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, 2012

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: 001-35317

ATLAS RESOURCE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware	45-3591625
(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 office)	(Zip code)

Registrant’s telephone number, including area code: (800) 251-0171

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	x
Non-accelerated filer	¨  (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 limited partner units of the registrant on November 1, 2012 was 39,911,497.

ATLAS RESOURCE PARTNERS, L.P.

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

TABLE OF CONTENTS

		PAGE
PART I.        FINANCIAL INFORMATION			3
Item 1.	Financial Statements (Unaudited)		3
	Consolidated Combined Balance Sheets as of September 30, 2012 and December 31, 2011		3
	Consolidated Combined Statements of Operations for the Three and Nine Months Ended September 30, 2012 and 2011		4
	Consolidated Combined Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2012 and 2011		5
	Consolidated Combined Statement of Partners’ Capital/Equity for the Nine Months Ended September 30, 2012		6
	Consolidated Combined Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011		7
	Notes to Consolidated Combined Financial Statements		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		35
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		53
Item 4.	Controls and Procedures		55
PART II.        OTHER INFORMATION			57
Item 1.	Legal Proceedings		57
Item 1A.	Risk Factors		57
Item 6.	Exhibits		62
SIGNATURES			66

2

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED COMBINED BALANCE SHEETS

(in thousands)

(Unaudited)

	September 30, 2012		December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	24,266	$	54,708
Accounts receivable		29,743		19,319
Current portion of derivative asset		6,518		13,801
Subscriptions receivable		8,495		34,455
Prepaid expenses and other		7,107		7,677
Total current assets		76,129		129,960
Property, plant and equipment, net		1,016,110		520,883
Goodwill and intangible assets, net		33,149		33,285
Long-term derivative asset		5,144		16,128
Other assets, net		8,410		857
	$	1,138,942	$	701,113
LIABILITIES AND PARTNERS’ CAPITAL/EQUITY
Current liabilities:
Accounts payable	$	42,831	$	36,731
Liabilities associated with drilling contracts		5,550		71,719
Current portion of derivative liability		280		—
Current portion of derivative payable to Drilling Partnerships		13,363		20,900
Accrued well drilling and completion costs		50,169		17,585
Accrued liabilities		33,039		35,952
Total current liabilities		145,232		182,887
Long-term debt		222,000		—
Long-term derivative liability		4,051		—
Long-term derivative payable to Drilling Partnerships		4,483		15,272
Asset retirement obligations and other		54,428		45,779
Commitments and contingencies
Partners’ Capital/Equity:
General partner’s interest		7,646		—
Preferred limited partners’ interests		96,110		—
Common limited partners’ interests		596,348		—
Equity		—		427,246
Accumulated other comprehensive income		8,644		29,929
Total partners’ capital/equity		708,748		457,175
	$	1,138,942	$	701,113

See accompanying notes to consolidated combined financial statements.

3

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED COMBINED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Revenues:
Gas and oil production	$	24,699		$	16,305		$	61,323		$	51,654
Well construction and completion		36,317			35,657			92,277			64,336
Gathering and processing		4,134			4,431			10,311			14,048
Administration and oversight		4,440			2,337			8,586			5,073
Well services		5,086			4,910			15,344			15,051
Other, net		67			(50	)		(4,952	)		(115	)
Total revenues		74,743			63,590			182,889			150,047
Costs and expenses:
Gas and oil production		7,295			3,990			16,247			11,953
Well construction and completion		31,581			30,449			79,882			54,754
Gathering and processing		4,558			4,880			13,185			16,377
Well services		2,232			2,043			7,076			6,077
General and administrative		16,147			4,757			48,427			12,275
Chevron transaction expense		7,670			—			7,670			—
Depreciation, depletion and amortization		13,918			8,071			33,848			24,019
Total costs and expenses		83,401			54,190			206,335			125,455
Operating income (loss)		(8,658	)		9,400			(23,446	)		24,592
Interest expense		(1,423	)		—			(2,529	)		—
Gain (loss) on asset sales and disposal		2			—			(7,019	)		48
Net income (loss)		(10,079	)		9,400			(32,994	)		24,640
Preferred limited partner dividends		(1,221	)		—			(1,221	)		—
Net income (loss) attributable to owner’s interest, common limited partners and the general partner	$	(11,300	)	$	9,400		$	(34,215	)	$	24,640
Allocation of net income (loss):
Portion applicable to owner’s interest (period prior to the transfer of assets on March 5, 2012)	$	—		$	9,400		$	250		$	24,640
Portion applicable to common limited partners and the general partner’s interests (period subsequent to the transfer of assets on March 5, 2012)		(11,300	)		—			(34,465	)		—
Net income (loss) attributable to owner’s interest, common limited partners and the general partner	$	(11,300	)	$	9,400		$	(34,215	)	$	24,640
Allocation of net loss attributable to common limited partners and the general partner:
Common limited partners’ interest	$	(11,074	)	$	—		$	(33,776	)	$	—
General partner’s interest		(226	)		—			(689	)		—
Net loss attributable to common limited partners and the general partner	$	(11,300	)	$	—		$	(34,465	)	$	—
Net loss attributable to common limited partners per unit:
Basic	$	(0.32	)	$	—		$	(1.06	)	$	—
Diluted	$	(0.32	)	$	—		$	(1.06	)	$	—
Weighted average common limited partner units outstanding:
Basic		35,068			—			31,865			—
Diluted		35,068			—			31,865			—

See accompanying notes to consolidated combined financial statements.

4

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED COMBINED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Net income (loss)	$	(10,079	)	$	9,400		$	(32,994	)	$	24,640
Income attributable to owner’s interest (period prior to the transfer of assets on March 5, 2012)		—			(9,400	)		(250	)		(24,640	)
Preferred limited partner dividends		(1,221	)		—			(1,221	)		—
Net loss attributable to common limited partners and the general partner		(11,300	)		—			(34,465	)		—
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges		(19,487	)		10,884			(5,832	)		17,733
Less: reclassification adjustment for realized gains in net income (loss)		(6,114	)		(279	)		(15,453	)		(9,588	)
Total other comprehensive income (loss)		(25,601	)		10,605			(21,285	)		8,145
Comprehensive income (loss) attributable to owner’s interest, common limited partners and the general partner	$	(36,901	)	$	20,005		$	(55,500	)	$	32,785
Comprehensive income (loss) attributable to owner’s interest (period prior to the transfer of assets on March 5, 2012)	$	—		$	20,005		$	(4,722	)	$	32,785
Comprehensive income (loss) attributable to common limited partners and the general partner’s interests (period subsequent to the transfer of assets on March 5, 2012)	$	(36,901	)	$	—		$	(50,778	)	$	—

See accompanying notes to consolidated combined financial statements.

5

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED COMBINED STATEMENT OF PARTNERS’ CAPITAL/EQUITY

(in thousands, except unit data)

(Unaudited)

	General Partners’ Interest					Preferred Limited Partners’ Interests				Common Limited Partners’ Interests								Accumulated Other Comprehensive Income			Total Partners’ Capital/ Equity
	Class A Units		Amount			Units		Amount		Units		Amount			Equity
Balance at January 1, 2012		—	$	—			—	$	—		—	$	—		$	427,246		$	29,929		$	457,175
Net income attributable to owner’s interest prior to the transfer of assets on March 5, 2012		—		—			—		—		—		—			250			—			250
Net investment from owner’s interest prior to the transfer of assets on March 5, 2012		—		—			—		—		—		—			5,625			—			5,625
Net assets contributed by owner to Atlas Resource Partners, L.P.		534,694		8,662			—		—		26,200,114		424,459			(433,121	)		—			—
Issuance of units		279,826		—			3,841,719		94,889		9,869,664		214,192			—			—			309,081
Unissued common units under incentive plans		—		—			—		—		—		7,833			—			—			7,833
Distributions paid to common limited partners and the general partner		—		(327	)		—		—		—		(16,035	)		—			—			(16,362	)
Distribution equivalent rights paid on unissued units under incentive plan		—		—			—		—		—		(325	)		—			—			(325	)
Net income (loss) attributable to common and preferred limited partners and the general partner subsequent to the transfer of assets on March 5, 2012		—		(689	)		—		1,221		—		(33,776	)		—			—			(33,244	)
Other comprehensive income (loss)		—		—			—		—		—		—			—			(21,285	)		(21,285	)
Balance at September 30, 2012		814,520	$	7,646			3,841,719	$	96,110		36,069,778	$	596,348		$	—		$	8,644		$	708,748

See accompanying notes to consolidated combined financial statements.

6

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED COMBINED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Nine Months Ended September 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(32,994	)	$	24,640
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		33,848			24,019
Non-cash (gain) loss on derivative value, net		(17,013	)		43,472
(Gain)/loss on asset sales and disposal		7,019			(48	)
Non-cash compensation expense		7,856			—
Amortization of deferred financing costs		1,028			—
Changes in operating assets and liabilities:
Accounts receivable and prepaid expenses and other		16,105			(6,533	)
Accounts payable and accrued liabilities		(30,836	)		(44,003	)
Net cash provided by (used in) operating activities		(14,987	)		41,547
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(73,379	)		(36,270	)
Net cash paid for acquisitions		(264,558	)		—
Other		69			—
Net cash used in investing activities		(337,868	)		(36,270	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities		264,000			—
Repayments under credit facilities		(42,000	)		—
Net investment from owners		5,625			54,709
Distributions paid to unit holders		(16,362	)		—
Net proceeds from issuance of common limited partner units		119,389			—
Deferred financing costs and other		(8,239	)		—
Net cash provided by financing activities		322,413			54,709
Net change in cash and cash equivalents		(30,442	)		59,986
Cash and cash equivalents, beginning of year		54,708			—
Cash and cash equivalents, end of period	$	24,266		$	59,986

See accompanying notes to consolidated combined financial statements.

7

ATLAS RESOURCE PARTNERS, L.P.

NOTES TO CONSOLIDATED COMBINED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION

Atlas Resource Partners, L.P. (the “Partnership”) is a publicly traded Delaware master-limited partnership (NYSE: ARP) and an independent developer and producer of natural gas and oil with operations in basins across the United States. The Partnership sponsors and manages tax-advantaged investment partnerships, in which it coinvests, to finance a portion of its natural gas and oil production activities. At September 30, 2012, Atlas Energy, L.P. (“ATLS”), a publicly traded master-limited partnership (NYSE: ATLS), owned 100% of the general partner Class A units and incentive distribution rights through which it manages and effectively controls the Partnership, and an approximate 51.5% limited partnership interest (20,960,000 limited partner units) in the Partnership.

The Partnership was formed in October 2011 to own and operate substantially all of ATLS’ exploration and production assets (the “Atlas Energy E&P Operations”), which were transferred to the Partnership on March 5, 2012. In February 2012, the board of ATLS’ general partner approved the distribution of approximately 5.24 million of the Partnership’s common units which were distributed on March 13, 2012 to ATLS’ unitholders using a ratio of 0.1021 of the Partnership’s limited partner units for each of ATLS’ common units owned on the record date of February 28, 2012. The distribution of the Partnership’s limited partner units represented approximately 20% of the common limited partner units outstanding.

