnership | Puts Purchased
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	360,000	[8]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	4.000	[8]
Fair Value Asset / (Liability)	$ 505	[1]
Production Period Ending December 31 2015 | Natural Gas - WAHA Basis Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	1,200,000	[8]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	(0.090)	[8]
Fair Value Asset / (Liability)	$ 41	[2]
Production Period Ending December 31 2015 | Natural Gas Liquids Natural Gasoline Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | gal	1,260,000	[8]
Derivative, Swap Type, Average Fixed Price | $ / gal	1.923	[8]
Fair Value Asset / (Liability)	$ 1,225	[3]
Production Period Ending December 31 2015 | Natural Gas Liquids Propane Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | gal	2,016,000	[8]
Derivative, Swap Type, Average Fixed Price | $ / gal	1.016	[8]
Fair Value Asset / (Liability)	$ 1,096	[4]
Production Period Ending December 31 2015 | Natural Gas Liquids - Butane Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | gal	378,000	[8]
Derivative, Swap Type, Average Fixed Price | $ / gal	1.248	[8]
Fair Value Asset / (Liability)	$ 237	[5]
Production Period Ending December 31 2015 | Natural Gas Liquids Iso Butane Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | gal	378,000	[8]
Derivative, Swap Type, Average Fixed Price | $ / gal	1.263	[8]
Fair Value Asset / (Liability)	$ 238	[6]
Production Period Ending December 31 2015 | Natural Gas Liquids – Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	487,500	[8]
Derivative, Swap Type, Average Fixed Price | $ / bbl	87.592	[8]
Fair Value Asset / (Liability)	$ 20,377	[7]
Production Period Ending December 31 2016 | Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	53,546,300	[8]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	4.229	[8]
Fair Value Asset / (Liability)	$ 75,852	[1]
Production Period Ending December 31 2016 | Natural Gas Put Options Drilling Partnership | Puts Purchased
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	1,440,000	[8]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	4.150	[8]
Fair Value Asset / (Liability)	$ 1,952	[1]
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	84,000	[8]
Derivative, Swap Type, Average Fixed Price | $ / bbl	85.651	[8]
Fair Value Asset / (Liability)	$ 3,038	[7]
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	1,557,000	[8]
Derivative, Swap Type, Average Fixed Price | $ / bbl	81.471	[8]
Fair Value Asset / (Liability)	$ 49,856	[7]
Production Period Ending December 31 2017 | Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	49,920,000	[8]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	4.219	[8]
Fair Value Asset / (Liability)	$ 60,364	[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	60,000	[8]
Derivative, Swap Type, Average Fixed Price | $ / bbl	83.780	[8]
Fair Value Asset / (Liability)	$ 1,828	[7]
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	1,140,000	[8]
Derivative, Swap Type, Average Fixed Price | $ / bbl	77.285	[8]
Fair Value Asset / (Liability)	$ 27,462	[7]
Production Period Ending December 31 2018 | Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	40,800,000	[8]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	4.170	[8]
Fair Value Asset / (Liability)	$ 44,298	[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	[8]
Derivative, Swap Type, Average Fixed Price | $ / bbl	76.281	[8]
Fair Value Asset / (Liability)	$ 22,073	[7]
Production Period Ending December 31 2019 | Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	15,960,000	[8]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	4.017	[8]
Fair Value Asset / (Liability)	$ 13,785	[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	[8]
Derivative, Swap Type, Average Fixed Price | $ / bbl	68.371	[8]
Fair Value Asset / (Liability)	$ 5,837	[7]

[1] Fair value based on forward NYMEX natural gas prices, as applicable.

[2] Fair value based on forward WAHA natural gas prices, as applicable

[3] Fair value based on forward Mt. Belvieu natural gasoline prices, as applicable.

[4] Fair value based on forward Mt. Belvieu propane prices, as applicable.

[5] Fair value based on forward Mt. Belvieu butane prices, as applicable.

[6] Fair value based on forward Mt. Belvieu iso butane prices, as applicable.

[7] Fair value based on forward WTI crude oil prices, as applicable.

[8] “MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons.

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Other Assets (Narrative) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Other Assets [Line Items]
Accumulated amortization	$ 39,945,000		$ 39,945,000		$ 20,675,000
Amortization of financing costs	3,600,000	$ 2,700,000	9,800,000	$ 7,000,000
Accelerated amortization of deferred financing costs	$ 0		5,200,000	0
Distributions received from unconsolidated companies			$ 2,104,000	1,244,000
Lightfoot LP
Other Assets [Line Items]
Equity method investment ownership percentage	12.00%		12.00%
Distributions received from unconsolidated companies	$ 1,400,000	500,000	$ 2,200,000	1,200,000
Lightfoot GP
Other Assets [Line Items]
Equity method investment ownership percentage	15.90%		15.90%
Lightfoot
Other Assets [Line Items]
Equity income in joint ventures	$ 300,000	400,000	$ 500,000	800,000
Atlas Resource Partners, L.P.
Other Assets [Line Items]
Accelerated amortization of deferred financing costs	0	0	4,300,000	0
Allowance for credit loss	0		$ 0		$ 0
Atlas Resource Partners, L.P. | Note Agreement, Option to Extend Maturity Date
Other Assets [Line Items]
Senior notes, maturity date			Mar. 31, 2027
Note agreement extension fee percent			1.00%
Atlas Resource Partners, L.P. | Notes Receivable
Other Assets [Line Items]
Senior notes, maturity date			Mar. 31, 2022
Note agreement interest rate per annum			2.25%
Other interest and dividend income	$ 21,000	$ 22,000	$ 64,000	$ 68,000

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Acquisitions

9 Months Ended

Sep. 30, 2015

Business Combinations [Abstract]

Acquisitions

NOTE 3—ACQUISITIONS

ARP’s Rangely Acquisition

On June 30, 2014, ARP completed an acquisition of a 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado from Merit Management Partners I, L.P., Merit Energy Partners III, L.P. and Merit Energy Company, LLC (collectively, “Merit Energy”) for approximately $408.9 million in cash, net of purchase price adjustments (the “Rangely Acquisition”). The purchase price was funded through borrowings under ARP’s revolving credit facility, the issuance of an additional $100.0 million of ARP’s 7.75% senior notes due 2021 (“7.75% ARP Senior Notes”) (see Note 7) and the issuance of 15,525,000 of ARP’s common limited partner units (see Note 12). The Rangely Acquisition had an effective date of April 1, 2014. The Company’s combined consolidated financial statements reflected the operating results of the acquired business commencing June 30, 2014 with the transaction closing.

ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9). In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $11.6 million of transaction fees which were included within non-controlling interests at December 31, 2014 on the Company’s combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred.

The following table presents the values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

Assets:
Prepaid expenses and other	$	4,041
Property, plant and equipment		405,416
Other assets, net		2,888
Total assets acquired	$	412,345
Liabilities:
Accrued liabilities		2,117
Asset retirement obligation		1,305
Total liabilities assumed		3,422
Net assets acquired	$	408,923

Other Acquisitions

ARP’s Arkoma Acquisition

On June 5, 2015, ARP completed the acquisition of the Company’s coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma for approximately $31.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). ARP funded the purchase price through the issuance of 6,500,000 common limited partner units (see Note 12). 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.

ARP’s and AGP’s Eagle Ford Acquisition

On November 5, 2014, ARP and AGP completed an acquisition of oil and natural gas liquid interests in the Eagle Ford Shale in Atascosa County, Texas from Cima Resources, LLC and Cinco Resources, Inc. (together “Cinco”) for $342.0 million, net of purchase price adjustments (the “Eagle Ford Acquisition”). Approximately $183.1 million was paid in cash by ARP and $19.9 million was paid by AGP at closing, and approximately $139.0 million was to be paid in four quarterly installments beginning December 31, 2014. On December 31, 2014, AGP made its first installment payment of $35.0 million related to its Eagle Ford Acquisition. Prior to the March 31, 2015 installment, ARP, AGP, and Cinco amended the purchase and sale agreement to alter the timing and amount of the quarterly payments beginning with the March 31, 2015 payment and ending December 31, 2015, with no change to the overall purchase price. On March 31, 2015, AGP paid $28.3 million and ARP issued $20.0 million of its Class D ARP Preferred Units (see Note 12) to satisfy the second installment related to the Eagle Ford Acquisition. On June 30, 2015, AGP paid $16.0 million and ARP paid $0.6 million to satisfy the third installment related to the Eagle Ford Acquisition. In September 2015, ARP agreed with AGP to have AGP transfer its remaining $36.3 million of deferred purchase obligation, along with the related undeveloped natural gas and oil properties, to ARP.  On September 30, 2015, ARP paid $17.5 million to satisfy the fourth installment related to the Eagle Ford Acquisition.  At September 30, 2015, ARP’s remaining deferred portion of the purchase price was $21.6 million, payable on December 31, 2015. The Eagle Ford Acquisition had an effective date of July 1, 2014. ARP’s issuance of Class D ARP Preferred Units represents a non-cash transaction for statement of cash flow purposes during the nine months ended September 30, 2015.

ARP’s GeoMet Acquisition

On May 12, 2014, ARP completed the acquisition of certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $97.9 million in cash, net of purchase price adjustments (the “GeoMet Acquisition”), with an effective date of January 1, 2014. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia.

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Fair Value of Financial Instruments (Schedule of Assets/Liabilities at Fair Value) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	$ 358,548	$ 279,254
Liabilities, gross	(7)	(468)
Total assets, fair value, net	358,541	278,786
Rabbi trust
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Rabbi trust	5,378	3,925
Level 1
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	5,378	3,925
Total assets, fair value, net	5,378	3,925
Level 1 | Rabbi trust
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Rabbi trust	5,378	3,925
Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	353,170	275,329
Liabilities, gross	(7)	(468)
Total assets, fair value, net	353,163	274,861
Atlas Resource Partners, L.P. | Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	2,457	2,767
Atlas Resource Partners, L.P. | Swap | Commodity Contract
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	349,348	267,242
Liabilities, gross	(7)	(401)
Atlas Resource Partners, L.P. | Commodity Options
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	803	5,320
Liabilities, gross		(67)
Atlas Resource Partners, L.P. | Level 2 | Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	2,457	2,767
Atlas Resource Partners, L.P. | Level 2 | Swap | Commodity Contract
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	349,348	267,242
Liabilities, gross	(7)	(401)
Atlas Resource Partners, L.P. | Level 2 | Commodity Options
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	803	5,320
Liabilities, gross		$ (67)
Atlas Growth Partners, L.P | Swap | Commodity Contract
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	562
Atlas Growth Partners, L.P | Level 2 | Swap | Commodity Contract
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	$ 562

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Property, Plant and Equipment (Summary of Property, Plant and Equipment) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Property Plant And Equipment [Abstract]
Proved properties: Leasehold interests	$ 469,684	$ 455,401
Proved properties: Pre-development costs	8,664	7,378
Proved properties: Wells and related equipment	3,158,769	3,082,429
Total proved properties	3,637,117	3,545,208
Unproved properties	316,924	311,946
Support equipment	44,274	37,359
Total natural gas and oil properties	3,998,315	3,894,513
Pipelines, processing and compression facilities	59,598	49,547
Rights of way	829	830
Land, buildings and improvements	9,202	9,160
Other	18,318	17,936
Total gross property, plant and equipment	4,086,262	3,971,986
Less – accumulated depreciation, depletion and amortization	(2,426,904)	(1,552,697)
Property, plant and equipment, Net, Total	$ 1,659,358	$ 2,419,289

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Debt (Tables)

9 Months Ended

Sep. 30, 2015

Debt Disclosure [Abstract]

Schedule of Long-term Debt Instruments

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

		September 30,		December 31,
		2015		2014
Term loan facilities	$	82,700	$	148,125
ARP revolving credit facility		563,000		696,000
ARP term loan facility		243,408		—
ARP 7.75% Senior Notes—due 2021		374,601		374,544
ARP 9.25% Senior Notes—due 2021		324,038		323,916
Total debt		1,587,747		1,542,585
Less current maturities		—		(1,500	)
Total long-term debt	$	1,587,747	$	1,541,085

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2015

Asset Retirement Obligation Disclosure [Abstract]

Reconciliation of Liability for Well Plugging and Abandonment Costs

A reconciliation of the Company’s subsidiaries’ liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Asset retirement obligations, beginning of period	$	110,937		$	101,455		$	108,101		$	91,214
Liabilities incurred		80			336			296			8,283
Liabilities settled		(1	)		(271	)		(547	)		(820	)
Accretion expense		1,584			1,471			4,750			4,314
Asset retirement obligations, end of period	$	112,600		$	102,991		$	112,600		$	102,991

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Derivative Instruments (Narrative) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Derivative Instruments Gain Loss [Line Items]
Cash flow hedges derivative assets at fair value, net	$ 353,200,000		$ 353,200,000		$ 274,900,000
Net gain in accumulated other comprehensive income	10,400,000		10,400,000
Cash flow hedge gain (losses) to be reclassified within twelve months			8,000,000
Cash flow hedge gain (loss) to be reclassified in later periods			2,400,000
Derivative instruments, gains reclassified from accumulated OCI into income, effective portion		$ 300,000		$ 800,000
Cash settlement gain (loss) on commodity derivative contracts	43,679,000	1,400,000	126,925,000	(22,700,000)
Gain (loss) recognized for hedge Ineffectiveness or as a result of discontinuance of cash flow hedges	0	$ 0	0	$ 0
Atlas Resource Partners, L.P.
Derivative Instruments Gain Loss [Line Items]
Net unrealized derivative assets payable to limited partners	$ 2,500,000		2,500,000
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

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Property, Plant and Equipment (Useful Life Narrative) (Details)	9 Months Ended
	Sep. 30, 2015
Pipelines, processing and compression facilities | Minimum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	2 years
Pipelines, processing and compression facilities | Maximum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	40 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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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2015

Derivatives Fair Value [Line Items]

Summary of Commodity Derivative Activity

The following table summarizes the commodity derivative activity for the three and nine months ended September 30, 2015 (in thousands):  

	Three Months EndedSeptember 30, 2015			Nine Months EndedSeptember 30, 2015
Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets(1)	$	(23,927	)	$	(77,048	)
Portion of settlements attributable to subsequent mark to market gains		(19,752	)		(49,877	)
Total cash settlements on commodity derivative contracts		(43,679	)		(126,925	)
2015 Unrealized gains prior to settlement(2)		10,989			17,822
Unrealized gain on open derivative contracts at September 30, 2015, net of amounts recognized in income in prior year(2)		120,788			192,644
Gains on mark-to-market derivatives	$	131,777		$	210,466

(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 the Company’s combined consolidated balance sheets as of the dates indicated (in thousands):

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Combined Consolidated Balance Sheets		Net Amount ofAssets Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Assets
As of September 30, 2015
Current portion of derivative assets	$	399	$	—	$	399
Long-term portion of derivative assets		163		—		163
Total derivative assets	$	562	$	—	$	562
As of December 31, 2014
Current portion of derivative assets	$	—	$	—	$	—
Long-term portion of derivative assets		—		—		—
Total derivative assets	$	—	$	—	$	—

	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Combined Consolidated Balance Sheets		Net Amount of Liabilities Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Liabilities
As of September 30, 2015
Current portion of derivative liabilities	$	—	$	—	$	—
Long-term portion of derivative liabilities		—		—		—
Total derivative liabilities	$	—	$	—	$	—
As of December 31, 2014
Current portion of derivative liabilities	$	—	$	—	$	—
Long-term portion of derivative liabilities		—		—		—
Total derivative liabilities	$	—	$	—	$	—

Commodity Derivative Instruments by Type Table

At September 30, 2015, AGP had the following commodity derivatives:

Crude Oil – Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Bbl)(1)		(per Bbl)(1)		(in thousands)(2)
2015		13,500	$	61.000	$	205
2016		18,000	$	63.150		249
2017		9,000	$	65.000		108
	AGP’s net assets				$	562

⁽¹⁾ “Bbl” represents barrels.

⁽²⁾ Fair value based on forward WTI crude oil prices, as applicable.

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 the Company’s combined consolidated balance sheets as of the dates indicated (in thousands):

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Combined Consolidated Balance Sheets			Net Amount ofAssets Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Assets
As of September 30, 2015
Current portion of derivative assets	$	146,629	$	(7	)	$	146,622
Long-term portion of derivative assets		205,979		—			205,979
Total derivative assets	$	352,608	$	(7	)	$	352,601
As of December 31, 2014
Current portion of derivative assets	$	144,357	$	(98	)	$	144,259
Long-term portion of derivative assets		130,972		(370	)		130,602
Total derivative assets	$	275,329	$	(468	)	$	274,861

	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Combined Consolidated Balance Sheets		Net Amount of Liabilities Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Liabilities
As of September 30, 2015
Current portion of derivative liabilities	$	(7	)	$	7	$	—
Long-term portion of derivative liabilities		—			—		—
Total derivative liabilities	$	(7	)	$	7	$	—
As of December 31, 2014
Current portion of derivative liabilities	$	(98	)	$	98	$	—
Long-term portion of derivative liabilities		(370	)		370		—
Total derivative liabilities	$	(468	)	$	468	$	—

Commodity Derivative Instruments by Type Table

At September 30, 2015, ARP had the following commodity derivatives:

Natural Gas – Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(MMBtu)(1)		(per MMBtu)(1)		(in thousands)(2)
2015		13,611,100	$	4.193	$	21,734
2016		53,546,300	$	4.229		75,852
2017		49,920,000	$	4.219		60,364
2018		40,800,000	$	4.170		44,298
2019		15,960,000	$	4.017		13,785
					$	216,033

Natural Gas – Costless Collars

Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap		Fair Value Asset
		(MMBtu)(1)		(per MMBtu)(1)		(in thousands)(2)
2015	Puts purchased		600,000	$	3.934	$	803
2015	Calls sold		600,000	$	4.634		—
						$	803

Natural Gas – Put Options – Drilling Partnerships

Production Period Ending December 31,	Option Type	Volumes		Average Fixed Price		Fair Value Asset
		(MMBtu)(1)		(per MMBtu)(1)		(in thousands)(2)
2015	Puts purchased		360,000	$	4.000	$	505
2016	Puts purchased		1,440,000	$	4.150		1,952
						$	2,457

Natural Gas – WAHA Basis Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price			Fair Value Asset
	(MMBtu)(1)		(per MMBtu)(1)			(in thousands)(7)
2015		1,200,000	$	(0.090	)	$	41
						$	41

Natural Gas Liquids – Natural Gasoline Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Gal)(1)		(per Gal)(1)		(in thousands)(8)
2015		1,260,000	$	1.923	$	1,225
					$	1,225

Natural Gas Liquids – Propane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Gal)(1)		(per Gal)(1)		(in thousands)(4)
2015		2,016,000	$	1.016	$	1,096
					$	1,096

Natural Gas Liquids – Butane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Gal)(1)		(per Gal)(1)		(in thousands)(5)
2015		378,000	$	1.248	$	237
					$	237

Natural Gas Liquids – Iso Butane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Gal)(1)		(per Gal)(1)		(in thousands)(6)
2015		378,000	$	1.263	$	238
					$	238

Natural Gas Liquids – Crude Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Bbl)(1)		(per Bbl)(1)		(in thousands)(3)
2016		84,000	$	85.651	$	3,038
2017		60,000	$	83.780		1,828
					$	4,866

Crude Oil – Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Bbl)(1)		(per Bbl)(1)		(in thousands)(3)
2015		487,500	$	87.592	$	20,377
2016		1,557,000	$	81.471		49,856
2017		1,140,000	$	77.285		27,462
2018		1,080,000	$	76.281		22,073
2019		540,000	$	68.371		5,837
					$	125,605
		ARP’s net assets			$	352,601

⁽¹⁾ “MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons.

⁽²⁾ Fair value based on forward NYMEX natural gas prices, as applicable.

⁽³⁾ Fair value based on forward WTI crude oil prices, as applicable.

⁽⁴⁾ Fair value based on forward Mt. Belvieu propane prices, as applicable.

⁽⁵⁾ Fair value based on forward Mt. Belvieu butane prices, as applicable.

⁽⁶⁾ Fair value based on forward Mt. Belvieu iso butane prices, as applicable.

⁽⁷⁾ Fair value based on forward WAHA natural gas prices, as applicable

⁽⁸⁾ Fair value based on forward Mt. Belvieu natural gasoline prices, as applicable.

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Fair Value of Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2015

Fair Value Disclosures [Abstract]

Company, ARP Assets and Liabilities Measured at Fair Value

Information for the Company and its subsidiaries’ assets and liabilities measured at fair value at September 30, 2015 and December 31, 2014 was as follows (in thousands):

	Level 1		Level 2			Level 3		Total
As of September 30, 2015
Assets, gross
Rabbi trust	$	5,378	$	—		$	—	$	5,378
ARP Commodity swaps		—		349,348			—		349,348
ARP Commodity puts		—		2,457			—		2,457
ARP Commodity options		—		803			—		803
AGP Commodity swaps		—		562			—		562
Total assets, gross		5,378		353,170			—		358,548
Liabilities, gross
ARP Commodity swaps		—		(7	)		—		(7	)
ARP Commodity options		—		—			—		—
AGP Commodity swaps		—		—			—		—
Total derivative liabilities, gross		—		(7	)		—		(7	)
Total assets, fair value, net	$	5,378	$	353,163		$	—	$	358,541
As of December 31, 2014
Assets, gross
Rabbi trust	$	3,925	$	—		$	—	$	3,925
ARP Commodity swaps		—		267,242			—		267,242
ARP Commodity puts		—		2,767			—		2,767
ARP Commodity options		—		5,320			—		5,320
Total assets, gross		3,925		275,329			—		279,254
Liabilities, gross
ARP Commodity swaps		—		(401	)		—		(401	)
ARP Commodity options		—		(67	)		—		(67	)
Total derivative liabilities, gross		—		(468	)		—		(468	)
Total assets, fair value, net	$	3,925	$	274,861		$	—	$	278,786

Schedule of Assets and Liabilities Measured on Non Recurring Basis

Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the three and nine months ended September 30, 2015 and 2014 was as follows (in thousands):

	Three Months Ended September 30,
	2015				2014
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	80	$	80	$	336	$	336
Total	$	80	$	80	$	336	$	336

	Nine Months Ended September 30,
	2015				2014
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	296	$	296	$	8,283	$	8,283
Total	$	296	$	296	$	8,283	$	8,283

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2015

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Combination

The consolidated balance sheet at September 30, 2015 and the related combined consolidated statements of operations for the three and nine months ended September 30, 2015, subsequent to the transfer of assets on February 27, 2015, include the accounts of the Company and its subsidiaries. The Company’s combined consolidated balance sheet at December 31, 2014, the combined consolidated statement of operations for the portion of 2015 which is prior to the transfer of assets on February 27, 2015, and the combined consolidated statement of operations for the three and nine months ended September 30, 2014 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 the Company had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various entities comprising the Company, Atlas Energy’s net investment in the Company is shown as equity in the 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 combined consolidated balance sheets and related 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 the Company. Actual balances and results could be different from those estimates. Transactions between the Company and other Atlas Energy operations have been identified in the combined consolidated financial statements as transactions between affiliates.

In connection with Atlas Energy’s merger with Targa and the concurrent Separation, the Company was 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 generally accepted accounting principles, the Company included $150.0 million of Atlas Energy’s original term loan at the time of issuance, and the related interest expense, within its historical financial statements. Atlas Energy’s other historical borrowings were allocated to the Company’s historical financial statements in the same ratio. The Company used proceeds from the issuance of its Series A preferred units (see Note 12) and borrowings under its term loan credit facilities (see Note 7) to fund the $150.0 million payment.

The Company combines the financial statements of ARP and AGP into its combined consolidated financial statements rather than presenting its ownership interest as equity investments, as the Company controls these entities through its general partnership interests therein. As such, the non-controlling interests in ARP and AGP are reflected as (income) loss attributable to non-controlling interests in the combined consolidated statements of operations and as a component of unitholders’ equity on the combined consolidated balance sheets. All material intercompany transactions have been eliminated.

In accordance with established practice in the oil and gas industry, the Company’s combined consolidated financial statements include its 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%. The Company’s 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 (see “Property, Plant and Equipment”).

Use of Estimates

The preparation of the Company’s 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 the Company’s combined consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Company’s combined consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired and liabilities assumed. Such estimates included estimated allocations made from the historical accounting records of Atlas Energy in order to derive the historical financial statements of the Company. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three and nine months ended September 30, 2015 and 2014 represent actual results in all material respects (see “Revenue Recognition”).

