UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended September 30, 2012March 31, 2013

OR

For the transition period fromto

Commission file number: 1-32953

ATLAS ENERGY, L.P.

(Exact name of registrant as specified in its charter)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  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.

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

The number of outstanding common units of the registrant on NovemberMay 1, 20122013 was 51,354,822.51,373,496.

ATLAS ENERGY, L.P. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

TABLE OF CONTENTS

PART 1.I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

See accompanying notes to consolidated combined financial statementsstatements.

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

See accompanying notes to consolidated combined financial statementsstatements.

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)

See accompanying notes to consolidated combined financial statementsstatements.

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in thousands, except unit data)

(Unaudited)

See accompanying notes to consolidated combined financial statementsstatements.

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

See accompanying notes to consolidated combined financial statementsstatements.

ATLAS ENERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED COMBINED FINANCIAL STATEMENTS

September 30, 2012March 31, 2013

(Unaudited)

NOTE 1 –— BASIS OF PRESENTATION

Atlas Energy, L.P., (the “Partnership” or “Atlas Energy”) is a publicly-traded Delaware master limited partnership formerly known as Atlas Pipeline Holdings, L.P. (NYSE: ATLS).

At September 30, 2012,March 31, 2013, the Partnership’s operations primarily consisted of its ownership interests in the following entities:

In February 2012, the board of directors (“the Board”) of the Partnership’s General Partner (“the Board”General Partner”) approved the formation of ARP as a newly created exploration and production master limited partnership and the related transfer of substantially all of the Partnership’s exploration and production assets to ARP on March 5, 2012. The Board also approved the distribution of approximately 5.24 million ARP common units to the Partnership’s unitholders, which were distributed on March 13, 2012 using a ratio of 0.1021 ARP limited partner units for each of the Partnership’s common units owned on the record date of February 28, 2012. The distribution of ARP limited partner units represented approximately 20% of the common limited partner units outstanding at March 13, 2012.

The accompanying consolidated combined financial statements, which are unaudited except that the balance sheet at December 31, 20112012 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the 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, 2011.2012. Certain amounts in the prior year’s consolidated combined financial statements have also been reclassified to conform to the current year presentation. Due to changes in business as a result of the formation of ARP during the year ended December 31, 2012, management of the Partnership modified its reportable operating segments. As a result, management of the Partnership reclassified the operating segment data for the three months ended March 2012 to be consistent with the three months ended March 31, 2013. The results of operations for the three and nine months ended September 30, 2012March 31, 2013 may not necessarily be indicative of the results of operations for the full year ending December 31, 2012.2013.

NOTE 2 –— SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Combination

The consolidated combined financial statements include the accounts of the Partnership and its consolidated subsidiaries, all of which are wholly-owned at September 30, 2012March 31, 2013, except for ARP and APL, which are controlled by the Partnership. Due to the

structure of the Partnership’s ownership interests in ARP and APL, the Partnership consolidates the

financial statements of ARP and APL into its consolidated combined financial statements rather than present its ownership interest as equity investments. As such, the non-controlling interests in ARP and APL are reflected as (income) loss attributable to non-controlling interests in its consolidated combined statements of operations and as a component of partners’ capital on its consolidated balance sheets. All material intercompany transactions have been eliminated.

On February 17, 2011, the Partnership acquired certain producing natural gas and oil properties, the partnership management business, and other assets (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of the Partnership’s general partner (see Note 3). Management of the Partnership 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 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 on the Partnership’s consolidated balance sheets. 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:

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 ARP 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 ARP’s Drilling Partnerships. Rather, ARP calculates these items specific to its own economics as further explained under the heading “Property, Plant and Equipment” elsewhere within this note.

The Partnership’s consolidated combined financial statements also include APL’s 95% ownership interest in joint ventures which individually own a 100% ownership interest in the West OK natural gas gathering system and processing plants and a 72.8% undivided interest in the West TX natural gas gathering system and processing plants. APL consolidates 100% of these joint ventures. The Partnership reflects the non-controlling 5% ownership interest in the joint ventures as non-controlling interests on its consolidated combined statements of operations. The Partnership also reflects the 5% ownership interest in the net assets of the joint ventures as non-controlling interests within partners’ capital on its consolidated balance sheets. The joint ventures have a $1.9 billion note receivable from the holder of the 5% ownership interest in the joint ventures, which was reflected within non-controlling interests on the Partnership’s consolidated balance sheets.

The West TX joint venture has a 72.8% undivided joint venture interest in the West TX system, of which the remaining 27.2% interest is owned by Pioneer Natural Resources Company (NYSE: PXD). Due to the West TX system’s status as an undivided joint venture, the West TX joint venture proportionally consolidates its 72.8% ownership interest in the assets and liabilities and operating results of the West TX system.

