8-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8-K/A

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of report (Date of earliest event reported): July 31, 2013

Atlas Energy, L.P.

(Exact name of registrant as specified in its chapter)

Delaware	1-32953	43-2094238
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

Park Place Corporate Center One 1000 Commerce Drive, Suite 400 Pittsburgh, PA	15275
(Address of principal executive offices)	(Zip Code)

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

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Explanatory Note

As previously reported, Atlas Energy, L.P. (“ATLS”) and certain of its affiliates, including Atlas Resource Partners, L.P., completed on July 31, 2013, the previously announced acquisition of oil and gas assets from EP Energy E&P Company, L.P. This Current Report on Form 8-K/A amends Item 9.01 of the Current Report on Form 8-K filed by ATLS, on August 6, 2013, to present certain financial statements of the properties acquired and to present certain unaudited pro forma financial information in connection with the acquisition.

Item 9.01. Financial Statements and Exhibits

(a) Financial Statements of Businesses Acquired.

• The Statements of Combined Revenues and Direct Expenses of Oil and Gas Properties Acquired By Atlas Resource Partners, L.P. for the period January 1, 2012 to May 24, 2012, the period May 25, 2012 to December 31, 2012, and the year ended December 31, 2011, together with independent auditors’ report thereon, and unaudited Statements of Combined Revenues and Direct Expenses of Oil and Gas Properties Acquired By Atlas Resource Partners, L.P. for the six months ended June 30, 2013, the period January 1, 2012 to May 24, 2012, and the period May 25, 2012 to June 30, 2012, are filed as Exhibit 99.1 to this Current Report on Form 8-K/A and are incorporated herein by reference.

(b) Pro Forma Financial Information

The unaudited pro forma consolidated balance sheet of ATLS as of June 30, 2013, and the related pro forma consolidated statements of operations for the six months ended June 30, 2013 and the year ended December 31, 2012, are filed as Exhibit 99.2 to this Current Report on Form 8-K/A and are incorporated herein by reference.

(d) Exhibits

23.1	Consent of Grant Thornton LLP
99.1	Statements of Combined Revenues and Direct Expenses of Oil and Gas Properties Acquired By Atlas Resource Partners, L.P. for the period ended January 1, 2012 to May 24, 2012, the period May 25, 2012 to December 31, 2012, and the year ended December 31, 2011, together with independent auditors’ report thereon, and unaudited Statements of Combined Revenues and Direct Expenses of Oil and Gas Properties Acquired By Atlas Resource Partners, L.P. for the six months ended June 30, 2013, the period January 1, 2012 to May 24, 2012, and the period May 25, 2012 to June 30, 2012
99.2	Unaudited pro forma consolidated financial statements

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SIGNATURES

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

Dated: October 15, 2013	ATLAS ENERGY, L.P.
	By: Atlas Energy GP, LLC, its general partner
	By:	/s/ Sean P. McGrath
	Name:	Sean P. McGrath
	Its:	Chief Financial Officer

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EXHIBIT INDEX

Exhibit No.	Description
23.1	Consent of Grant Thornton LLP
99.1	Statements of Combined Revenues and Direct Expenses of Oil and Gas Properties Acquired By Atlas Resource Partners, L.P. for the period January 1, 2012 to May 24, 2012, the period May 25, 2012 to December 31, 2012, and the year ended December 31, 2011, together with independent auditors’ report thereon, and unaudited Statements of Combined Revenues and Direct Expenses of Oil and Gas Properties Acquired By Atlas Resource Partners, L.P. for the six months ended June 30, 2013, the period January 1, 2012 to May 24, 2012, and the period May 25, 2012 to June 30, 2012
99.2	Unaudited pro forma consolidated financial statements

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EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our report dated October 9, 2013, with respect to the Statements of Combined Revenues and Direct Expenses of Oil and Gas Properties Acquired by Atlas Resource Partners, L.P. from EP Energy LLC for the year ended December 31, 2011, the period January 1, 2012 to May 24, 2012, and the period May 25, 2102 to December 31, 2012 included in the Current Report of Atlas Energy, L.P. on Form 8-K/A, dated July 31, 2013. We hereby consent to the incorporation by reference of said report in the Registration Statements of Atlas Energy, L.P. on Forms S-8 (File No. 333-138589, effective November 9, 2006, File No. 333-173082, effective March 25, 2011 and File No. 333-180568, effective April 4, 2012).