Receivables

Accounts receivable on the combined consolidated balance sheets consist primarily of the trade accounts receivable associated with the Company and its subsidiaries. In evaluating the realizability of accounts receivable, management performs ongoing credit evaluations of customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness, as determined by management’s review of customers’ credit information. The Company and its subsidiaries extend credit on sales on an unsecured basis to many of their customers. At September 30, 2015 and December 31, 2014, the Company had recorded no allowance for uncollectible accounts receivable on its combined consolidated balance sheets.

Inventory

The Company had $8.7 million and $8.9 million of inventory at September 30, 2015 and December 31, 2014, respectively, which were included within prepaid expenses and other current assets on its combined consolidated balance sheets. The Company values inventories at the lower of cost or market. The Company’s inventories, which consist primarily of ARP’s materials, pipes, supplies and other inventories, were principally determined using the average cost method.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Company’s results of operations.

The Company’s subsidiaries follow the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. “Mcf” is defined as one thousand cubic feet.

The Company’s subsidiaries’ depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include ARP’s costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by ARP for its interests, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s combined consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s combined consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s combined consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Impairment of Long-Lived Assets

The Company and its subsidiaries review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s subsidiaries’ plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. The Company’s subsidiaries estimate prices based upon current contracts in place, adjusted for basis differentials and market-related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, ARP’s reserve estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include ARP’s actual capital contributions and a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

ARP’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to ARP operating and administrative fees in addition to their proportionate share of external operating expenses. These assumptions could result in ARP’s calculation of depletion and impairment being different than its proportionate share of the Drilling Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Company and ARP cannot predict what reserve revisions may be required in future periods.

ARP’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships, which ARP sponsors and owns an interest in but does not control. ARP’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which ARP may be unable to recover due to the Drilling Partnerships’ legal structure. ARP may have to pay additional consideration in the future as a Drilling Partnership’s wells become uneconomic to the Drilling Partnership under the terms of the Drilling Partnership’s drilling and operating agreement in order to recover these excess reserves, in addition to ARP becoming responsible for paying associated future operating, development and plugging costs of the well interests acquired, and to acquire any additional residual interests in the wells held by the Drilling Partnership’s limited partners. The acquisition of any such uneconomic well interest from the Drilling Partnership by ARP is governed under the Drilling Partnership’s limited partnership agreement. In general, ARP will seek consent from the Drilling Partnership’s limited partners to acquire the well interests from the Drilling Partnership based upon ARP’s determination of fair market value.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate that the Company’s subsidiaries will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. There were no impairments of unproved gas and oil properties recorded on the Company’s combined consolidated statements of operations for the three and nine months ended September 30, 2015 and 2014.

Capitalized Interest

ARP capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP were 6.5% and 5.4% for the three months ended September 30, 2015 and 2014, respectively, and 6.4% and 5.7% for the nine months ended September 30, 2015 and 2014, respectively. The amounts of interest capitalized by ARP were $4.0 million and $3.7 million for the three months ended September 30, 2015 and 2014, respectively, and $12.0 million and $9.4 million for the nine months ended September 30, 2015 and 2014, respectively.

Intangible Assets

ARP has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. ARP amortizes contracts acquired on a declining balance method over their respective estimated useful lives.

The following table reflects the components of intangible assets being amortized at September 30, 2015 and December 31, 2014 (in thousands):

	September 30,			December 31,			Estimated Useful Lives
	2015			2014			In Years
Gross Carrying Amount	$	14,344		$	14,344			13
Accumulated Amortization		(13,829	)		(13,653	)
Net Carrying Amount	$	515		$	691

Amortization expense on intangible assets was $0.1 million for both the three months ended September 30, 2015 and 2014. Amortization expense on intangible assets was $0.2 million for both the nine months ended September 30, 2015 and 2014. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2015 - $0.2million; 2016 - $0.1million; 2017 - $0.1 million; 2018 - $0.1 million; and 2019 - $0.1 million.

Goodwill

At September 30, 2015 and December 31, 2014, the Company had $13.6 million of goodwill recorded in connection with ARP’s prior consummated acquisitions. No changes in the carrying amount of goodwill were recorded for the three and nine months ended September 30, 2015 and 2014.

ARP tests goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units. ARP’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including ARP’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, ARP also considers the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ARP’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in ARP’s industry to determine whether those valuations appear reasonable in management’s judgment. ARP’s management will continue to evaluate goodwill at least annually or when impairment indicators arise.

As a result of its goodwill impairment evaluation at December 31, 2014, ARP recognized an $18.1 million non-cash impairment charge within asset impairments on the Company’s combined consolidated statement of operations for the year ended December 31, 2014. The goodwill impairment resulted from the reduction in ARP’s estimated fair value of its gas and oil production reporting unit in comparison to its carrying amount at December 31, 2014. ARP’s estimated fair value of its gas and oil production reporting unit was impacted by a decline in overall commodity prices during the fourth quarter of 2014.

Derivative Instruments

ARP and AGP enter into certain financial contracts to manage their exposure to movement in commodity prices and interest rates (see Note 8). The derivative instruments recorded in the combined consolidated balance sheets are measured as either an asset or liability at fair value. Changes in the fair value of derivative instruments are recognized currently in the Company’s combined consolidated statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Company and ARP discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s combined consolidated statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 will be reclassified to the combined consolidated statements of operations in the periods in which those respective derivative contracts settle. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within unitholders’ equity on the Company’s consolidated balance sheets and reclassified to the Company’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings.

Asset Retirement Obligations

The Company’s subsidiaries recognize an estimated liability for the plugging and abandonment of gas and oil wells and related facilities (see Note 6). The Company’s subsidiaries also recognize a liability for future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Company‘s subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

ARP Preferred Units

In connection with ARP’s acquisition of certain proved reserves and associated assets from Titan Operating, L.L.C. in July 2012, ARP issued 3.8 million newly created convertible Class B ARP preferred units (“Class B ARP Preferred Units”). While outstanding, the Class B ARP Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. On December 23, 2014, 3,796,900 of Class B ARP Preferred Units were converted into common units, while the remaining 39,654 Class B ARP Preferred Units were converted into common units on July 25, 2015. In connection with ARP’s acquisition of certain proved reserves and associated assets from EP Energy, Inc. in July 2013, ARP issued 3.7 million newly created convertible Class C ARP preferred units to Atlas Energy (“Class C ARP Preferred Units”). While outstanding, the Class C ARP Preferred Units will receive regular quarterly cash distributions equal to the greater of (i) $0.51 and (ii) the quarterly common unit distribution. In October 2014, in connection with ARP’s acquisition of assets in the Eagle Ford Shale (see Note 3), ARP issued 3.2 million of its 8.625% Class D cumulative redeemable perpetual preferred units (“Class D ARP Preferred Units”) and in March 2015, issued an additional 800,000 Class D ARP Preferred Units (see Note 12). The initial quarterly distribution on the Class D ARP Preferred Units was $0.616927 per unit, representing the distribution for the period from October 2, 2014 through January 14, 2015. Subsequent to January 14, 2015, ARP pays quarterly distributions on the Class D ARP Preferred Units at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference. In April 2015, ARP issued 255,000 of its newly created 10.75% Class E Cumulative Redeemable Perpetual ARP preferred units (“Class E ARP Preferred Units”). The initial quarterly distribution on the Class E ARP Preferred Units was $0.6793 per unit, representing the distribution for the period from April 14, 2015 through July 15, 2015. Subsequent to July 15, 2015, ARP will pay future quarterly distributions on the Class E Preferred Units at an annual rate of $2.6875 per unit, or 10.75% of the liquidation preference. At September 30, 2015 and December 31, 2014, $103.5 million and $78.0 million, respectively, related to ARP’s preferred units, are included within non-controlling interests on the Company’s combined consolidated statements of unitholders’ equity.

Income Taxes

The Company, ARP, AGP, Lightfoot and the respective subsidiaries thereof are not subject to U.S. federal and most state income taxes. The partners of these entities are liable for income tax in regard to their distributive share of the entities’ taxable income. Such taxable income may vary substantially from net income (loss) reported in the accompanying combined consolidated financial statements. Certain corporate subsidiaries of ARP are subject to federal and state income tax. The federal and state income taxes related to the Company and these corporate subsidiaries were immaterial to the combined consolidated financial statements as of September 30, 2015 and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for these corporate subsidiaries in the accompanying combined consolidated financial statements.

Each of the entities which comprise the Company evaluates tax positions taken or expected to be taken in the course of preparing their respective tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Company’s management does not believe it has any tax positions taken within its combined consolidated financial statements that would not meet this threshold. The Company’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Company has not recognized any such potential interest or penalties in its combined consolidated financial statements for the three and nine months ended September 30, 2015 and 2014.

The entities comprising the Company file Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the entities comprising the Company are no longer subject to income tax examinations by major tax authorities for years prior to 2011 and are not currently being examined by any jurisdiction and are not aware of any potential examinations as of September 30, 2015.

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 share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. A portion of the Company’s phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plans and incentive compensation agreements (see Note 14), contain non-forfeitable rights to distribution equivalents of the Company. The participation rights result in a non-contingent transfer of value each time the Company declares 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 loss allocated to the common unitholders for purposes of calculating net loss attributable to common unitholders per unit (in thousands, except unit data):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Net loss	$	(582,313	)	$	(4,349	)	$	(588,377	)	$	(46,195	)
Preferred unitholder dividends		(1,009	)		—			(2,346	)		—
Loss attributable to non-controlling interests		439,969			5,137			420,411			33,828
(Income) loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015)		—			(788	)		10,475			12,367
Net loss utilized in the calculation of net loss attributable to common unitholders per unit – basic and diluted(1)	$	(143,353	)	$	—		$	(159,837	)	$	—

(1) Net loss attributable to common unitholders per unit is calculated by dividing net income (loss) attributable to common unitholders, less income allocable to participating securities, by the sum of the weighted average number of common unitholder 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. For the three months ended September 30, 2015, net loss attributable common unitholders per unit is not allocated to approximately 69,000 phantom units, 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 nine months ended September 30, 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 68,000 phantom units, 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 three and nine months ended September 30, 2015, distributions on the Company’s Series A preferred units were excluded, because the inclusion of such preferred distributions would have been anti-dilutive.

The following table sets forth the reconciliation of the Company’s 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 September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Weighted average number of common unitholders per unit—basic		26,011		—		26,011		—
Add effect of dilutive incentive awards(1)		—		—		—		—
Add effect of dilutive convertible preferred units(1)		—		—		—		—
Weighted average number of common unitholders per unit—diluted		26,011		—		26,011		—

(1) For the three months ended September 30, 2015, 2,737,000 phantom units 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 nine months ended September 30, 2015, 1,492,000 phantom units 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 three and nine months ended September 30, 2015, potential common units issuable upon conversion of the Company’s 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.

Revenue Recognition

Natural gas and oil production. The Company’s subsidiaries’ gas and oil production operations generally sell natural gas, crude oil and NGLs at prevailing market prices. Typically, sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which the Company’s subsidiaries have an interest with other producers, are recognized on the basis of the entity’s percentage ownership of the working interest and/or overriding royalty.

ARP’s Drilling Partnerships. Certain energy activities are conducted by ARP through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by ARP is deployed to drill and complete wells included within the partnership. As ARP deploys Drilling Partnership investor capital, it recognizes certain management fees it is entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if ARP has Drilling Partnership investor capital that has not yet been deployed, it will recognize a current liability titled “Liabilities Associated with Drilling Contracts” on the Company’s combined consolidated balance sheets. After the Drilling Partnership well is completed and turned in line, ARP is entitled to receive additional operating and management fees, which are included within well services and administration and oversight revenue, respectively, on a monthly basis while the well is operating. In addition to the management fees it is entitled to receive for services provided, ARP is also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which generally approximate 30%. ARP recognizes its Drilling Partnership management fees in the following manner:

· Well construction and completion. For each well that is drilled by a Drilling Partnership, ARP receives a 15% mark-up on those costs incurred to drill and complete wells included within the partnership. Such fees are earned, in accordance with the partnership agreement, and recognized as the services are performed, typically between 60 and 270 days.

· Administration and oversight. For each well drilled by a Drilling Partnership, ARP receives a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which is earned, in accordance with the partnership agreement, and recognized at the initiation of the well. Additionally, the Drilling Partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. The well administrative fee is earned on a monthly basis as the services are performed.

· Well services. Each Drilling Partnership pays ARP a monthly per well operating fee, currently $1,000 to $2,000, depending on the type of well, for the life of the well. Such fees are earned on a monthly basis as the services are performed.

While the 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.

ARP’s gathering and processing revenue. Gathering and processing revenue includes gathering fees ARP charges to the Drilling Partnership wells for ARP’s processing plants in the New Albany and the Chattanooga shales. Generally, ARP charges a gathering fee to the Drilling Partnership wells equivalent to the fees ARP remits. In Appalachia, a majority of the 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 the Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%.

The Company’s subsidiaries’ gas and oil production operations accrue unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” for further description). The Company had unbilled revenues at September 30, 2015 and December 31, 2014 of $48.5 million and $85.5 million, respectively, which were included in accounts receivable within its combined consolidated balance sheets.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Company’s combined consolidated financial statements, and for all periods presented, only include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges (see Note 8). The Company does not have any other type of transaction which would be included within other comprehensive income (loss).

Recently Issued Accounting Standards

In September 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-16, Business Combinations (Subtopic 805) (“Update 2015-16”) which eliminates the need to retrospectively adjust previously issued financial statements for changes in provisional amounts recognized at the date on which a business was acquired and later revised based on new information about facts and circumstances that existed at the acquisition date.  Subsequent to the effective date of this accounting standard, such adjustments will be applied prospectively and the nature of, and reason for, the change in accounting principle will be disclosed.  The Company will adopt the requirements of Update 2015-16 upon its effective date of January 1, 2016, and the Company does not anticipate it having a material impact on its financial position, results of operations or related disclosures.  

In August 2015, the FASB issued ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements which was a clarification of its previously issued ASU 2015-03, Interest—Imputation of Interest (“Update 2015-15”) requiring entities to present debt issuance costs related to a recognized debt liability as a direct deduction from the carrying amount of that debt liability. Given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to line-of-credit arrangements, ASU 2015-15 effectively allows an entity to defer line-of-credit issuance costs and present such costs as an asset.  These deferred debt issuance costs may be amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Company will adopt the requirements of Update 2015-15 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In April 2015, the FASB issued ASU 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (“Update 2015-06”). Under Topic 260, Earnings per Share, master limited partnerships (“MLPs”) apply the two-class method to calculate earnings per unit (“EPU”) because the general partner, limited partners, and incentive distribution rights holders each participate differently in the distribution of available cash. When a general partner transfers (or “drops down”) net assets to an MLP and that transaction is accounted for as a transaction between entities under common control, the statements of operations of the MLP are adjusted retrospectively to reflect the drop down transaction as if it occurred on the earliest date during which the entities were under common control. The amendments in Update 2015-06 specify that for purposes of calculating historical EPU under the two-class method, the earnings (losses) of a transferred business before the date of a drop down transaction should be allocated entirely to the general partner interest, and previously reported EPU of the limited partners would not change as a result of a drop down transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the drop down transaction occurs also are required. The amendments in Update 2015-06 are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted and amendments in Update 2015-06 should be applied retrospectively for all financial statements presented. The Company will adopt the requirements of Update 2015-06 upon its effective date of January 1, 2016, and the Company does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In March 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30) (“Update 2015-03”). The amendments in Update 2015-03 are intended to simplify presentation of debt issuance costs and require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs would not be affected by the amendments in Update 2015-03. The amendments in Update 2015-03 are effective for periods beginning after December 15, 2015, and interim periods within those periods. Early adoption is permitted, including adoption in an interim period, and an entity should apply the new guidance on a retrospective basis. The Company will adopt the requirements of Update 2015-03 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“Update 2015-02”). The amendments in Update 2015-02 are intended to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures.  The amendments simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The amendments in Update 2015-02 are effective for periods beginning after December 31, 2015. Early adoption is permitted, including adoption in an interim period. The Company will adopt the requirements of Update 2015-02 upon its effective date of January 1, 2016, and is evaluating the impact of adoption on its financial position, results of operations or related disclosures.

In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The Company will adopt the requirements of Update 2015-01 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815) – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity (“Update 2014-16”). Certain classes of shares include features that entitle the holders to preferences and rights (such as conversion rights, redemption rights, voting powers, and liquidation and dividend payment preferences) over the other shareholders. Shares that include embedded derivative features are referred to as hybrid financial instruments, which must be separated from the host contract and accounted for as a derivative if certain criteria are met under Subtopic 815-10.One criterion requires evaluating whether the nature of the host contract is more akin to debt or to equity and whether the economic characteristics and risks of the embedded derivative feature are “clearly and closely related” to the host contract. In making that evaluation, an issuer or investor may consider all terms and features in a hybrid financial instrument including the embedded derivative feature that is being evaluated for separate accounting or may consider all terms and features in the hybrid financial instrument except for the embedded derivative feature that is being evaluated for separate accounting. The use of different methods can result in different accounting outcomes for economically similar hybrid financial instruments.Additionally, there is diversity in practice with respect to the consideration of redemption features in relation to other features when determining whether the nature of a host contract is more akin to debt or to equity. The amendments in Update 2014-16 clarify how current U.S. GAAP should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. The effects of initially adopting the amendments in Update 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in the form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. The amendments in Update 2014-16 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The Company will adopt the requirements of Update 2014-16 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early adoption is permitted. The Company will adopt the requirements of Update 2014-15 upon its effective date in 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In June 2014, the FASB issued ASU 2014-12, Compensation—Stock Compensation (Topic 718) (“Update 2014-12”). The amendments in Update 2014-12 require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in Update 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. The Company will adopt the requirements of Update 2014-12 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles—Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is not permitted. The Company will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2018, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

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Cash Distribution (Distributions Declared) (Tables)

9 Months Ended

Sep. 30, 2015

Schedule of Distributions Made by Partnership

Distributions declared by AGP from January 1, 2014 through September 30, 2015 were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	For the Quarter Ended	Cash Distribution per CommonLimited Partner Unit		Total Cash Distribution to Common Limited Partners		Total Cash Distribution to the GeneralPartner’s Class A Units
February 14, 2014(1)	December 31, 2013	$	0.1167	$	120	$	2
May 15, 2014	March 31, 2014	$	0.1750	$	223	$	6
August 14, 2014	June 30, 2014	$	0.1750	$	342	$	7
November 14, 2014	September 30, 2014	$	0.1750	$	841	$	16
February 13, 2015	December 31, 2014	$	0.1750	$	1,636	$	33
May 15, 2015	March 31, 2015	$	0.1750	$	2,180	$	45
August 14, 2015	June 30, 2015	$	0.1750	$	2,646	$	54

(1) Represents a pro-rated cash distribution of $0.1750 per common limited partner unit and general partner unit for the period from November 1, 2013, the date AGP commenced operations.

Atlas Resource Partners, L.P.

Schedule of Distributions Made by Partnership

Distributions declared by the Company related to its Class A preferred units were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	For MonthEnded	Total Cash DistributionTo CommonUnitholders		Total Cash Distribution To PreferredUnitholders
May 15, 2015	March 31, 2015	$	—	$	333
June 12, 2015	April 30, 2015	$	—	$	334
July 15, 2015	May 31, 2015	$	—	$	334
August 14, 2015	June 30, 2015	$	—	$	335
September 14, 2015	July 31, 2015	$	—	$	336
October 15, 2015	August 31, 2015	$	—	$	336

Distributions declared by ARP from January 1, 2014 through September 30, 2015 were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	For Month Ended	Cash Distribution per CommonLimited Partner Unit		Total Cash Distribution to Common Limited Partners		Total Cash Distribution To Preferred Limited Partners(1)			Total Cash Distribution to the GeneralPartner’s Class A Units
March 17, 2014	January 31, 2014	$	0.1933	$	12,718	$	1,467		$	1,055
April 14, 2014	February 28, 2014	$	0.1933	$	12,719	$	1,466		$	1,055
May 15, 2014	March 31, 2014	$	0.1933	$	12,719	$	1,466		$	1,054
June 13, 2014	April 30, 2014	$	0.1933	$	15,752	$	1,466		$	1,279
July 15, 2014	May 31, 2014	$	0.1933	$	15,752	$	1,466		$	1,279
August 14, 2014	June 30, 2014	$	0.1966	$	16,029	$	1,492		$	1,377
September 12, 2014	July 31, 2014	$	0.1966	$	16,028	$	1,493		$	1,378
October 15, 2014	August 31, 2014	$	0.1966	$	16,032	$	1,491		$	1,378
November 14, 2014	September 30, 2014	$	0.1966	$	16,032	$	1,492		$	1,378
December 15, 2014	October 31, 2014	$	0.1966	$	16,033	$	1,491		$	1,378
January 14, 2015	November 30, 2014	$	0.1966	$	16,779	$	745	(1)	$	1,378
February 13, 2015	December 31, 2014	$	0.1966	$	16,782	$	745	(1)	$	1,378
March 17, 2015	January 31, 2015	$	0.1083	$	9,284	$	643	(1)	$	203
April 14, 2015	February 28, 2015	$	0.1083	$	9,347	$	643	(1)	$	204
May 15, 2015	March 31, 2015	$	0.1083	$	9,444	$	643	(1)	$	206
June 12, 2015	April 30, 2015	$	0.1083	$	10,179	$	642	(1)	$	221
July 15, 2015	May 31, 2015	$	0.1083	$	10,304	$	643	(1)	$	223
August 14, 2015	June 30, 2015	$	0.1083	$	10,309	$	637	(2)	$	223
September 14, 2015	July 31, 2015	$	0.1083	$	10,571	$	638	(2)	$	229
October 15, 2015	August 31, 2015	$	0.1083	$	10,949	$	637	(2)	$	236

(1) Includes payments for the Class B and Class C preferred unit monthly distributions.

(2) Includes payments for the Class C preferred unit monthly distributions. The remaining Class B Preferred Units were converted on July 25, 2015, and the Class B Preferred Unitholders received additional ARP common units upon conversion in lieu of the June distribution. No Class B Preferred Units were outstanding at September 30, 2015.  