The Partnership’s consolidated financial statements also include APL’s 60% interest in Centrahoma Processing LLC (“Centrahoma”), which was acquired on December 20, 2012 as part of the acquisition of assets from Cardinal Midstream, LLC (the “Cardinal Acquisition”) (see Note 3). The remaining 40% ownership interest is held by MarkWest Oklahoma Gas Company LLC (“MarkWest”), a wholly-owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE). APL consolidates 100% of this joint venture and the non-controlling interest in the joint venture is reflected on the Partnership’s consolidated statements of operations. The Partnership also reflects the non-controlling interest in the net assets of the joint ventures within partners’ capital on its consolidated balance sheets (see Note 3).

Use of Estimates

The preparation of the Partnership’s consolidated combined financial statements in conformity with accounting principles generally accepted in the United StatesU.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the 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 Transferred Business prior to February 17, 2011, the date of acquisition (see“Principles of Consolidationacquired and Combination”).liabilities assumed. 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,March 31, 2013 and 2012 and 2011 represent actual results in all material respects (see“Revenue Recognition”).

Receivables

Accounts receivable on the consolidated balance sheets consist solely of the trade accounts receivable associated with ARP’s and APL’s operations. In evaluating the realizability of its accounts receivable, management of ARP and APL 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 ARP’s and APL’s customers’ credit information. ARP and APL extend credit on sales on an unsecured basis to many of its customers. At September 30, 2012March 31, 2013 and December 31, 2011,2012, ARP and APL had recorded no allowance for uncollectible accounts receivable on the Partnership’s consolidated balance sheets.

Inventory

ARP and APL had $11.5$13.8 million and $16.0$13.5 million of inventory at September 30, 2012March 31, 2013 and December 31, 2011,2012, respectively, which were included within prepaid expenses and other current assets on the Partnership’s consolidated balance sheets. ARP values inventories at the lower of cost or market. ARP’s inventories, which consist of materials, pipes, supplies and other inventories, were principally determined using the average cost method. APL’s crude oil and refined product inventory costs consistsconsist of APL’s natural gas liquids line fill, which represents amounts receivable for natural gas liquids (“NGL’s”)NGLs delivered to counterparties for which the counterparty will pay at a designated later period at a price determined by the then current market price.

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. APL follows the composite method of depreciation and has determined the composite groups to be the major asset classes of its gathering, processing and processingtreating systems. Under the composite depreciation method, any gain or loss upon disposition or retirement of pipeline, gas gathering, processing and processingtreating components, is recorded to accumulated depreciation.

ARP 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 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.

ARP’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 ARP’s costs of property interests in proportionately consolidated investment partnerships,Drilling Partnerships, joint venture wells, wells drilled solely by ARP for its interests, properties purchased and working interests with other outside operators.

Upon the sale or retirement of an ARP 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 ARP well, ARP credits the proceeds to accumulated depreciation and depletion within the Partnership’s consolidated balance sheets. Upon ARP’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 and its subsidiaries review their 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 ARP’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 ARP’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. ARP 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, ARP’s reserve estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include ARP’s actual capital contributions, 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.

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

ARP’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships, which ARP sponsors and owns an interest in but does not control. ARP’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which ARP may be unable to recover due to the Drilling Partnerships’ legal structure. ARP may have to pay additional consideration in the future as a 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 ARP 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 ARP.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate that ARP 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 ARP for the three and nine months ended September 30, 2012March 31, 2013 and 2011.2012.

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, 2011,2012, the Partnership recognized $7.0$9.5 million of asset impairmentimpairments related to ARP’s gas and oil properties within property, plant and equipment on its consolidated balance sheet for its shallow natural gas wells in the Antrim and Niobrara Shale. This impairmentShales. These impairments related to the carrying amountamounts of these gas and oil properties being in excess of ARP’s estimate of their fair valuevalues at December 31, 2011.2012. The estimate of the fair valuevalues 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 ARP for the three and nine months ended September 30, 2012March 31, 2013 and 2011.2012.

Capitalized Interest

ARP and APL capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP and APL in the aggregate were 5.1%6.1% and 6.3%6.7% for the three months ended September 30,March 31, 2013 and 2012, and 2011, respectively, and 5.9% and 7.0% for the nine months ended September 30, 2012 and 2011, respectively. The aggregate amounts of interest capitalized by ARP and APL were $2.8$5.9 million and $1.7$2.3 million for the three months ended September 30,March 31, 2013 and 2012, and 2011, respectively, and $7.3 million and $3.2 million for the nine months ended September 30, 2012 and 2011, respectively.