The accompanying consolidated combined financial statements, which are unaudited except that the balance sheet at December 31, 2011 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 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 Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated combined financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2011. Certain amounts in the prior year’s combined financial statements have been reclassified to conform to the current year presentation. The results of operations for the three and nine months ended September 30, 2012 may not necessarily be indicative of the results of operations for the full year ending December 31, 2012.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Combination

The Partnership’s consolidated combined balance sheet at September 30, 2012, the statement of operations for the three months ended September 30, 2012, and the portion of the consolidated combined statement of operations for the nine months ended September 30, 2012 subsequent to the transfer of assets on March 5, 2012 include the accounts of the Partnership and its wholly-owned subsidiaries. The Partnership’s combined balance sheet at December 31, 2011, the portion of the consolidated combined statements of operations for the nine months ended September 30, 2012 prior to the transfer of assets on March 5, 2012 and the combined statement of operations for the three and nine months ended September 30, 2011 were derived from the separate records maintained by ATLS and may not necessarily be indicative of the conditions that would have existed if the Partnership had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all of the various entities comprising Atlas E&P Operations prior to the date of transfer, ATLS’ net investment is shown as equity in the combined 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 consolidated combined balance sheets and related consolidated combined statements of operations. Such estimates included allocations made from the historical accounting records of ATLS, based on management’s best estimates, in order to derive the financial statements of the Partnership for the periods presented. Actual balances and results could be different from those estimates. Transactions between the Partnership and other ATLS operations have been identified in the consolidated combined statements as transactions between affiliates, where applicable.

On February 17, 2011, ATLS acquired certain natural gas and oil properties, the partnership management business, and other assets (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of ATLS’ general partner (see Note 3). Management of ATLS determined that the acquisition of the Transferred Business constituted a transaction between entities under common control. In comparison to the acquisition method of accounting, whereby the purchase price for the

8

asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business based upon their fair values with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital/equity on the Partnership’s combined balance sheet. Also, in comparison to the acquisition method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in the Partnership’s consolidated combined financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect to the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, the Partnership reflected the impact of the acquisition of the Transferred Business on its consolidated combined financial statements in the following manner:

• Recognized the assets acquired and liabilities assumed from the Transferred Business at their historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital/equity;

• Retrospectively adjusted its consolidated combined financial statements for any date prior to February 17, 2011, the date of acquisition, to reflect its results on a consolidated combined basis with the results of the Transferred Business as of or at the beginning of the respective period; and

• Adjusted the presentation of its consolidated combined statements of operations for any date prior to February 17, 2011 to reflect the results of operations attributable to the Transferred Business as a reduction of net income (loss) to determine income (loss) attributable to common limited partners and the general partner. The Transferred Business’ historical financial statements prior to the date of acquisition reflect an allocation of general and administrative expenses determined by AEI to the underlying business segments, including the Transferred Business. The Partnership has reviewed AEI’s general and administrative expense allocation methodology, which is based on the relative total assets of AEI and the Transferred Business, for the Transferred Business’ historical financial statements prior to the date of acquisition and believes the methodology is reasonable and reflects the approximate general and administrative costs of its underlying business segments.

In accordance with established practice in the oil and gas industry, the Partnership’s consolidated combined financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the energy partnerships in which the Partnership has an interest (“the Drilling Partnerships”). Such interests typically range from 20% to 41%. The Partnership’s financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships. Rather, the Partnership calculates these items specific to its own economics as further explained under the heading “Property, Plant and Equipment” elsewhere within this note.

Use of Estimates

The preparation of the Partnership’s consolidated combined financial statements in conformity with accounting principles generally accepted in the United States 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 Partnership’s consolidated combined financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s consolidated combined 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. Such estimates included estimated allocations made from the historical accounting records of AEI in order to derive the historical financial statements of the Partnership. 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, 2012 and 2011 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).

9

Receivables

Accounts receivable on the consolidated combined balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the Partnership’s management performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the Partnership’s customers’ credit information. The Partnership extends credit on sales on an unsecured basis to many of its customers. At September 30, 2012 and December 31, 2011, the Partnership had recorded no allowance for uncollectible accounts receivable on its consolidated combined balance sheets.

Inventory

The Partnership had $4.0 million and $3.9 million of inventory at September 30, 2012 and December 31, 2011, respectively, which were included within prepaid expenses and other current assets on the Partnership’s consolidated combined balance sheets. The Partnership values inventories at the lower of cost or market. The Partnership’s inventories, which consist of 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 which 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 which 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 Partnership’s results of operations.

The Partnership follows 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 (“NGLs”) 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 Partnership’s 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 the Partnership’s costs of property interests in proportionately consolidated investment partnerships, joint venture wells, wells drilled solely by the Partnership 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 Partnership’s consolidated combined statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its consolidated combined balance sheets. Upon the Partnership’s 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 Partnership’s consolidated combined 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 Partnership reviews its 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 the Partnership’s 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

10

Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Partnership estimates 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, the Partnership’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 the Partnership’s actual capital contributions, an additional carried interest (generally 5% to 10%), a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

The Partnership’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to the Partnership their proportionate share of these expenses plus a profit margin. These assumptions could result in the Partnership’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 Partnership cannot predict what reserve revisions may be required in future periods.

The Partnership’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 the Partnership sponsors and owns an interest in but does not control. The Partnership’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which the Partnership may be unable to recover due to the Drilling Partnerships’ legal structure. The Partnership may have to pay additional consideration in the future as a well or Drilling Partnership becomes uneconomic under the terms of the Drilling Partnership’s agreement in order to recover these excess reserves and to acquire any additional residual interests in the wells held by other partnership investors. The acquisition of any well interest from the Drilling Partnership by the Partnership is governed under the Drilling Partnership’s agreement and in general, must be at fair market value supported by an appraisal of an independent expert selected by the Partnership.

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 Partnership 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 Partnership for the three and nine months ended September 30, 2012 and 2011.

Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2011, the Partnership recognized $7.0 million of asset impairment related to gas and oil properties within property, plant and equipment on its combined balance sheet for its shallow natural gas wells in the Niobrara Shale. This impairment related to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2011. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement. There were no impairments of proved gas and oil properties recorded by the Partnership for the three and nine months ended September 30, 2012 and 2011.

Capitalized Interest

The Partnership 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 rate used to capitalize interest on combined borrowed funds by the Partnership was 3.1% and 3.5% for the three and nine months ended September 30, 2012, respectively, and 2.4% for the nine months ended September 30, 2011. The aggregate amounts of interest capitalized by the Partnership were $0.6 million and $1.0 million for the three and nine months ended September 30, 2012, respectively, and $0.1 million for the nine months ended September 30, 2011. There was no interest capitalized during the three months ended September 30, 2011.

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Intangible Assets

The Partnership recorded its intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. The Partnership 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, 2012 and December 31, 2011 (in thousands):

	September 30, 2012			December 31, 2011			Estimated Useful Lives In Years
Gross Carrying Amount	$	14,344		$	14,344		13
Accumulated Amortization		(12,979	)		(12,843	)
Net Carrying Amount	$	1,365		$	1,501

Amortization expense on intangible assets was $45,000 and $0.2 million for the three months ended September 30, 2012 and 2011, respectively, and $0.1 million and $0.5 million for the nine months ended September 30, 2012 and 2011, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2012 – $0.2 million; 2013 – $0.2 million; 2014 – $0.1 million; 2015 – $0.1 million; and 2016 – $0.1 million.

Goodwill

At September 30, 2012 and December 31, 2011, the Partnership had $31.8 million of goodwill recorded in connection with its prior consummated acquisitions. There were no changes in the carrying amount of goodwill for the three and nine months ended September 30, 2012 and 2011.

The Partnership 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, the Partnership’s management must apply judgment in determining the estimated fair value of these reporting units. The Partnership’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 Partnership’s assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to the Partnership’s 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 the Partnership’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, the Partnership’s management 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 the Partnership’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in the Partnership’s industry to determine whether those valuations appear reasonable in management’s judgment. Management will continue to evaluate goodwill at least annually or when impairment indicators arise. During the three and nine months ended September 30, 2012 and 2011, no impairment indicators arose and no goodwill impairments were recognized by the Partnership.

Derivative Instruments

The Partnership enters into certain financial contracts to manage its exposure to movement in commodity prices and interest rates (see Note 8). The derivative instruments recorded in the consolidated combined balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s consolidated combined statements of operations unless specific hedge accounting criteria are met.

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Asset Retirement Obligations

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 6). The Partnership recognizes a liability for its 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 Partnership also considers the estimated salvage value in the calculation of depreciation, depletion and amortization.

Stock-Based Compensation

The Partnership recognizes all share-based payments to employees, including grants of employee stock options, in the consolidated combined financial statements based on their fair values (see Note 14).

Other Assets

The Partnership had $8.4 million and $0.9 million of other assets at September 30, 2012 and December 31, 2011, respectively, which were included on the Partnership’s consolidated combined balance sheets. Of the $8.4 million of other assets at September 30, 2012, $6.9 million related to deferred financing costs (net of $1.6 million of accumulated amortization) associated with the Partnership’s credit facility, which are recorded at cost and amortized over the term of the respective debt agreement. The Partnership recorded $0.5 million and $1.0 million of amortization of deferred financing costs during the three and nine months ended September 30, 2012, respectively.

Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of the general partner’s and the preferred unitholders’ interests, by the weighted average number of common limited partner units outstanding during the period. Net income (loss) attributable to common limited partners is determined by deducting net income attributable to participating securities, if applicable, and net income (loss) attributable to the General Partner’s Class A units. The General Partner’s interest in net income (loss) is calculated on a quarterly basis based upon its Class A units and incentive distributions to be distributed for the quarter (see Note 13), with a priority allocation of net income to the General Partner’s incentive distributions, if any, in accordance with the partnership agreement, and the remaining net income (loss) allocated with respect to the General Partner’s and limited partners’ ownership interests.

Prior to the transfer of assets to the Partnership on March 5, 2012 (see Note 1), the Partnership had no common units or General Partner Class A units outstanding. In addition, the Partnership had no net income (loss) attributable to common limited partners and the general partner prior to March 5, 2012.

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

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. Phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plan (see Note 14), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights would result in a non-contingent transfer of value each time the Partnership 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.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Net income (loss)	$	(10,079	)	$	9,400		$	(32,994	)	$	24,640
Income applicable to owner’s interest (period prior to transfer of assets on March 5, 2012)		—			(9,400	)		(250	)		(24,640	)
Preferred limited partner dividends		(1,221	)		—			(1,221	)		—
Net loss attributable to common limited partners and the general partner		(11,300	)		—			(34,465	)		—
Less: General partner’s interest		226			—			689			—
Net loss attributable to common limited partners		(11,074	)		—			(33,776	)		—
Less: Net income attributable to participating securities – phantom units		—			—			—			—
Net loss utilized in the calculation of net loss attributable to common limited partners per unit	$	(11,074	)	$	—		$	(33,776	)	$	—

Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, as calculated by the treasury stock method. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Partnership’s long-term incentive plan (see Note 14).

The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands):

	Three Months  Ended September 30,				Nine Months  Ended September 30,
	2012		2011		2012		2011
Weighted average number of common limited partner units – basic		35,068		—		31,865		—
Add effect of dilutive incentive awards(1)		—		—		—		—
Add effect of dilutive convertible preferred limited partner units(1)		—		—		—		—
Weighted average number of common limited partner units – diluted		35,068		—		31,865		—

⁽¹⁾  For the three and nine months ended September 30, 2012, approximately 898,000 and 575,000 phantom units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. For the three and nine months ended September 30, 2012, potential common limited partner units issuable upon conversion of the Partnership’s Class B preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive.