Date Cash Distribution Paid	For the Period	Cash Distribution per Class D PreferredLimited Partner Unit		Total Cash DistributionTo Class D Preferred Limited Partners
January 15, 2015	October 2, 2014 – January 14, 2015	$	0.6169270	$	1,974
April 15, 2015	January 15, 2015 – April 14, 2015	$	0.5390630	$	2,156
July 15, 2015	April 15, 2015 – July 14, 2015	$	0.5390625	$	2,157
October 15, 2015	July 15, 2015 – October 14, 2015	$	0.5390625	$	2,205

Date Cash Distribution Paid	For the Period	Cash Distribution per Class E PreferredLimited Partner Unit		Total Cash DistributionTo Class E Preferred Limited Partners
July 15, 2015	April 14, 2015 – July 14, 2015	$	0.6793	$	173
October 15, 2015	July 15, 2015 – October 14, 2015	$	0.6718750	$	172

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Operating Segment Information (Reconciliation of Segment Revenues to Total Revenues) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Segment Reporting Information [Line Items]
Total revenues	$ 262,834	$ 208,589	$ 606,880	$ 512,340
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Total revenues	257,895	206,699	597,609	506,953
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Total revenues	4,591	1,538	8,767	4,563
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Total revenues	$ 348	$ 352	$ 504	$ 824

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Acquisitions (Rangely Acquisition) (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended		3 Months Ended	9 Months Ended
	Jun. 30, 2014	May. 31, 2014	Sep. 30, 2015	Sep. 30, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Partners unit, issued			5,519,110	8,404,934
Rangely Acquisition
Business Acquisition [Line Items]
Partners unit, issued		15,525,000
Atlas Resource Partners, L.P. | 7.75% Senior Notes
Business Acquisition [Line Items]
Debt instrument, interest rate, stated percentage			7.75%	7.75%	7.75%
Atlas Resource Partners, L.P. | Rangely Acquisition
Business Acquisition [Line Items]
Business acquisition, percentage of voting interests acquired	25.00%
Business acquisition, cost of acquired entity, cash paid	$ 408.9
Debt instrument, maturity date	Aug. 15, 2021
Business acquisition, effective date of acquisition	Apr. 01, 2014
Business acquisition, purchase price allocation, methodology	ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9).
Business acquisition, purchase price allocation, status	In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $11.6 million of transaction fees which were included within non-controlling interests at December 31, 2014 on the Company’s combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred.
Business acquisition, cost of acquired entity, transaction costs					$ 11.6
Atlas Resource Partners, L.P. | Rangely Acquisition | 7.75% Senior Notes
Business Acquisition [Line Items]
Proceed from additional senior notes	$ 100.0
Debt instrument, interest rate, stated percentage	7.75%
Partners unit, issued	15,525,000

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Debt (ARP Credit Facility) (Details) - USD ($)	3 Months Ended	9 Months Ended
	Mar. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Atlas Resource Partners, L.P.
Line Of Credit Facility [Line Items]
Revolving credit facility		$ 563,000,000	$ 696,000,000
Revolving Credit Facility
Line Of Credit Facility [Line Items]
Line of Credit Facility, current borrowing capacity		750,000,000
Revolving credit facility		563,000,000
Letters of credit outstanding maximum		20,000,000
Letters of credit outstanding amount		$ 4,300,000
Line of Credit Facility collateral		ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor.
Line of Credit Facility interest rate description		at ARP’s election, at either an adjusted LIBOR rate plus an applicable margin between 1.50% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.50% and 1.75% per annum. If the borrowing base utilization (as defined in the ARP Credit Agreement) is less than 90%, the applicable margin on Eurodollar Loans and ABR Loans (each as defined in the ARP Credit Agreement) will be increased by 0.25%. ARP is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.375% per annum if less than 50% of the borrowing base is utilized and 0.5% if 50% or more of the borrowing base is utilized, which is included within interest expense on the Company’s combined consolidated statements of operations. At September 30, 2015, the weighted average interest rate on outstanding borrowings under the credit facility was 2.75%.
Line of Credit Facility, weighted average interest rate		2.75%
Line Of Credit Facility covenant terms		The ARP Credit Agreement contains customary covenants that limit ARP’s ability to incur additional indebtedness (excluding second lien debt in an aggregate principal amount of up to $300.0 million), grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. ARP was in compliance with these covenants as of September 30, 2015. The ARP Credit Agreement also requires that ARP maintain a ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than (i) 5.25 to 1.0 as of the last day of the quarters ending on March 31, 2015, June 30, 2015, September 30, 2015, December 31, 2015 and March 31, 2016, (ii) 5.00 to 1.0 as of the last day of the quarters ending on June 30, 2016, September 30, 2016 and December 31, 2016, (iii) 4.50 to 1.0 as of the last day of the quarter ending on March 31, 2017 and (iv) 4.00 to 1.0 as of the last day of each quarter thereafter, and a ratio of current assets (as defined in the ARP Credit Agreement) to current liabilities (as defined in the ARP Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.
Line of Credit Facility, Covenant Compliance		ARP was in compliance with these covenants as of September 30, 2015.
Required Total Funded Debt to EBITDA ratio	5.25%
Required current assets to current liabilities ratio		1.00%
Current assets to current liabilities ratio		1.40%
Total Funded Debt to EBITDA ratio		5.20%
Revolving Credit Facility | Atlas Resource Partners, L.P.
Line Of Credit Facility [Line Items]
Percentage of stated amount of senior notes or additional second lien debt that borrowing base reduced		25.00%
Aggregate principal amount of second lien debt		$ 300,000,000
Revolving Credit Facility | Quarter Ended June Thirty Two Thousand And Fifteen
Line Of Credit Facility [Line Items]
Required Total Funded Debt to EBITDA ratio		5.25%
Revolving Credit Facility | Quarter Ended September Thirty Two Thousand And Fifteen
Line Of Credit Facility [Line Items]
Required Total Funded Debt to EBITDA ratio		5.25%
Revolving Credit Facility | Quarter Ended December Thirty First Two Thousand And Fifteen
Line Of Credit Facility [Line Items]
Required Total Funded Debt to EBITDA ratio		5.25%
Revolving Credit Facility | Quarter Ended March Thirty First Two Thousand And Sixteen
Line Of Credit Facility [Line Items]
Required Total Funded Debt to EBITDA ratio		5.25%
Revolving Credit Facility | Quarter Ended June Thirty Two Thousand And Sixteen
Line Of Credit Facility [Line Items]
Required Total Funded Debt to EBITDA ratio		5.00%
Revolving Credit Facility | Quarter Ended September Thirty Two Thousand And Sixteen
Line Of Credit Facility [Line Items]
Required Total Funded Debt to EBITDA ratio		5.00%
Revolving Credit Facility | Quarter Ended December Thirty First Two Thousand And Sixteen
Line Of Credit Facility [Line Items]
Required Total Funded Debt to EBITDA ratio		5.00%
Revolving Credit Facility | Quarter Ended March Thirty First Two Thousand And Seventeen
Line Of Credit Facility [Line Items]
Required Total Funded Debt to EBITDA ratio		4.50%
Revolving Credit Facility | Fiscal quarters ending thereafter
Line Of Credit Facility [Line Items]
Required Total Funded Debt to EBITDA ratio		4.00%
Revolving Credit Facility | Maximum | Borrowing base utilization is less than 90% | Atlas Resource Partners, L.P.
Line Of Credit Facility [Line Items]
Percentage of borrowing base utilized		90.00%

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Benefit Plans (2015 Long Term Incentive Plan Narrative) (Details) - 2015 Long Term Incentive Plan	9 Months Ended
	Sep. 30, 2015 shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Description	The Board of Directors of the Company approved and adopted the Company’s 2015 Long-Term Incentive Plan (“2015 LTIP”) effective February 2015. The 2015 LTIP provides equity incentive awards to officers, employees and managing board members of the Company and its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for the Company. The 2015 LTIP is administered by a committee consisting of the Board or committee of the Board or board of an affiliate appointed by the Board (the “LTIP Committee”).
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	5,250,000
Phantom Units, Restricted Units and Unit Options Outstanding	2,581,510
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	2,668,490

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COMBINED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 54,950	$ 58,358
Accounts receivable	91,706	115,290
Advances to affiliates		4,389
Current portion of derivative asset	147,021	144,259
Subscriptions receivable	23,054	32,398
Prepaid expenses and other	26,022	26,789
Total current assets	342,753	381,483
Property, plant and equipment, net	1,659,358	2,419,289
Goodwill and intangible assets, net	14,154	14,330
Long-term derivative asset	206,142	130,602
Other assets, net	83,454	80,611
Total assets	2,305,861	3,026,315
Current liabilities:
Current portion of long-term debt		1,500
Accounts payable	85,792	123,670
Liabilities associated with drilling contracts		40,611
Current portion of derivative payable to Drilling Partnerships	1,881	932
Accrued interest	11,428	26,479
Accrued well drilling and completion costs	65,629	92,910
Deferred acquisition purchase price	39,167	105,000
Accrued liabilities	46,224	64,854
Total current liabilities	250,121	455,956
Long-term debt, less current portion	1,587,747	1,541,085
Asset retirement obligations and other	$ 122,982	$ 114,059
Commitments and contingencies
Unitholders’/owner’s equity:
Common unitholders’ equity	$ (34,624)
Series A preferred equity	38,393
Owner’s equity		$ 147,308
Accumulated other comprehensive income	10,388	54,008
Unitholders'/owner's equity excluding non-controlling interests	14,157	201,316
Non-controlling interests	330,854	713,899
Total unitholders’/owner’s equity	345,011	915,215
Total liabilities and unitholders’/owner’s equity	$ 2,305,861	$ 3,026,315

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Property, Plant and Equipment (Narrative) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Property Plant And Equipment [Line Items]
Loss on asset sales and disposal	$ (362,000)	$ (92,000)	$ (276,000)	$ (1,683,000)
Asset impairment			679,537,000
Non-cash property, plant and equipment additions			12,000,000	42,600,000
Proved Properties
Property Plant And Equipment [Line Items]
Asset impairment		0		0
Future Hedge Gains	68,000,000
Atlas Resource Partners, L.P. | Unproved Properties
Property Plant And Equipment [Line Items]
Asset impairment	0	$ 0	0	$ 0
Atlas Resource Partners, L.P. | Proved Properties
Property Plant And Equipment [Line Items]
Asset impairment	$ 747,500,000		$ 747,500,000

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COMBINED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss		$ (588,377)	$ (46,195)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		131,043	177,513
Asset impairment		679,537
Loss on early extinguishment of debt		4,726
Unrealized gain on derivatives	[1]	(192,644)
Amortization of deferred financing costs		19,270	7,039
Non-cash compensation expense		7,819	6,343
(Gain) loss on asset sales and disposal		(190)	1,683
Distributions paid to non-controlling interests		(92,266)	(105,278)
Equity income in unconsolidated companies		(502)	(833)
Distributions received from unconsolidated companies		2,104	1,244
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other		152,425	(73,588)
Accounts payable and accrued liabilities		(196,053)	5,489
Net cash used in operating activities		(73,108)	(26,583)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(123,067)	(162,726)
Net cash paid for acquisitions		(49,060)	(507,093)
Other		(1,060)	(2,060)
Net cash used in investing activities		(173,187)	(671,879)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities		758,041	1,034,000
Repayments under credit facilities		(725,657)	(794,125)
Net proceeds from subsidiary long term debt			97,386
Net proceeds from issuance of Series A units		40,000
Net proceeds from issuance of subsidiary units to the public		206,331	470,151
Retirement of subsidiary common limited partner units			(637)
Net distributions to preferred unitholders		(1,672)
Net distributions paid to unitholders		(19,758)	(52,905)
Amortization of discount on subsidiary debt		8,052	188
Deferred financing costs, distribution equivalent rights and other		(22,450)	(9,466)
Net cash provided by financing activities		242,887	744,592
Net change in cash and cash equivalents		(3,408)	46,130
Cash and cash equivalents, beginning of year		58,358	10,625
Cash and cash equivalents, end of period		$ 54,950	$ 56,755

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

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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	Sep. 30, 2015 USD ($) bbl $ / bbl
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	$ 562	[1]
Production Period Ending December 31 2015
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	13,500	[2]
Derivative, Swap Type, Average Fixed Price | $ / bbl	61.000	[2]
Fair Value Asset / (Liability)	$ 205	[1]
Production Period Ending December 31 2016
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	18,000	[2]
Derivative, Swap Type, Average Fixed Price | $ / bbl	63.150	[2]
Fair Value Asset / (Liability)	$ 249	[1]
Production Period Ending December 31 2017
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	9,000	[2]
Derivative, Swap Type, Average Fixed Price | $ / bbl	65.000	[2]
Fair Value Asset / (Liability)	$ 108	[1]

[1] Fair value based on forward WTI crude oil prices, as applicable.

[2] “Bbl” represents barrels.

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Basis of Presentation (Narrative) (Details) - USD ($) $ in Millions		6 Months Ended	9 Months Ended
	Feb. 27, 2015	Jun. 30, 2015	Sep. 30, 2015
Basis Of Presentation [Line Items]
Percentage of interest represented by common units which is effected by pro rata distribution	100.00%
Lightfoot Capital Partners, LP
Basis Of Presentation [Line Items]
General partner ownership interest			15.90%
Common limited partner ownership interest			12.00%
Atlas Resource Partners, L.P.
Basis Of Presentation [Line Items]
General partner ownership interest			100.00%
Common limited partner ownership interest			23.60%
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		$ 233.0	$ 233.0
Common limited partner units purchased		$ 5.0	$ 5.0
Preferred Limited Partner Units
Basis Of Presentation [Line Items]
Common limited partner interest in ARP, units			3,749,986

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Certain Relationships and Related Party Transactions (Narrative) (Details)	9 Months Ended
	Sep. 30, 2015
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.

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Subsequent Events

9 Months Ended

Sep. 30, 2015

Subsequent Events [Abstract]

Subsequent Events

NOTE 16—SUBSEQUENT EVENTS

The Company

On October 28, 2015, the Company declared a monthly cash distribution of $0.3 million for the month ended September 30, 2015 related to its Series A Preferred Units. The distribution will be paid on November 13, 2015 to unitholders of record at the close of business on November 9, 2015.

Atlas Resource

Cash Distributions. On October 28, 2015, ARP declared a monthly distribution of $0.1083 per common unit for the month of September 30, 2015. The $11.9 million distribution, including $0.2 million and $0.6 million to the general partner and preferred limited partners, respectively, will be paid on November 13, 2015 to unitholders of record at the close of business on November 9, 2015.

On October 15, 2015, ARP paid a quarterly distribution of $0.5390625 per Class D ARP Preferred Unit, or $2.2 million, for the period from July 15, 2015 through October 14, 2015 to Class D ARP Preferred Unitholders of record as of October 1, 2015.

On October 15, 2015, ARP paid a quarterly distribution of $0.6791875 per Class E ARP Preferred Unit, or $0.2 million, for the period from July 15, 2015 through October 14, 2015 to Class E ARP Preferred Unitholders of record as of October 1, 2015.

Atlas Growth

On November 5, 2015, AGP declared a quarterly distribution of $0.1750 per common unit for the quarter ended September 30, 2015. The $4.2 million distribution, including $0.1 million to the general partner, will be paid on November 13, 2015 to unitholders of record at the close of business on September 30, 2015.

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Summary of Significant Accounting Policies (Narrative) (Details) - USD ($)					1 Months Ended			2 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended
	Jul. 25, 2015	Jan. 14, 2015	Dec. 23, 2014	Jul. 31, 2013	Apr. 30, 2015	Mar. 31, 2015	Oct. 31, 2014	Jul. 15, 2015	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Summary Of Significant Accounting Policies [Line Items]
Repayments under credit facilities											$ 725,657,000	$ 794,125,000
Pro-rata share in Drilling Partnerships											30.00%
Allowance for Doubtful Accounts Receivable									$ 0		$ 0		$ 0
Materials, supplies and other inventory									8,700,000		8,700,000		8,900,000
Impairments of Unproved Gas and Oil Properties									$ 0	$ 0	$ 0	$ 0
Weighted Average Interest Rate Used To Capitalize Interest									6.50%	5.40%	6.40%	5.70%
Interest Costs Capitalized									$ 4,000,000	$ 3,700,000	$ 12,000,000	$ 9,400,000
Amortization of Intangible Assets									100,000	100,000	200,000	200,000
Future Amortization Expense, remainder of 2015									200,000		200,000
Future Amortization Expense, 2016									100,000		100,000
Future Amortization Expense, 2017									100,000		100,000
Future Amortization Expense, 2018									100,000		100,000
Future Amortization Expense, 2019									100,000		100,000
Goodwill									13,639,000		13,639,000		13,639,000
Changes in carrying amount of goodwill									$ 0	$ 0	$ 0	$ 0
Partners unit, issued									5,519,110		8,404,934
Percentage of Preferred Unit Regular Quarterly Cash Distributions											10.75%
Deferred income tax benefit											$ 0
Monthly administrative fee per well											$ 75
Gathering Fee Percentage											16.00%
Gathering Fee Percentage Net Margin											3.00%
Unbilled Contracts Receivable									$ 48,500,000		$ 48,500,000		85,500,000
Minimum
Summary Of Significant Accounting Policies [Line Items]
Recognition period to receive fees											60 days
Amount of fixed fees received by each well drilled											$ 100,000
Monthly operating fee paid per well											$ 1,000
Return on unhedged revenue percentage											100.00%
Period of return on unhedged revenue											5 years
Maximum
Summary Of Significant Accounting Policies [Line Items]
Recognition period to receive fees											270 days
Amount of fixed fees received by each well drilled											$ 500,000
Monthly operating fee paid per well											$ 2,000
Percentage on unhedged revenue											50.00%
Return on unhedged revenue percentage											120.00%
Period of return on unhedged revenue											8 years
Class E Preferred Units
Summary Of Significant Accounting Policies [Line Items]
Partners unit, issued					255,000
Partners' Capital Account, Units, Percentage					10.75%
Preferred Unit Regular Quarterly Cash Distributions Per Unit								$ 0.6793
Preferred Unit Regular Quarterly Cash Distributions Per Unit there after								$ 2.6875	$ 25.00		$ 25.00
Percentage of Preferred Unit Regular Quarterly Cash Distributions					10.75%
Atlas Resource Partners, L.P. | Preferred class D
Summary Of Significant Accounting Policies [Line Items]
Non-controlling interests									$ 103,500,000		$ 103,500,000		78,000,000
Drilling Partnership wells
Summary Of Significant Accounting Policies [Line Items]
Gathering Fee Percentage											13.00%
ARP Acquisitions
Summary Of Significant Accounting Policies [Line Items]
Goodwill									$ 13,600,000		$ 13,600,000		13,600,000
Goodwill, Impairment Loss													$ 18,100,000
Preferred stock participation rights											While outstanding, the Class C ARP Preferred Units will receive regular quarterly cash distributions equal to the greater of (i) $0.51 and (ii) the quarterly common unit distribution.
ARP Acquisitions | Class B Preferred Units
Summary Of Significant Accounting Policies [Line Items]
Conversion of Class B preferred units (units)	39,654		3,796,900
ARP Acquisitions | Class C Preferred Units | Minimum
Summary Of Significant Accounting Policies [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit				$ 0.51
ARP Acquisitions | Preferred class D
Summary Of Significant Accounting Policies [Line Items]
Partners unit, issued						800,000	3,200,000
Partners' Capital Account, Units, Percentage							8.625%
Preferred Unit Regular Quarterly Cash Distributions Per Unit		$ 0.616927
Preferred Unit Regular Quarterly Cash Distributions Per Unit there after		$ 2.15625
Percentage of Preferred Unit Regular Quarterly Cash Distributions		8.625%
Titan Acquisition | Atlas Resource Partners, L.P.
Summary Of Significant Accounting Policies [Line Items]
Preferred stock participation rights											While outstanding, the Class B ARP Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution
Titan Acquisition | Atlas Resource Partners, L.P. | Class B Preferred Units
Summary Of Significant Accounting Policies [Line Items]
Partners unit, issued											3,800,000
Titan Acquisition | Atlas Resource Partners, L.P. | Class B Preferred Units | Minimum
Summary Of Significant Accounting Policies [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit											$ 0.40
Secured Term Facility
Summary Of Significant Accounting Policies [Line Items]
Repayments under credit facilities											$ 150,000,000
Credit facility				$ 240,000,000
Series A Preferred Units | Secured Term Facility
Summary Of Significant Accounting Policies [Line Items]
Proceeds from Issuance of Convertible Preferred Stock											$ 150,000,000

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Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2015

Accounting Policies [Abstract]

Schedule of the Components of Intangible Assets Being Amortized

The following table reflects the components of intangible assets being amortized at September 30, 2015 and December 31, 2014 (in thousands):

	September 30,			December 31,			Estimated Useful Lives
	2015			2014			In Years
Gross Carrying Amount	$	14,344		$	14,344			13
Accumulated Amortization		(13,829	)		(13,653	)
Net Carrying Amount	$	515		$	691

Reconciliation of Net Income (Loss)

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Net loss	$	(582,313	)	$	(4,349	)	$	(588,377	)	$	(46,195	)
Preferred unitholder dividends		(1,009	)		—			(2,346	)		—
Loss attributable to non-controlling interests		439,969			5,137			420,411			33,828
(Income) loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015)		—			(788	)		10,475			12,367
Net loss utilized in the calculation of net loss attributable to common unitholders per unit – basic and diluted(1)	$	(143,353	)	$	—		$	(159,837	)	$	—

(1) Net loss attributable to common unitholders per unit is calculated by dividing net income (loss) attributable to common unitholders, less income allocable to participating securities, by the sum of the weighted average number of common unitholder 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. For the three months ended September 30, 2015, net loss attributable common unitholders per unit is not allocated to approximately 69,000 phantom units, 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 nine months ended September 30, 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 68,000 phantom units, 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 three and nine months ended September 30, 2015, distributions on the Company’s Series A preferred units were excluded, because the inclusion of such preferred distributions would have been anti-dilutive.

Reconciliation of the Company's Weighted Average Number of Common Unit holder Units

The following table sets forth the reconciliation of the Company’s 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 September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Weighted average number of common unitholders per unit—basic		26,011		—		26,011		—
Add effect of dilutive incentive awards(1)		—		—		—		—
Add effect of dilutive convertible preferred units(1)		—		—		—		—
Weighted average number of common unitholders per unit—diluted		26,011		—		26,011		—

(1) For the three months ended September 30, 2015, 2,737,000 phantom units 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 nine months ended September 30, 2015, 1,492,000 phantom units 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 three and nine months ended September 30, 2015, potential common units issuable upon conversion of the Company’s 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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Issuances of Units (Atlas Resource Partners) (Details) - USD ($)	1 Months Ended							3 Months Ended	6 Months Ended	9 Months Ended	12 Months Ended
	Aug. 31, 2015	May. 31, 2015	Apr. 30, 2015	Oct. 31, 2014	Aug. 31, 2014	May. 31, 2014	Mar. 31, 2014	Sep. 30, 2015	Jun. 30, 2015	Sep. 30, 2015	Dec. 31, 2014	Jul. 15, 2015	Mar. 31, 2015
Capital Unit [Line Items]
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%
Partners unit, issued								5,519,110		8,404,934
Proceeds from Issuance of Common Limited Partners Units								$ 18,600,000		$ 40,000,000
Payments for Commissions								$ 400,000		$ 1,000,000
Percentage of Preferred Unit Regular Quarterly Cash Distributions										10.75%
Atlas Growth Partners, L.P
Capital Unit [Line Items]
Common limited partner units issued									$ 233,000,000	$ 233,000,000
Common limited partner units purchased									$ 5,000,000	5,000,000
Atlas Resource Partners, L.P.
Capital Unit [Line Items]
Gain on sale of subsidiary unit issuances										$ 3,400,000	$ 45,000,000
Preferred class D and E
Capital Unit [Line Items]
Redemption price per unit								$ 25.00		$ 25.00
Preferred class D
Capital Unit [Line Items]
Tentative date for preferred stock redemption										Oct. 15, 2019
Preferred class D | Atlas Resource Partners, L.P.
Capital Unit [Line Items]
Partners' Capital Account, Units, Percentage										8.625%
Preferred class E
Capital Unit [Line Items]
Tentative date for preferred stock redemption										Apr. 15, 2020
Preferred class E | Atlas Resource Partners, L.P.
Capital Unit [Line Items]
Partners' Capital Account, Units, Percentage										10.75%
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
Arkoma Acquisition | Atlas Resource Partners, L.P.
Capital Unit [Line Items]
Partners unit, issued										6,500,000
Rangely Acquisition
Capital Unit [Line Items]
Partners unit, issued						15,525,000
Partners Capital Account Units Date Of Sale										May 2014
Subsidiary or Equity Method Investee, Price-Per-Share						$ 19.90
Partners Capital Account Sale Of Units						$ 297,300,000
ARP’s Geomet Acquisition
Capital Unit [Line Items]
Partners unit, issued							6,325,000
Partners Capital Account Units Date Of Sale										March 2014
Subsidiary or Equity Method Investee, Price-Per-Share							$ 21.18
Partners Capital Account Sale Of Units							$ 129,000,000
Equity Distribution Agreement with MLV & Co. LLC
Capital Unit [Line Items]
Proceeds from Issuance of Common Limited Partners Units										$ 1,000,000
Payments for Commissions										$ 200,000
Over Allotment Units Issued | Rangely Acquisition
Capital Unit [Line Items]
Partners unit, issued						2,025,000
Over Allotment Units Issued | ARP’s Geomet Acquisition
Capital Unit [Line Items]
Partners unit, issued							825,000
Class D and Class E Preferred Units | Equity Distribution Agreement with MLV & Co. LLC
Capital Unit [Line Items]
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.	3.00%
Class D Preferred Units
Capital Unit [Line Items]
Partners' Capital Account, Units, Percentage	8.625%
Class D Preferred Units | Eagle Ford Acquisition
Capital Unit [Line Items]
Partners' Capital Account, Units, Percentage				8.625%
Partners unit, issued				3,200,000
Partners Capital Account Units Date Of Sale										October 2014
Subsidiary or Equity Method Investee, Price-Per-Share				$ 25.00									$ 25.00
Percentage of Preferred Unit Regular Quarterly Cash Distributions				8.625%
Preferred Unit Regular Quarterly Cash Distributions Per Unit there after				$ 2.15625
Class D Preferred Units | Equity Distribution Agreement with MLV & Co. LLC
Capital Unit [Line Items]
Partners unit, issued								90,328		90,328
Class E Preferred Units
Capital Unit [Line Items]
Partners' Capital Account, Units, Percentage			10.75%
Partners unit, issued			255,000
Partners Capital Account Units Date Of Sale										April 2015
Partners Capital Account Sale Of Units			$ 6,000,000
Redemption price per unit			$ 25.00
Percentage of Preferred Unit Regular Quarterly Cash Distributions			10.75%
Preferred Unit Regular Quarterly Cash Distributions Per Unit there after								$ 25.00		$ 25.00		$ 2.6875
Class E Preferred Units | Equity Distribution Agreement with MLV & Co. LLC
Capital Unit [Line Items]
Partners unit, issued								1,083		1,083

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Basis of Presentation

9 Months Ended

Sep. 30, 2015

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Basis of Presentation

NOTE 1—BASIS OF PRESENTATION

Atlas Energy Group, LLC is a Delaware limited liability company formed in October 2011 (the “Company”). At September 30, 2015, the Company’s operations primarily consisted of its ownership interests in the following:

· 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 23.6% 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 (NYSE: ARP) 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;

· 80.0% general partner interest and a 2.1% limited partner interest in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership that currently conducts natural gas and oil operations in the mid-continent region of the United States. 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, the Company purchased $5.0 million common limited partner units; and

· 15.9% general partner interest and 12.0% limited partner interest in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, its general partner, which incubate new MLPs and invest in existing MLPs.  

