UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q10-Q/A

(Amendment No. 1)

(Mark One)

For the quarterly period ended June 30,March 31, 2013

OR

For the transition period from                to                

Commission file number: 1-32953

ATLAS ENERGY, L.P.

(Exact name of registrant as specified in its charter)

Registrant’sRegistrant'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 August 5,May 1, 2013 was 51,389,574.51,373,496.

EXPLANATORY NOTE

This Amendment No. 1 on Form 10-Q/A (the “Amendment”) amends Atlas Energy, L.P.’s (the “Partnership”) Quarterly Report on Form 10-Q for the three months ended March 31, 2013, as originally filed with the Securities and Exchange Commission on May 9, 2013 (the “Original Filing”). The Partnership is filing the Amendment due to staff comments from the United States Securities and Exchange Commission solely to amend and restate:

(a) Part I—Item 1 “Financial Statements” to revise the consolidated statements of comprehensive income (loss) of the Partnership and subsidiaries to reorder certain line items and subtotals presented, separately disclose the amounts of total other comprehensive income (loss), consolidated comprehensive income (loss), including amounts attributable to the common limited partners and attributable to non-controlling interests, and revise certain headings in such financial statements;

(b) Part I—Item 4 “Controls and Procedures” to include a discussion of a material weakness identified subsequent to the Original Filing; and

(c) Part II—Item 6 “Exhibits” to indicate that new certifications by the Partnership’s general partner’s principal executive and principal financial officers, as required by Rule 12b-15, are filed as exhibits to the Amendment.

This Amendment does not affect any other parts of, or exhibits to, the Original Filing, nor does it reflect events occurring after the date of the Original Filing. The previously reported amounts of comprehensive income (loss) attributable to common limited partners did not change for either period.

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS ENERGY, L.P. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM10-Q

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

See accompanying notes to consolidated financial statements.

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

See accompanying notes to consolidated financial statements.

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)

(As Restated)

See accompanying notes to consolidated financial statements.

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in thousands, except unit data)

(Unaudited)

See accompanying notes to consolidated financial statements.

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

See accompanying notes to consolidated financial statements.

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30,March 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 (NYSE: ATLS).

At June 30,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 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 financial statements, which are unaudited except that the balance sheet at December 31, 2012 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 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, 2012. Certain amounts in the prior year’s consolidated financial statements have 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 and six months ended June 30,March 2012 to be consistent with the three and six months ended June 30,March 31, 2013. The results of operations for the three and six months ended June 30,March 31, 2013 may not necessarily be indicative of the results of operations for the full year ending December 31, 2013.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Combination

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

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

ARP and APL into its consolidated 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 statements of operations and as a component of partners’ capital on its consolidated balance sheets. All material intercompany transactions have been eliminated.

In accordance with established practice in the oil and gas industry, the Partnership’s consolidated 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 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 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 financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired and liabilities assumed. 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 six months ended June 30,March 31, 2013 and 2012 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 June 30,March 31, 2013 and December 31, 2012, ARP and APL had recorded no allowance for uncollectible accounts receivable on the Partnership’s consolidated balance sheets.

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Inventory

ARP and APL had $15.4$13.8 million and $13.5 million of inventory at June 30,March 31, 2013 and December 31, 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 consist of APL’s natural gas liquids line fill, which represents amounts receivable for 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 treating systems. Under the composite depreciation method, any gain or loss upon disposition or retirement of pipeline, gas gathering, processing and treating 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 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 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 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’sasset'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

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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 six months ended June 30,March 31, 2013 and 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, 2012, the Partnership recognized $9.5 million of asset impairments 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 Shales. These impairments related to the carrying amounts of these gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2012. The estimate of the fair values 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 six months ended June 30,March 31, 2013 and 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 5.8%6.1% and 5.8%6.7% for the three months ended June 30, 2013 and 2012, respectively, and 6.0% and 6.2% for the six months ended June 30,March 31, 2013 and 2012, respectively. The aggregate amounts of interest capitalized by ARP and APL were $4.8$5.9 million and $2.3 million for the three months ended June 30, 2013 and 2012, respectively, and $10.7 million and $4.6 million for the six months ended June 30,March 31, 2013 and 2012, respectively.