Revenue Recognition

Certain energy activities are conducted by the Partnership through, and a portion of its revenues are attributable to, the Drilling Partnerships. The Partnership contracts with the Drilling Partnerships to drill partnership wells. The contracts require that the Drilling Partnerships must pay the Partnership the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed between 60 and 270 days. On an uncompleted contract, the Partnership classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Liabilities Associated with Drilling Contracts” on the Partnership’s consolidated combined balance sheets. The Partnership recognizes well services revenues at the time the services are performed. The Partnership is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned, which are included in administration and oversight revenues within its consolidated combined statements of operations.

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The Partnership generally sells natural gas, crude oil and NGLs at prevailing market prices. Generally, the Partnership’s 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 2 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 Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records 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” accounting policy for further description). The Partnership had unbilled revenues at September 30, 2012 and December 31, 2011 of $22.4 million and $12.6 million, respectively, which were included in accounts receivable within the Partnership’s consolidated combined 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 accounting principles generally accepted in the United States, 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)” and for the Partnership include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.

Recently Adopted Accounting Standards

In October 2012, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2012-04, Technical Corrections and Improvements (“Update 2012-04”). The amendments in this update are presented in two sections – Technical Corrections and Improvements (Section A) and Conforming Amendments Related to Fair Value Measurements (Section B). The amendments in Section A correct differences between source literature and the Accounting Standards Codification (“ASC”), provide clarification of guidance through updating wording, correcting references, or a combination of both, and move guidance from its current location in the ASC to a more appropriate location. The amendments in Section B are intended to conform terminology and clarify certain guidance in various topics of the ASC to fully reflect the fair value measurement and disclosure requirements of Topic 820. The amendments do not introduce any new fair value measurements and are not intended to result in a change in the application of the requirements in Topic 820 or fundamentally change other principles of U.S. GAAP. The amendments in Update 2012-04 that do not have transition guidance are effective upon issuance and those amendments that are subject to the transition guidance will be effective for fiscal periods beginning after December 15, 2012. The Partnership adopted the requirements of Update 2012-04 on September 30, 2012, and it did not have a material impact on its financial position, results of operations or related disclosures. The Partnership also believes the transition guidance will have no impact on its financial position, results of operations or related disclosures upon its effective date of January 1, 2013.

In August 2012, the FASB issued ASU 2012-03, Technical Amendments and Corrections to SEC Sections: Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 114, Technical Amendments Pursuant to SEC Release No. 33-9250, and Corrections Related to FASB Accounting Standards Update 2010-22 (SEC Update) (“Update 2012-03”). Update 2012-03 codified amendments and corrections to the ASC for various Securities and Exchange Commission (“SEC”) paragraphs pursuant or related to 1) the issuance of Staff Accounting Bulletin (“SAB”) 114; 2) the SEC’s Final Rule, Technical Amendments to Commission Rules and Forms Related to the FASB’s Accounting Standards Codification, Release No. 3350-9250, 34-65052, and IC-29748 August 8, 2011; 3) ASU 2010-22, Accounting for Various Topics – Technical Corrections to SEC Paragraphs (SEC Update); and 4) other various Status Sections. The Partnership adopted the requirements of Update 2012-03 on September 30, 2012, and it did not have a material impact on its financial position, results of operations or related disclosures.

In December 2011, the FASB issued ASU 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“Update 2011-12”). The amendments in this update effectively defer the implementation of the changes made in Update 2011-05, Comprehensive Income (Topic 220): Presentation of

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Comprehensive Income (“Update 2011-05”), related to the presentation of reclassification adjustments out of accumulated other comprehensive income. Under Update 2011-05 which was issued by the FASB in June 2011, entities are provided the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. Under each methodology, an entity is required to present each component of net income along with a total net income, each component of other comprehensive income and a total amount for comprehensive income. Update 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. As a result of Update 2011-12, entities are required to disclose reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect prior to Update 2011-05. All other requirements in Update 2011-05 are not affected by Update 2011-12. These requirements are effective for interim and annual reporting periods beginning after December 15, 2011. Accordingly, entities are not required to comply with presentation requirements of Update 2011-05 related to the disclosure of reclassifications out of accumulated other comprehensive income. The Partnership included consolidated combined statements of comprehensive income (loss) within this Form 10-Q upon the adoption of these ASUs on January 1, 2012. The adoption had no material impact on the Partnership’s financial condition or results of operations.

In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosure about Offsetting Assets and Liabilities (“Update 2011-11”). The amendments in this update require an entity to disclose both gross and net information about both financial and derivative instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the statement of financial position. An entity shall disclose at the end of a reporting period certain quantitative information separately for assets and liabilities that are within the scope of Update 2011-11, as well as provide a description of the rights of setoff associated with an entity’s recognized assets and recognized liabilities subject to an enforceable master netting arrangement or similar agreement. Entities are required to implement the amendments for interim and annual reporting periods beginning after January 1, 2013 and such amendments shall be applied retrospectively for any period presented that begins before the date of initial application. The Partnership has elected to early adopt these requirements and updated its disclosures to meet these requirements effective January 1, 2012 (see Note 8). The adoption had no material impact on the Partnership’s financial position or results of operations.

In September 2011, the FASB issued ASU 2011-08, Intangibles-Goodwill and Other (Topic 350): Testing Goodwill for Impairment (“Update 2011-08”). The amendments in Update 2011-08 allow an entity to first assess qualitative factors in determining the necessity of performing the two-step quantitative goodwill impairment test. If, after assessing qualitative factors, an entity determines it is not likely that the fair value of a reporting unit is less than its carrying amount, performing the two-step impairment test is unnecessary. Under the amendments in Update 2011-08, an entity has the option to bypass the qualitative assessment and proceed directly to performing the first step of the two-step impairment test. The amendments are effective for interim and annual goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The Partnership adopted the amendments of Update 2011-08 upon its effective date of January 1, 2012. The adoption had no material impact on the Partnership’s financial position or results of operations.

In May 2011, the FASB issued ASU 2011-04, Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“Update 2011-04”). The amendments in Update 2011-04 revise the wording used to describe many of the requirements for measuring fair value and for disclosing information about fair value measurements in U.S. GAAP. For many of the amendments, the guidance is not necessarily intended to result in a change in the application of the requirements in Topic 820; rather it is intended to clarify the intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. As a result, Update 2011-04 aims to provide common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards. These requirements are effective for interim and annual reporting periods beginning after December 15, 2011. The Partnership updated its disclosures to meet these requirements upon the adoption of Update 2011-04 on January 1, 2012 (see Note 9). The adoption had no material impact on the Partnership’s financial position or results of operations.

Recently Issued Accounting Standards

In July 2012, the FASB issued ASU 2012-02, Intangibles – Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment (“Update 2012-02”). The amendments in Update 2012-02 allow an entity to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. The “more likely than not” threshold is defined as having a likelihood of more than 50 percent. If, after assessing qualitative factors, an entity determines it is not likely that the

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indefinite-lived intangible asset is impaired, then no further action is required. If impairment is deemed more likely than not, the entity is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount of the asset. Additionally, under the amendments in Update 2012-02, an entity has the option to bypass the qualitative assessment for any indefinite-lived intangible asset in any period and proceed directly to performing the quantitative impairment test. An entity will be able to resume performing the qualitative assessment in any subsequent period. The amendments are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption being permitted. The Partnership will apply the requirements of Update 2012-02 upon its effective date of January 1, 2013, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

NOTE 3 – ATLAS ENERGY, L.P. ACQUISITION FROM ATLAS ENERGY, INC.

On February 17, 2011, ATLS acquired the Transferred Business from AEI, including the following exploration and production assets that were transferred to the Partnership on March 5, 2012:

• AEI’s investment management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which the Partnership funds a portion of its natural gas and oil well drilling;

• proved reserves located in the Appalachian Basin, the Niobrara formation in Colorado, the New Albany Shale of west central Indiana, the Antrim Shale of northern Michigan and the Chattanooga Shale of northeastern Tennessee; and

• certain producing natural gas and oil properties, upon which the Partnership is the developer and producer.

Concurrent with ATLS’ acquisition of the Transferred Business, AEI was sold to Chevron Corporation (NYSE: CVX) (“Chevron”). In connection with the transaction, ATLS received $118.7 million with respect to a contractual cash transaction adjustment from AEI related to certain exploration and production liabilities assumed by ATLS. Including the cash transaction adjustment, the net book value of the Transferred Business was approximately $522.9 million. Certain amounts included within the contractual cash transaction adjustment were subject to a reconciliation period with Chevron following the consummation of the transaction. The reconciliation period was assumed by the Partnership on March 5, 2012, as certain amounts included within the contractual cash transaction adjustment remained in dispute between the parties. During the three months ended September 30, 2012, the Partnership recognized a $7.7 million charge on its consolidated combined statement of operations regarding its reconciliation process with Chevron, which was settled in October 2012 (see Note 11).

Management of ATLS determined that the acquisition of the Transferred Business constituted a transaction between entities under common control. As such, ATLS recognized the assets acquired and liabilities assumed at historical carrying value at the date of acquisition, with the difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital on its consolidated combined balance sheet. ATLS recognized a non-cash decrease of $261.0 million in partners’ capital on its consolidated combined balance sheet based on the excess net book value above the value of the consideration paid to AEI. The following table presents the historical carrying value of the assets acquired and liabilities assumed by ATLS, including the effect of cash transaction adjustments, as of February 17, 2011 (in thousands):

Cash	$	153,350
Accounts receivable		18,090
Accounts receivable – affiliate		45,682
Prepaid expenses and other		6,955
Total current assets		224,077
Property, plant and equipment, net		516,625
Goodwill		31,784
Intangible assets, net		2,107
Other assets, net		20,416
Total long-term assets		570,932
Total assets acquired	$	795,009
Accounts payable	$	59,202
Net liabilities associated with drilling contracts		47,929
Accrued well completion costs		39,552
Current portion of derivative payable to Drilling Partnerships		25,659
Accrued liabilities		25,283
Total current liabilities		197,625
Long-term derivative payable to Drilling Partnerships		31,719
Asset retirement obligations		42,791
Total long-term liabilities		74,510
Total liabilities assumed	$	272,135
Historical carrying value of net assets acquired	$	522,874

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The Partnership reflected the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which the Transferred Business was acquired and retrospectively adjusted its prior year financial statements to furnish comparative information (see Note 2).

NOTE 4 – ACQUISITIONS

Titan Acquisition

On July 25, 2012, the Partnership completed the acquisition of Titan Operating, L.L.C. (“Titan”) in exchange for 3.8 million common units and 3.8 million newly-created convertible Class B preferred units (which had a collective value of $193.2 million, based upon the closing price of the Partnership’s publicly traded units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments (see Note 12). Through the acquisition of Titan, the Partnership acquired interests in approximately 52 proved developed natural gas wells and approximately 250 Bcfe of proved reserves and 700 Bcfe of proved, probable and possible reserves and associated assets in the Barnett Shale, located in Bend Arch – Fort Worth Basin in North Texas. The cash paid at closing was funded through borrowings under the Partnership’s credit facility. The common units and preferred units were issued and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”) (see Note 12). The Partnership accounted for the issuance of common and preferred limited partner units in exchange for the Titan assets acquired as a non-cash item in its consolidated combined statement of cash flows for the nine months ended September 30, 2012.

The Partnership accounted for this transaction under the acquisition method of accounting. Accordingly, the Partnership evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9). In conjunction with the issuance of common and preferred limited partner units associated with the acquisition, the Partnership recorded $3.4 million of transaction fees within common and preferred limited partners’ interests for the three and nine months ended September 30, 2012 on the Partnership’s consolidated combined balance sheets. All other costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as the Partnership continues to evaluate the facts and circumstances that existed as of the acquisition date.