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

The accompanying combined consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2014 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and 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. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014. The results of operations for the three and nine months ended September 30, 2015 may not necessarily be indicative of the results of operations for the full year ending December 31, 2015.

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COMBINED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenues:
Gas and oil production	$ 94,612,000	$ 130,937,000	$ 300,249,000	$ 342,456,000
Well construction and completion	23,054,000	61,204,000	63,665,000	126,917,000
Gathering and processing	1,685,000	3,061,000	6,046,000	11,287,000
Administration and oversight	5,495,000	6,177,000	7,301,000	12,072,000
Well services	5,842,000	6,597,000	18,568,000	18,441,000
Gain on mark-to-market derivatives	131,777,000		210,466,000
Other, net	369,000	613,000	585,000	1,167,000
Total revenues	262,834,000	208,589,000	606,880,000	512,340,000
Costs and expenses:
Gas and oil production	42,300,000	52,004,000	131,908,000	134,590,000
Well construction and completion	20,046,000	53,221,000	55,361,000	110,363,000
Gathering and processing	2,473,000	3,214,000	7,406,000	11,900,000
Well services	2,398,000	2,617,000	6,735,000	7,525,000
General and administrative	21,704,000	17,299,000	82,037,000	63,487,000
Depreciation, depletion and amortization	43,311,000	65,068,000	131,043,000	177,513,000
Asset impairment	679,537,000	0	679,537,000	0
Total costs and expenses	811,769,000	193,423,000	1,094,027,000	505,378,000
Operating income (loss)	(548,935,000)	15,166,000	(487,147,000)	6,962,000
Loss on asset sales and disposal	(362,000)	(92,000)	(276,000)	(1,683,000)
Interest expense	(28,290,000)	(19,423,000)	(96,228,000)	(51,474,000)
Loss on extinguishment of debt	(4,726,000)		(4,726,000)
Net loss	(582,313,000)	(4,349,000)	(588,377,000)	(46,195,000)
Preferred unitholders’ dividends	(1,009,000)		(2,346,000)
Loss attributable to non-controlling interests	439,969,000	5,137,000	420,411,000	33,828,000
Net income (loss) attributable to unitholders’/owner’s interests	(143,353,000)	788,000	(170,312,000)	(12,367,000)
Allocation of net income (loss) attributable to unitholders’/owner’s interests:
Portion applicable to owner’s interest (period prior to the transfer of assets on February 27, 2015)		788,000	(10,475,000)	(12,367,000)
Portion applicable to unitholders’ interests (period subsequent to the transfer of assets on February 27, 2015)	(143,353,000)		(159,837,000)
Net income (loss) attributable to unitholders’/owner’s interests	$ (143,353,000)	$ 788,000	$ (170,312,000)	$ (12,367,000)
Net loss attributable to unitholders per common unit:
Basic	$ (5.51)		$ (6.15)
Diluted	$ (5.51)		$ (6.15)
Weighted average common units outstanding:
Basic	26,011		26,011
Diluted	26,011		26,011

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2015

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

NOTE 11—COMMITMENTS AND CONTINGENCIES

General Commitments

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 September 30, 2015, 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 the three months ended September 30, 2015 and 2014, $0.4 million and $0.9 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. For the nine months ended September 30, 2015 and 2014, $1.5 million and $4.7 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.

In connection with the Eagle Ford Acquisition (see Note 3), ARP guaranteed the timely payment of the deferred portion of the purchase price that is to be paid by AGP. Pursuant to the agreement between ARP and AGP, ARP will have the right to receive some or all of the assets acquired by AGP in the event of its failure to contribute its portion of any deferred payments. In September 2015, ARP agreed with AGP to have AGP transfer its remaining $36.3 million of deferred purchase obligation, along with the related undeveloped natural gas and oil properties, to ARP. ARP’s deferred purchase obligation is included within deferred acquisition purchase price on the Company’s combined consolidated balance sheets at September 30, 2015 and December 31, 2014 (see Note 3). AGP’s deferred purchase obligation was included within deferred acquisition purchase price on the Company’s combined consolidated balance sheet at December 31, 2014 (see Note 3).

In connection with ARP’s GeoMet Acquisition (see Note 3), ARP acquired certain long-term annual firm transportation obligations. Estimated fixed and determinable portions of ARP’s firm transportation obligations as of September 30, 2015 were as follows: 2015— $0.9 million; 2016— $3.6 million; 2017— $2.5 million; 2018— $1.8 million; 2019— $1.8 million; thereafter— $6.5 million.

In connection with ARP’s acquisition of assets from EP Energy E&P Company, L.P. on July 31, 2013 (the “EP Energy Acquisition”), ARP acquired certain long-term annual firm transportation obligations. Estimated fixed and determinable portions of ARP’s firm transportation obligations as of September 30, 2015 were as follows: 2015— $2.2 million; 2016— $2.2 million; and 2017 to 2019— none.

As of September 30, 2015, the Company’s subsidiaries are committed to expend approximately $45.0 million on drilling and completion expenditures.

Legal Proceedings

The Company and its subsidiaries are parties to various routine legal proceedings arising out of the ordinary course of its business. Management of the Company and its subsidiaries believe that none of these actions, individually or in the aggregate, will have a material adverse effect on the Company’s financial condition or results of operations.

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Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Nov. 04, 2015
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q3
Entity Registrant Name	Atlas Energy Group, LLC
Entity Central Index Key	0001623595
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Trading Symbol	ATLS
Entity Common Stock, Units Outstanding		26,010,766

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Issuances of Units

9 Months Ended

Sep. 30, 2015

Proceeds From Issuance Or Sale Of Equity [Abstract]

Issuances of Units

NOTE 12—ISSUANCES OF UNITS

The Company recognizes gains or losses on ARP’s and AGP’s equity transactions as credits or debits, respectively, to unitholders’ equity on its combined consolidated balance sheets rather than as income or loss on its combined consolidated statements of operations. These gains or losses represent the Company’s 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 (see Note 2).

On February 27, 2015 the Company issued and sold an aggregate of 1.6 million of its 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 the Company’s 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 the Company to holders of the Company’s 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 the Company’s 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 of the Company; and (ii) the lower of (a) 110.0% of the volume weighted average price for the Company’s common units on the NYSE over the 30 trading days following the distribution date; and (b) $16.00 per common unit of the Company. The Company sold the Series A Preferred Units in a private transaction exempt from registration under Section 4(2) of the Securities Act. The Series A Preferred Units resulted in proceeds to the Company of $40.0 million. The Company used the proceeds to fund a portion of the $150.0 million payment by the Company 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 the unitholders of the Company, 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.

Atlas Resource Partners

In August 2015, ARP entered into a distribution agreement with MLV & Co. LLC (“MLV”). Pursuant to the distribution agreement, ARP may sell from time to time through MLV ARP’s 8.625% Class D ARP Cumulative Redeemable Perpetual Preferred Units (“Class D ARP Preferred Units”) and Class E ARP Cumulative Redeemable Perpetual Preferred Units (“Class E ARP Preferred Units”) having a maximum aggregate offering price of up to $100 million. Sales of Class D and Class E ARP Preferred 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 of 1933, as amended, including sales made directly on the NYSE, the existing trading market for the Units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP will pay MLV a commission, which shall not be more than 3.0% of the gross sales price of Class D and Class E ARP Preferred Units. ARP has agreed to reimburse MLV for certain expenses incurred in connection with entering into the distribution agreement. Under the terms of the distribution agreement, ARP may also sell Class D and Class E ARP Preferred Units from time to time to MLV as principal for its own account at a price to be agreed upon at the time of sale. Any sale of Class D and Class E ARP Preferred Units to MLV as principal would be pursuant to the terms of a separate terms agreement between ARP and MLV. During the three and nine months ended September 30, 2015, ARP issued 90,328 Class D ARP Preferred Units and 1,083 Class E ARP Preferred Units under the preferred equity distribution program for net proceeds of $1.0 million, net of $0.2 million in commissions and offering expenses paid.

In May 2015, in connection with the Arkoma Acquisition (see Note 3), 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 approximately $49.7 million. ARP used a portion of the net proceeds to fund the Arkoma Acquisition and to reduce borrowings outstanding under ARP’s revolving 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 approximately $6.0 million.  ARP pays distributions on the Class E ARP Preferred Units at a rate of 10.75% per annum of the stated liquidation preference of $25.00.

In October 2014, in connection with the Eagle Ford Acquisition (see Note 3), ARP issued 3,200,000 8.625% Class D Preferred Units at a public offering price of $25.00 per unit, yielding net proceeds of approximately $77.3 million from the offering, after deducting underwriting discounts and estimated offering expenses. ARP used the net proceeds from the offering to fund a portion of the Eagle Ford Acquisition. 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. ARP pays cumulative distributions on a quarterly basis, at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference.

The Class D and Class E ARP Preferred Units rank senior to ARP’s common units and Class C ARP Preferred Units with respect to the payment of distributions and distributions upon a liquidation event. The Class D and Class E ARP Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by ARP or converted into its common units in connection with a change in control. At any time on or after October 15, 2019 for the Class D ARP Preferred Units and April 15, 2020 for the ARP Class E Preferred Units, ARP may, at its option, redeem the such preferred units in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, ARP may redeem such preferred units following certain changes of control, as described in the respective Certificates of Designation. If ARP does not exercise this redemption option upon a change of control, then holders of such preferred units will have the option to convert the preferred units into a number of ARP common units as set forth in the respective Certificates of Designation. If ARP exercises any of its redemption rights relating to such preferred units, the holders will not have the conversion right described above with respect to the preferred units called for redemption.

In August 2014, ARP entered into 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 terms agreement between ARP and such Agent. During the three months ended September 30, 2015, ARP issued 5,519,110 common limited partner units under the equity distribution program for net proceeds of $18.6 million, net of $0.4 million in commissions and offering expenses paid. During the nine months ended September 30, 2015, ARP issued 8,404,934 common limited partner units under the equity distribution program for net proceeds of $40.0 million, net of $1.0 million in commissions and offering expenses paid.

In May 2014, in connection with the Rangely Acquisition (see Note 3), ARP issued 15,525,000 of its common limited partner units (including 2,025,000 units pursuant to an over-allotment option) in a public offering at a price of $19.90 per unit, yielding net proceeds of approximately $297.3 million.

In March 2014, in connection with the GeoMet Acquisition (see Note 3), ARP issued 6,325,000 of its common limited partner units (including 825,000 units pursuant to an over-allotment option) in a public offering at a price of $21.18 per unit, yielding net proceeds of approximately $129.0 million.

Atlas Growth Partners

AGP has issued approximately $233.0 million of its common limited partner units through a private placement offering that expired on June 30, 2015. Of the $233.0 million of gross funds raised, we purchased $5.0 million common limited partner units during the offering.

In connection with the issuance of ARP’s and AGP’s unit offerings during the nine months ended September 30, 2015, the Company recorded gains of $3.4 million within unitholders’ equity and a corresponding decrease in non-controlling interests on its combined consolidated balance sheet and combined consolidated statement of unitholders’/owner’s equity. For the year ended December 31, 2014, the Company recorded gains of $45.0 million within equity and a corresponding decrease in non-controlling interests on its combined consolidated balance sheets and combined consolidated statement of equity.

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Operating Segment Information (Narrative) (Details)	9 Months Ended
	Sep. 30, 2015 Segment
Segment Reporting [Abstract]
Number of reportable operating segments	3

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COMBINED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Statement Of Income And Comprehensive Income [Abstract]
Net loss	$ (582,313)	$ (4,349)	$ (588,377)	$ (46,195)
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges		70,362		5,268
Reclassification adjustment for gains due to impairment	(68,021)		(68,021)
Less: reclassification adjustment for realized (gains) losses of cash flow hedges in net loss	(23,927)	(1,388)	(77,048)	22,703
Total other comprehensive income (loss)	(91,948)	68,974	(145,069)	27,971
Comprehensive income (loss)	(674,261)	64,625	(733,446)	(18,224)
Comprehensive (income) loss attributable to non-controlling interests	509,678	(44,776)	521,860	11,263
Comprehensive income (loss) attributable to unitholders’/owner’s interest	$ (164,583)	$ 19,849	$ (211,586)	$ (6,961)

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2015

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

NOTE 6—ASSET RETIREMENT OBLIGATIONS

The Company’s subsidiaries recognize an estimated liability for the plugging and abandonment of their respective gas and oil wells and related facilities. The Company’s subsidiaries also recognize a liability for their respective future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Company’s subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability for asset retirement obligations was based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The Company’s subsidiaries have no assets legally restricted for purposes of settling asset retirement obligations. Except for the Company’s subsidiaries’ gas and oil properties, there were no other material retirement obligations associated with tangible long-lived assets.

ARP proportionately consolidates its ownership interest of the asset retirement obligations of its Drilling Partnerships. At September 30, 2015, the Drilling Partnerships had $45.6 million of aggregate asset retirement obligation liabilities recognized on their combined balance sheets allocable to the limited partners, exclusive of ARP’s proportional interest in such liabilities. Under the terms of the respective partnership agreements, ARP maintains the right to retain a portion or all of the distributions to the limited partners of its Drilling Partnerships to cover the limited partners’ share of the plugging and abandonment costs up to a specified amount per month. As of September 30, 2015, ARP has withheld approximately $4.3 million of limited partner distributions related to the asset retirement obligations of certain Drilling Partnerships. ARP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within each Drilling Partnership near the end of their useful life. On a partnership-by-partnership basis, ARP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors, including commodity price trends, the natural decline in the production of the wells, and current and future costs. Generally, ARP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon ARP’s decision to retain all future distributions to the limited partners of its Drilling Partnerships, ARP will assume the related asset retirement obligations of the limited partners.

A reconciliation of the Company’s subsidiaries’ liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Asset retirement obligations, beginning of period	$	110,937		$	101,455		$	108,101		$	91,214
Liabilities incurred		80			336			296			8,283
Liabilities settled		(1	)		(271	)		(547	)		(820	)
Accretion expense		1,584			1,471			4,750			4,314
Asset retirement obligations, end of period	$	112,600		$	102,991		$	112,600		$	102,991

The above accretion expense was included in depreciation, depletion and amortization in the Company’s combined consolidated statements of operations and the asset retirement obligation liabilities were included within asset retirement obligations and other in the Company’s combined consolidated balance sheets. During the year ended December 31, 2014, AGP incurred $0.1 million of future plugging and abandonment liabilities within purchase accounting related to the acquisition it consummated during the period. During the year ended December 31, 2014, ARP incurred $7.0 million of future plugging and abandonment liabilities within purchase accounting related to the acquisitions it consummated during the period (see Note 3). During the nine months ended September 30, 2014, ARP incurred $6.6 million of future plugging and abandonment liabilities within purchase accounting for the Rangely and GeoMet acquisitions it consummated during the period (see Note 3). No future plugging and abandonment liabilities related to consummated acquisitions were incurred during the three and nine months ended September 30, 2015.

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Other Assets

9 Months Ended

Sep. 30, 2015

Other Assets Noncurrent Disclosure [Abstract]

Other Assets

NOTE 5—OTHER ASSETS

The following is a summary of other assets at the dates indicated (in thousands):

		September 30,	December 31,
	2015		2014
Deferred financing costs, net of accumulated amortization of $39,945 and $20,675 at September 30, 2015 and December 31, 2014, respectively	$	49,299	$	46,120
Investment in Lightfoot		19,521		21,123
Rabbi Trust		5,378		3,925
Security deposits		231		229
ARP notes receivable		3,871		3,866
Other		5,154		5,348
	$	83,454	$	80,611

Deferred financing costs. Deferred financing costs are recorded at cost and amortized over the terms of the respective debt agreements (see Note 7). Amortization expense of the Company’s and its subsidiaries’ deferred financing costs was $3.6 million and $2.7 million for the three months ended September 30, 2015 and 2014, respectively, and $9.8 million and $7.0 million for the nine months ended September 30, 2015 and 2014, respectively, which was recorded within interest expense on the Company’s combined consolidated statements of operations. During the nine months ended September 30, 2015, the Company recognized $5.2 million for accelerated amortization of deferred financing costs associated with Atlas Energy, L.P.’s credit facility and term loan. There was no accelerated amortization of deferred financing costs for the Company during the three months ended September 30, 2015 and the nine months ended September 30, 2014.

During the nine months ended September 30, 2015, ARP recognized $4.3 million for accelerated amortization of deferred financing costs associated with a reduction of the borrowing base under its revolving credit facility. There was no accelerated amortization of deferred financing costs for ARP during the three months ended September 30, 2015 and 2014 and during the nine months ended September 30, 2014.

ARP notes receivable. At September 30, 2015 and December 31, 2014, ARP had notes receivable with certain investors of its Drilling Partnerships, which were included within other assets, net on the Company’s combined consolidated balance sheets. The notes have a maturity date of March 31, 2022, and a 2.25% per annum interest rate. The maturity date of the notes can be extended to March 31, 2027, subject to certain closing conditions, including an extension fee of 1.0% of the outstanding principal balance. The Company recognized interest income within other, net on the Company’s combined consolidated statements of operations of approximately $21,000 and $22,000, respectively, for the three months ended September 30, 2015 and 2014, and approximately $64,000 and $68,000 for the nine months ended September 30, 2015 and 2014, respectively. At September 30, 2015 and December 31, 2014, ARP recorded no allowance for credit losses within the Company’s combined consolidated balance sheets based upon payment history and ongoing credit evaluations associated with the ARP notes receivable.

Investment in Lightfoot. At September 30, 2015, the Company had an approximate 12.0% interest in Lightfoot L.P. and an approximate 15.9% interest in Lightfoot G.P., 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. The Company accounts for its investment in Lightfoot under the equity method of accounting. During the three months ended September 30, 2015 and 2014, the Company recognized equity income of approximately $0.3 million and $0.4 million, respectively, within other, net on the Company’s combined consolidated statements of operations. During the nine months ended September 30, 2015 and 2014, the Company recognized equity income of approximately $0.5 million and $0.8 million, respectively, within other, net on the Company’s combined consolidated statements of operations. During the three months ended September 30, 2015 and 2014, the Company received net cash distributions of approximately $1.4 million and $0.5 million, respectively. During the nine months ended September 30, 2015 and 2014, the Company received net cash distributions of approximately $2.2 million and $1.2 million, respectively.

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2015

Accounting Policies [Abstract]

Principles of Consolidation and Combination

Principles of Consolidation and Combination

The consolidated balance sheet at September 30, 2015 and the related combined consolidated statements of operations for the three and nine months ended September 30, 2015, subsequent to the transfer of assets on February 27, 2015, include the accounts of the Company and its subsidiaries. The Company’s combined consolidated balance sheet at December 31, 2014, the combined consolidated statement of operations for the portion of 2015 which is prior to the transfer of assets on February 27, 2015, and the combined consolidated statement of operations for the three and nine months ended September 30, 2014 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 the Company had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various entities comprising the Company, Atlas Energy’s net investment in the Company is shown as equity in the 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 combined consolidated balance sheets and related 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 the Company. Actual balances and results could be different from those estimates. Transactions between the Company and other Atlas Energy operations have been identified in the combined consolidated financial statements as transactions between affiliates.

In connection with Atlas Energy’s merger with Targa and the concurrent Separation, the Company was 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 generally accepted accounting principles, the Company included $150.0 million of Atlas Energy’s original term loan at the time of issuance, and the related interest expense, within its historical financial statements. Atlas Energy’s other historical borrowings were allocated to the Company’s historical financial statements in the same ratio. The Company used proceeds from the issuance of its Series A preferred units (see Note 12) and borrowings under its term loan credit facilities (see Note 7) to fund the $150.0 million payment.

The Company combines the financial statements of ARP and AGP into its combined consolidated financial statements rather than presenting its ownership interest as equity investments, as the Company controls these entities through its general partnership interests therein. As such, the non-controlling interests in ARP and AGP are reflected as (income) loss attributable to non-controlling interests in the combined consolidated statements of operations and as a component of unitholders’ equity on the combined consolidated balance sheets. All material intercompany transactions have been eliminated.

In accordance with established practice in the oil and gas industry, the Company’s combined consolidated financial statements include its 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%. The Company’s 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 (see “Property, Plant and Equipment”).

Use of Estimates

Use of Estimates

The preparation of the Company’s 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 the Company’s combined consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Company’s combined consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired and liabilities assumed. Such estimates included estimated allocations made from the historical accounting records of Atlas Energy in order to derive the historical financial statements of the Company. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three and nine months ended September 30, 2015 and 2014 represent actual results in all material respects (see “Revenue Recognition”).

Receivables

Receivables

Accounts receivable on the combined consolidated balance sheets consist primarily of the trade accounts receivable associated with the Company and its subsidiaries. In evaluating the realizability of accounts receivable, management performs ongoing credit evaluations of customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness, as determined by management’s review of customers’ credit information. The Company and its subsidiaries extend credit on sales on an unsecured basis to many of their customers. At September 30, 2015 and December 31, 2014, the Company had recorded no allowance for uncollectible accounts receivable on its combined consolidated balance sheets.

Inventory

Inventory

The Company had $8.7 million and $8.9 million of inventory at September 30, 2015 and December 31, 2014, respectively, which were included within prepaid expenses and other current assets on its combined consolidated balance sheets. The Company values inventories at the lower of cost or market. The Company’s inventories, which consist primarily of ARP’s materials, pipes, supplies and other inventories, were principally determined using the average cost method.

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Company’s results of operations.

The Company’s subsidiaries follow the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. “Mcf” is defined as one thousand cubic feet.

The Company’s subsidiaries’ depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include ARP’s costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by ARP for its interests, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s combined consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s combined consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s combined consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Impairment of Long-Lived Assets

Impairment of Long-Lived Assets

The Company and its subsidiaries review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s subsidiaries’ plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. The Company’s subsidiaries estimate prices based upon current contracts in place, adjusted for basis differentials and market-related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, ARP’s reserve estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include ARP’s actual capital contributions and a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

ARP’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to ARP operating and administrative fees in addition to their proportionate share of external operating expenses. These assumptions could result in ARP’s calculation of depletion and impairment being different than its proportionate share of the Drilling Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Company and ARP cannot predict what reserve revisions may be required in future periods.

ARP’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships, which ARP sponsors and owns an interest in but does not control. ARP’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which ARP may be unable to recover due to the Drilling Partnerships’ legal structure. ARP may have to pay additional consideration in the future as a Drilling Partnership’s wells become uneconomic to the Drilling Partnership under the terms of the Drilling Partnership’s drilling and operating agreement in order to recover these excess reserves, in addition to ARP becoming responsible for paying associated future operating, development and plugging costs of the well interests acquired, and to acquire any additional residual interests in the wells held by the Drilling Partnership’s limited partners. The acquisition of any such uneconomic well interest from the Drilling Partnership by ARP is governed under the Drilling Partnership’s limited partnership agreement. In general, ARP will seek consent from the Drilling Partnership’s limited partners to acquire the well interests from the Drilling Partnership based upon ARP’s determination of fair market value.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate that the Company’s subsidiaries will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. There were no impairments of unproved gas and oil properties recorded on the Company’s combined consolidated statements of operations for the three and nine months ended September 30, 2015 and 2014.

Capitalized Interest

Capitalized Interest

ARP capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP were 6.5% and 5.4% for the three months ended September 30, 2015 and 2014, respectively, and 6.4% and 5.7% for the nine months ended September 30, 2015 and 2014, respectively. The amounts of interest capitalized by ARP were $4.0 million and $3.7 million for the three months ended September 30, 2015 and 2014, respectively, and $12.0 million and $9.4 million for the nine months ended September 30, 2015 and 2014, respectively.

Intangible Assets

Intangible Assets

ARP has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. ARP amortizes contracts acquired on a declining balance method over their respective estimated useful lives.