/s/ GRANT THORNTON LLP

Cleveland, Ohio

October 15, 2013

EX-99.1

Exhibit 99.1

REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

Management of

EP Energy LLC

We have audited the accompanying Statements of Combined Revenues and Direct Expenses of Oil and Gas Properties (the “Statements”) Acquired by Atlas Resource Partners, L.P. from EP Energy LLC, for the period January 1, 2012 to May 24, 2012, the period May 25, 2012 to December 31, 2012, and the year ended December 31, 2011, and the related notes to the Statements.

Management’s responsibility for the financial statements

Management is responsible for the preparation and fair presentation of these Statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of the Statements that are free from material misstatement, whether due to fraud or error.

Auditor’s responsibility

Our responsibility is to express an opinion on these Statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the Statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the Statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the Statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the Statements referred to above present fairly, in all material respects, the Combined Revenues and Direct Expenses of Oil and Gas Properties Acquired by Atlas Resource Partners, L.P. for the period January 1, 2012 to May 24, 2012, the period May 25, 2012 to December 31, 2012, and the year ended December 31, 2011 in accordance with accounting principles generally accepted in the United States of America.

Emphasis of matter

We draw attention to Note 1 to the Statements, which describes that the accompanying Statements were prepared for the purpose of complying with the rules and regulations of Securities and Exchange Commission and are not intended to be a complete presentation of EP Energy LLC’s revenues and expenses. Our opinion is not modified with respect to this matter.

We also draw attention to Note 1 to the Statements, which describes that effective May 24, 2012, EP Energy LLC was acquired in a business combination accounted for under the acquisition method of accounting. As a result of the acquisition, the financial information for the period after the acquisition is presented on a different basis of accounting than that for the period before the acquisition and therefore the financial information for the two periods is not comparable. Our opinion is not modified with respect to this matter.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

October 9, 2013

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STATEMENTS OF COMBINED REVENUES AND DIRECT EXPENSES

OF OIL AND GAS PROPERTIES ACQUIRED BY ATLAS RESOURCE PARTNERS, L.P.

(In thousands)

	Successor Period		Predecessor Period
	For the		For the
	Period of		Period of			For the
	May 25 to		January 1 to			Year Ended
	December 31,		May 24,			December 31,
	2012		2012			2011
Gas and oil revenues	$	81,533	$	47,564		$	198,332
Direct expenses:
Operating expenses		42,625		31,625			84,551
Depreciation, depletion and amortization		19,076		49,373			102,336
Total direct expenses		61,701		80,998			186,887
Revenues in excess of (less than) direct expenses	$	19,832	$	(33,434	)	$	11,445

The accompanying notes are an integral part of these combined statements.

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STATEMENTS OF COMBINED REVENUES AND DIRECT EXPENSES

OF OIL AND GAS PROPERTIES ACQUIRED BY ATLAS RESOURCE PARTNERS, L.P.

(In thousands)

(Unaudited)

	Successor Period				Predecessor Period
	For the		For the		For the
	Six Months		Period of		Period of
	Ended		May 25 to		January 1 to
	June 30,		June 30,		May 24
	2013		2012		2012
Gas and oil revenues	$	77,701	$	11,074	$	47,564
Direct expenses:
Operating expenses		35,615		7,203		31,625
Depreciation, depletion and amortization		15,207		2,305		49,373
Total direct expenses		50,822		9,508		80,998
Revenues in excess of (less than) direct expenses	$	26,879	$	1,566	$	(33,434	)

The accompanying notes are an integral part of these combined statements.

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NOTES TO STATEMENTS OF COMBINED REVENUES AND DIRECT EXPENSES

OF OIL AND GAS PROPERTIES ACQUIRED BY ATLAS RESOURCE PARTNERS, L.P.

1. BASIS OF PRESENTATION

On July 31, 2013, Atlas Resource Partners, L.P. (“Atlas”) closed on the previously announced acquisition of certain assets (the “Properties”) from EP Energy E&P Company, L.P. (“EP Energy”) for approximately $705.9 million in cash, net of purchase price adjustments. The assets acquired included coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming (the “Coal-bed Methane Assets”). The Properties were acquired on May 24, 2012, by EP Energy from its related party predecessor with investment funds affiliated with and managed by Apollo Global Management LLC and other private equity investors. Subsequent to this acquisition, EP Energy began applying the successful efforts method of accounting for its oil and natural gas exploration and development activities (see “Depreciation, Depletion, and Amortization”).