The following table presents the preliminary 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:
Cash and cash equivalents	$	372
Accounts receivable		5,253
Prepaid expenses and other		131
Total current assets		5,756
Natural gas and oil properties		210,704
Other assets, net		131
	$	216,591
Liabilities:
Accounts payable	$	676
Revenue distribution payable		3,091
Accrued liabilities		1,816
Total current liabilities		5,583
Asset retirement obligation and other		2,418
		8,001
Net assets acquired	$	208,590

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Carrizo Acquisition

On April 30, 2012, the Partnership completed the acquisition of certain oil and natural gas assets from Carrizo Oil and Gas, Inc. (NASDAQ: CRZO; “Carrizo”) for approximately $187.0 million in cash. The assets acquired include interests in approximately 200 producing natural gas wells from the Barnett Shale, located in Bend Arch–Fort Worth Basin in North Texas, proved undeveloped acres also in the Barnett Shale and gathering pipelines and associated gathering facilities that service certain of the acquired wells. The purchase price was funded through borrowings under the Partnership’s credit facility and $119.5 million of net proceeds from the sale of 6.0 million of its common units at a negotiated purchase price per unit of $20.00, of which $5.0 million was purchased by certain executives of the Partnership. The common units were issued in a private transaction exempt from registration under Section 4(2) of the Securities Act (see Note 12).

The Partnership accounted for this transaction under the acquisition method of accounting. Accordingly, the Partnership evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9). In conjunction with the issuance of common limited partner units associated with the acquisition, the Partnership recorded $1.1 million of transaction fees within common limited partners’ interests for the nine months ended September 30, 2012 on the Partnership’s consolidated combined balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as the Partnership continues to evaluate the facts and circumstances that existed as of the acquisition date.

The following table presents the preliminary 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:
Natural gas and oil properties	$	190,946
Liabilities:
Asset retirement obligation		3,903
Net assets acquired	$	187,043

Due to the commingled nature of the Partnership’s acquisitions in the Barnett Shale, it was impractical to provide separate financial information for each of the acquisitions subsequent to their respective dates of acquisition included within the Partnership’s consolidated combined statements of operations for the three and nine months ended September 30, 2012. Subsequent to their respective dates of acquisition and combined with the effect of the Partnership’s additional capital expenditures incurred, the Titan and Carrizo acquisitions had combined total revenues of $11.3 million and net income of $0.5 million for the three months ended September 30, 2012, and total combined revenues of $15.4 million and net loss of $0.6 million for the nine months ended September 30, 2012.

The following data presents pro forma revenues, net income (loss) and basic and diluted net income (loss) per unit for the Partnership as if the Titan and Carrizo acquisitions, including the borrowings under the credit facility and issuance of common and preferred units, had occurred on January 1, 2011. The Partnership prepared these pro forma unaudited financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the acquisitions had occurred on January 1, 2011 or the results that will be attained in future periods (in thousands, except per share data; unaudited):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012			2011
Total revenues and other	$	74,743		$	83,957	$	196,899		$	212,567
Net income (loss)		(10,079	)		13,869		(44,591	)		39,229
Net income (loss) attributable to common limited partners and the general partner		(11,300	)		—		(46,039	)		—
Net income (loss) attributable to common limited partners per unit:
Basic	$	(0.32	)	$	—	$	(1.25	)	$	—
Diluted	$	(0.32	)	$	—	$	(1.25	)	$	—

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Equal Acquisition

In April 2012, the Partnership acquired a 50% interest in approximately 14,500 net undeveloped acres in the oil and NGL area of the Mississippi Lime play in northwestern Oklahoma for $18.0 million from subsidiaries of Equal Energy, Ltd. (“Equal”) (NYSE: EQU; TSX: EQU). The transaction was funded through borrowings under the Partnership’s revolving credit facility. Concurrent with the purchase of acreage, the Partnership and Equal entered into a participation and development agreement for future drilling in the Mississippi Lime play. The Partnership served as the drilling and completion operator, while Equal undertook production operations, including water disposal. In September 2012, the Partnership acquired Equal’s remaining 50% interest in the undeveloped acres, as well as approximately 8 Mmcfed of net production in the Mississippi Lime region and salt water disposal infrastructure for $41.3 million, including $1.3 million related to certain post-closing adjustments. The additional acquisition was subject to certain post-closing adjustments and funded with available borrowings under the Partnership’s revolving credit facility. As a result of the Partnership’s acquisition of Equal’s remaining interest in the undeveloped acres, the existing joint venture agreement between the Partnership and Equal in the Mississippi Lime position was terminated and all infrastructure associated with the assets, principally the salt water disposal system, is operated by the Partnership.

NOTE 5 – PROPERTY, PLANT AND EQUIPMENT

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

	September 30, 2012			December 31, 2011			Estimated Useful Lives in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	159,999		$	61,587
Pre-development costs		1,796			2,540
Wells and related equipment		1,060,481			828,780
Total proved properties		1,222,276			892,907
Unproved properties		231,040			43,253
Support equipment		11,800			9,413
Total natural gas and oil properties		1,465,116			945,573
Pipelines, processing and compression facilities		32,178			32,149		2 – 40
Rights of way		84			84		20 – 40
Land, buildings and improvements		6,790			4,822		3 – 40
Other		8,983			1,180		3 – 10
		1,513,151			983,808
Less – accumulated depreciation, depletion and amortization		(497,041	)		(462,925	)
	$	1,016,110		$	520,883

In March 2012, the Partnership recognized a $7.0 million loss on asset disposal, pertaining to its decision to terminate a farm out agreement with a third party for well drilling in the South Knox area of the New Albany Shale that was originally entered into in 2010. The farm out agreement contained certain well drilling targets for the Partnership to maintain ownership of the South Knox processing plant, which the Partnership’s management decided in 2012 to not achieve due to the current natural gas price environment. As a result, the Partnership’s management forfeited its interest in the processing plant and related properties and recorded a loss related to the net book values of those assets during the nine months ended September 30, 2012.

During the year ended December 31, 2011, the Partnership recognized $7.0 million of asset impairment related to its gas and oil properties within property, plant and equipment, net on its combined balance sheet for its shallow natural gas wells in the Niobrara Shale. This impairment related to the carrying amount of gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2011. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

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NOTE 6 – ASSET RETIREMENT OBLIGATIONS

The Partnership recognized an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities. The Partnership also recognized a liability for its 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 Partnership also considers the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability was based on the Partnership’s 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 Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its gas and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets.

A reconciliation of the Partnership’s 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,
	2012			2011			2012			2011
Asset retirement obligations, beginning of period	$	51,046		$	43,932		$	45,779		$	42,673
Liabilities incurred		2,424			276			6,516			369
Liabilities settled		(198	)		(18	)		(448	)		(150	)
Accretion expense		768			650			2,193			1,948
Asset retirement obligations, end of period	$	54,040		$	44,840		$	54,040		$	44,840

The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated combined statements of operations and the asset retirement obligation liabilities were included within asset retirement obligations and other in the Partnership’s consolidated combined balance sheets. During the three and nine months ended September 30, 2012, the Partnership incurred $2.0 million and $5.9 million, respectively, of future plugging and abandonment costs related to the acquisitions it consummated during the period (see Note 4).

NOTE 7 – DEBT

Credit Facility

At September 30, 2012, the Partnership had a senior secured credit facility with a syndicate of banks with a borrowing base of $310.0 million with $222.0 million outstanding. Concurrent with the closing of the Titan acquisition on July 25, 2012, the Partnership expanded the borrowing base on its revolving credit line from $250.0 million to $310.0 million. The credit facility matures in March 2016 and the borrowing base will be redetermined semi-annually in May and November. Up to $20.0 million of the credit facility may be in the form of standby letters of credit which would reduce the Partnership’s borrowing capacity, of which $0.6 million was outstanding at September 30, 2012, and was not reflected as borrowings on the Partnership’s consolidated combined balance sheet. The 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. Additionally, obligations under the facility are guaranteed by substantially all of the Partnership’s subsidiaries. Borrowings under the credit facility bear interest, at the Partnership’s election, at either LIBOR plus an applicable margin between 2.00% and 3.00% 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 1.00% and 2.00%. The Partnership is also required to pay a fee of 0.5% per annum on the unused portion of the borrowing base, which is included within interest expense on its consolidated combined statements of operations. At September 30, 2012, the weighted average interest rate was 2.7%.

The credit agreement contains customary covenants that limit the Partnership’s ability to incur additional indebtedness, 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 Partnership was in compliance with these covenants as of September 30, 2012. The credit agreement also requires the Partnership to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to four quarters (actual or annualized, as applicable) of EBITDA (as defined in the credit agreement) not greater than 3.75 to 1.0 as of the last day of any fiscal quarter, a ratio of current assets (as defined in the credit

21

agreement) to current liabilities (as defined in the credit agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter, and a ratio of four quarters (actual or annualized, as applicable) of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) of not less than 2.5 to 1.0 as of the last day of any fiscal quarter. Based on the definitions contained in the Partnership’s credit facility, its ratio of current assets to current liabilities was 1.1 to 1.0, its ratio of Total Funded Debt to EBITDA was 2.2 to 1.0 and its ratio of EBITDA to Consolidated Interest Expense was 35.1 to 1.0 at September 30, 2012.

NOTE 8 – DERIVATIVE INSTRUMENTS

The Partnership uses a number of different derivative instruments, principally swaps, collars and options, in connection with their commodity and interest rate price risk management activities. Management enters 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. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits 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.

Management formally documents all relationships between the Partnership’s hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity derivative contracts to the forecasted transactions. Management assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Partnership will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by management of the Partnership through the utilization of market data, will be recognized immediately within other, net in the Partnership’s consolidated combined statements of operations. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value of derivative instruments as accumulated other comprehensive income and reclassifies the portion relating to commodity derivatives to gas and oil production revenues within the Partnership’s consolidated combined statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, management recognized changes in fair value within gain on mark-to-market derivatives in the Partnership’s consolidated combined statements of operations as they occur.

The Partnership enters 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 Partnership’s consolidated combined 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 Partnership’s consolidated combined balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its consolidated combined balance sheets of $7.3 million and $29.9 million at September 30, 2012 and December 31, 2011, respectively. Of the $8.6 million of net gain in accumulated other comprehensive income within partners’ capital/equity on the Partnership’s consolidated combined balance sheet related to derivatives at September 30, 2012, if the fair values of the instruments remain at current market values, the Partnership will reclassify $5.2 million of gains to gas and oil production revenue on its consolidated combined statement of operations over the next twelve month period as these contracts expire. Aggregate gains of $3.4 million of gas and oil production revenues will be reclassified to the Partnership’s consolidated combined statements of operations in later periods as the remaining contracts expire. Actual amounts that will be reclassified will vary as a result of future price changes.