The following table reflects the components of intangible assets being amortized at September 30, 2015 and December 31, 2014 (in thousands):

	September 30,			December 31,			Estimated Useful Lives
	2015			2014			In Years
Gross Carrying Amount	$	14,344		$	14,344			13
Accumulated Amortization		(13,829	)		(13,653	)
Net Carrying Amount	$	515		$	691

Amortization expense on intangible assets was $0.1 million for both the three months ended September 30, 2015 and 2014. Amortization expense on intangible assets was $0.2 million for both the nine months ended September 30, 2015 and 2014. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2015 - $0.2million; 2016 - $0.1million; 2017 - $0.1 million; 2018 - $0.1 million; and 2019 - $0.1 million.

Goodwill

Goodwill

At September 30, 2015 and December 31, 2014, the Company had $13.6 million of goodwill recorded in connection with ARP’s prior consummated acquisitions. No changes in the carrying amount of goodwill were recorded for the three and nine months ended September 30, 2015 and 2014.

ARP tests goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units. ARP’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including ARP’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, ARP also considers the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ARP’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in ARP’s industry to determine whether those valuations appear reasonable in management’s judgment. ARP’s management will continue to evaluate goodwill at least annually or when impairment indicators arise.

As a result of its goodwill impairment evaluation at December 31, 2014, ARP recognized an $18.1 million non-cash impairment charge within asset impairments on the Company’s combined consolidated statement of operations for the year ended December 31, 2014. The goodwill impairment resulted from the reduction in ARP’s estimated fair value of its gas and oil production reporting unit in comparison to its carrying amount at December 31, 2014. ARP’s estimated fair value of its gas and oil production reporting unit was impacted by a decline in overall commodity prices during the fourth quarter of 2014.

Derivative Instruments

Derivative Instruments

ARP and AGP enter into certain financial contracts to manage their exposure to movement in commodity prices and interest rates (see Note 8). The derivative instruments recorded in the combined consolidated balance sheets are measured as either an asset or liability at fair value. Changes in the fair value of derivative instruments are recognized currently in the Company’s combined consolidated statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Company and ARP discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s combined consolidated statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 will be reclassified to the combined consolidated statements of operations in the periods in which those respective derivative contracts settle. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within unitholders’ equity on the Company’s consolidated balance sheets and reclassified to the Company’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings.

Asset Retirement Obligations

Asset Retirement Obligations

The Company’s subsidiaries recognize an estimated liability for the plugging and abandonment of gas and oil wells and related facilities (see Note 6). The Company’s subsidiaries also recognize a liability for future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Company‘s subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

ARP Preferred Units

ARP Preferred Units

In connection with ARP’s acquisition of certain proved reserves and associated assets from Titan Operating, L.L.C. in July 2012, ARP issued 3.8 million newly created convertible Class B ARP preferred units (“Class B ARP Preferred Units”). While outstanding, the Class B ARP Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. On December 23, 2014, 3,796,900 of Class B ARP Preferred Units were converted into common units, while the remaining 39,654 Class B ARP Preferred Units were converted into common units on July 25, 2015. In connection with ARP’s acquisition of certain proved reserves and associated assets from EP Energy, Inc. in July 2013, ARP issued 3.7 million newly created convertible Class C ARP preferred units to Atlas Energy (“Class C ARP Preferred Units”). While outstanding, the Class C ARP Preferred Units will receive regular quarterly cash distributions equal to the greater of (i) $0.51 and (ii) the quarterly common unit distribution. In October 2014, in connection with ARP’s acquisition of assets in the Eagle Ford Shale (see Note 3), ARP issued 3.2 million of its 8.625% Class D cumulative redeemable perpetual preferred units (“Class D ARP Preferred Units”) and in March 2015, issued an additional 800,000 Class D ARP Preferred Units (see Note 12). The initial quarterly distribution on the Class D ARP Preferred Units was $0.616927 per unit, representing the distribution for the period from October 2, 2014 through January 14, 2015. Subsequent to January 14, 2015, ARP pays quarterly distributions on the Class D ARP Preferred Units at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference. In April 2015, ARP issued 255,000 of its newly created 10.75% Class E Cumulative Redeemable Perpetual ARP preferred units (“Class E ARP Preferred Units”). The initial quarterly distribution on the Class E ARP Preferred Units was $0.6793 per unit, representing the distribution for the period from April 14, 2015 through July 15, 2015. Subsequent to July 15, 2015, ARP will pay future quarterly distributions on the Class E Preferred Units at an annual rate of $2.6875 per unit, or 10.75% of the liquidation preference. At September 30, 2015 and December 31, 2014, $103.5 million and $78.0 million, respectively, related to ARP’s preferred units, are included within non-controlling interests on the Company’s combined consolidated statements of unitholders’ equity.

Income Taxes

Income Taxes

The Company, ARP, AGP, Lightfoot and the respective subsidiaries thereof are not subject to U.S. federal and most state income taxes. The partners of these entities are liable for income tax in regard to their distributive share of the entities’ taxable income. Such taxable income may vary substantially from net income (loss) reported in the accompanying combined consolidated financial statements. Certain corporate subsidiaries of ARP are subject to federal and state income tax. The federal and state income taxes related to the Company and these corporate subsidiaries were immaterial to the combined consolidated financial statements as of September 30, 2015 and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for these corporate subsidiaries in the accompanying combined consolidated financial statements.

Each of the entities which comprise the Company evaluates tax positions taken or expected to be taken in the course of preparing their respective tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Company’s management does not believe it has any tax positions taken within its combined consolidated financial statements that would not meet this threshold. The Company’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Company has not recognized any such potential interest or penalties in its combined consolidated financial statements for the three and nine months ended September 30, 2015 and 2014.

The entities comprising the Company file Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the entities comprising the Company are no longer subject to income tax examinations by major tax authorities for years prior to 2011 and are not currently being examined by any jurisdiction and are not aware of any potential examinations as of September 30, 2015.

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 share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. A portion of the Company’s phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plans and incentive compensation agreements (see Note 14), contain non-forfeitable rights to distribution equivalents of the Company. The participation rights result in a non-contingent transfer of value each time the Company declares 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 loss allocated to the common unitholders for purposes of calculating net loss attributable to common unitholders per unit (in thousands, except unit data):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Net loss	$	(582,313	)	$	(4,349	)	$	(588,377	)	$	(46,195	)
Preferred unitholder dividends		(1,009	)		—			(2,346	)		—
Loss attributable to non-controlling interests		439,969			5,137			420,411			33,828
(Income) loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015)		—			(788	)		10,475			12,367
Net loss utilized in the calculation of net loss attributable to common unitholders per unit – basic and diluted(1)	$	(143,353	)	$	—		$	(159,837	)	$	—

(1) Net loss attributable to common unitholders per unit is calculated by dividing net income (loss) attributable to common unitholders, less income allocable to participating securities, by the sum of the weighted average number of common unitholder 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. For the three months ended September 30, 2015, net loss attributable common unitholders per unit is not allocated to approximately 69,000 phantom units, 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 nine months ended September 30, 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 68,000 phantom units, 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 three and nine months ended September 30, 2015, distributions on the Company’s Series A preferred units were excluded, because the inclusion of such preferred distributions would have been anti-dilutive.

The following table sets forth the reconciliation of the Company’s 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 September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Weighted average number of common unitholders per unit—basic		26,011		—		26,011		—
Add effect of dilutive incentive awards(1)		—		—		—		—
Add effect of dilutive convertible preferred units(1)		—		—		—		—
Weighted average number of common unitholders per unit—diluted		26,011		—		26,011		—

(1) For the three months ended September 30, 2015, 2,737,000 phantom units 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 nine months ended September 30, 2015, 1,492,000 phantom units 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 three and nine months ended September 30, 2015, potential common units issuable upon conversion of the Company’s 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.

Revenue Recognition

Revenue Recognition

Natural gas and oil production. The Company’s subsidiaries’ gas and oil production operations generally sell natural gas, crude oil and NGLs at prevailing market prices. Typically, sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which the Company’s subsidiaries have an interest with other producers, are recognized on the basis of the entity’s percentage ownership of the working interest and/or overriding royalty.

ARP’s Drilling Partnerships. Certain energy activities are conducted by ARP through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by ARP is deployed to drill and complete wells included within the partnership. As ARP deploys Drilling Partnership investor capital, it recognizes certain management fees it is entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if ARP has Drilling Partnership investor capital that has not yet been deployed, it will recognize a current liability titled “Liabilities Associated with Drilling Contracts” on the Company’s combined consolidated balance sheets. After the Drilling Partnership well is completed and turned in line, ARP is entitled to receive additional operating and management fees, which are included within well services and administration and oversight revenue, respectively, on a monthly basis while the well is operating. In addition to the management fees it is entitled to receive for services provided, ARP is also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which generally approximate 30%. ARP recognizes its Drilling Partnership management fees in the following manner:

· Well construction and completion. For each well that is drilled by a Drilling Partnership, ARP receives a 15% mark-up on those costs incurred to drill and complete wells included within the partnership. Such fees are earned, in accordance with the partnership agreement, and recognized as the services are performed, typically between 60 and 270 days.

· Administration and oversight. For each well drilled by a Drilling Partnership, ARP receives a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which is earned, in accordance with the partnership agreement, and recognized at the initiation of the well. Additionally, the Drilling Partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. The well administrative fee is earned on a monthly basis as the services are performed.

· Well services. Each Drilling Partnership pays ARP a monthly per well operating fee, currently $1,000 to $2,000, depending on the type of well, for the life of the well. Such fees are earned on a monthly basis as the services are performed.

While the 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.

ARP’s gathering and processing revenue. Gathering and processing revenue includes gathering fees ARP charges to the Drilling Partnership wells for ARP’s processing plants in the New Albany and the Chattanooga shales. Generally, ARP charges a gathering fee to the Drilling Partnership wells equivalent to the fees ARP remits. In Appalachia, a majority of the 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 the Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%.

The Company’s subsidiaries’ gas and oil production operations accrue unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” for further description). The Company had unbilled revenues at September 30, 2015 and December 31, 2014 of $48.5 million and $85.5 million, respectively, which were included in accounts receivable within its combined consolidated balance sheets.

Comprehensive Income (Loss)

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Company’s combined consolidated financial statements, and for all periods presented, only include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges (see Note 8). The Company does not have any other type of transaction which would be included within other comprehensive income (loss).

Recently Issued Accounting Standards

Recently Issued Accounting Standards

In September 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-16, Business Combinations (Subtopic 805) (“Update 2015-16”) which eliminates the need to retrospectively adjust previously issued financial statements for changes in provisional amounts recognized at the date on which a business was acquired and later revised based on new information about facts and circumstances that existed at the acquisition date.  Subsequent to the effective date of this accounting standard, such adjustments will be applied prospectively and the nature of, and reason for, the change in accounting principle will be disclosed.  The Company will adopt the requirements of Update 2015-16 upon its effective date of January 1, 2016, and the Company does not anticipate it having a material impact on its financial position, results of operations or related disclosures.  

In August 2015, the FASB issued ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements which was a clarification of its previously issued ASU 2015-03, Interest—Imputation of Interest (“Update 2015-15”) requiring entities to present debt issuance costs related to a recognized debt liability as a direct deduction from the carrying amount of that debt liability. Given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to line-of-credit arrangements, ASU 2015-15 effectively allows an entity to defer line-of-credit issuance costs and present such costs as an asset.  These deferred debt issuance costs may be amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Company will adopt the requirements of Update 2015-15 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In April 2015, the FASB issued ASU 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (“Update 2015-06”). Under Topic 260, Earnings per Share, master limited partnerships (“MLPs”) apply the two-class method to calculate earnings per unit (“EPU”) because the general partner, limited partners, and incentive distribution rights holders each participate differently in the distribution of available cash. When a general partner transfers (or “drops down”) net assets to an MLP and that transaction is accounted for as a transaction between entities under common control, the statements of operations of the MLP are adjusted retrospectively to reflect the drop down transaction as if it occurred on the earliest date during which the entities were under common control. The amendments in Update 2015-06 specify that for purposes of calculating historical EPU under the two-class method, the earnings (losses) of a transferred business before the date of a drop down transaction should be allocated entirely to the general partner interest, and previously reported EPU of the limited partners would not change as a result of a drop down transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the drop down transaction occurs also are required. The amendments in Update 2015-06 are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted and amendments in Update 2015-06 should be applied retrospectively for all financial statements presented. The Company will adopt the requirements of Update 2015-06 upon its effective date of January 1, 2016, and the Company does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In March 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30) (“Update 2015-03”). The amendments in Update 2015-03 are intended to simplify presentation of debt issuance costs and require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs would not be affected by the amendments in Update 2015-03. The amendments in Update 2015-03 are effective for periods beginning after December 15, 2015, and interim periods within those periods. Early adoption is permitted, including adoption in an interim period, and an entity should apply the new guidance on a retrospective basis. The Company will adopt the requirements of Update 2015-03 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“Update 2015-02”). The amendments in Update 2015-02 are intended to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures.  The amendments simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The amendments in Update 2015-02 are effective for periods beginning after December 31, 2015. Early adoption is permitted, including adoption in an interim period. The Company will adopt the requirements of Update 2015-02 upon its effective date of January 1, 2016, and is evaluating the impact of adoption on its financial position, results of operations or related disclosures.

In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The Company will adopt the requirements of Update 2015-01 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815) – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity (“Update 2014-16”). Certain classes of shares include features that entitle the holders to preferences and rights (such as conversion rights, redemption rights, voting powers, and liquidation and dividend payment preferences) over the other shareholders. Shares that include embedded derivative features are referred to as hybrid financial instruments, which must be separated from the host contract and accounted for as a derivative if certain criteria are met under Subtopic 815-10.One criterion requires evaluating whether the nature of the host contract is more akin to debt or to equity and whether the economic characteristics and risks of the embedded derivative feature are “clearly and closely related” to the host contract. In making that evaluation, an issuer or investor may consider all terms and features in a hybrid financial instrument including the embedded derivative feature that is being evaluated for separate accounting or may consider all terms and features in the hybrid financial instrument except for the embedded derivative feature that is being evaluated for separate accounting. The use of different methods can result in different accounting outcomes for economically similar hybrid financial instruments.Additionally, there is diversity in practice with respect to the consideration of redemption features in relation to other features when determining whether the nature of a host contract is more akin to debt or to equity. The amendments in Update 2014-16 clarify how current U.S. GAAP should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. The effects of initially adopting the amendments in Update 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in the form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. The amendments in Update 2014-16 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The Company will adopt the requirements of Update 2014-16 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early adoption is permitted. The Company will adopt the requirements of Update 2014-15 upon its effective date in 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In June 2014, the FASB issued ASU 2014-12, Compensation—Stock Compensation (Topic 718) (“Update 2014-12”). The amendments in Update 2014-12 require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in Update 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. The Company will adopt the requirements of Update 2014-12 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles—Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is not permitted. The Company will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2018, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

Derivatives, Methods of Accounting, Derivative Types

AGP and ARP use a number of different derivative instruments, principally swaps, collars, and options, in connection with their commodity and interest rate price risk management activities. AGP and ARP enter into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold or interest payments on the underlying debt instrument are due. Under commodity-based swap agreements, AGP and ARP receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.  

Derivatives, Methods of Accounting, Hedge Effectiveness

On January 1, 2015, ARP discontinued hedge accounting for its qualified commodity derivatives. As such, changes in fair value of these derivatives after December 31, 2014 are recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s combined consolidated statements of operations. The fair values of these commodity derivative instruments at December 31, 2014, which were recognized in accumulated other comprehensive income within unitholders’ equity on the Company’s combined consolidated balance sheet, are being reclassified to the Company’s combined consolidated statements of operations at the time the originally hedged physical transactions settle.

Derivatives, Basis and Use of Derivatives, Use of Derivatives

AGP and ARP enter into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Company’s combined consolidated balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Company’s combined consolidated balance sheets as the initial value of the options.

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Cash Distributions

9 Months Ended

Sep. 30, 2015

Distributions Made To Members Or Limited Partners [Abstract]

Cash Distributions

NOTE 13—CASH DISTRIBUTIONS

The Company’s Cash Distributions. The Company has a cash distribution policy under which it distributes, within 50 days following the end of each calendar quarter, all of its available cash (as defined in its limited liability company agreement) for that quarter to its unitholders. Distributions declared by the Company related to its Class A preferred units were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	For MonthEnded	Total Cash DistributionTo CommonUnitholders		Total Cash Distribution To PreferredUnitholders
May 15, 2015	March 31, 2015	$	—	$	333
June 12, 2015	April 30, 2015	$	—	$	334
July 15, 2015	May 31, 2015	$	—	$	334
August 14, 2015	June 30, 2015	$	—	$	335
September 14, 2015	July 31, 2015	$	—	$	336
October 15, 2015	August 31, 2015	$	—	$	336

On October 28, 2015, the Company declared a monthly distribution of $0.3 million for the month ended September 30, 2015 related to its Series A Preferred Units. The distribution will be paid on November 13, 2015 to unitholders of record at the close of business on November 9, 2015.

ARP Cash Distributions. In January 2014, ARP’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program whereby it distributes all of its available cash (as defined in ARP’s partnership agreement) for that month to its unitholders within 45 days from the month end. Prior to that, ARP paid quarterly cash distributions within 45 days from the end of each calendar quarter. If ARP’s common unit distributions in any quarter exceed specified target levels, the Company will receive between 13% and 48% of such distributions in excess of the specified target levels. While outstanding, the Class B ARP Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.40 (or $0.1333 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. While outstanding, the Class C ARP Preferred Units will receive regular quarterly cash distributions equal to the greater of (i) $0.51 (or $0.17 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. The initial quarterly distribution on the Class D ARP Preferred Units was $0.616927 per unit, representing the distribution for the period from October 2, 2014 through January 14, 2015. ARP pays quarterly distributions on the Class D ARP Preferred Units at an annual rate of $2.15625 per unit, $0.5390625 per unit paid on a quarterly basis, or 8.625% of the liquidation preference. ARP pays distributions on the Class E ARP Preferred Units at an annual rate of $2.6875 per unit, or $0.671875 per unit on a quarterly basis, or 10.75% of the $25.00 liquidation preference.

Distributions declared by ARP from January 1, 2014 through September 30, 2015 were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	For Month Ended	Cash Distribution per CommonLimited Partner Unit		Total Cash Distribution to Common Limited Partners		Total Cash Distribution To Preferred Limited Partners(1)			Total Cash Distribution to the GeneralPartner’s Class A Units
March 17, 2014	January 31, 2014	$	0.1933	$	12,718	$	1,467		$	1,055
April 14, 2014	February 28, 2014	$	0.1933	$	12,719	$	1,466		$	1,055
May 15, 2014	March 31, 2014	$	0.1933	$	12,719	$	1,466		$	1,054
June 13, 2014	April 30, 2014	$	0.1933	$	15,752	$	1,466		$	1,279
July 15, 2014	May 31, 2014	$	0.1933	$	15,752	$	1,466		$	1,279
August 14, 2014	June 30, 2014	$	0.1966	$	16,029	$	1,492		$	1,377
September 12, 2014	July 31, 2014	$	0.1966	$	16,028	$	1,493		$	1,378
October 15, 2014	August 31, 2014	$	0.1966	$	16,032	$	1,491		$	1,378
November 14, 2014	September 30, 2014	$	0.1966	$	16,032	$	1,492		$	1,378
December 15, 2014	October 31, 2014	$	0.1966	$	16,033	$	1,491		$	1,378
January 14, 2015	November 30, 2014	$	0.1966	$	16,779	$	745	(1)	$	1,378
February 13, 2015	December 31, 2014	$	0.1966	$	16,782	$	745	(1)	$	1,378
March 17, 2015	January 31, 2015	$	0.1083	$	9,284	$	643	(1)	$	203
April 14, 2015	February 28, 2015	$	0.1083	$	9,347	$	643	(1)	$	204
May 15, 2015	March 31, 2015	$	0.1083	$	9,444	$	643	(1)	$	206
June 12, 2015	April 30, 2015	$	0.1083	$	10,179	$	642	(1)	$	221
July 15, 2015	May 31, 2015	$	0.1083	$	10,304	$	643	(1)	$	223
August 14, 2015	June 30, 2015	$	0.1083	$	10,309	$	637	(2)	$	223
September 14, 2015	July 31, 2015	$	0.1083	$	10,571	$	638	(2)	$	229
October 15, 2015	August 31, 2015	$	0.1083	$	10,949	$	637	(2)	$	236

(1) Includes payments for the Class B and Class C preferred unit monthly distributions.

(2) Includes payments for the Class C preferred unit monthly distributions. The remaining Class B Preferred Units were converted on July 25, 2015, and the Class B Preferred Unitholders received additional ARP common units upon conversion in lieu of the June distribution. No Class B Preferred Units were outstanding at September 30, 2015.  

Date Cash Distribution Paid	For the Period	Cash Distribution per Class D PreferredLimited Partner Unit		Total Cash DistributionTo Class D Preferred Limited Partners
January 15, 2015	October 2, 2014 – January 14, 2015	$	0.6169270	$	1,974
April 15, 2015	January 15, 2015 – April 14, 2015	$	0.5390630	$	2,156
July 15, 2015	April 15, 2015 – July 14, 2015	$	0.5390625	$	2,157
October 15, 2015	July 15, 2015 – October 14, 2015	$	0.5390625	$	2,205

Date Cash Distribution Paid	For the Period	Cash Distribution per Class E PreferredLimited Partner Unit		Total Cash DistributionTo Class E Preferred Limited Partners
July 15, 2015	April 14, 2015 – July 14, 2015	$	0.6793	$	173
October 15, 2015	July 15, 2015 – October 14, 2015	$	0.6718750	$	172

On October 28, 2015, ARP declared a monthly distribution of $0.1083 per common unit for the month of September 30, 2015. The $11.9 million distribution, including $0.2 million and $0.6 million to the general partner and preferred limited partners, respectively, will be paid on November 13, 2015 to unitholders of record at the close of business on November 9, 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 target 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 declared by AGP from January 1, 2014 through September 30, 2015 were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	For the Quarter Ended	Cash Distribution per CommonLimited Partner Unit		Total Cash Distribution to Common Limited Partners		Total Cash Distribution to the GeneralPartner’s Class A Units
February 14, 2014(1)	December 31, 2013	$	0.1167	$	120	$	2
May 15, 2014	March 31, 2014	$	0.1750	$	223	$	6
August 14, 2014	June 30, 2014	$	0.1750	$	342	$	7
November 14, 2014	September 30, 2014	$	0.1750	$	841	$	16
February 13, 2015	December 31, 2014	$	0.1750	$	1,636	$	33
May 15, 2015	March 31, 2015	$	0.1750	$	2,180	$	45
August 14, 2015	June 30, 2015	$	0.1750	$	2,646	$	54

(1) Represents a pro-rated cash distribution of $0.1750 per common limited partner unit and general partner unit for the period from November 1, 2013, the date AGP commenced operations.

On November 5, 2015, AGP declared a quarterly distribution of $0.1750 per common unit for the quarter ended September 30, 2015. The $4.2 million distribution, including $0.1 million to the general partner, will be paid on November 13, 2015 to unitholders of record at the close of business on September 30, 2015.

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Operating Segment Information (Capital Expenditures) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Segment Reporting Information [Line Items]
Capital expenditures	$ 40,458	$ 56,497	$ 123,067	$ 162,726
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Capital expenditures	32,799	55,930	102,290	150,579
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Capital expenditures	$ 7,659	$ 567	$ 20,777	$ 12,147

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Fair Value of Financial Instruments

9 Months Ended

Sep. 30, 2015

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

NOTE 9—FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company and its subsidiaries have established a hierarchy to measure their financial instruments at fair value which requires them to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect the Company’s and its subsidiaries’ own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Company and its subsidiaries use a market approach fair value methodology to value the assets and liabilities for their outstanding derivative contracts (see Note 8) and the Company’s rabbi trust assets (see Note 14). ARP and AGP manage and report derivative assets and liabilities on the basis of their exposure to market risks and credit risks by counterparty. ARP’s and AGP’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument. Investments held in the Company’s rabbi trust are publicly traded equity and debt securities and are therefore defined as Level 1 fair value measurements.