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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 it 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 an acquisition of a gas gathering system 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 three months ended March 31, 2013, including an $8.4 million reduction of the fair value of intangible assets with finite lives. APL’s purchase price allocation for the Cardinal Acquisition has not been completed as of March 31, 2013, and estimates of fair value reflected as of March 31, 2013 are subject to 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 June 30,March 31, 2013 and December 31, 2012 (in thousands):

Amortization expense on intangible assets was $22.3$8.2 million and $6.0$5.9 million for the three months ended June 30, 2013 and 2012, respectively, and $30.5 million and $11.9 million for the six months ended June 30,March 31, 2013 and 2012, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2013 – $78.5- $34.2 million; 2014 – $92.3- $31.0 million; 2015 – $87.0- $25.9 million; 2016 – $86.7- $25.8 million; and 2017 – $80.9- $19.8 million.

Goodwill

At June 30,March 31, 2013, the Partnership had $534.1 million of goodwill, which consisted of $31.8 million related to prior ARP consummated acquisitions and $502.3 million related to APL’s Cardinal and TEAK acquisitions (see Note 3). At December 31, 2012, the Partnership had $351.1 million of goodwill, which consisted of $31.8 million related to prior ARP consummated acquisitions and $319.3 million related to APL’s acquisitions during the year ended December 31, 2012 of which $310.9 million related to the Cardinal acquisition (see Note 3). The change in goodwill is primarily related to an addition of $279.3 million of goodwill from the TEAK acquisition offset by a $97.2 million reduction in goodwill related to an adjustment of the fair value of assets acquired and liabilities assumed from the Cardinal acquisition (see Note 3). The goodwill related to APL’s Cardinal acquisitionAcquisition is a result of the strategic industry position of the assets and potential future synergies. The goodwill related to the TEAK acquisition is a result of the strategic industry position. The valuation assessmentspurchase price allocation for the TEAK and Cardinal acquisitions haveAcquisition has not been completed as of June 30, 2013. Theand the estimated goodwill allocation as of June 30,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 six months ended June 30,March 31, 2013.

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ARP and APL test theirits 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 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 consider 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 six months ended June 30,March 31, 2013, and 2012, 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 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 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 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 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 and six months ended June 30,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 June 30,March 31, 2013, except for: 1) an ongoing examination by the Texas Comptroller of Public Accounts related to APL’s Texas

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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 2)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 June 30,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 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 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) 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):

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

Accrued Producer Liabilities

Accrued producer liabilities on the Partnership’s consolidated balance sheets represent APL’s accrued purchase commitments payable to producers related to the natural gas gathered and processed through its system under its POP and Keep-Whole contracts (see “Revenue Recognition”).

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 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 statements of operations.

ARP generally sells natural gas, crude oil and NGLs at prevailing market prices. 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 two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which 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:

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ARP and APL accrue unbilled revenue and APL accrues the related purchase costs 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” for further description). ARP and APL had unbilled revenues at June 30,March 31, 2013 and December 31, 2012 of $155.6$121.6 million and $134.2 million, respectively, which were included in accounts receivable within the Partnership’s consolidated balance sheets. APL’s accrued purchase costs at June 30, 2013 and December 31, 2012 are included within accrued producer liabilities 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 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 at June 30,March 31, 2013, only include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges (see Note 9).

In 2013, the Partnership revised the presentation of its consolidated statements of comprehensive income (loss) in order to more clearly distinguish the amounts of other comprehensive income (loss) attributable to each of the Partnership and the non-controlling interest. This change in presentation has been applied to all periods presented. The previously reported amounts of other comprehensive income (loss) attributable to the Partnership did not change for any period.

Recently Adopted Accounting Standards

In February 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2013-02,Comprehensive Income (Topic(Topic 220)(“ (“Update 2013-02”).Update 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 its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their 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 amendments prospectively for reporting periods beginning after December 15, 2012, with early adoption being permitted. The Partnership adopted the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it had no material impact on its financial position, results of operations or related disclosures.