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

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Combined Balance Sheets			Net Amount of Assets Presented in the Consolidated Combined Balance Sheets
Offsetting Derivative Assets
As of September 30, 2012
Current portion of derivative assets	$	11,078	$	(4,560	)	$	6,518
Long-term portion of derivative assets		12,256		(7,112	)		5,144
Current portion of derivative liabilities		8		(8	)		—
Long-term portion of derivative liabilities		2,764		(2,764	)		—
Total derivative assets	$	26,106	$	(14,444	)	$	11,662
As of December 31, 2011
Current portion of derivative assets	$	14,146	$	(345	)	$	13,801
Long-term portion of derivative assets		21,485		(5,357	)		16,128
Total derivative assets	$	35,631	$	(5,702	)	$	29,929

	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Combined Balance Sheets		Net Amount of Liabilities Presented in the Consolidated Combined Balance Sheets
Offsetting Derivative Liabilities
As of September 30, 2012
Current portion of derivative assets	$	(4,560	)	$	4,560	$	—
Long-term portion of derivative assets		(7,112	)		7,112		—
Current portion of derivative liabilities		(288	)		8		(280	)
Long-term portion of derivative liabilities		(6,815	)		2,764		(4,051	)
Total derivative liabilities	$	(18,775	)	$	14,444	$	(4,331	)
As of December 31, 2011
Current portion of derivative liabilities	$	(345	)	$	345	$	—
Long-term portion of derivative liabilities		(5,357	)		5,357		—
Total derivative liabilities	$	(5,702	)	$	5,702	$	—

The following table summarizes the gain or loss recognized in the Partnership’s consolidated combined statements of operations for effective derivative instruments for the periods indicated (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Gain (loss) recognized in accumulated OCI	$	(19,487	)	$	10,884		$	(5,832	)	$	17,733
Gain reclassified from accumulated OCI into income	$	(6,114	)	$	(279	)	$	(15,453	)	$	(9,588	)

The Partnership enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its 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. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

In March 2012, the Partnership entered into contracts which provided the option to enter into swap contracts (“swaptions”) up through May 31, 2012 for production volumes related to wells acquired from Carrizo (see Note 4). In connection with the swaption contracts, the Partnership paid premiums of $4.6 million, which represented the fair value of contracts on the date of the transaction and was initially recorded as a derivative asset on the Partnership’s consolidated combined balance sheet and was fully amortized as of June 30, 2012. For the nine months ended September 30, 2012, the Partnership recorded approximately $4.6 million of amortization expense in other, net on the Partnership’s consolidated combined statements of operations related to the swaption contracts.

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In June 2012, the Partnership received approximately $3.9 million in net proceeds from the early termination of natural gas and oil derivative positions for production periods from 2015 through 2016. In conjunction with the early termination of these derivatives, the Partnership entered into new derivative positions at prevailing prices at the time of the transaction. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under the Partnership’s credit facility (see Note 7). The gain recognized upon the early termination of these derivative positions will continue to be reported in accumulated other comprehensive income and will be reclassified into the Partnership’s consolidated statements of operations in the same periods in which the hedged production revenues would have been recognized in earnings.

The Partnership recognized gains of $6.1 million and $0.3 million for the three months ended September 30, 2012 and 2011, respectively, and $15.5 million and $9.6 million for the nine months ended September 30, 2012 and 2011, respectively, on settled contracts covering commodity production. These gains were included within gas and oil production revenue in the Partnership’s consolidated combined statements of operations. As the underlying prices and terms in the Partnership’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, 2012 and 2011 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

At September 30, 2012, the Partnership had the following commodity derivatives:

Natural Gas Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset/(Liability)
	(mmbtu)(1)		(per mmbtu)(1)		(in thousands)(2)
2012		5,591,000	$	3.378	$	328
2013		21,529,700	$	3.853		114
2014		16,233,000	$	4.215		562
2015		11,994,500	$	4.259		(1,346	)
2016		9,866,300	$	4.334		(2,056	)
2017		3,600,000	$	4.579		(549	)
					$	(2,947	)

Natural Gas Costless Collars

Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap		Fair Value Asset/(Liability)
		(mmbtu)(1)		(per mmbtu)(1)		(in thousands)(2)
2012	Puts purchased		1,080,000	$	4.074	$	880
2012	Calls sold		1,080,000	$	5.279		(2	)
2013	Puts purchased		5,520,000	$	4.395		4,297
2013	Calls sold		5,520,000	$	5.443		(446	)
2014	Puts purchased		3,840,000	$	4.221		2,230
2014	Calls sold		3,840,000	$	5.120		(1,065	)
2015	Puts purchased		3,480,000	$	4.234		2,049
2015	Calls sold		3,480,000	$	5.129		(1,469	)
						$	6,474

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Natural Gas Put Options

Production Period Ending December 31,	Option Type	Volumes		Average Fixed Price		Fair Value Asset
		(mmbtu)(1)		(per mmbtu)(1)		(in thousands)(2)
2012	Puts purchased		1,470,000	$	2.802	$	16
2013	Puts purchased		3,180,000	$	3.450		633
2014	Puts purchased		1,800,000	$	3.800		621
2015	Puts purchased		1,440,000	$	4.000		634
2016	Puts purchased		1,440,000	$	4.150		776
						$	2,680

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)
2012		6,750	$	103.804	$	96
2013		18,600	$	100.669		129
2014		36,000	$	97.693		221
2015		45,000	$	89.504		23
					$	469

Crude Oil Costless Collars

Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap		Fair Value Asset/ (Liability)
		(Bbl)(1)		(per Bbl)(1)		(in thousands)(3)
2012	Puts purchased		15,000	$	90.000	$	50
2012	Calls sold		15,000	$	117.912		(11	)
2013	Puts purchased		60,000	$	90.000		495
2013	Calls sold		60,000	$	116.396		(167	)
2014	Puts purchased		41,160	$	84.169		388
2014	Calls sold		41,160	$	113.308		(221	)
2015	Puts purchased		29,250	$	83.846		315
2015	Calls sold		29,250	$	110.654		(194	)
						$	655
Total net asset						$	7,331

⁽¹⁾  “Mmbtu” represents million British Thermal Units; “Bbl” represents barrels.

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

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

Prior to its merger with Chevron on February 17, 2011, AEI monetized its derivative instruments, including those related to the future natural gas and oil production of the Transferred Business (see Note 3). AEI also monetized derivative instruments which were specifically related to the future natural gas and oil production of the limited partners of the Drilling Partnerships. At September 30, 2012, remaining hedge monetization cash proceeds of $15.3 million related to the amounts hedged on behalf of the Drilling Partnerships’ limited partners were included within cash and cash equivalents on the Partnership’s consolidated combined balance sheet, and the Partnership will allocate the monetization net proceeds to the Drilling Partnerships’ limited partners based on their natural gas and oil production generated over the period of the original derivative contracts. The Partnership reflected the remaining hedge monetization proceeds within current and long-term portion of derivative payable to Drilling Partnerships on its consolidated combined balance sheets as of September 30, 2012 and December 31, 2011.

In June 2012, the Partnership 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, 2012, 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.

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The derivatives payable to the Drilling Partnerships related to both the hedge monetization proceeds and future natural gas production of the Drilling Partnerships at September 30, 2012 and December 31, 2011 were included in the Partnership’s consolidated combined balance sheets as follows (in thousands):

	September 30, 2012			December 31, 2011
Current portion of derivative payable to Drilling Partnerships:
Hedge monetization proceeds	$	(13,032	)	$	(20,900	)
Hedge contracts covering future natural gas production		(331	)		—
Long-term portion of derivative payable to Drilling Partnerships:
Hedge monetization proceeds		(2,325	)		(15,272	)
Hedge contracts covering future natural gas production		(2,158	)		—
	$	(17,846	)	$	(36,172	)

At September 30, 2012, the Partnership had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships will have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under its senior secured credit facility (see Note 7), the Partnership 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 Partnerships. The Partnership, as general partner of the Drilling Partnerships, will administer 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 Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets.

NOTE 9 – FAIR VALUE OF FINANCIAL INSTRUMENTS

Management has established a hierarchy to measure the Partnership’s financial instruments at fair value which requires it 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 Partnership’s 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 Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 8). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’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 the NYMEX quoted prices for futures and options contracts traded on NYMEX that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.

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Information for assets and liabilities measured at fair value at September 30, 2012 and December 31, 2011 was as follows (in thousands):

	Level 1		Level 2			Level 3		Total
As of September 30, 2012
Derivative assets, gross
Commodity swaps	$	—	$	12,722		$	—	$	12,722
Commodity puts		—		2,679			—		2,679
Commodity options		—		10,705			—		10,705
Total derivative assets, gross		—		26,106			—		26,106
Derivative liabilities, gross
Commodity swaps		—		(15,201	)		—		(15,201	)
Commodity puts		—		—			—		—
Commodity options		—		(3,574	)		—		(3,574	)
Total derivative liabilities, gross		—		(18,775	)		—		(18,775	)
Total derivatives, fair value, net	$	—	$	7,331		$	—	$	7,331
As of December 31, 2011
Derivative assets, gross
Commodity swaps	$	—	$	20,908		$	—	$	20,908
Commodity puts		—		—			—		—
Commodity options		—		14,723			—		14,723
Total derivative assets, gross		—		35,631			—		35,631
Derivative liabilities, gross
Commodity swaps		—		—			—		—
Commodity puts		—		—			—		—
Commodity options		—		(5,702	)		—		(5,702	)
Total derivative liabilities, gross		—		(5,702	)		—		(5,702	)
Total derivatives, fair value, net	$	—	$	29,929		$	—	$	29,929

Other Financial Instruments

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

The Partnership’s other current assets and liabilities on its consolidated combined 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 outstanding borrowings under the revolving credit facility, which bear interest at a variable interest rate, approximate their estimated fair values and thus are categorized as Level 1.

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

Management estimates the fair value of its 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 Partnership and estimated inflation rates. Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the three and nine months ended September 30, 2012 and 2011 were as follows (in thousands):

	Three Months Ended September 30,
	2012				2011
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	2,424	$	2,424	$	276	$	276
Total	$	2,424	$	2,424	$	276	$	276

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	Nine Months Ended September 30,
	2012				2011
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	6,516	$	6,516	$	369	$	369
Total	$	6,516	$	6,516	$	369	$	369

Management estimates the fair value of the Partnership’s 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. For the year ended December 31, 2011, the Partnership recognized a $7.0 million impairment of long-lived assets which was defined as a Level 3 fair value measurement (see Note 2 – Impairment of Long-Lived Assets). No impairments were recognized for the three and nine months ended September 30, 2012 and 2011 (see Note 5).

During the nine months ended September 30, 2012, the Partnership completed the acquisitions of certain oil and gas assets from Carrizo and certain proved reserves and associated assets from Titan (see Note 4). 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 the Partnership’s existing methodology for recognizing an estimated liability for the plugging and abandonment of its gas and oil wells (see Note 6). These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are subject to change.

NOTE 10 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Partnership conducts certain activities through, and a portion of its revenues are attributable to, the Drilling Partnerships. The Partnership serves as general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the general partner, the Partnership is liable for the Drilling Partnerships’ liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Drilling Partnerships. The Partnership 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

The Partnership 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. Subject to certain conditions, investor partners in certain Drilling Partnerships have the right to present their interests for purchase by the Partnership, as managing general partner. The Partnership is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on its historical experience, the management of the Partnership believes that any liability incurred would not be material. Also, the Partnership has agreed to subordinate a portion of its share of net partnership revenues from the Drilling Partnerships to the benefit of the investor partners until they have received specified returns, typically 10% per year determined on a cumulative basis, over a specific period, typically the first five to seven years, in accordance with the terms of the partnership agreements. For the three months ended September 30, 2012 and 2011, $1.8 million and $0.9 million, respectively, of the Partnership’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships. For the nine months ended September 30, 2012 and 2011, $3.6 million of the Partnership’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships.