Information for the Company and its subsidiaries’ assets and liabilities measured at fair value at September 30, 2015 and December 31, 2014 was as follows (in thousands):

	Level 1		Level 2			Level 3		Total
As of September 30, 2015
Assets, gross
Rabbi trust	$	5,378	$	—		$	—	$	5,378
ARP Commodity swaps		—		349,348			—		349,348
ARP Commodity puts		—		2,457			—		2,457
ARP Commodity options		—		803			—		803
AGP Commodity swaps		—		562			—		562
Total assets, gross		5,378		353,170			—		358,548
Liabilities, gross
ARP Commodity swaps		—		(7	)		—		(7	)
ARP Commodity options		—		—			—		—
AGP Commodity swaps		—		—			—		—
Total derivative liabilities, gross		—		(7	)		—		(7	)
Total assets, fair value, net	$	5,378	$	353,163		$	—	$	358,541
As of December 31, 2014
Assets, gross
Rabbi trust	$	3,925	$	—		$	—	$	3,925
ARP Commodity swaps		—		267,242			—		267,242
ARP Commodity puts		—		2,767			—		2,767
ARP Commodity options		—		5,320			—		5,320
Total assets, gross		3,925		275,329			—		279,254
Liabilities, gross
ARP Commodity swaps		—		(401	)		—		(401	)
ARP Commodity options		—		(67	)		—		(67	)
Total derivative liabilities, gross		—		(468	)		—		(468	)
Total assets, fair value, net	$	3,925	$	274,861		$	—	$	278,786

Other Financial Instruments

The estimated fair values of the Company’s and its subsidiaries’ other financial instruments have been determined based upon their assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Company and its subsidiaries could realize upon the sale or refinancing of such financial instruments.

The Company’s and its subsidiaries’ other current assets and liabilities on its 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 the Company’s and ARP’s debt at September 30, 2015 and December 31, 2014, which consist principally of ARP’s senior notes, borrowings under the Company’s term loan facilities, and borrowings under ARP’s term loan and revolving credit facilities, were $1,077.2 million and $1,363.4 million, respectively, compared with the carrying amounts of $1,587.7 million and $1,542.6 million, respectively. The carrying values of outstanding borrowings under the respective revolving and term loan credit facilities, which bear interest at variable interest rates, approximated their estimated fair values. The estimated fair values of the ARP senior notes were based upon the market approach and calculated using the yields of the ARP senior notes 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

The Company’s subsidiaries estimate the fair value of their respective asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Company’s subsidiaries and estimated inflation rates (see Note 6).

Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the three and nine months ended September 30, 2015 and 2014 was as follows (in thousands):

	Three Months Ended September 30,
	2015				2014
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	80	$	80	$	336	$	336
Total	$	80	$	80	$	336	$	336

	Nine Months Ended September 30,
	2015				2014
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	296	$	296	$	8,283	$	8,283
Total	$	296	$	296	$	8,283	$	8,283

The Company’s subsidiaries estimate the fair value of their long-lived assets in connection with reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances. See Note 4 for a discussion of current year impairments. No impairments were recognized during the three and nine months ended September 30, 2014.

During the year ended December 31, 2014, ARP completed the Eagle Ford, Rangely and GeoMet acquisitions and AGP completed the Eagle Ford Acquisition (see Note 3). The fair value measurements of assets acquired and liabilities assumed for each of these acquisitions are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The estimated fair values of the assets acquired and liabilities assumed in the Eagle Ford Acquisition as of the acquisition date, which are reflected in the Company’s combined consolidated balance sheet as of September 30, 2015 are subject to change as the final valuations have not yet been completed, and such changes could be material. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under the Company’s subsidiaries’ existing methodology for recognizing an estimated liability for the plugging and abandonment of their gas and oil wells (see Note 6). These inputs require significant judgments and estimates by the Company’s subsidiaries’ management at the time of the valuation and are subject to change.

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Derivative Instruments (Fair Value of ARP's Derivative Instruments Table) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Assets	$ 358,548	$ 279,254
Gross Amounts of Recognized Liabilities	(7)	(468)
Atlas Resource Partners, L.P. | Current portion of derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Liabilities	(7)	(98)
Gross Amounts Offset in the Combined Consolidated Balance Sheets	7	98
Atlas Resource Partners, L.P. | Long-term portion of derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Liabilities		(370)
Gross Amounts Offset in the Combined Consolidated Balance Sheets		370
Atlas Resource Partners, L.P. | Total derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Liabilities	(7)	(468)
Gross Amounts Offset in the Combined Consolidated Balance Sheets	7	468
Atlas Resource Partners, L.P. | Current portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Assets	146,629	144,357
Gross Amounts Offset in the Combined Consolidated Balance Sheets	(7)	(98)
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets	146,622	144,259
Atlas Resource Partners, L.P. | Long-term portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Assets	205,979	130,972
Gross Amounts Offset in the Combined Consolidated Balance Sheets		(370)
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets	205,979	130,602
Atlas Resource Partners, L.P. | Total derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Assets	352,608	275,329
Gross Amounts Offset in the Combined Consolidated Balance Sheets	(7)	(468)
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets	$ 352,601	$ 274,861

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Debt

9 Months Ended

Sep. 30, 2015

Debt Disclosure [Abstract]

Debt

NOTE 7—DEBT

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

		September 30,		December 31,
		2015		2014
Term loan facilities	$	82,700	$	148,125
ARP revolving credit facility		563,000		696,000
ARP term loan facility		243,408		—
ARP 7.75% Senior Notes—due 2021		374,601		374,544
ARP 9.25% Senior Notes—due 2021		324,038		323,916
Total debt		1,587,747		1,542,585
Less current maturities		—		(1,500	)
Total long-term debt	$	1,587,747	$	1,541,085

Term Loan Facilities

On August 10, 2015, the Company entered into a credit agreement (the “Riverstone Credit Agreement”) with Riverstone Credit Partners, L.P., as administrative agent, and the lenders party thereto, for a new term loan facility (the “Riverstone Term Loan Facility”) in an aggregate principal amount of $82.7 million maturing in August 2020.The borrowings under the Riverstone Term Loan Facility were used to repay in full outstanding borrowings under the Company’s existing term loan facility.

The Company’s obligations under the Riverstone Term Loan Facility are secured on a first priority basis by security interests in substantially all of the assets of the Company and each of New Atlas Holdings, LLC, the Company’s direct wholly owned subsidiary, Atlas Lightfoot, LLC and any other material subsidiary of the Company that later guarantees indebtedness under the Riverstone Term Loan Facility, including all equity interests directly held by New Atlas Holdings, LLC or any guarantor and all tangible and intangible property of the Company and the guarantors (subject to certain customary exclusions and exceptions).

Borrowings under the Riverstone Term Loan Facility bear interest, at the Company’s option, at either (i) LIBOR plus 7.0% (as used with respect to the Riverstone Term Loan Facility, “Eurodollar Loans”) or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 6.0% (as used with respect to the Riverstone Term Loan Facility, an “ABR Loan”). Interest is generally payable at interest payment periods selected by the Company for Eurodollar Loans and quarterly for ABR Loans. At September 30, 2015, $82.7 million was outstanding under the Riverstone Term Loan Facility. At September 30, 2015, the weighted average interest rate on outstanding borrowings under the Riverstone Term Loan Facility was 8.0%.

The Riverstone Credit Agreement contains customary covenants that limit the Company’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. The Company was in compliance with these covenants as of September 30, 2015. The Riverstone Credit Agreement also requires that (a) the Total Leverage Ratio (as defined in the Riverstone Credit Agreement) not be greater than 4.00 to 1.00, beginning with the fiscal quarter ending March 31, 2016; (b) the full repayment of Company have liquidity of not less than $5 million at the end of each fiscal quarter, beginning with the fiscal quarter ending December 31, 2015; and (c) the Asset Coverage Ratio (as defined in the Riverstone Credit Agreement) not be less than 1.75 to 1.00 during the period from September 30, 2015 to June 30, 2016. Based on the definitions contained in the Credit Agreement, at September 30, 2015, the Company’s Total Leverage Ratio was 2.6 to 1.0 and the Company’s Asset Coverage Ratio was 2.9 to 1.0.

The Company has the right at any time to prepay any borrowings outstanding under the Riverstone Term Loan Facility, subject to the payment of a prepayment premium specified therein. Subject to certain exceptions, the Company may also be required to prepay all or a portion of the Riverstone Term Loan Facility in certain instances, including the following:

· at the end of each fiscal quarter, the Company must repay the Riverstone Term Loan Facility in an amount equal to: (i) if the Total Leverage Ratio is equal to or greater than 3.50 to 1.00, 100% of Distributable Cash (as defined in the Riverstone Credit Agreement), (ii) if the Total Leverage Ratio is equal to or greater than 3.00 to 1.00 but less than 3.25 to 1.00, 75% of Distributable Cash, (iii) if the Total Leverage Ratio is equal to or greater than 2.75 to 1.00 but less than 3.00 to1.00, 50% of Distributable Cash, (iv) if the Total Leverage Ratio is equal to or greater than 2.50 to 1.00 but less than 2.75 to1.00, 25% of Distributable Cash, and (v) if the Total Leverage Ratio is less than 2.50 to 1.00, 0% of Distributable Cash.

· if, at any time after June 30, 2016, the Asset Coverage Ratio is less than 2.00 to 1.00, the Company must prepay the Riverstone Term Loan Facility in an aggregate principal amount necessary to achieve an Asset Coverage Ratio of greater than 2.00 to 1.00; the Asset Coverage Ratio is equal to the ratio of the Asset Value (the sum of the discounted net present values of the loan parties’ oil and gas properties, cash and cash equivalents, and the values of certain equity interests of ARP, Atlas Lightfoot, LLC, AGP and certain other midstream and upstream companies, determined as set forth in the Riverstone Credit Agreement) to Total Funded Debt (as defined in the Riverstone Credit Agreement);

· if the Company or any restricted subsidiary of the Company disposes of property or assets (including equity interests) to a person other than a loan party or receives insurance or condemnation proceeds following a casualty event, the Company must repay the Riverstone Term Loan Facility in an aggregate principal amount equal to 100% of the net cash proceeds from such disposition or casualty event; and

· if the Company or any restricted subsidiary of the Company issues or incurs any debt or issues any equity, the Company must repay the Riverstone Term Loan Facility in an aggregate principal amount equal to 100% of the net cash proceeds of such issuances or incurrences of debt or issuances of equity.

On February 27, 2015, the Company entered into a credit agreement with Deutsche Bank AG New York Branch, as administrative agent, and the lenders party thereto (the “Credit Agreement”). The Credit Agreement provided for a Secured Senior Interim Term Loan Facility in an aggregate principal amount of $30.0 million (the “Interim Term Loan Facility”) and a Secured Senior Term Loan A Facility in an aggregate principal amount of approximately $97.8 million (the “Term Loan A Facility” and together with the Interim Term Loan Facility, the “Term Loan Facilities”). In June 2015, the Company prepaid $33.1 million on the Term Loan Facilities in connection with the Arkoma Acquisition (see Note 3). On August 10, 2015, the Company repaid in full the remaining $82.7 million outstanding under the Term Loan Facilities.

The proceeds from the issuance of the Term Loan Facilities were used to fund a portion of the Company’s $150.0 million payment to Atlas Energy in connection with the repayment of Atlas Energy’s term loan (see Note 2). The Interim Term Loan Facility matured on August 27, 2015 and the Term Loan A Facility was to mature on February 26, 2016. The Company’s obligations under the Term Loan Facilities were secured on a first priority basis by security interests in substantially all of the assets of the Company and its material subsidiaries, including all equity interests directly held by the Company, New Atlas Holdings, LLC, or any other guarantor, and all tangible and intangible property. Borrowings under the Term Loan Facilities bore interest, at the Company’s option, at either (i) LIBOR plus 7.5% (as used with respect to the Term Loan Facilities, “Eurodollar Loans”) or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, in each case plus 6.5% (as was used with the Term Loan Facilities, an “ABR Loan”). Interest was generally payable at interest payment periods selected by the Company for Eurodollar Loans and quarterly for ABR Loans.

The Company had the right at any time to prepay any borrowings outstanding under the Term Loan Facilities, without premium or penalty, provided the Interim Term Loan Facility was repaid prior to the Term Loan A Facility. Subject to certain exceptions, the Company may also have been required to prepay all or a portion of the Term Loan Facilities in certain instances, including the following:

· if, at any time, the Recognized Value Ratio (as defined in the Credit Agreement) was less than 2.00 to 1.00, the Company must have prepaid the Term Loan Facilities and any revolving loans outstanding in an aggregate principal amount necessary to achieve a Recognized Value Ratio of greater than 2.00 to 1.00; the Recognized Value Ratio was equal to the ratio of the Recognized Value (the sum of the discounted net present values of the Loan Parties’ oil and gas properties and the values of the common units, Class A Units and Class C Units of ARP, determined as set forth in the Credit Agreement) to Total Funded Debt (as defined in the Credit Agreement);

· if the Company disposed of all or any portion of the Arkoma Assets (as defined in the Credit Agreement), the Company must have prepaid the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds resulting from such disposition;

· if the Company or any of its restricted subsidiaries disposed of property or assets (including equity interests), the Company must have repaid the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds from such disposition or casualty event; and;

· if the Company incurred any debt or issues any equity, it must have repaid the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds of such issuances or incurrences of debt or issuances of equity.

The Credit Agreement contained customary covenants that limited the Company’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. The Credit Agreement also required that the Total Leverage Ratio (as defined in the Credit Agreement) not be greater than (i) as of the last day of any fiscal quarter prior to the full repayment of the Interim Term Loan Facility, 3.75 to 1.00, and (ii) as of the last day of any quarter thereafter, 3.50 to 1.00.

Atlas Energy Term Loan Facility

On July 31, 2013, Atlas Energy entered into a $240.0 million secured term loan facility with a group of outside investors (the “Term Facility”). At December 31, 2014, $148.1 million of the Term Facility was attributable to the Company. The Term Facility had a maturity date of July 31, 2019. Borrowings under the Term Facility bore interest, at Atlas Energy’s election, at either an adjusted LIBOR rate plus an applicable margin of 5.50% per annum or the alternate base rate (as defined in the Term Facility) (“ABR”) plus an applicable margin of 4.50% per annum. Interest was generally payable quarterly for ABR loans and, for LIBOR loans at the interest periods selected by Atlas Energy. Atlas Energy was required to repay principal at the rate of $0.6 million per quarter commencing December 31, 2013 and continuing until the maturity date when the remaining balance was due. At December 31, 2014, the weighted average interest rate on outstanding borrowings under the Term Facility was 6.5%.  

In connection with Atlas Energy’s merger with Targa, the Term Facility was repaid in full on February 27, 2015.

ARP Credit Facility

ARP is a party to a Second Amended and Restated Credit Agreement dated July 31, 2013, as amended, with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (the “ARP Credit Agreement”), which provides for a senior secured revolving credit facility with a borrowing base of $750.0 million as of September 30, 2015.  

ARP’s borrowing base is scheduled for semi-annual redeterminations on November 1, 2015 and thereafter on May 1 and November 1 of each year. In July 2015, the determination by the lenders reaffirmed ARP’s $750.0 million borrowing base. The ARP Credit Agreement also provides that ARP’s borrowing base will be reduced by 25% of the stated amount of any senior notes issued, or additional second lien debt incurred, after July 1, 2015. At September 30, 2015, $563.0 million was outstanding under the credit facility. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which $4.3 million was outstanding at September 30, 2015. ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. Borrowings under the credit facility bear interest, at ARP’s election, at either an adjusted LIBOR rate plus an applicable margin between 1.50% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.50% and1.75% per annum. If the borrowing base utilization (as defined in the ARP Credit Agreement) is less than 90%, the applicable margin on Eurodollar Loans and ABR Loans (each as defined in the ARP Credit Agreement) will be increased by 0.25%. ARP is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.375% per annum if less than 50% of the borrowing base is utilized and 0.5% if 50% or more of the borrowing base is utilized, which is included within interest expense on the Company’s combined consolidated statements of operations. At September 30, 2015, the weighted average interest rate on outstanding borrowings under the credit facility was 2.75%.

The ARP Credit Agreement contains customary covenants that limit ARP’s ability to incur additional indebtedness (excluding second lien debt in an aggregate principal amount of up to $300.0 million), grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. ARP was in compliancewith these covenants as of September 30, 2015. The ARP Credit Agreement also requires that ARP maintain a ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than (i) 5.25 to 1.0 as of the last day of the quarters ending on March 31, 2015, June 30, 2015, September 30, 2015, December 31, 2015 and March 31, 2016, (ii) 5.00 to 1.0 as of the last day of the quarters ending on June 30, 2016, September 30, 2016 and December 31, 2016, (iii) 4.50 to 1.0 as of the last day of the quarter ending on March 31, 2017 and (iv) 4.00 to 1.0 as of the last day of each quarter thereafter, and a ratio of current assets (as defined in the ARP Credit Agreement) to current liabilities (as defined in the ARP Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. Based on the definitions contained in the ARP Credit Agreement, at September 30, 2015, ARP’s ratio of current assets to current liabilities was 1.4 to 1.0, and its ratio of Total Funded Debt to EBITDA was 5.2 to 1.0.

ARP Term Loan Facility

On February 23, 2015, ARP entered into a Second Lien Credit Agreement with certain lenders and Wilmington Trust, National Association, as administrative agent. The Second Lien Credit Agreement provides for a second lien term loan in an original principal amount of $250.0 million (the “ARP Term Loan Facility”). The ARP Term Loan Facility matures on February 23, 2020. The ARP Term Loan Facility is presented net of unamortized discount of $6.6 million at September 30, 2015.

ARP has the option to prepay the ARP Term Loan Facility at any time, and is required to offer to prepay the ARP Term Loan Facility with 100% of the net cash proceeds from the issuance or incurrence of any debt and 100% of the excess net cash proceeds from certain asset sales and condemnation recoveries. ARP is also required to offer to prepay the ARP Term Loan Facility upon the occurrence of a change of control. All prepayments are subject to the following premiums, plus accrued and unpaid interest:

· the make-whole premium (plus an additional amount if such prepayment is optional and funded with proceeds from the issuance of equity) for prepayments made during the first 12 months after the closing date;

· 4.5% of the principal amount prepaid for prepayments made between 12 months and 24 months after the closing date;

· 2.25% of the principal amount prepaid for prepayments made between 24 months and 36 months after the closing date; and

· no premium for prepayments made following 36 months after the closing date.

ARP’s obligations under the ARP Term Loan Facility are secured on a second priority basis by security interests in all of its assets and those of its restricted subsidiaries (the “Loan Parties”) that guarantee ARP’s existing first lien revolving credit facility. In addition, the obligations under the ARP Term Loan Facility are guaranteed by ARP’s material restricted subsidiaries. Borrowings under the ARP Term Loan Facility bear interest, at ARP’s option, at either (i) LIBOR plus 9.0% or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 8.0% (an “ABR Loan”). Interest is generally payable at the applicable maturity date for Eurodollar loans and quarterly for ABR loans. At September 30, 2015, the weighted average interest rate on outstanding borrowings under the term loan facility was 10.0%.

The Second Lien Credit Agreement contains customary covenants that limit ARP’s ability to make restricted payments, take on indebtedness, issue preferred stock, grant liens, conduct sales of assets and subsidiary stock, make distributions from restricted subsidiaries, conduct affiliate transactions and engage in other business activities. In addition, the Second Lien Credit Agreement contains covenants substantially similar to those in ARP’s existing first lien revolving 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 in compliance with these covenants as of September 30, 2015.

Under the Second Lien Credit Agreement, ARP may elect to add one or more incremental term loan tranches to the ARP Term Loan Facility so long as the aggregate outstanding principal amount of the ARP Term Loan Facility plus the principal amount of any incremental term loan does not exceed $300.0 million and certain other conditions are adhered to.  Any such incremental term loans may not mature on a date earlier than February 23, 2020.

Senior Notes

At September 30, 2015, ARP had $374.6 million outstanding of its 7.75% senior unsecured notes due 2021 (“7.75% ARP Senior Notes”). The 7.75% ARP Senior Notes were presented net of a $0.4 million unamortized discount as of September 30, 2015. Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable for up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, ARP may redeem the 7.75% ARP Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (as defined in the governing indenture), plus accrued and unpaid interest, if any. On and after January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 7.75% ARP Senior Notes.

At September 30, 2015, ARP had $324.0 million outstanding of its 9.25% senior unsecured notes due 2021 (“9.25% ARP Senior Notes”). The 9.25% ARP Senior Notes were presented net of a $1.0 million unamortized discount as of September 30, 2015. Interest on the 9.25% ARP Senior Notes is payable semi-annually on February 15 and August 15. At any time prior to August 15, 2017, ARP may redeem the 9.25% ARP Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (as defined in the governing indenture), plus accrued and unpaid interest, if any. At any time on or after August 15, 2017, ARP may redeem some or all of the 9.25% ARP Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 100.0%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 9.25% ARP Senior Notes.

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 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 limitations of 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 September 30, 2015.

Cash payments for interest by the Company and its subsidiaries on their respective borrowings were $93.7 million and $62.5 million for the nine months ended September 30, 2015 and 2014, respectively.

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Derivative Instruments

9 Months Ended

Sep. 30, 2015

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Instruments

NOTE 8—DERIVATIVE INSTRUMENTS

AGP and ARP use a number of different derivative instruments, principally swaps, collars, and options, in connection with their commodity and interest rate price risk management activities. AGP and ARP enter into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold or interest payments on the underlying debt instrument are due. Under commodity-based swap agreements, AGP and ARP receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.  

On January 1, 2015, ARP discontinued hedge accounting for its qualified commodity derivatives. As such, changes in fair value of these derivatives after December 31, 2014 are recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s combined consolidated statements of operations. The fair values of these commodity derivative instruments at December 31, 2014, which were recognized in accumulated other comprehensive income within unitholders’ equity on the Company’s combined consolidated balance sheet, are being reclassified to the Company’s combined consolidated statements of operations at the time the originally hedged physical transactions settle.

AGP and ARP enter into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Company’s combined consolidated balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Company’s combined consolidated balance sheets as the initial value of the options.

AGP and ARP enter into commodity future option and collar 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 other natural gas liquids contracts are based on an OPIS Mt. Belvieu index.

Derivatives are recorded on the Company’s combined consolidated balance sheets as assets or liabilities at fair value. The Company reflected net derivative assets on its combined consolidated balance sheets of $353.2 million and $274.9 million at September 30, 2015 and December 31, 2014, respectively. Of the $10.4 million of net gain in accumulated other comprehensive income within unitholders’ equity on the Company’s combined consolidated balance sheet related to derivatives at September 30, 2015, the Company will reclassify $8.0 million of gains to its combined consolidated statement of operations over the next twelve-month period as these contracts expire with the remaining $2.4 million of gains being reclassified to the Company’s combined consolidated statements of operations in later periods as the remaining contracts expire. During the three and nine months ended September 30, 2014, $0.3 million and $0.8 million were reclassified from other comprehensive income related to derivative instruments entered into during that same period.

The following table summarizes the commodity derivative activity for the three and nine months ended September 30, 2015 (in thousands):  

	Three Months EndedSeptember 30, 2015			Nine Months EndedSeptember 30, 2015
Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets(1)	$	(23,927	)	$	(77,048	)
Portion of settlements attributable to subsequent mark to market gains		(19,752	)		(49,877	)
Total cash settlements on commodity derivative contracts		(43,679	)		(126,925	)
2015 Unrealized gains prior to settlement(2)		10,989			17,822
Unrealized gain on open derivative contracts at September 30, 2015, net of amounts recognized in income in prior year(2)		120,788			192,644
Gains on mark-to-market derivatives	$	131,777		$	210,466

(1) Recognized in gas and oil production revenue.

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

The Company had cash settlement gains of $43.7 million and $1.4 million during the three months ended September 30, 2015 and 2014, respectively, and cash settlement gains of $126.9 million and cash settlement losses of $22.7 million during the nine months ended September 30, 2015 and 2014, respectively. As the underlying prices and terms in the Company’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three and nine months ended September 30, 2015 and 2014 for hedge ineffectiveness.

Atlas Growth

At May 1, 2015, AGP entered into a secured credit facility agreement with a syndicate of banks. As of the date hereof, the lenders under the credit facility have no commitment to lend to 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. 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. AGP was in compliance with these covenants as of September 30, 2015. 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. AGP has elected not to utilize hedge accounting for its derivative instruments.  

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

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Combined Consolidated Balance Sheets		Net Amount ofAssets Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Assets
As of September 30, 2015
Current portion of derivative assets	$	399	$	—	$	399
Long-term portion of derivative assets		163		—		163
Total derivative assets	$	562	$	—	$	562
As of December 31, 2014
Current portion of derivative assets	$	—	$	—	$	—
Long-term portion of derivative assets		—		—		—
Total derivative assets	$	—	$	—	$	—

	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Combined Consolidated Balance Sheets		Net Amount of Liabilities Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Liabilities
As of September 30, 2015
Current portion of derivative liabilities	$	—	$	—	$	—
Long-term portion of derivative liabilities		—		—		—
Total derivative liabilities	$	—	$	—	$	—
As of December 31, 2014
Current portion of derivative liabilities	$	—	$	—	$	—
Long-term portion of derivative liabilities		—		—		—
Total derivative liabilities	$	—	$	—	$	—

At September 30, 2015, AGP had the following commodity derivatives:

Crude Oil – Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Bbl)(1)		(per Bbl)(1)		(in thousands)(2)
2015		13,500	$	61.000	$	205
2016		18,000	$	63.150		249
2017		9,000	$	65.000		108
	AGP’s net assets				$	562

⁽¹⁾ “Bbl” represents barrels.