Intangible Assets

Customer contracts and relationships.APL amortizes intangible assets with finite lives in connection with natural gas gathering contracts and customer relationships assumed in certain consummated acquisitions, which APLit amortizes over their estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At a minimum, APL will assess the useful lives of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for APL’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition, adjusted for APL’s management’s estimate of whether the individual relationships will continue in excess or less than the average length. During the year ended December 31, 2012, APL completed acquisitionsan acquisition of variousa gas gathering systemssystem and related assets, which it accounted for as a business combination and initially recognized $10.6 million as customer contract intangible assets in its preliminary purchase price allocation. APL revised its preliminary acquisition purchase price allocation during the ninethree months ended September 30, 2012. APL accountedMarch 31, 2013, including an $8.4 million reduction of the fair value of intangible assets with finite lives. APL’s purchase price allocation for these acquisitionsthe Cardinal Acquisition has not been completed as business combinationsof March 31, 2013, and recognized $20.2 million related to customer contracts with an estimated useful lifeestimates of 10-14 years. The initial recordingfair value reflected as of these transactions was based upon preliminary valuation assessments and isMarch 31, 2013 are subject to change.change and changes could be material.

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

The following table reflects the components of intangible assets being amortized at September 30, 2012March 31, 2013 and December 31, 20112012 (in thousands):

		March 31, 2013				December 31, 2012				Estimated Useful Lives In Years
Gross Carrying Amount:
Customer contracts and relationships		$	316,813			$	325,246			7 – 14
Partnership management and operating contracts			14,344				14,344			13
		$	331,157			$	339,590
Accumulated Amortization:
Customer contracts and relationships		$	(134,027	)		$	(125,886	)
Partnership management and operating contracts			(13,092	)			(13,024	)
		$	(147,119	)		$	(138,910	)
Net Carrying Amount:
Customer contracts and relationships		$	182,786			$	199,360
Partnership management and operating contracts			1,252				1,320
		$	184,038			$	200,680

Amortization expense on intangible assets was $6.3$8.2 million and $5.9 million for the three months ended September 30,March 31, 2013 and 2012, and 2011, respectively, and $18.1 million and $17.8 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 - $24.4 million; 2013 - $25.0– $34.2 million; 2014 - $21.4– $31.0 million; 2015 - $16.4– $25.9 million; 2016 – $25.8 million; and 2016 - $16.42017 – $19.8 million.

Goodwill

At September 30, 2012 and DecemberMarch 31, 2011,2013, the Partnership had $31.8$351.1 million of goodwill, recorded in connection withwhich consisted of $31.8 million related to prior ARP consummated acquisitions.acquisitions and $319.3 million related to APL’s acquisitions during the year ended December 31, 2012 (see Note 3). The goodwill related to APL’s Cardinal Acquisition is a result of the strategic industry position of the assets and potential future synergies. The purchase price allocation for the Cardinal Acquisition has not been completed and the estimated goodwill allocation as of March 31, 2013 is subject to change and may be material. There were no changes in the carrying amount of goodwill for ARP and APL for the three and nine months ended September 30, 2012 and 2011.March 31, 2013.

ARP testsand APL test its goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, management must apply judgment in

determining the estimated fair value of these reporting units. ARP’s and APL’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets.assets and the available market data of the respective industry group. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including ARP’s and APL’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, ARP and APL also considersconsider the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ARP’s and APL’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in ARP’s and APL’s industry to determine whether those valuations appear reasonable in management’s judgment. ARP’s and APL’s 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,March 31, 2013, no impairment indicators arose and no goodwill impairments were recognized for ARP or APL by the Partnership.

Capital Leases

Leased property and equipment meeting capital lease criteria are capitalized based on the minimum payments required under the lease and are included within property, plant and equipment on the Partnership’s consolidated balance sheets. Obligations under capital leases are accounted for as current and noncurrent liabilities and are included within debt on the Partnership’s consolidated balance sheets. Amortization is calculated on a straight-line method based upon the estimated useful lives of the assets (see Note 9)8).

Derivative Instruments

ARP and APL enter into certain financial contracts to manage their exposure to movement in commodity prices and interest rates (see Note 10)9). The derivative instruments recorded in the consolidated balance sheets were measured as either an asset or liability at fair value. Changes in ARP’s and APL’s derivative instrument’s fair value are recognized currently in the Partnership’s consolidated combined statements of operations unless specific hedge accounting criteria are met.

Asset Retirement Obligations

ARP recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 8)7). ARP also 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 and its subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

Income Taxes

The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income (loss) reported in the accompanying consolidated financial statements.

The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its consolidated financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Partnership has not recognized any potential interest or penalties in its consolidated financial statements for the three months ended March 31, 2013 and 2012.