Immediately following the acquisition of the Transferred Business, ATLS received from Chevron $118.7 million related to a contractual cash transaction adjustment related to certain liabilities of the Transferred Business at February 17, 2011. Following the closing of the acquisition of the Transferred Business, ATLS entered into a reconciliation process with Chevron to determine the final cash adjustment amount pursuant to the transaction agreement. The reconciliation process was assumed by the Partnership on March 5, 2012, as certain amounts included within the contractual cash transaction adjustment remained in dispute between the parties. During the three months ended September 30, 2012, the Partnership recognized a $7.7 million charge on its consolidated combined statement of operations regarding its reconciliation process with Chevron, which was settled in October 2012. At September 30, 2012, the Partnership had a $13.5 million liability included within accrued liabilities on its consolidated combined balance sheet related to the settlement of this matter.

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The Partnership is party to employment agreements with certain executives that provide compensation and certain other benefits. The agreements also provide for severance payments under certain circumstances.

As of September 30, 2012, the Partnership is committed to expend approximately $20.4 million, principally on drilling and completion expenditures.

Legal Proceedings

A subsidiary of the Partnership entered into two agreements with the United States Environmental Protection Agency (the “EPA”), effective on September 25, 2012, to settle alleged violations in connection with a fire that occurred at a natural gas well and associated well pad site in Washington County, Pennsylvania in 2010. The EPA alleged non-compliance with the Clean Air Act, including with respect to the storage and handling of the natural gas condensate as well as non-compliance with the Emergency Planning and Community Right-to-Know Act of 1986. The subsidiary agreed to a civil penalty of $84,506 under a consent agreement and agreed to upgrade its facility pursuant to an administrative settlement agreement.

On August 3, 2011, CNX Gas Company LLC filed a lawsuit in the United States District Court for the Eastern District of Tennessee at Knoxville styled CNX Gas Company LLC vs. Miller Energy Resources, Inc., Chevron Appalachia, LLC as successor in interest to Atlas America, LLC, Cresta Capital Strategies, LLC, and Scott Boruff, No. 3:11-cv-00362. On April 16, 2012 Atlas Energy Tennessee, LLC, an indirect wholly-owned subsidiary of the Partnership, was brought in to the lawsuit by way of Amended Complaint. On April 23, 2012, the Court dismissed Chevron Appalachia, LLC as a party on the grounds of lack of subject matter jurisdiction over that entity.

The lawsuit alleges that CNX entered into a Letter of Intent with Miller Energy for the purchase by CNX of certain leasehold interests containing oil and natural gas rights, representing around 30,000 acres in East Tennessee. The lawsuit also alleges that Miller Energy breached the Letter of Intent by refusing to close by the date provided and by allegedly entertaining offers from third parties for the same leasehold interests. Allegations of inducement of breach of contract and related claims are made by CNX against the remaining defendants, on the theory that these parties knew of the terms of the Letter of Intent and induced Miller Energy to breach the Letter of Intent. CNX is seeking $15.5 million in damages. The Partnership asserts that it acted in good faith and believes that the outcome of the litigation will be resolved in its favor.

The Partnership is also a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.

NOTE 12 – ISSUANCES OF UNITS

Titan Acquisition

On July 25, 2012, the Partnership completed the acquisition of certain proved reserves and associated assets in the Barnett Shale from Titan in exchange for 3.8 million Partnership common units and 3.8 million newly-created convertible Class B preferred units (which have a collective value of $193.2 million, based upon the closing price of the Partnership’s publicly traded common units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments (see Note 4). The preferred units are voluntarily convertible to common units on a one-for-one basis within three years of the acquisition closing date at a strike price of $26.03 plus all unpaid preferred distributions per unit, and will be mandatorily converted to common units on the third anniversary of the issuance. While outstanding, the preferred units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution.

The Partnership entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC by January 25, 2013 to register the resale of the common units issued on the acquisition closing date and those issuable upon conversion of the preferred units. The Partnership agreed to use its commercially reasonable efforts to have the registration statement declared effective by March 31, 2013, and to cause the registration statement to be continuously effective until the earlier of (i) the date as of which all such common units registered thereunder are sold by the holders and (ii) one year after the date of effectiveness. On September 19, 2012, the Partnership filed a registration statement with the SEC in satisfaction of the registration requirements of the registration rights agreement and the registration statement was declared effective by the SEC on October 2, 2012.

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Carrizo Acquisition

On April 30, 2012, the Partnership completed the acquisition of certain oil and gas assets from Carrizo (see Note 4). To partially fund the acquisition, the Partnership sold 6.0 million of its common units in a private placement at a negotiated purchase price per unit of $20.00, for gross proceeds of $120.6 million, of which $5.0 million was purchased by certain executives of the Partnership. The common units issued by the Partnership are subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulated that the Partnership would (a) file a registration statement with the SEC by October 30, 2012 and (b) cause the registration statement to be declared effective by the SEC by December 31, 2012. On July 11, 2012, the Partnership filed a registration statement with the SEC for the common units subject to the registration rights agreement in satisfaction of one of the requirements of the registration rights agreement noted previously. On August 28, 2012, the registration statement was declared effective by the SEC.

Common Unit Distribution

In February 2012, the board of directors of ATLS’ general partner approved the distribution of approximately 5.24 million common units which were distributed on March 13, 2012 to ATLS’ unitholders using a ratio of 0.1021 limited partner units for each of ATLS’ common units owned on the record date of February 28, 2012. The distribution of these limited partner units represented approximately 20.0% of the common limited partner units outstanding (see Note 1).

NOTE 13 – CASH DISTRIBUTIONS

The Partnership has a cash distribution policy under which it distributes, within 45 days following the end of each calendar quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders and general partner. If the Partnership’s common unit distributions in any quarter exceed specified target levels, ATLS will receive between 13% and 48% of such distributions in excess of the specified target levels.

Date Cash Distribution Paid	For Quarter Ended	Cash Distribution per Common Limited Partner Unit			Total Cash Distribution to Common Limited Partners		Total Cash Distribution to the General Partner’s Class A Units
							(in thousands)
May 15, 2012	March 31, 2012	$	0.12	(1)	$	3,144	$	64
August 14, 2012	June 30, 2012	$	0.40		$	12,891	$	263

⁽¹⁾  Represents a pro-rated cash distribution of $0.40 per common limited partner unit for the period from March 5, 2012, the date ATLS’ exploration and production assets were transferred to the Partnership, to March 31, 2012.

On October 25, 2012, the Partnership declared a cash distribution of $0.43 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2012. The $17.5 million distribution, including $0.4 million and $1.7 million to the general partner and preferred limited partners, respectively, will be paid on November 14, 2012 to unitholders of record at the close of business on November 5, 2012.

NOTE 14 – BENEFIT PLAN

2012 Long-Term Incentive Plan

The Partnership’s 2012 Long-Term Incentive Plan (“2012 LTIP”), effective March 2012, provides incentive awards to officers, employees and directors and employees of the general partner and its affiliates, consultants and joint venture partners (collectively, the “Participants”) who perform services for the Partnership. The 2012 LTIP is administered by the board of the general partner, a committee of the board or the board (or committee of the board) of an affiliate (the “LTIP Committee”). Under the 2012 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 2,900,000 common limited partner units. At September 30, 2012, the Partnership had 2,454,476 phantom units, restricted units and restricted options outstanding under the 2012 LTIP with 445,524 phantom units, restricted units and unit options available for grant.

Upon a “change in control”, as defined in the 2012 LTIP, all unvested awards held by directors will immediately vest in full. In the case of awards held by eligible employees, upon the eligible employee’s termination of employment without “cause”, as defined in the 2012 LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), in any case following a change in control, 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.

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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, but subject to the terms of any award agreements and employment agreements to which the 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 the 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 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 LTIP Committee deems necessary or appropriate.

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. Phantom units are subject to terms and conditions determined by the LTIP Committee, which may include vesting restrictions. In tandem with phantom unit grants, the LTIP Committee may grant distribution equivalent rights (“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 the Partnership with respect to a common unit during the period that the underlying phantom unit is outstanding. Through September 30, 2012, phantom units granted under the 2012 LTIP generally will vest 25% of the original granted amount on each of the next four anniversaries of the date of grant. Of the phantom units outstanding under the 2012 LTIP at September 30, 2012, 210,993 units will vest within the following twelve months. All phantom units outstanding under the 2012 LTIP at September 30, 2012 include DERs. During the three and nine months ended September 30, 2012, respectively, the Partnership paid $0.3 million with respect to the 2012 LTIP’s DERs. No amounts were paid during the three and nine months ended September 30, 2011, respectively, with respect to the DERs. These amounts were recorded as reductions of partners’ capital on the Partnership’s consolidated combined balance sheet.

The following table sets forth the 2012 LTIP phantom unit activity for the periods indicated:

	Three Months Ended September 30,
	2012					2011
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value
Outstanding, beginning of period		810,476		$	24.69		—	$	—
Granted		129,500			25.23		—		—
Vested(1)		—			—		—		—
Forfeited		(1,000	)		24.67		—		—
Outstanding, end of period(2)(3)		938,976		$	24.76		—	$	—
Non-cash compensation expense recognized (in thousands)				$	2,915			$	—

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	Nine Months Ended September 30,
	2012					2011
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value
Outstanding, beginning of year		—		$	—		—	$	—
Granted		939,976			24.76		—		—
Vested(1)		—			—		—		—
Forfeited		(1,000	)		24.67		—		—
Outstanding, end of period(2)(3)		938,976		$	24.76		—	$	—
Non-cash compensation expense recognized (in thousands)				$	4,655			$	—

⁽¹⁾  No phantom unit awards vested during the three and nine months ended September 30, 2012 and 2011.

⁽²⁾  The aggregate intrinsic value for phantom unit awards outstanding at September 30, 2012 was $24.0 million.

⁽³⁾  There was $23,000 classified within accrued liabilities on the Partnership’s consolidated combined balance sheet at September 30, 2012, representing 3,476 units, due to the option of the participants to settle in cash instead of units. No amounts were classified within accrued liabilities on the Partnership’s consolidated combined balance sheet at December 31, 2011. The respective weighted average grant date fair value for these units was $28.75 at September 30, 2012.

At September 30, 2012, the Partnership had approximately $8.6 million in unrecognized compensation expense related to unvested phantom units outstanding under the 2012 LTIP based upon the fair value of the awards.

Unit Options

A unit option is the right to purchase a Partnership common unit in the future at a predetermined price (the exercise price). The exercise price of each option is determined by the LTIP Committee and may be equal to or greater than the fair market value of a common unit on the date the option is granted. The LTIP Committee will determine the vesting and exercise restrictions applicable to an 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. Through September 30, 2012, unit options granted under the 2012 LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. There were 378,875 unit options outstanding under the 2012 LTIP at September 30, 2012 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, 2012 and 2011.

The following table sets forth the 2012 LTIP unit option activity for the periods indicated:

	Three Months Ended September 30,
	2012					2011
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of period		1,499,500		$	24.67		—	$	—
Granted		18,000			25.18		—		—
Exercised(1)		—			—		—		—
Forfeited		(2,000	)		24.67		—		—
Outstanding, end of period(2)(3)		1,515,500		$	24.68		—	$	—
Options exercisable, end of period(4)		—		$	—		—	$	—
Non-cash compensation expense recognized (in thousands)				$	1,927			$	—

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	Nine Months Ended September 30,
	2012					2011
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of year		—		$	—		—	$	—
Granted		1,517,500			24.68		—		—
Exercised(1)		—			—		—		—
Forfeited		(2,000	)		24.67		—		—
Outstanding, end of period(2)(3)		1,515,500		$	24.68		—	$	—
Options exercisable, end of period(4)		—		$	—		—	$	—
Non-cash compensation expense recognized (in thousands)				$	3,201			$	—

⁽¹⁾ No options were exercised during the three and nine months ended September 30, 2012 and 2011.