⁽²⁾ Fair value based on forward WTI crude oil prices, as applicable.

Atlas Resource

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

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Combined Consolidated Balance Sheets			Net Amount ofAssets Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Assets
As of September 30, 2015
Current portion of derivative assets	$	146,629	$	(7	)	$	146,622
Long-term portion of derivative assets		205,979		—			205,979
Total derivative assets	$	352,608	$	(7	)	$	352,601
As of December 31, 2014
Current portion of derivative assets	$	144,357	$	(98	)	$	144,259
Long-term portion of derivative assets		130,972		(370	)		130,602
Total derivative assets	$	275,329	$	(468	)	$	274,861

	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Combined Consolidated Balance Sheets		Net Amount of Liabilities Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Liabilities
As of September 30, 2015
Current portion of derivative liabilities	$	(7	)	$	7	$	—
Long-term portion of derivative liabilities		—			—		—
Total derivative liabilities	$	(7	)	$	7	$	—
As of December 31, 2014
Current portion of derivative liabilities	$	(98	)	$	98	$	—
Long-term portion of derivative liabilities		(370	)		370		—
Total derivative liabilities	$	(468	)	$	468	$	—

At September 30, 2015, ARP had the following commodity derivatives:

Natural Gas – Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(MMBtu)(1)		(per MMBtu)(1)		(in thousands)(2)
2015		13,611,100	$	4.193	$	21,734
2016		53,546,300	$	4.229		75,852
2017		49,920,000	$	4.219		60,364
2018		40,800,000	$	4.170		44,298
2019		15,960,000	$	4.017		13,785
					$	216,033

Natural Gas – Costless Collars

Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap		Fair Value Asset
		(MMBtu)(1)		(per MMBtu)(1)		(in thousands)(2)
2015	Puts purchased		600,000	$	3.934	$	803
2015	Calls sold		600,000	$	4.634		—
						$	803

Natural Gas – Put Options – Drilling Partnerships

Production Period Ending December 31,	Option Type	Volumes		Average Fixed Price		Fair Value Asset
		(MMBtu)(1)		(per MMBtu)(1)		(in thousands)(2)
2015	Puts purchased		360,000	$	4.000	$	505
2016	Puts purchased		1,440,000	$	4.150		1,952
						$	2,457

Natural Gas – WAHA Basis Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price			Fair Value Asset
	(MMBtu)(1)		(per MMBtu)(1)			(in thousands)(7)
2015		1,200,000	$	(0.090	)	$	41
						$	41

Natural Gas Liquids – Natural Gasoline Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Gal)(1)		(per Gal)(1)		(in thousands)(8)
2015		1,260,000	$	1.923	$	1,225
					$	1,225

Natural Gas Liquids – Propane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Gal)(1)		(per Gal)(1)		(in thousands)(4)
2015		2,016,000	$	1.016	$	1,096
					$	1,096

Natural Gas Liquids – Butane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Gal)(1)		(per Gal)(1)		(in thousands)(5)
2015		378,000	$	1.248	$	237
					$	237

Natural Gas Liquids – Iso Butane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Gal)(1)		(per Gal)(1)		(in thousands)(6)
2015		378,000	$	1.263	$	238
					$	238

Natural Gas Liquids – Crude Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Bbl)(1)		(per Bbl)(1)		(in thousands)(3)
2016		84,000	$	85.651	$	3,038
2017		60,000	$	83.780		1,828
					$	4,866

Crude Oil – Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Bbl)(1)		(per Bbl)(1)		(in thousands)(3)
2015		487,500	$	87.592	$	20,377
2016		1,557,000	$	81.471		49,856
2017		1,140,000	$	77.285		27,462
2018		1,080,000	$	76.281		22,073
2019		540,000	$	68.371		5,837
					$	125,605
		ARP’s net assets			$	352,601

⁽¹⁾ “MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons.

⁽²⁾ Fair value based on forward NYMEX natural gas prices, as applicable.

⁽³⁾ Fair value based on forward WTI crude oil prices, as applicable.

⁽⁴⁾ Fair value based on forward Mt. Belvieu propane prices, as applicable.

⁽⁵⁾ Fair value based on forward Mt. Belvieu butane prices, as applicable.

⁽⁶⁾ Fair value based on forward Mt. Belvieu iso butane prices, as applicable.

⁽⁷⁾ Fair value based on forward WAHA natural gas prices, as applicable

⁽⁸⁾ Fair value based on forward Mt. Belvieu natural gasoline prices, as applicable.

In June 2012, ARP entered into natural gas put option contracts which related to future natural gas production of the Drilling Partnerships. Therefore, a portion of any unrealized derivative gain or loss is allocable to the limited partners of the Drilling Partnerships based on their share of estimated gas production related to the derivatives not yet settled. At September 30, 2015, net unrealized derivative assets of $2.5 million were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts.

During the nine months ended September 30, 2015, the Company received approximately $4.9 million in net proceeds from the early termination of its 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 the Company’s Term Loan Facilities (see Note 7).

At September 30, 2015, 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 its revolving credit facility (see Note 7), 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. Each participating Drilling Partnership’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets and by a guarantee of the general partner of the Drilling Partnership. ARP, as the ultimate general partner of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnerships’ 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.

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Certain Relationships and Related Party Transactions

9 Months Ended

Sep. 30, 2015

Related Party Transactions [Abstract]

Certain Relationships And Related Party Transactions

NOTE 10—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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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Fair Value of Financial Instruments (Schedule of Assets and Liabilities Measured on Non Recurring Basis) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities incurred	$ 80	$ 336	$ 296	$ 8,283
Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities incurred	80	336	296	8,283
Asset Retirement Obligations
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities incurred	80	336	296	8,283
Asset Retirement Obligations | Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities incurred	$ 80	$ 336	$ 296	$ 8,283

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Operating Segment Information (Balance Sheet) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Goodwill	$ 13,639	$ 13,639
Total assets	2,305,861	3,026,315
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Goodwill	13,639	13,639
Total assets	2,096,758	2,791,553
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Total assets	171,522	190,161
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Total assets	$ 37,581	$ 44,601

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Commitments and Contingencies (General Commitments) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Percentage of present value of future cash flows			10.00%
Net partnership revenues subordinated	$ 400,000	$ 900,000	$ 1,500,000	$ 4,700,000
Commitment to expend			45,000,000
ARP’s Geomet Acquisition
Contractual obligation, due remainder of the fiscal year	900,000		900,000
Contractual obligation, due in second year	3,600,000		3,600,000
Contractual obligation, due in third year	2,500,000		2,500,000
Contractual obligation, due in fourth year	1,800,000		1,800,000
Contractual obligation, due in fifth year	1,800,000		1,800,000
Contractual obligation, due in thereafter	6,500,000		6,500,000
EP Energy Acquisition
Contractual obligation, due remainder of the fiscal year	2,200,000		2,200,000
Contractual obligation, due in second year	2,200,000		2,200,000
Contractual obligation, due in third year	0		0
Contractual obligation, due in fourth year	0		0
Contractual obligation, due in fifth year	$ 0		$ 0
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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Fair Value of Financial Instruments (Narrative) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Long-term debt, fair value	$ 1,077,200,000		$ 1,077,200,000		$ 1,363,400,000
Long-term debt	1,587,700,000		1,587,700,000		$ 1,542,600,000
Asset impairment	$ 679,537,000	$ 0	$ 679,537,000	$ 0
Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Business acquisition, purchase price allocation, status			During the year ended December 31, 2014, ARP completed the Eagle Ford, Rangely and GeoMet acquisitions and AGP completed the Eagle Ford Acquisition (see Note 3). The fair value measurements of assets acquired and liabilities assumed for each of these acquisitions are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The estimated fair values of the assets acquired and liabilities assumed in the Eagle Ford Acquisition as of the acquisition date, which are reflected in the Company’s combined consolidated balance sheet as of September 30, 2015 are subject to change as the final valuations have not yet been completed, and such changes could be material. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under the Company’s subsidiaries’ existing methodology for recognizing an estimated liability for the plugging and abandonment of their gas and oil wells (see Note 6). These inputs require significant judgments and estimates by the Company’s subsidiaries’ management at the time of the valuation and are subject to change.

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Operating Segment Information (Tables)

9 Months Ended

Sep. 30, 2015

Segment Reporting [Abstract]

Operating Segment Data

The Company’s operations include three reportable operating segments: ARP, AGP, and corporate and other. These operating segments reflect the way the Company manages its operations and makes business decisions. Corporate and other includes the Company’s equity investment in Lightfoot (see Note 1), as well as its general and administrative and interest expenses. Operating segment data for the periods indicated were as follows (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Atlas Resource:
Revenues	$	257,895		$	206,699		$	597,609		$	506,953
Operating costs and expenses		(80,486	)		(123,567	)		(244,126	)		(313,720	)
Depreciation, depletion and amortization expense		(40,463	)		(64,578	)		(125,948	)		(176,077	)
Asset impairment		(672,246	)		—			(672,246	)		—
Loss on asset sales and disposal		(362	)		(92	)		(276	)		(1,686	)
Interest expense		(25,192	)		(16,577	)		(75,105	)		(43,028	)
Segment income (loss)	$	(560,854	)	$	1,885		$	(520,092	)	$	(27,558	)
Atlas Growth:
Revenues	$	4,591		$	1,538		$	8,767		$	4,563
Operating costs and expenses		(3,385	)		(3,885	)		(11,697	)		(8,622	)
Asset impairment		(7,291	)		—			(7,291	)		—
Depreciation, depletion and amortization expense		(2,848	)		(490	)		(5,095	)		(1,436	)
Interest expense		(14	)		—			(14	)		—
Segment loss	$	(8,947	)	$	(2,837	)	$	(15,330	)	$	(5,495	)
Corporate and other:
Revenues	$	348		$	352		$	504		$	824
General and administrative		(5,050	)		(903	)		(27,624	)		(5,523	)
Gain on asset sales and disposal		—			—			—			3
Interest expense		(3,084	)		(2,846	)		(21,109	)		(8,446	)
Loss on early extinguishment of debt		(4,726	)		—			(4,726	)		—
Segment loss	$	(12,512	)	$	(3,397	)	$	(52,955	)	$	(13,142	)
Reconciliation of segment income (loss) to net loss:
Segment income (loss):
Atlas Resource	$	(560,854	)	$	1,885		$	(520,092	)	$	(27,558	)
Atlas Growth		(8,947	)		(2,837	)		(15,330	)	$	(5,495	)
Corporate and other		(12,512	)	$	(3,397	)	$	(52,955	)	$	(13,142	)
Net loss	$	(582,313	)	$	(4,349	)	$	(588,377	)	$	(46,195	)
Reconciliation of segment revenues to total revenues:
Segment revenues:
Atlas Resource	$	257,895		$	206,699		$	597,609		$	506,953
Atlas Growth		4,591			1,538			8,767		$	4,563
Corporate and other		348			352			504		$	824
Total revenues	$	262,834		$	208,589		$	606,880		$	512,340
Capital expenditures:
Atlas Resource	$	32,799		$	55,930		$	102,290		$	150,579
Atlas Growth		7,659			567			20,777			12,147
Corporate and other		—			—			—			—
Total capital expenditures	$	40,458		$	56,497		$	123,067		$	162,726

	September 30,		December 31,
	2015		2014
Balance sheet:
Goodwill:
Atlas Resource	$	13,639	$	13,639
Atlas Growth		—		—
Corporate and other		—		—
	$	13,639	$	13,639
Total assets:
Atlas Resource	$	2,096,758	$	2,791,553
Atlas Growth		171,522		190,161
Corporate and other		37,581		44,601
	$	2,305,861	$	3,026,315

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Debt (Term Loan Facilities) (Details)		1 Months Ended	9 Months Ended
	Aug. 10, 2015 USD ($)	Jun. 30, 2015 USD ($)	Sep. 30, 2015 USD ($)	Sep. 30, 2014 USD ($)	Feb. 27, 2015 USD ($)	Dec. 31, 2014 USD ($)
Debt Instrument [Line Items]
Line of Credit Facility, initiation date			Feb. 27, 2015
Term Loan Facilities, outstanding			$ 1,587,700,000			$ 1,542,600,000
Repayment of debt		$ 33,100,000
Repayments under credit facilities			$ 725,657,000	$ 794,125,000
Riverstone Credit Agreement
Debt Instrument [Line Items]
Line of Credit Facility interest rate description			Borrowings under the Riverstone Term Loan Facility bear interest, at the Company’s option, at either (i) LIBOR plus 7.0% (as used with respect to the Riverstone Term Loan Facility, “Eurodollar Loans”) or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 6.0% (as used with respect to the Riverstone Term Loan Facility, an “ABR Loan”). Interest is generally payable at interest payment periods selected by the Company for Eurodollar Loans and quarterly for ABR Loans.
Term Loan Facilities, outstanding			$ 82,700,000
Outstanding Term Facility, weighted average interest rate			8.00%
Liquidity Requirement			$ 5,000,000
Total leverage ratio			2.6
Asset coverage ratio			2.9
Minimum asset coverage ratio required after June twenty sixteen			2.00
Required repayment from net cash proceeds disposition casualty			100.00%
Required repayment from net cash proceeds equity debt issuance incurrence			100.00%
Riverstone Credit Agreement | Total Leverage Ratio 3 - 3.25
Debt Instrument [Line Items]
Required repayment of distributable cash			75.00%
Riverstone Credit Agreement | Total Leverage Ratio 2.75 -3
Debt Instrument [Line Items]
Required repayment of distributable cash			50.00%
Riverstone Credit Agreement | Total Leverage Ratio 2.5 - 2.75
Debt Instrument [Line Items]
Required repayment of distributable cash			25.00%
Riverstone Credit Agreement | Total Leverage Ratio Less Than 2.5
Debt Instrument [Line Items]
Required repayment of distributable cash			0.00%
Riverstone Credit Agreement | Maximum
Debt Instrument [Line Items]
Required total leverage ratio			4.00
Riverstone Credit Agreement | Maximum | Total Leverage Ratio Greater Than 3.5
Debt Instrument [Line Items]
Required repayment of distributable cash			100.00%
Riverstone Credit Agreement | Maximum | Total Leverage Ratio 3 - 3.25
Debt Instrument [Line Items]
Total leverage ratio			3.25
Riverstone Credit Agreement | Maximum | Total Leverage Ratio 2.75 -3
Debt Instrument [Line Items]
Total leverage ratio			3.00
Riverstone Credit Agreement | Maximum | Total Leverage Ratio 2.5 - 2.75
Debt Instrument [Line Items]
Total leverage ratio			2.75
Riverstone Credit Agreement | Maximum | Total Leverage Ratio Less Than 2.5
Debt Instrument [Line Items]
Total leverage ratio			2.50
Riverstone Credit Agreement | Minimum
Debt Instrument [Line Items]
Required total leverage ratio			1.75
Riverstone Credit Agreement | Minimum | Total Leverage Ratio Greater Than 3.5
Debt Instrument [Line Items]
Total leverage ratio			3.50
Riverstone Credit Agreement | Minimum | Total Leverage Ratio 3 - 3.25
Debt Instrument [Line Items]
Total leverage ratio			3.00
Riverstone Credit Agreement | Minimum | Total Leverage Ratio 2.75 -3
Debt Instrument [Line Items]
Total leverage ratio			2.75
Riverstone Credit Agreement | Minimum | Total Leverage Ratio 2.5 - 2.75
Debt Instrument [Line Items]
Total leverage ratio			2.50
Riverstone Credit Agreement | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	7.00%
Riverstone Credit Agreement | Federal Funds Effective Swap Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	0.50%
Riverstone Credit Agreement | One Month L I B O R
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	1.00%
Riverstone Credit Agreement | Base Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	2.00%
Riverstone Credit Agreement | Alternate Base Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	6.00%
Term loan facilities
Debt Instrument [Line Items]
Line of Credit Facility, initiation date			Aug. 10, 2015
Term loan initial balance			$ 82,700,000
Repayment of debt	$ 82,700,000
Recognized value ratio, description			Recognized Value Ratio (as defined in the Credit Agreement) was less than 2.00 to 1.00, the Company must have prepaid the Term Loan Facilities and any revolving loans outstanding in an aggregate principal amount necessary to achieve a Recognized Value Ratio of greater than 2.00 to 1.00; the Recognized Value Ratio was equal to the ratio of the Recognized Value
Net cash proceeds from disposition of assets			100.00%
Leverage ratio under condition one			3.75%
Leverage ratio under condition two			3.50%
Term loan facilities | Maximum
Debt Instrument [Line Items]
Recognized value ratio			2.00%
Term loan facilities | Minimum
Debt Instrument [Line Items]
Recognized value ratio			2.00%
Secured Term Loan Facility
Debt Instrument [Line Items]
Repayments under credit facilities			$ 150,000,000
Secured Term Loan Facility | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			7.50%
Secured Term Loan Facility | Federal Funds Effective Swap Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			0.50%
Secured Term Loan Facility | One Month L I B O R
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			1.00%
Secured Term Loan Facility | Base Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			2.00%
Secured Term Loan Facility | Alternate Base Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			6.50%
Credit Agreement
Debt Instrument [Line Items]
Line of Credit Facility interest rate description			Borrowings under the Term Loan Facilities bore interest, at the Company’s option, at either (i) LIBOR plus 7.5% (as used with respect to the Term Loan Facilities, “Eurodollar Loans”) or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, in each case plus 6.5% (as was used with the Term Loan Facilities, an “ABR Loan”).
Credit Agreement | Term loan facilities
Debt Instrument [Line Items]
Line of Credit Facility, expiration date			Aug. 31, 2020
Credit Agreement | Interim Term Loan Facility
Debt Instrument [Line Items]
Line of Credit Facility, expiration date			Aug. 27, 2015
Line of Credit Facility, aggregate principal amount					$ 30,000,000
Credit Agreement | Term A Loan Facility
Debt Instrument [Line Items]
Line of Credit Facility, expiration date			Feb. 26, 2016
Line of Credit Facility, aggregate principal amount					$ 97,800,000

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Operating Segment Information

9 Months Ended

Sep. 30, 2015

Segment Reporting [Abstract]

Operating Segment Information

NOTE 15—OPERATING SEGMENT INFORMATION

The Company’s operations include three reportable operating segments: ARP, AGP, and corporate and other. These operating segments reflect the way the Company manages its operations and makes business decisions. Corporate and other includes the Company’s equity investment in Lightfoot (see Note 1), as well as its general and administrative and interest expenses. Operating segment data for the periods indicated were as follows (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Atlas Resource:
Revenues	$	257,895		$	206,699		$	597,609		$	506,953
Operating costs and expenses		(80,486	)		(123,567	)		(244,126	)		(313,720	)
Depreciation, depletion and amortization expense		(40,463	)		(64,578	)		(125,948	)		(176,077	)
Asset impairment		(672,246	)		—			(672,246	)		—
Loss on asset sales and disposal		(362	)		(92	)		(276	)		(1,686	)
Interest expense		(25,192	)		(16,577	)		(75,105	)		(43,028	)
Segment income (loss)	$	(560,854	)	$	1,885		$	(520,092	)	$	(27,558	)
Atlas Growth:
Revenues	$	4,591		$	1,538		$	8,767		$	4,563
Operating costs and expenses		(3,385	)		(3,885	)		(11,697	)		(8,622	)
Asset impairment		(7,291	)		—			(7,291	)		—
Depreciation, depletion and amortization expense		(2,848	)		(490	)		(5,095	)		(1,436	)
Interest expense		(14	)		—			(14	)		—
Segment loss	$	(8,947	)	$	(2,837	)	$	(15,330	)	$	(5,495	)
Corporate and other:
Revenues	$	348		$	352		$	504		$	824
General and administrative		(5,050	)		(903	)		(27,624	)		(5,523	)
Gain on asset sales and disposal		—			—			—			3
Interest expense		(3,084	)		(2,846	)		(21,109	)		(8,446	)
Loss on early extinguishment of debt		(4,726	)		—			(4,726	)		—
Segment loss	$	(12,512	)	$	(3,397	)	$	(52,955	)	$	(13,142	)
Reconciliation of segment income (loss) to net loss:
Segment income (loss):
Atlas Resource	$	(560,854	)	$	1,885		$	(520,092	)	$	(27,558	)
Atlas Growth		(8,947	)		(2,837	)		(15,330	)	$	(5,495	)
Corporate and other		(12,512	)	$	(3,397	)	$	(52,955	)	$	(13,142	)
Net loss	$	(582,313	)	$	(4,349	)	$	(588,377	)	$	(46,195	)
Reconciliation of segment revenues to total revenues:
Segment revenues:
Atlas Resource	$	257,895		$	206,699		$	597,609		$	506,953
Atlas Growth		4,591			1,538			8,767		$	4,563
Corporate and other		348			352			504		$	824
Total revenues	$	262,834		$	208,589		$	606,880		$	512,340
Capital expenditures:
Atlas Resource	$	32,799		$	55,930		$	102,290		$	150,579
Atlas Growth		7,659			567			20,777			12,147
Corporate and other		—			—			—			—
Total capital expenditures	$	40,458		$	56,497		$	123,067		$	162,726

	September 30,		December 31,
	2015		2014
Balance sheet:
Goodwill:
Atlas Resource	$	13,639	$	13,639
Atlas Growth		—		—
Corporate and other		—		—
	$	13,639	$	13,639
Total assets:
Atlas Resource	$	2,096,758	$	2,791,553
Atlas Growth		171,522		190,161
Corporate and other		37,581		44,601
	$	2,305,861	$	3,026,315

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Property, Plant and Equipment (Tables)

9 Months Ended

Sep. 30, 2015

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):

	September 30,			December 31,			Estimated Useful Lives
	2015			2014			in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	469,684		$	455,401
Pre-development costs		8,664			7,378
Wells and related equipment		3,158,769			3,082,429
Total proved properties		3,637,117			3,545,208
Unproved properties		316,924			311,946
Support equipment		44,274			37,359
Total natural gas and oil properties		3,998,315			3,894,513
Pipelines, processing and compression facilities		59,598			49,547			2 – 40
Rights of way		829			830			20 – 40
Land, buildings and improvements		9,202			9,160			3 – 40
Other		18,318			17,936			3 – 10
		4,086,262			3,971,986
Less – accumulated depreciation, depletion and amortization		(2,426,904	)		(1,552,697	)
	$	1,659,358		$	2,419,289

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Asset Retirement Obligations (Reconciliation of Liability for Well Plugging and Abandonment Costs) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Asset Retirement Obligation Roll Forward Analysis Roll Forward
Asset retirement obligations, beginning of period	$ 110,937	$ 101,455	$ 108,101	$ 91,214
Liabilities incurred	80	336	296	8,283
Liabilities settled	(1)	(271)	(547)	(820)
Accretion expense	1,584	1,471	4,750	4,314
Asset retirement obligations, end of period	$ 112,600	$ 102,991	$ 112,600	$ 102,991

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Acquisitions (Rangely Acquisition Schedule of Assets Acquired and Liabilities Assumed) (Details) - Rangely Acquisition $ in Thousands	Jun. 30, 2014 USD ($)
Business Acquisition [Line Items]
Prepaid expenses and other	$ 4,041
Property, plant and equipment	405,416
Other assets, net	2,888
Total assets acquired	412,345
Accrued liabilities	2,117
Asset retirement obligation	1,305
Total liabilities assumed	3,422
Net assets acquired	$ 408,923

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COMBINED CONSOLIDATED STATEMENT OF UNITHOLDERS'/OWNER'S EQUITY (Unaudited) - 9 months ended Sep. 30, 2015 - USD ($) $ in Thousands	Total	Series A Preferred Equity	Common Unitholders' Equity	Owner's Equity	Accumulated Other Comprehensive Income	Non-Controlling Interest
Balance at Dec. 31, 2014	$ 915,215			$ 147,308	$ 54,008	$ 713,899
Net loss attributable to owner’s interest prior to the transfer of assets on February 27, 2015	(10,475)			(10,475)
Net distribution to owner’s interest prior to the transfer of assets on February 27, 2015	(19,758)			(19,758)
Net assets contributed by owner to Atlas Energy Group, LLC			$ 117,075	$ (117,075)
Net assets contributed by owner to Atlas Energy Group, LLC, units			26,010,766
Issuance of units , number of units		1,616,047
Issuance of units	266,330	$ 40,401	$ (401)			226,330
Distributions to non-controlling interests	(91,750)					(91,750)
Net issued and unissued units under incentive plan	7,357		2,757			4,600
Distribution equivalent rights paid on unissued units under incentive plans	(516)					(516)
Distribution payable	3,251	(336)				3,587
Gain on sale from subsidiary unit issuances			3,436			(3,436)
Distributions paid to preferred equity unitholders	(1,672)	(1,672)
Other comprehensive loss	(145,069)				(43,620)	(101,449)
Net loss	(577,902)		(157,491)			(420,411)
Balance at Sep. 30, 2015	$ 345,011	$ 38,393	$ (34,624)		$ 10,388	$ 330,854
Balance units at Sep. 30, 2015		1,616,047	26,010,766

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Property, Plant and Equipment

9 Months Ended

Sep. 30, 2015

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):

	September 30,			December 31,			Estimated Useful Lives
	2015			2014			in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	469,684		$	455,401
Pre-development costs		8,664			7,378
Wells and related equipment		3,158,769			3,082,429
Total proved properties		3,637,117			3,545,208
Unproved properties		316,924			311,946
Support equipment		44,274			37,359
Total natural gas and oil properties		3,998,315			3,894,513
Pipelines, processing and compression facilities		59,598			49,547			2 – 40
Rights of way		829			830			20 – 40
Land, buildings and improvements		9,202			9,160			3 – 40
Other		18,318			17,936			3 – 10
		4,086,262			3,971,986
Less – accumulated depreciation, depletion and amortization		(2,426,904	)		(1,552,697	)
	$	1,659,358		$	2,419,289

During the three and nine months ended September 30, 2015, the Company recognized $0.4 million and $0.3 million of gains on asset sales and disposals, respectively. During the three and nine months ended September 30, 2014, the Company recognized $0.1 million and $1.7 million, respectively, of losses on asset sales and disposals. The $1.7 million loss during the nine months ended September 30, 2014 was primarily related to ARP’s sale of producing wells in the Niobrara Shale in connection with the settlement of a third party farm out agreement.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate the Company’s subsidiaries will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. There were no impairments of unproved gas and oil properties recorded by the Company’s subsidiaries for the three and nine months ended September 30, 2015 and 2014.

Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. For the three and nine months ended September 30, 2015, the Company recognized $747.5 million of asset impairment primarily related to ARP’s oil and gas properties in the Barnett, Coal-bed Methane, Southern Appalachia, Marcellus and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices, reduced by $68.0 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairment and the related hedge gains are included in asset impairment expense in the Company’s combined consolidated results of operations for the three and nine months ended September 30, 2015. There were no asset impairments of proved gas and oil properties for the three and nine months ended September 30, 2014.

During the nine months ended September 30, 2015 and 2014, the Company recognized $12.0 million and $42.6 million, respectively, of non-cash property, plant and equipment additions, which were included within the changes in accounts payable and accrued liabilities on the Company’s combined consolidated statement of cash flows.

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Derivative Instruments (Fair Values of the Company's Derivative Instruments Table) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Assets	$ 358,548	$ 279,254
Gross Amounts of Recognized Liabilities	(7)	$ (468)
Atlas Growth Partners, L.P | Current portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Assets	399
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets	399
Atlas Growth Partners, L.P | Long-term portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Assets	163
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets	163
Atlas Growth Partners, L.P | Total derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Assets	562
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets	$ 562

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Operating Segment Information (Reconciliation of Segment Income (Loss) to Net Loss) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Segment Reporting Information [Line Items]
Net loss	$ (582,313)	$ (4,349)	$ (588,377)	$ (46,195)
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Net loss	(560,854)	1,885	(520,092)	(27,558)
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Net loss	(8,947)	(2,837)	(15,330)	(5,495)
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Net loss	$ (12,512)	$ (3,397)	$ (52,955)	$ (13,142)

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Cash Distributions - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions			1 Months Ended																				3 Months Ended								9 Months Ended
	Nov. 05, 2015	Oct. 28, 2015	Aug. 31, 2015	Jul. 31, 2015	Jun. 30, 2015	May. 31, 2015	Apr. 30, 2015	Mar. 31, 2015	Feb. 28, 2015	Jan. 31, 2015	Dec. 31, 2014	Nov. 30, 2014	Oct. 31, 2014	Sep. 30, 2014	Aug. 31, 2014	Jul. 31, 2014	Jun. 30, 2014	May. 31, 2014	Apr. 30, 2014	Mar. 31, 2014	Feb. 28, 2014	Jan. 31, 2014	Jun. 30, 2015	Mar. 31, 2015	Jan. 14, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 30, 2014	Dec. 31, 2013	Sep. 30, 2015
Preferred class E
Distribution Made To Limited Partner [Line Items]
Preferred Stock Liquidation Preference																															$ 25.00
Cash Distribution Declared | Subsequent Event
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Declaration Date		Oct. 28, 2015
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit		$ 0.1083
Cash Distribution Declared | Series A Preferred Units | Subsequent Event
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Declaration Date		Oct. 28, 2015
Distribution Made to Member or Limited Partner, Cash Distributions Paid		$ 0.3
Cash Distribution Paid | Subsequent Event
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid		$ 11.9
Distribution Made to Member or Limited Partner, Distribution Date		Nov. 13, 2015
Distribution Made to Member or Limited Partner, Date of Record		Nov. 09, 2015
Cash Distribution Paid | Subsequent Event | General Partner
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid		$ 0.2
Cash Distribution Paid | Series A Preferred Units | Subsequent Event
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Distribution Date		Nov. 13, 2015
Distribution Made to Member or Limited Partner, Date of Record		Nov. 09, 2015
Atlas Energy
Distribution Made To Limited Partner [Line Items]
Distribution Policy, Members or Limited Partners, Description																															The Company has a cash distribution policy under which it distributes, within 50 days following the end of each calendar quarter, all of its available cash (as defined in its limited liability company agreement) for that quarter to its unitholders.
Atlas Resource Partners, L.P.
Distribution Made To Limited Partner [Line Items]
Distribution Policy, Members or Limited Partners, Description																															ARP Cash Distributions. In January 2014, ARP’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program whereby it distributes all of its available cash (as defined in ARP’s partnership agreement) for that month to its unitholders within 45 days from the month end. Prior to that, ARP paid quarterly cash distributions within 45 days from the end of each calendar quarter.
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit			$ 0.1083	$ 0.1083	$ 0.1083	$ 0.1083	$ 0.1083	$ 0.1083	$ 0.1083	$ 0.1083	$ 0.1966	$ 0.1966	$ 0.1966	$ 0.1966	$ 0.1966	$ 0.1966	$ 0.1966	$ 0.1933	$ 0.1933	$ 0.1933	$ 0.1933	$ 0.1933
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. | Maximum
Distribution Made To Limited Partner [Line Items]
Percentage Of Distributions In Excess Of Targets																															48.00%
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
Atlas Resource Partners, L.P. | Preferred Class B | Minimum
Distribution Made To Limited Partner [Line Items]
Preferred Unit Regular Quarterly Cash Distributions Per Unit																															0.40
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. | Class C Preferred Units | Minimum
Distribution Made To Limited Partner [Line Items]
Preferred Unit Regular Quarterly Cash Distributions Per Unit																															0.51
Atlas Resource Partners, L.P. | Preferred class D
Distribution Made To Limited Partner [Line Items]
Preferred Unit Regular Quarterly Cash Distributions Per Unit																									$ 0.616927						0.5390625
Preferred Unit Regular Cash Distributions Per Unit																															$ 2.15625
Partners' Capital Account, Units, Percentage																															8.625%
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%
Atlas Resource Partners, L.P. | Cash Distribution Declared | Subsequent Event
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Declaration Date		Oct. 28, 2015
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit		$ 0.1083
Atlas Resource Partners, L.P. | Cash Distribution Paid | Subsequent Event
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid		$ 11.9
Distribution Made to Member or Limited Partner, Distribution Date		Nov. 13, 2015
Distribution Made to Member or Limited Partner, Date of Record		Nov. 09, 2015
Atlas Resource Partners, L.P. | Cash Distribution Paid | Subsequent Event | General Partner
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid		$ 0.2
Atlas Resource Partners, L.P. | Cash Distribution Paid | Subsequent Event | Preferred Limited Partners' Interest
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid		$ 0.6
Atlas Growth Partners, L.P
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit																							$ 0.1750	$ 0.1750		$ 0.1750	$ 0.1750	$ 0.1750	$ 0.1750	$ 0.1167
Quarterly cash distribution target																															$ 0.175
Yearly cash distribution target																															$ 0.70
Atlas Growth Partners, L.P | Cash Distribution Declared | Subsequent Event
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Declaration Date	Nov. 05, 2015
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit	$ 0.1750
Atlas Growth Partners, L.P | Cash Distribution Paid | Subsequent Event
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 4.2
Distribution Made to Member or Limited Partner, Distribution Date	Nov. 14, 2015
Distribution Made to Member or Limited Partner, Date of Record	Nov. 09, 2015
Atlas Growth Partners, L.P | Cash Distribution Paid | Subsequent Event | General Partner
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 0.1

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Other Assets (Tables)

9 Months Ended

Sep. 30, 2015

Other Assets Noncurrent Disclosure [Abstract]

Summary of Other Assets

The following is a summary of other assets at the dates indicated (in thousands):

		September 30,	December 31,
	2015		2014
Deferred financing costs, net of accumulated amortization of $39,945 and $20,675 at September 30, 2015 and December 31, 2014, respectively	$	49,299	$	46,120
Investment in Lightfoot		19,521		21,123
Rabbi Trust		5,378		3,925
Security deposits		231		229
ARP notes receivable		3,871		3,866
Other		5,154		5,348
	$	83,454	$	80,611

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Benefit Plans (2015 Unit Option Activity) (Details) - 2015 Unit Options - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights			The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Generally, unit options to be granted under the 2015 LTIP will vest over a designated period of time.
Years From Date Of Grant Unit Option Awards Expire			10 years
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months	0		0
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options	$ 0	$ 0	$ 0	$ 0

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Summary of Significant Accounting Policies (Schedule of Net Income Reconciliation) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Reconciliation Of Net Income [Line Items]
Net loss	$ (582,313)	$ (4,349)	$ (588,377)	$ (46,195)
Portion applicable to owner’s interest (period prior to the transfer of assets on February 27, 2015)		788	(10,475)	(12,367)
Net loss utilized in the calculation of net loss attributable to common unitholders per unit – basic and diluted	$ (143,353)		$ (159,837)
Antidilutive Phantom Unit Securities Excluded from Computation of Diluted Earnings Attributable to Common Unit Holders Outstanding Units	69,000		68,000
Continuing Operations
Reconciliation Of Net Income [Line Items]
Preferred unitholder dividends	$ (1,009)		$ (2,346)
Loss attributable to non-controlling interests	$ 439,969	5,137	420,411	33,828
Portion applicable to owner’s interest (period prior to the transfer of assets on February 27, 2015)		$ (788)	$ 10,475	$ 12,367

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Benefit Plans

9 Months Ended

Sep. 30, 2015

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Benefit Plans

NOTE 14—BENEFIT PLANS

2015 Long-Term Incentive Plan

The Board of Directors of the Company approved and adopted the Company’s 2015 Long-Term Incentive Plan (“2015 LTIP”) effective February 2015. The 2015 LTIP provides equity incentive awards to officers, employees and managing board members of the Company and its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for the Company. The 2015 LTIP is administered by a committee consisting of the Board or committee of the Board or board of an affiliate appointed by the Board (the “LTIP Committee”). Under the 2015 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 5,250,000 units. At September 30, 2015, the Company had 2,581,510 phantom units and unit options outstanding under the 2015 LTIP, with 2,668,490 phantom units and unit options available for grant.

In the case of awards held by eligible employees, following a “change in control”, as defined in the 2015 LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the 2015 LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full.

In connection with a change in control, the LTIP Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any Participant, subject to the terms of any award agreements and employment agreements to which the Company (or any affiliate) and any Participant are party, may take one or more of the following actions (with discretion to differentiate between individual Participants and awards for any reason):

· cause awards to be assumed or substituted by the surviving entity (or a parent, subsidiary or affiliate of such surviving entity);

· accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards shall vest (and, with respect to options, become exercisable) as to the units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction;

· provide for the payment of cash or other consideration to Participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards);

· terminate all or some awards upon the consummation of the change-in-control transaction, but only if the LTIP Committee provides for full vesting of awards immediately prior to the consummation of such transaction; and

· make such other modifications, adjustments or amendments to outstanding awards as the LTIP Committee deems necessary or appropriate.

2015 Phantom Units. A phantom unit entitles a Participant to receive a Company common unit or its then-Fair Market Value in cash or other securities or property, upon vesting of the phantom unit. In tandem with phantom unit grants, the LTIP Committee may grant Distribution Equivalent Rights (“DERs”), which are the right to receive cash, securities, or property per phantom unit in an amount equal to, and at the same time as, the cash distributions or other distributions of securities or property the Company makes on a common unit during the period such phantom unit is outstanding. Generally, phantom units to be granted to employees under the 2015 LTIP will vest over a designated period of time and phantom units granted to non-employee directors generally vest over a four year period, 25% per year. Of the phantom units outstanding under the 2015 LTIP at September 30, 2015, there are 846,372 units that will vest within the following twelve months. The director phantom units outstanding under the 2015 LTIP at September 30, 2015 include DERs. No amounts were paid during the three and nine months ended September 30, 2015 and 2014 with respect to DERs.

The following table sets forth the 2015 LTIP phantom unit activity for the periods indicated:

	Three Months Ended September 30,
	2015					2014
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value
Outstanding, beginning of period		2,764,210		$	6.50		—	$	—
Granted		10,500			4.20		—		—
Vested(1)		—			—		—		—
Forfeited		(193,200	)		6.43		—		—
Outstanding, end of period(2)(3)(4)		2,581,510		$	6.49		—	$	—
Non-cash compensation expense recognized (in thousands)				$	2,375			$	—

	Nine Months Ended September 30,
	2015					2014
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		—		$	—		—	$	—
Granted		2,774,710			6.49		—		—
Vested(1)		—			—		—		—
Forfeited		(193,200	)		6.43		—		—
Outstanding, end of period(2)(3)(4)		2,581,510		$	6.49		—	$	—
Non-cash compensation expense recognized (in thousands)				$	3,322			$	—

(1) No phantom unit awards vested during the three and nine months ended September 30, 2015 and 2014.

(2) The aggregate intrinsic value of phantom unit awards outstanding at September 30, 2015 was approximately $5.8 million.

(3) There was $0.1 million recognized as liabilities on the Company’s consolidated balance sheet at September 30, 2015 representing 68,910 units, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair value for these units was $9.07at September 30, 2015.

At September 30, 2015, the Company had approximately $13.0 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2015 LTIP based upon the fair value of the awardswhich is expected to be recognized over a weighted average period of 1.8 years.  

2015 Unit Options. A unit option entitles a Participant to receive a common unit of the Company upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option shall not be less than the fair market value of the Company’s common unit on the date of grant of the option. The LTIP Committee also determines how the exercise price may be paid by the Participant. The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Generally, unit options to be granted under the 2015 LTIP will vest over a designated period of time. There are no unit options outstanding under the 2015 LTIP at September 30, 2015. No cash was received from the exercise of options for the three and nine months ended September 30, 2015 and 2014, respectively.

Restricted Units

Restricted units are actual common units issued to a participant that are subject to vesting restrictions and evidenced in such manner as the LTIP Committee may deem appropriate, including book-entry registration or issuance of one or more unit certificates. Prior to or upon the grant of an award of restricted units, the LTIP Committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both. A holder of restricted units will have certain rights of holders of common units in general, including the right to vote the restricted units. However, during the period in which the restricted units are subject to vesting restrictions, the holder will not be permitted to sell, assign, transfer, pledge or otherwise encumber the restricted units. There were no restricted units granted, issued or outstanding through September 30, 2015.

Rabbi Trust

In 2011, the Company established an excess 401(k) plan relating to certain executives. In connection with the plan, the Company established a “rabbi” trust for the contributed amounts. At September 30, 2015 and December 31, 2014, the Company reflected $5.4 million and $3.9 million, respectively, related to the value of the rabbi trust within other assets, net on its combined consolidated balance sheets, and recorded corresponding liabilities of $5.4 million and $3.9 million as of those same dates within asset retirement obligations and other on its combined consolidated balance sheets. During the three and nine months ended September 30, 2015 and 2014, no distributions were made to participants related to the rabbi trust.

ARP Long-Term Incentive Plan

ARP’s 2012 Long-Term Incentive Plan (the “ARP LTIP”), effective March 2012, provides incentive awards to officers, employees and directors as well as employees of the Company and its affiliates, consultants and joint venture partners who perform services for ARP. The ARP LTIP is administered by the board of the Company, a committee of the board or the board (or committee of the board) of an affiliate (the “ARP LTIP Committee”). Under ARP’s 2012 LTIP, the ARP LTIP Committee may grant awards of phantom units, restricted units, or unit options for an aggregate of 2,900,000 common limited partner units of ARP. At September 30, 2015, ARP had 1,736,920 phantom units, restricted units and unit options outstanding under the ARP LTIP with 182,008 phantom units, restricted units and unit options available for grant. Share based payments to non-employee directors, which have a cash settlement option, are recognized within liabilities in the consolidated financial statements based upon their current fair market value.

In the case of awards held by eligible employees, following a “change in control”, as defined in the ARP LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the ARP LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full.

In connection with a change in control, the ARP LTIP Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which the Company, as general partner, (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason):

· cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity);

· accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to ARP’s common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction;

· provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards);

· terminate all or some awards upon the consummation of the change-in-control transaction, but only if the ARP LTIP Committee provides for full vesting of awards immediately prior to the consummation of such transaction; and

· make such other modifications, adjustments or amendments to outstanding awards or the new equity plan as the ARP LTIP Committee deems necessary or appropriate.

ARP Phantom Units. Phantom units represent rights to receive a common unit, an amount of cash or other securities or property based on the value of a common unit, or a combination of common units and cash or other securities or property upon vesting. Phantom units are subject to terms and conditions determined by the ARP LTIP Committee, which may include vesting restrictions. In tandem with phantom unit grants, the ARP LTIP Committee may grant DERs, which are the right to receive an amount in cash, securities, or other property equal to, and at the same time as, the cash distributions or other distributions of securities or other property made by ARP with respect to a common unit during the period that the underlying phantom unit is outstanding. Phantom units granted under the ARP LTIP generally will vest 25% of the original granted amount on each of the four anniversaries of the date of grant. Of the phantom units outstanding under the ARP LTIP at September 30, 2015, 162,496 units will vest within the following twelve months. All phantom units outstanding under the ARP LTIP at September 30, 2015 include DERs. During the three months ended September 30, 2015 and 2014, ARP paid $0.1 million and $0.5 million, respectively, with respect to the ARP LTIP’s DERs. During the nine months ended September 30, 2015 and 2014, ARP paid $0.6 million and $1.5 million, respectively, with respect to the ARP LTIP’s DERs. These amounts were recorded as reductions of equity on the Company’s combined consolidated balance sheets.

The following table sets forth the ARP LTIP phantom unit activity for the periods indicated:

	Three Months Ended September 30,
	2015					2014
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of period		411,257		$	21.10		901,207		$	23.29
Granted		—			—		9,400			19.85
Vested and issued(1)		(68,187	)		22.15		(115,797	)		24.54
Forfeited		(23,914	)		23.00		—			—
Outstanding, end of period(2)(3)		319,156		$	20.74		794,810		$	23.07
Vested and not yet issued(4)		3,125		$	21.02		5,412		$	25.25
Non-cash compensation expense recognized (in thousands)				$	375				$	1,647

	Nine Months Ended September 30,
	2015					2014
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		799,192		$	22.70		839,808		$	24.31
Granted		9,730			8.50		236,423			20.28
Vested and issued(1)		(457,727	)		23.75		(262,671	)		24.51
Forfeited		(32,039	)		23.01		(18,750	)		23.00
Outstanding, end of period(2)(3)		319,156		$	20.74		794,810		$	23.07
Vested and not yet issued(4)		3,125		$	21.02		5,412		$	25.25
Non-cash compensation expense recognized (in thousands)				$	3,692				$	4,968

(1) The intrinsic values of phantom unit awards vested and issued during the three months ended September 30, 2015 and 2014 were $0.3 million and $2.3 million, respectively, and $3.9 million and $5.2 million during the nine months ended September 30, 2015 and 2014, respectively.

(2) The aggregate intrinsic value for phantom unit awards outstanding at September 30, 2015was $0.9 million.

(3) There were approximately $16,000 and $0.1 million recognized as liabilities on the Company’s consolidated balance sheets at September 30, 2015 and December 31, 2014, respectively, representing 14,005 and 26,579units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were $13.39 and $21.16at September 30, 2015 and December 31, 2014, respectively. There was $0.2 million recognized as liabilities on the Company’s consolidated balance sheet at the period ended September 30, 2014 representing 29,035 units that participants may opt to settle in cash instead of units. The weighted average grant date fair value for these units was $21.09 at September 30, 2014.

(4) The intrinsic values of phantom unit awards vested, but not yet issued at September 30, 2015 and 2014 were approximately $2,000 and $0.1 million, respectively.

At September 30, 2015, ARP had approximately $2.3 million in unrecognized compensation expense related to unvested phantom units outstanding under the ARP LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 1.6 years.

ARP Unit Options. A unit option is the right to purchase an ARP common unit in the future at a predetermined price (the exercise price). The exercise price of each ARP unit option is determined by the ARP LTIP Committee and may be equal to or greater than the fair market value of ARP’s common unit on the date of grant of the option. The ARP LTIP Committee will determine the vesting and exercise restrictions applicable to an ARP award of options, if any, and the method by which the exercise price may be paid by the participant. Unit option awards expire 10 years from the date of grant. Unit options granted under the ARP LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. There were 83,163 unit options outstanding under the ARP LTIP at September 30, 2015 that will vest within the following twelve months. No cash was received from the exercise of options for the three and nine months ended September 30, 2015 and 2014.

The following table sets forth the ARP LTIP unit option activity for the periods indicated:

	Three Months Ended September 30,
	2015						2014
	Number of Unit Options			Weighted Average Exercise Price			Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of period		1,452,800		$	24.66			1,468,925		$	24.66
Granted		—			—			—			—
Exercised (1)		—			—			—			—
Forfeited		(35,036	)		24.67			(3,750	)		24.67
Outstanding, end of period(2)(3)		1,417,764		$	24.66			1,465,175		$	24.66
Options exercisable, end of period(4)		1,332,976		$	24.67			732,025		$	24.67
Non-cash compensation expense recognized (in thousands)				$	(87	)				$	342

	Nine Months Ended September 30,
	2015					2014
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of year		1,458,300		$	24.66		1,482,675		$	24.66
Granted		—			—		—			—
Exercised (1)		—			—		—			—
Forfeited		(40,536	)		24.68		(17,500	)		24.46
Outstanding, end of period(2)(3)		1,417,764		$	24.66		1,465,175		$	24.66
Options exercisable, end of period(4)		1,332,976		$	24.67		732,025		$	24.67
Non-cash compensation expense recognized (in thousands)				$	805				$	1,374

(1) No options were exercised during the three and nine months ended September 30, 2015 and 2014.

(2) The weighted average remaining contractual life for outstanding options at September 30, 2015 was 6.6 years.

(3) There were no aggregate intrinsic values of options outstanding at September 30, 2015 and 2014.

(4) The weighted average remaining contractual life for exercisable options at September 30, 2015 was 6.6 years. There were no intrinsic values for options exercisable at September 30, 2015 and 2014.

At September 30, 2015, ARP had approximately $0.1 million in unrecognized compensation expense related to unvested unit options outstanding under the ARP LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 0.6 years. ARP used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted.

Restricted Units

Restricted units are actual common units issued to a participant that are subject to vesting restrictions and evidenced in such manner as the ARP LTIP Committee may deem appropriate, including book-entry registration or issuance of one or more unit certificates. Prior to or upon the grant of an award of restricted units, the ARP LTIP Committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both. A holder of restricted units will have certain rights of holders of common units in general, including the right to vote the restricted units. However, during the period in which the restricted units are subject to vesting restrictions, the holder will not be permitted to sell, assign, transfer, pledge or otherwise encumber the restricted units. There were no restricted units granted, issued or outstanding through September 30, 2015.