The accompanying statements include revenues from the sale of crude oil, natural gas liquids and natural gas production and direct expenses associated with the Properties for the indicated periods prior to the closing date. Revenues and direct expenses are presented on the accrual basis of accounting and were derived from EP Energy’s historical accounting records. During the periods presented, the Properties were not accounted for or operated as a separate division or entity by EP Energy, therefore, certain expenses such as general and administrative, interest and corporate income taxes were not allocated to the Properties. Accordingly, complete separate financial statements reflecting the financial position, results of operations and cash flows of the Properties prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) are not presented because the information necessary to prepare such statements is neither readily available on an individual property basis, nor practicable to obtain in these circumstances. As such, the accompanying statements are not intended to be a complete presentation of the revenues and expenses of the Properties and are not indicative of the results of the operation of the Properties going forward due to the omission of various expenses as described above. Accordingly, the accompanying combined statements of revenues and direct expenses of the Properties are presented in lieu of the GAAP financial statements required under Item 3-05 of Securities and Exchange Commission (“SEC”) Regulation S-X.

Revenue Recognition

Gas revenues are recognized when production is sold to purchasers at a fixed or determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. Gas revenues have been presented on the sales method of accounting whereby revenue is recognized for all gas sold to purchasers, regardless of whether the sales are proportionate to the ownership interest in the property. Revenues are reported net of royalties and other revenue interests of third parties. All gas sales prior to May 25, 2012 were sold to a related party. For the period May 25 to December 31, 2012, four customers individually accounted for 25%, 15%, 12% and 11% of gas revenues.

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Direct Expenses

Direct operating expenses are recognized when incurred and include (a) lease operating expenses which consist of lease and well repairs and maintenance, gathering and transportation, utilities and other direct operating expenses (b) production taxes and (c) ad valorem taxes.

Depreciation, Depletion and Amortization

Depreciation, depletion, and amortization expenses are reflected under the successful efforts method of accounting for natural gas and oil extraction activities for periods subsequent to May 24, 2012, and under the full cost method for periods prior to May 24, 2012. On May 24, 2012, investment funds affiliated with and managed by Apollo Global Management LLC and other private equity investors acquired EP Energy. Subsequent to this acquisition, EP Energy began applying the successful efforts method of accounting for oil and natural gas exploration and development activities. Under the successful efforts method, the provision for depreciation, depletion, and amortization is determined on a basis identified by common geological structure or stratigraphic conditions applied to total capitalized costs, plus future abandonment costs net of salvage value, using the unit of production method. Lease acquisition costs are amortized over total proved reserves, and other exploratory drilling and all developmental costs are amortized over total proved developed reserves.

Prior to the acquisition of EP Energy (May 24, 2012), depletion was calculated under the full cost method. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves were capitalized on a country-by-country basis. Under full cost accounting, capitalized costs associated with proved reserves were amortized over the life of the proved reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties were excluded from the amortizable base until these properties were evaluated or determined that the costs were impaired. On a quarterly basis, unproved property costs were transferred into the amortizable base when properties were determined to have proved reserves. The amortizable base included future development costs; dismantlement, restoration and abandonment costs, net of estimated salvage values; and geological and geophysical costs incurred that could not be associated with specific unevaluated properties or prospects.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the reporting period. These estimates and assumptions are based on management’s best estimates and judgment. Actual results may differ from the estimates and assumptions used in the preparation of the combined statements of revenues and direct operating expenses. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Management evaluates subsequent events through the date the financial statements are issued.

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 periods indicated in the accompanying statements represent actual results in all material respects.

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The statements of combined revenues and direct expenses for the six months ended June 30, 2013 and 2012, are unaudited, but in the opinion of management include all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the accompanying combined revenues and direct expenses of the interim periods.

2. COMMITMENTS AND CONTINGENCIES

Pursuant to the terms of the purchase and sale agreement between EP Energy and Atlas, certain liabilities arising in connection with ownership of the Properties prior to the effective date are retained by EP Energy. Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the combined statements of revenues and direct expenses.

3. SUBSEQUENT EVENTS

On July 31, 2013, Atlas completed its acquisition of the Properties for cash consideration of $705.9 million, net of purchase price adjustments, which remains subject to final post-closing adjustments. The Company has evaluated subsequent events through October 9, 2013 and no additional events requiring disclosure have occurred.

4. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

The following tables summarize the net ownership interest in the proved gas and oil reserves and the standardized measure of discounted future net cash flows related to the proved gas and oil reserves for the Properties. and these estimates were prepared by EP Energy based on the reserve reports prepared for EP Energy’s Annual Reports on Form 10-K for the years ended December 31, 2012 and 2011. The standardized measure presented here excludes income taxes as the tax basis for the Properties is not applicable on a go-forward basis. The proved gas and oil reserve estimates and other components of the standardized measure were determined in accordance with the authoritative guidance of the Financial Accounting Standards Board and the SEC.