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Recently Issued Accounting Standards

In July 2013, the FASB issued ASU 2013-11,Income Taxes (Topic 740) – Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists(“Update 2013-11”), which, among other changes, requires an entity to present an unrecognized tax benefit as a liability and not net with deferred tax assets when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes under the tax law of the applicable jurisdiction that would result from the disallowance of a tax position or when the tax law of the applicable tax jurisdiction does not require, and the entity does not intend to, use the deferred tax asset for such purpose. These requirements are effective for interim and annual reporting periods beginning after December 15, 2013. Early adoption is permitted. These amendments should be applied prospectively to all unrecognized tax benefits that exist at the effective date. Retrospective application is permitted. The Partnership will apply the requirements of Update 2013-11 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In July 2013, the FASB issued ASU 2013-10,Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes(“Update 2013-10”). Currently, Topic 815 provides guidance on the risks that are permitted to be hedged in a fair value or cash flow hedge. In addition, only the interest rates on direct Treasury obligations of the U.S. Government (UST) and the London Interbank Offered Rate (LIBOR) swap rate are considered benchmark interest rates. Update 2013-10 amends Topic 815 to include the Overnight Index Swap Rate (OIS), also referred to as the Fed Funds Effective Swap Rate, as a U.S. benchmark interest rate for hedge accounting purposes. Including the OIS as an acceptable U.S. benchmark interest rate in addition to UST and LIBOR will provide risk managers with a more comprehensive spectrum of interest rate resets to utilize as the designated benchmark interest rate risk component under the hedge accounting guidance in Topic 815. Update 2013-10 is effective for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. The Partnership will apply the requirements of Update 2013-10 upon its effective date of July 17, 2013, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In February 2013, the FASB issued ASU 2013-04,Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date(“ (“Update 2013-04”). Update 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 2013-04 requires an entity to measure joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting 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 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership will apply the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

NOTE 3 ��– ACQUISITIONS

ARP’s DTE Acquisition

On December 20, 2012, ARP completed the acquisition of DTE Gas Resources, LLC from DTE Energy Company (NYSE: DTE; “DTE”) for $257.4 million, subject to certain post-closing adjustments (the “DTE Acquisition”). In connection with entering into a purchase agreement related to the DTE Acquisition, ARP issued approximately 7.9 million of its common limited partner units through a public offering in November 2012 for $174.5 million, which was used to partially repay amounts outstanding under its revolving credit facility prior to closing (see Note 14). The cash paid at closing was funded through $179.8 million of borrowings under ARP’s revolving credit facility and $77.6 million through borrowings under ARP’s term loan credit facility (see Note 8).

ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 10). 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 ARP 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):

ARP’s Titan Acquisition

On July 25, 2012, ARP 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 an estimated collective value of $193.2 million, based upon the closing price of ARP’s publicly traded units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments (see Note 14). The cash paid at closing was funded through borrowings under ARP’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 14).

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ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 10).

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

ARP’s Carrizo Acquisition

On April 30, 2012, ARP 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 purchase price was funded through borrowings under ARP’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 14).

ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 10).

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

APL’s TEAK Acquisition.

On May 7, 2013, APL completed the acquisition of 100% of the equity interests held by TEAK Midstream, LLC (“TEAK”) for $1.0 billion in cash, subject to customary purchase price adjustments, less cash received (the “TEAK Acquisition”), including $50.0 million placed into escrow pending final settlement of working capital adjustments and to cover potential indemnity claims. The funds placed into escrow were recognized within prepaid expenses and other on the Partnership’s consolidated balance sheet as of June 30, 2013. Through the TEAK Acquisition, APL acquired natural gas gathering and processing facilities in southern Texas, including two cryogenic processing facilities, related gathering pipelines, a 75% interest in T2 LaSalle Gathering Company (“T2 LaSalle”), a 50% interest in T2 Eagle Ford Gathering Company (“T2 Eagle Ford”), and a 50% interest in T2 EF Cogeneration Holdings, LLC (“T2 Co-Gen”) (collectively, the “T2 Joint Ventures”).

APL funded the purchase price for the TEAK Acquisition through:

Subsequent to the closing of the TEAK Acquisition, APL issued $400.0 million of its 4.75% unsecured senior notes due November 15, 2021 (“4.75% APL Senior Notes”) on May 10, 2013 for net proceeds of $391.5 million to reduce the level of borrowings under its revolving credit facility, including amounts borrowed in connection with the TEAK Acquisition (see Note 8).

APL accounted for this transaction under the acquisition method of accounting. Accordingly, APL evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 10). In conjunction with the issuance of APL’s common and preferred limited partner units associated with the acquisition, $16.6 million of transaction fees were included in the net proceeds recorded within non-controlling interests on the Partnership’s consolidated balance sheet. All other costs associated with the acquisition 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 APL 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 TEAK Acquisition, based on their estimated fair values at the date of the acquisition (in thousands):