⁽²⁾ The weighted average remaining contractual life for outstanding options at September 30, 2012 was 9.6 years.

⁽³⁾ The aggregate intrinsic value of options outstanding at September 30, 2012 was approximately $1.3 million.

⁽⁴⁾ No options were exercisable at September 30, 2012.

At September 30, 2012, the Partnership had approximately $11.6 million in unrecognized compensation expense related to unvested unit options outstanding under the 2012 LTIP based upon the fair value of the awards. The Partnership used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the periods indicated:

	Three Months Ended September 30, 2012			Nine Months Ended September 30, 2012
Expected dividend yield		2.5	%		1.5	%
Expected unit price volatility		46.0	%		47.0	%
Risk-free interest rate		0.8	%		1.0	%
Expected term (in years)		6.25			6.25
Fair value of unit options granted	$	8.72		$	9.78

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 during 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.

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NOTE 15 – OPERATING SEGMENT INFORMATION

The Partnership’s operations include three reportable operating segments. These operating segments reflect the way the Partnership manages its operations and makes business decisions. Operating segment data for the periods indicated were as follows (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Gas and oil production:
Revenues	$	24,699		$	16,305		$	61,323		$	51,654
Operating costs and expenses		(7,295	)		(3,990	)		(16,247	)		(11,953	)
Depreciation, depletion and amortization expense		(12,576	)		(6,882	)		(29,663	)		(20,626	)
Segment income	$	4,828		$	5,433		$	15,413		$	19,075
Well construction and completion:
Revenues	$	36,317		$	35,657		$	92,277		$	64,336
Operating costs and expenses		(31,581	)		(30,449	)		(79,882	)		(54,754	)
Segment income	$	4,736		$	5,208		$	12,395		$	9,582
Other partnership management:(1)
Revenues	$	13,727		$	11,628		$	29,289		$	34,057
Operating costs and expenses		(6,790	)		(6,923	)		(20,261	)		(22,454	)
Depreciation, depletion and amortization expense		(1,342	)		(1,189	)		(4,185	)		(3,393	)
Segment income	$	5,595		$	3,516		$	4,843		$	8,210
Reconciliation of segment income to net income (loss):
Segment income:
Gas and oil production	$	4,828		$	5,433		$	15,413		$	19,075
Well construction and completion		4,736			5,208			12,395			9,582
Other partnership management		5,595			3,516			4,843			8,210
Total segment income		15,159			14,157			32,651			36,867
General and administrative expenses(2)		(16,147	)		(4,757	)		(48,427	)		(12,275	)
Chevron transaction expense(2)		(7,670	)		—			(7,670	)		—
Gain (loss) on asset sales and disposal(2)		2			—			(7,019	)		48
Interest expense(2)		(1,423	)		—			(2,529	)		—
Net income (loss)	$	(10,079	)	$	9,400		$	(32,994	)	$	24,640
Capital expenditures
Gas and oil production	$	25,703		$	20,581		$	65,882		$	29,053
Other partnership management		242			776			1,260			3,207
Corporate and other		1,782			531			6,237			4,010
Total capital expenditures	$	27,727		$	21,888		$	73,379		$	36,270

	September 30, 2012		December 31, 2011
Balance sheet
Goodwill:
Gas and oil production	$	18,145	$	18,145
Well construction and completion		6,389		6,389
Other partnership management		7,250		7,250
	$	31,784	$	31,784
Total assets:
Gas and oil production	$	1,040,213	$	593,320
Well construction and completion		7,097		6,987
Other partnership management		53,969		44,981
Corporate and other		37,663		55,825
	$	1,138,942	$	701,113

⁽¹⁾  Includes revenues and expenses from well services, gathering and processing, administration and oversight and other, net that do not meet the quantitative threshold for reporting segment information.

⁽²⁾  The Partnership notes that gain (loss) on asset sales and disposal, general and administrative expenses, Chevron transaction expense and interest expense have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.

NOTE 16 – SUBSEQUENT EVENTS

Cash Distribution. On October 25, 2012, the Partnership declared a cash distribution of $0.43 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2012. The $17.5 million distribution, including $0.4 million and $1.7 million to the general partner and preferred limited partners, respectively, will be paid on November 14, 2012 to unitholders of record at the close of business on November 5, 2012.

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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, 2011. 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.

BUSINESS OVERVIEW

We are a publicly-traded Delaware master-limited partnership (NYSE: ARP) and an independent developer and producer of natural gas and oil, with operations in basins across the United States. We sponsor and manage tax-advantaged investment partnerships, in which we coinvest, to finance a portion of our natural gas and oil production activities.

At September 30, 2012, Atlas Energy, L.P. (“ATLS”), a publicly traded master-limited partnership (NYSE: ATLS), owned 100% of our general partner Class A units and incentive distribution rights through which it manages and effectively controls us, and an approximate 51.5% limited partnership ownership interest (20,960,000 limited partner units) in us.

We were formed in October 2011 to own and operate substantially all of ATLS’ exploration and production assets (the “Atlas Energy E&P Operations”), which were transferred to us on March 5, 2012. In February 2012, the board of directors of ATLS’ general partner approved the distribution of approximately 5.24 million of our common units which were distributed on March 13, 2012 to ATLS’ unitholders using a ratio of 0.1021 of our limited partner units for each of ATLS’ common units owned on the record date of February 28, 2012. The distribution of our limited partner units represented approximately 20% of the common limited partner units outstanding.

On February 17, 2011, ATLS acquired certain assets and liabilities (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of ATLS’ general partner. These assets principally included the following exploration and production assets which were included within Atlas Energy’s E&P Operations:

• AEI’s investment management business, which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which we fund a portion of our natural gas and oil well drilling;

• proved reserves located in the Appalachia Basin, the Niobrara formation in Colorado, the New Albany Shale of west central Indiana, the Antrim Shale of northern Michigan, and the Chattanooga Shale of northeastern Tennessee; and

• certain producing natural gas and oil properties, upon which we are developers and producers.

FINANCIAL PRESENTATION

Our consolidated combined balance sheet at September 30, 2012, the statement of operations for the three months ended September 30, 2012, and the portion of the consolidated combined statement of operations for the nine months ended September 30, 2012 subsequent to the transfer of assets on March 5, 2012 include our accounts and our wholly-owned subsidiaries. Our combined balance sheet at December 31, 2011, the portion of the consolidated combined statements of operations for the nine months ended September 30, 2012 prior to the transfer of assets on March 5, 2012 and the combined statement of operations for the three and nine months ended September 30, 2011 were derived from the separate records maintained by ATLS and may not necessarily be indicative of the conditions that would have existed if we had been operated as an unaffiliated entity. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the consolidated combined balance sheets and related consolidated combined statements of operations. Such estimates included allocations made from the historical accounting records of ATLS, based on management’s best estimates, in order to derive our financial statements for the periods presented prior to the transfer of assets. Actual balances and results could be different from those estimates.

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Upon the acquisition of the Transferred Business on February 17, 2011, ATLS’ management determined that the acquisition constituted a transaction between entities under common control. In comparison to the acquisition method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital/equity. Also, in comparison to the acquisition method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in our consolidated combined financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect of the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, we reflected the impact of the acquisition of the Transferred Business on our consolidated combined financial statements in the following manner:

• Recognized the assets acquired and liabilities assumed from the Transferred Business at their historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital/equity;

• Retrospectively adjusted our consolidated combined financial statements for any date prior to February 17, 2011, the date of acquisition, to reflect our results on a consolidated combined basis with the results of the Transferred Business as of or at the beginning of the respective period; and

• Adjusted the presentation of our consolidated combined statements of operations for any date prior to February 17, 2011 to reflect the results of operations attributable to the Transferred Business as a reduction of net income (loss) to determine income (loss) attributable to common limited partners and the general partner. The Transferred Business’ historical financial statements prior to the date of acquisition reflect an allocation of general and administrative expenses determined by AEI to the underlying business segments, including the Transferred Business. We have reviewed AEI’s general and administrative expense allocation methodology, which is based on the relative total assets of AEI and the Transferred Business, for the Transferred Business’ historical financial statements prior to the date of acquisition and believe the methodology is reasonable and reflects the approximate general and administrative costs of our underlying business segments.

SUBSEQUENT EVENTS

Cash Distribution. On October 25, 2012, we declared a cash distribution of $0.43 per unit on our outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2012. The $17.5 million distribution, including $0.4 million and $1.7 million to the general partner and preferred limited partners, respectively, will be paid on November 14, 2012 to unitholders of record at the close of business on November 5, 2012.

RECENT DEVELOPMENTS

Acquisition of Titan Operating, L.L.C. On July 25, 2012, we completed the acquisition of Titan Operating, L.L.C. (“Titan”) in exchange for 3.8 million common units and 3.8 million newly-created convertible Class B preferred units (which had a collective value of $193.2 million, based upon the closing price of our publicly traded units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments (see “Issuance of Units”). Through the acquisition of Titan, we acquired interests in approximately 52 proved developed natural gas wells and approximately 250 Bcfe of proved reserves and 700 Bcfe of proved, probable and possible reserves and associated assets in the Barnett Shale, located in the Bend Arch – Fort Worth Basin in North Texas. Also, we entered into an amendment to our senior secured revolving credit facility on July 26, 2012 to increase the borrowing base from $250.0 million to $310.0 million. The cash paid at closing was funded through borrowings under our credit facility (see “Credit Facility”). The common units and preferred units were issued and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”) (see “Issuance of Units”).

Acquisition of Assets from Carrizo Oil & Gas, Inc. On April 30, 2012, we acquired certain oil and natural gas assets from Carrizo Oil & Gas, Inc. (NASDAQ: CRZO; “Carrizo”) for approximately $187.0 million in cash. The assets acquired include interests in approximately 200 producing natural gas wells from the Barnett Shale, located in Bend Arch – Fort Worth Basin in North Texas, proved undeveloped acres also in the Barnett Shale and gathering pipelines and associated gathering facilities that service certain of the acquired wells. The purchase price was funded through borrowing under our credit

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facility and $119.5 million of net proceeds from the sale of 6.0 million of our common units at a negotiated purchase price per unit of $20.00, of which $5.0 million was purchased by certain of our executives. The common units were issued in a private transaction exempt from registration under Section 4 (2) of the Securities Act (see “Issuance of Units”).

Equal Acquisition. In April 2012, we acquired a 50% interest in approximately 14,500 net undeveloped acres in the oil and NGL area of the Mississippi Lime play in northwestern Oklahoma for $18.0 million from subsidiaries of Equal Energy, Ltd. (“Equal”) (NYSE: EQU; TSX: EQU). The transaction was funded through borrowings under our revolving credit facility (see “Credit Facility”). Concurrent with the purchase of acreage, we and Equal entered into a participation and development agreement for future drilling in the Mississippi Lime play. We served as the drilling and completion operator, while Equal undertook production operations, including water disposal. In September 2012, we acquired Equal’s remaining 50% interest in the undeveloped acres, as well as approximately 8 Mmcfed of net production in the Mississippi Lime region and salt water disposal infrastructure for $41.3 million, including $1.3 million related to certain post-closing adjustments. The additional acquisition was subject to certain post-closing adjustments and funded with available borrowings under our revolving credit facility (see “Credit Facility”). As a result of our acquisition of Equal’s remaining interest in the undeveloped acres, the existing joint venture agreement between us and Equal in the Mississippi Lime position was terminated and all infrastructure associated with the assets, principally the salt water disposal system, is operated by us.