Proved Gas and Oil Reserve Quantities

Proved reserves are those quantities of gas and oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. The net proved gas and oil reserves and changes in net proved gas and oil reserves attributable to the Properties, all of which are located primarily in the states of New Mexico, Alabama and Wyoming, are summarized below:

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	Natural Gas (MMcf)			Crude Oil, Condensate and Natural Gas Liquids (MBbls)		Total (MMcfe)
Proved developed and undeveloped reserves -
January 1, 2011		783,356			—		783,356
Extensions and discoveries		18,780			—		18,780
Revisions of previous estimates		14,150			—		14,150
Production		(50,505	)		—		(50,505	)
End of Year—December 31, 2011		765,781			—		765,781
Proved developed reserves at beginning of year		554,906			—		554,906
Proved developed reserves at end of year		545,237			—		545,237
Proved undeveloped reserves at beginning of year		228,450			—		228,450
Proved undeveloped reserves at end of year		220,544			—		220,544
Proved developed and undeveloped reserves -
January 1, 2012		765,781			—		765,781
Extensions and discoveries		1,705			—		1,705
Revisions of previous estimates		(164,020	)		—		(164,020	)
Production		(47,030	)		—		(47,030	)
End of Year—December 31, 2012		556,436			—		556,436
Proved developed reserves at beginning of year		545,237			—		545,237
Proved developed reserves at end of year		431,502			—		431,502
Proved undeveloped reserves at beginning of year		220,544			—		220,544
Proved undeveloped reserves at end of year		124,934			—		124,934

Standardized Measure

The standardized measure of discounted future net cash flows before income taxes related to the proved gas and oil reserves of the Properties is as follows:

	Years Ended December 31,
	2012			2011
	(in thousands)
Future cash inflows	$	1,321,983		$	2,822,400
Future production costs		(738,248	)		(1,204,952	)
Future development costs		(163,469	)		(298,624	)
Future net cash flows		420,266			1,318,824
Less 10% annual discount for estimated timing of cash flows		(201,674	)		(726,648	)
Standardized measure of discounted future net cash flows	$	218,592		$	592,176

FASB requirements for gas and oil reserve estimation and disclosure require that reserve estimates and future cash flows be based on the average market prices for sales of gas and oil on the first calendar day of each month during the year. The average prices used for 2012 and 2011 under these rules were $2.76 and $4.12 per Mcf.

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Future operating expenses and development costs are computed primarily by EP Energy’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the proved gas and oil reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. The standardized measure presented here does not include the effects of income taxes as the tax basis for the Properties is not applicable on a go-forward basis. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in gas and oil reserve estimates.

Changes in Standardized Measure

Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved gas and oil reserves of the Properties are as follows:

	Years Ended December 31,
	2012			2011
	(in thousands)
Changes in Standardized Measure:
Standardized measure—beginning of year	$	592,176		$	660,619
Revisions to reserves proved in prior years:
Net change in sales prices and production costs related to future production		(349,076	)		(26,668	)
Net change in estimated future development costs		73,781			(15,697	)
Net change due to revisions in quantity estimates		(94,806	)		16,432
Accretion of discount		72,665			80,681
Changes in production rates (timing) and other		(535	)		(18,876	)
Total revisions		(297,971	)		35,872
Net change due to extensions and discoveries, net of estimated future development and production costs		540			10,650
Sales of oil and gas produced, net of production costs		(78,153	)		(137,357	)
Previously estimated development costs incurred		2,000			22,392
Net change in standardized measure of discounted future net cash flows		(373,584	)		(68,443	)
Standardized measure—end of year	$	218,592		$	592,176