The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2009. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of March 31, 2013, except for: 1) an ongoing examination by the Texas Comptroller of Public Accounts related to APL’s Texas

Franchise Tax for franchise report years 2008 through 2011; 2) an examination by the IRS related to one of APL’s corporate subsidiaries’ Federal Corporate Return for the period ended December 31, 2011; and 3) an examination by the IRS related to one of ARP’s subsidiaries’ Federal Partnership Return for the period ended December 31, 2011.

Certain corporate subsidiaries of the Partnership are subject to federal and state income tax. With the exception of a corporate subsidiary acquired by APL through the Cardinal Acquisition (see Note 3), the federal and state income taxes related to the Partnership and these corporate subsidiaries were immaterial to the consolidated financial statements as of March 31, 2013 and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for these corporate subsidiaries in the accompanying consolidated financial statements. APL’s corporate subsidiary accounts for income taxes under the asset and liability method. Deferred income taxes are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value. The effective tax rate differs from the statutory rate due primarily to APL earnings that are generally not subject to federal and state income taxes at the APL level (see Note 11).

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 16).

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 net income attributable to participating securities, if applicable, by the weighted average number of common limited partner units outstanding during the period.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. The Partnership’s phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plans and incentive compensation agreements (see Note 16), 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.

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

(1)

Net income attributable to common limited partners’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the three and nine months ended September 30,March 31, 2013 and 2012, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 2,106,0002,216,000 and 2,046,0001,929,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.

Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, 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 plans (see Note 16).

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):

Revenue Recognition

Atlas Resource.Certain energy activities are conducted by ARP through, and a portion of its revenues are attributable to, the Drilling Partnerships. ARP contracts with the Drilling Partnerships to drill partnership wells. The contracts require that the Drilling Partnerships must pay ARP 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, ARP 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 balance sheets. ARP recognizes well services revenues at the time the services are performed. ARP 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 the Partnership’s consolidated combined statements of operations.

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

Atlas Pipeline.APL’s revenue primarily consists of the sale of natural gas and NGLs, along with the fees earned from its gathering, processing, treating and transportation operations. Under certain agreements, APL purchases natural gas from producers, moves it into receipt points on its pipeline systems and then sells the natural gas, or produced NGLs, if any, at delivery points on its systems. Under other agreements, APL gathers natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas and NGLs is recognized upon physical delivery. In connection with its gathering, processing and transportation operations, APL enters into the following types of contractual relationships with its producers and shippers:

•

Percentage of Proceeds (“POP”) Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this contract-type, APL and the producer are directly dependent on the volume of the commodity and its value; APL effectively owns a percentage of the commodity and revenues are directly correlated to its market value. POP contracts may include a fee component which is charged to the producer.

ARP and APL accrue unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from ARP’s and APL’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). ARP and APL had unbilled revenues at September 30, 2012March 31, 2013 and December 31, 20112012 of $85.0$121.6 million and $81.2$134.2 million, respectively, which were included in accounts receivable within the Partnership’s consolidated balance sheets.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States,U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s consolidated financial statements, and for the Partnershipat March 31, 2013, only include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.hedges (see Note 9).

Recently Adopted Accounting Standards

In October 2012,February 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2012-04,No. 2013-02,Technical Corrections and ImprovementsComprehensive Income (Topic 220) (“(“Update 2012-04”2013-02”). The amendmentsUpdate 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income 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 locationentirety is 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 andsame reporting period as incurred. For other amounts that are not intendedrequired to resultbe reclassified in a change intheir entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement 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 effectiveprospectively for fiscalreporting periods beginning after December 15, 2012.2012, with early adoption being permitted. 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 disclosures2013-02 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, 2012,2013, and it did not have ahad no 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 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 10). 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 11). The adoption had no material impact on the Partnership’s financial position or results of operations.

Recently Issued Accounting Standards

In July 2012,February 2013, the FASB issued ASU 2012-02,2013-04,Intangibles – GoodwillObligations Resulting from Joint and Other (Topic 350): Testing Indefinite- Lived Intangible AssetsSeveral Liability Arrangements for ImpairmentWhich the Total Amount of the Obligation is Fixed at the Reporting Date(“Update 2012-02”2013-04”). The amendmentsUpdate 2013-04 provides guidance for the recognition, measurement, and disclosure, of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2012-02 allow2013-04 requires an entity to first assess qualitative factors to determine whethermeasure joint and several liability arrangements for which 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 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 carryingtotal amount of the asset. Additionally, underobligation is fixed at the amendments inreporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2012-02, an entity has2013-04 provides disclosure guidance on the option to bypassnature and amount of 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 areobligation as well as other information. Update 2013-04 is effective for annual and interim impairment tests performed for fiscal years and interim periods within those years, beginning after SeptemberDecember 15, 2012, with early adoption being permitted.2013. The Partnership will apply the requirements of Update 2012-022013-04 upon its effective date of January 1, 2013,2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.