CONTRACTUAL REVENUE ARRANGEMENTS

Natural Gas. We market the majority of our natural gas production to gas utility companies, gas marketers, local distribution companies and industrial or other end-users. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indexes are as follows: Appalachian Basin and Mississippi Lime, primarily the NYMEX spot market price; Barnett Shale, primarily the Waha spot market price; New Albany Shale and Antrim Shale, primarily the Texas Gas Zone SL and Chicago Hub spot market prices; and Niobrara formation, primarily the Cheyenne Hub spot market price.

Crude Oil. Crude oil produced from our wells flows directly into storage tanks where it is picked up by an oil company, a common carrier or pipeline companies acting for an oil company, which is purchasing the crude oil. We sell any oil produced at the prevailing spot market price in each region.

Natural Gas Liquids. Natural gas liquids (“NGL’s”) are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas (low BTU content) to meet pipeline specifications for long-haul transport to end users. We sell our NGL production at the prevailing spot market price for NGLs.

We do not have delivery commitments for fixed and determinable quantities of natural gas, oil or NGLs in any future periods under existing contracts or agreements.

Investment Partnerships. We generally have funded a portion of our drilling activities through sponsorship of tax-advantaged investment drilling partnerships. In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues, which are not directly dependent on commodity prices. As managing general partner of the investment partnerships, we receive the following fees:

• Well construction and completion. For each well that is drilled by an investment partnership, we receive a 15% to 18% mark-up on those costs incurred to drill and complete the well;

• Administration and oversight. For each well drilled by an investment partnership, we receive a fixed fee between $15,000 and $400,000, depending on the type of well drilled. Additionally, the partnership pays us a monthly per well administrative fee of $75 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well;

• Well services. Each partnership pays us a monthly per well operating fee, currently $100 to $2,000, for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the wells; and

• Gathering. Each royalty owner, partnership and certain other working interest owners pay us a gathering fee, which generally ranges from $0.35 per Mcf to the amount of the competitive gathering fee, currently defined as 13% of the gross sales price of the natural gas. In general, pursuant to gathering agreements we have with a third-party gathering system which gathers the majority of our natural gas, we must also pay an additional amount equal to the excess of the gathering fees collected from the investment partnerships up to an amount equal to approximately 16% of the realized natural gas sales price (adjusted for the settlement of natural gas derivative instruments). As a result, some of our gathering expenses within our partnership management segment, specifically those in the Appalachian Basin, will generally exceed the revenues collected from investment partnerships by approximately 3%.

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GENERAL TRENDS AND OUTLOOK

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

The areas in which we operate are experiencing a significant increase in natural gas, oil and NGL production related to new and increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques, including horizontal and multiple fracturing techniques. The increase in the supply of natural gas has put a downward pressure on domestic prices. While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas, oil and NGL reserves.

Our future gas and oil reserves, production, cash flow, our ability to make payments on our revolving credit facility and our ability to make distributions to our unitholders, including ATLS, depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. We face the challenge of natural production declines and volatile natural gas and oil prices. As initial reservoir pressures are depleted, natural gas production from particular wells decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce.

RESULTS OF OPERATIONS

GAS AND OIL PRODUCTION

Production Profile. Currently, we have focused our natural gas and oil production operations in various shale plays throughout the United States. As part of ATLS’ agreement with AEI to acquire the Transferred Business on February 17, 2011, we have certain agreements which restrict our ability to drill additional wells in certain areas of Pennsylvania, New York and West Virginia, including portions of the Marcellus Shale. Through September 30, 2012, we have established production positions in the following areas:

• the Appalachia basin, including the Marcellus Shale, a rich, organic shale that generally contains dry, pipeline-quality natural gas; 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; and 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 Barnett Shale in the Bend Arch Fort Worth Basin in northern Texas, a hydro-carbon producing shale in which we established a position following our acquisitions of assets from Carrizo and Titan during 2012 (see “Recent Developments”);

• the Mississippi Lime play in northwestern Oklahoma, an oil and natural gas liquids rich area, in which we established a position following our acquisitions from Equal during 2012 (see “Recent Developments”);

• the Niobrara Shale in northeastern Colorado, a predominantly biogenic shale play that produces dry gas;

• the New Albany Shale in southwestern Indiana, a biogenic shale play with a long-lived and shallow decline profile; and

• the Antrim Shale in Michigan, where we produce out of the biogenic region of the shale similar to the New Albany Shale.

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The following table presents the number of wells we drilled, both gross and for our interest, and the number of gross wells we turned in line during the three and nine months ended September 30, 2012 and 2011:

	Three Months  Ended September 30,				Nine Months  Ended September 30,
	2012		2011		2012		2011
Gross wells drilled:
Appalachia		8		9		22		12
Barnett		9		—		9		—
Mississippi Lime		2		—		4		—
Niobrara		—		33		51		50
		19		42		86		62
Our share of gross wells drilled(1):
Appalachia		2		2		6		3
Barnett		8		—		8		—
Mississippi Lime		—		—		1		—
Niobrara		—		6		15		12
		10		8		30		15
Gross wells turned in line:
Appalachia		13		—		46		1
Barnett		3		—		3		—
Mississippi Lime		2		—		2		—
New Albany/Antrim		—		—		—		13
Niobrara		26		7		98		37
		44		7		149		51

⁽¹⁾  Includes (i) our percentage interest in the wells in which we have a direct ownership interest and (ii) our percentage interest in the wells based on our percentage ownership in our investment partnerships.

Production Volumes. The following table presents our total net natural gas, oil, and natural gas liquids production volumes and production per day for the three and nine months ended September 30, 2012 and 2011:

	Three Months  Ended September 30,				Nine Months  Ended September 30,
	2012		2011		2012		2011
Production:(1)(2)
Appalachia:(3)
Natural gas (MMcf)		3,642		2,492		9,661		7,689
Oil (000’s Bbls)		25		27		79		81
Natural gas liquids (000’s Bbls)		38		38		116		122
Total (MMcfe)		4,022		2,880		10,832		8,910
Barnett:(4)
Natural gas (MMcf)		4,055		—		5,830		—
Oil (000’s Bbls)		—		—		—		—
Natural gas liquids (000’s Bbls)		60		—		63		—
Total (MMcfe)		4,417		—		6,210		—
Mississippi Lime:(5)
Natural gas (MMcf)		59		—		59		—
Oil (000’s Bbls)		—		—		—		—
Natural gas liquids (000’s Bbls)		—		—		—		—
Total (MMcfe)		59		—		59		—
New Albany/Antrim:
Natural gas (MMcf)		286		283		837		866
Total (MMcfe)		286		283		837		866
Niobrara:
Natural gas (MMcf)		73		42		198		95
Total (MMcfe)		73		42		198		95
Total:
Natural gas (MMcf)		8,115		2,818		16,586		8,651
Oil (000’s Bbls)		25		27		80		81
Natural gas liquids (000’s Bbls)		98		38		179		122
Total (MMcfe)		8,857		3,206		18,136		9,871

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Production per day: (1)(2)
Appalachia:(3)
Natural gas (Mcfd)	39,583	27,088	35,260	28,166
Oil (Bpd)	275	294	290	297
Natural gas liquids (Bpd)	414	408	422	448
Total (Mcfed)	43,716	31,304	39,533	32,637
Barnett:(4)
Natural gas (Mcfd)	49,440	—	21,278	—
Oil (Bpd)	2	—	1	—
Natural gas liquids (Bpd)	865	—	230	—
Total (Mcfed)	54,642	—	22,663	—
Mississippi Lime:(5)
Natural gas (Mcfd)	7,391	—	216	—
Oil (Bpd)	—	—	—	—
Natural gas liquids (Bpd)	—	—	—	—
Total (Mcfed)	7,391	—	216	—
New Albany/Antrim:
Natural gas (Mcfd)	3,111	3,081	3,054	3,172
Total (Mcfed)	3,111	3,081	3,054	3,172
Niobrara:
Natural gas (Mcfd)	792	461	723	349
Total (Mcfed)	792	461	723	349
Total: (4)(5)
Natural gas (Mcfd)	88,208	30,629	60,531	31,687
Oil (Bpd)	277	294	291	297
Natural gas liquids (Bpd)	1,067	408	652	448
Total (Mcfed)	96,275	34,845	66,189	36,158

⁽¹⁾  Production quantities consist of the sum of (i) our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells, and (ii) our proportionate share of production from wells owned by the investment partnerships in which we have an interest, based on our equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells.

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

⁽³⁾  Appalachia includes our production located in Pennsylvania, Ohio, New York, West Virginia and Tennessee.

⁽⁴⁾  Volumetric production per day for Barnett for the three months ended September 30, 2012 includes production per day associated with the Titan operational assets for the 68-day period from July 25, 2012, the date of acquisition, through September 30, 2012. Total Barnett production per day for the nine months ended September 30, 2012 represents Barnett volume production for the full 274-day period. Total production per day represents total production volume over the 92 and 274 days within the three and nine months ended September 30, 2012, respectively.

⁽⁵⁾  Volumetric production per day for Mississippi Lime for the three months ended September 30, 2012 includes production per day associated with the acquisition of the remaining 50% interest in Equal’s operational assets for the 7-day period from September 24, 2012, the date of acquisition, through September 30, 2012. Total Mississippi Lime production per day for the nine months ended September 30, 2012 represents volume production for the full 274-day period. Total production per day represents total production volume over the 92 and 274 days within the three and nine months ended September 30, 2012, respectively.

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Production Revenues, Prices and Costs. Our production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised 94% of our proved reserves on an energy equivalent basis at December 31, 2011. The following table presents our production revenues and average sales prices for our natural gas, oil, and natural gas liquids production for the three and nine months ended September 30, 2012 and 2011, along with our average production costs, taxes, and transportation and compression costs in each of the reported periods:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Production revenues (in thousands):
Appalachia:(1)
Natural gas revenue	$	8,776	$	10,726	$	29,993	$	33,888
Oil revenue		2,223		2,255		7,601		7,341
Natural gas liquids revenue		895		1,861		4,148		5,930
Total revenues	$	11,894	$	14,842	$	41,742	$	47,159
Barnett:
Natural gas revenue	$	9,666	$	—	$	13,606	$	—
Oil revenue		16		—		18		—
Natural gas liquids revenue		1,620		—		1,767		—
Total revenues	$	11,302	$	—	$	15,391	$	—
Mississippi Lime:
Natural gas revenue	$	112	$	—	$	112	$	—
Oil revenue		—		—		—		—
Natural gas liquids revenue		—		—		—		—
Total revenues	$	112	$	—	$	112	$	—
New Albany/Antrim:
Natural gas revenue	$	1,108	$	1,272	$	3,398	$	4,041
Total revenues	$	1,108	$	1,272	$	3,398	$	4,041
Niobrara:
Natural gas revenue	$	283	$	191	$	680	$	454
Total revenues	$	283	$	191	$	680	$	454
Total:
Natural gas revenue	$	19,945	$	12,189	$	47,789	$	38,383
Oil revenue		2,239		2,255		7,619		7,341
Natural gas liquids revenue		2,515		1,861