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EX-99.2

Exhibit 99.2

UNAUDITED PRO FORMA FINANCIAL INFORMATION

The following unaudited pro forma consolidated financial data reflects Atlas Energy, L.P.’s (NYSE: ATLS; the “Partnership” or “ATLS”) historical results as adjusted on a pro forma basis to give effect to (A) Atlas Resource Partners, L.P.’s (NYSE: ARP; “ARP”) acquisitions of (i) certain assets from Carrizo Oil & Gas, Inc. (NASDAQ: CRZO; “Carrizo”) on April 30, 2012 and the related issuance of 6.0 million common limited partner units in a private placement to partially fund the purchase price, (ii) certain proved reserves and associated assets from Titan Operating, L.L.C. (“Titan”) on July 25, 2012 for 3.8 million ARP common limited partner units and 3.8 million ARP convertible Class B preferred units, as well as $15.4 million in cash for closing adjustments, (iii) DTE Gas Resources, LLC (“DTE”) for gross cash consideration of $257.4 million funded with borrowings under ARP’s revolving and term loan credit facilities, and (iv) certain oil and gas assets from EP Energy E&P Company, L.P. (“EP Energy”) for $705.9 million in cash, net of purchase price adjustments (the “EP Energy Acquisition”), funded with borrowings under ARP’s revolving credit facility, ARP’s issuance of its newly created ARP Class C convertible preferred units to the Partnership and the issuance of the ARP’s 9.25% senior notes due August 15, 2021 (“9.25% ARP Senior Notes”); (B) (i) Atlas Pipeline Partners, L.P.’s (NYSE: APL; “APL”) December 20, 2012 acquisition from Cardinal Midstream, LLC (“Cardinal”) of 100% of the equity interests in three wholly-owned subsidiaries (the “Cardinal Acquisition”), which includes a 60% interest in a joint venture, known as Centrahoma Processing, LLC (“Centrahoma”), of which the remaining 40% interest in Centrahoma is owned by MarkWest Oklahoma Gas Company, LLC (“MarkWest”), a wholly-owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE; “MWE”), (ii) the related issuance of 10.5 million of APL’s common limited partner units in a public offering to partially fund the purchase, (iii) the related issuance of $175.0 million of APL’s 6.625% senior unsecured notes due on October 1, 2020 (“6.625% APL Senior Notes”) to partially fund the purchase price, and (iv) borrowings from APL’s senior secured revolving credit facility to partially fund the purchase price; and (C) (i) APL’s May 7, 2013 acquisition from TEAK Midstream, LLC (“TEAK”) of 100% of the outstanding member and other ownership interests of TEAK for $1.0 billion, (ii) the related issuance of 11.8 million of APL’s common limited partner units in a public offering to partially fund the purchase price, (iii) APL’s issuance of $400.0 million of its Class D convertible preferred units to partially fund the purchase price, and (iv) the related issuance of $400.0 million of APL’s 4.75% senior unsecured notes due on November 15, 2021 (“4.75% APL Senior Notes”) to partially fund the purchase price. The estimated adjustments to give effect to the acquisitions are described in the notes to the unaudited pro forma financial data.

The unaudited pro forma consolidated statements of operations information for the six months ended June 30, 2013 and the year ended December 31, 2012 assume the following transactions had occurred as of January 1, 2012. In addition, the pro forma consolidated balance sheet as of June 30, 2013 reflects the following transactions as if they had occurred on June 30, 2013:

• the Carrizo acquisition for gross cash consideration of $190.0 million, net of $3.0 million of purchase price reductions for working capital and other amounts, which was funded through (i) the private placement of approximately 6.0 million ARP common units at a negotiated purchase price of $20.00 per unit and (ii) borrowings of $67.5 million under ARP’s revolving credit facility;

• the Titan acquisition for 3.8 million ARP common units and 3.8 million ARP convertible Class B preferred units, as well as $15.4 million in cash for closing adjustments, which was funded through borrowings under ARP’s revolving credit facility;

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• the sale of 7.9 million of ARP’s common units for net proceeds of $174.5 million, the net proceeds of which were used to repay borrowings under ARP’s revolving credit facility prior to funding the cash consideration for the DTE acquisition;

• the DTE acquisition for gross cash consideration of $257.4 million, including $2.4 million of adjustments for working capital, which was funded through borrowings of $179.8 million from ARP’s revolving credit facility and $77.6 from ARP’s term loan credit facility;

• the issuance of ARP’s 7.75% senior unsecured notes due on January 15, 2021 (“7.75% ARP Senior Notes”) for net proceeds of $268.3 million, which were used to repay all of the indebtedness and accrued interest outstanding under ARP’s term loan credit facility and a portion of that outstanding under ARP’s revolving credit facility;

• the EP Energy Acquisition for cash consideration of $705.9 million, net of purchase price adjustments, which was funded through borrowings under ARP’s revolving credit facility, the sale of 15.0 million of ARP’s common units for net proceeds of $313.1 million (which were issued in June 2013), the issuance of ARP’s newly created Class C convertible preferred units to ATLS for $86.6 million and net proceeds of $242.8 million from the issuance of 9.25% ARP Senior Notes at a discount of 99.297% (which were issued in July 2013). The historical results of operations for the period January 1, 2012 to December 31, 2012 and from January 1, 2012 to June 30, 2012, which include the results of operations of EP Energy subsequent to its acquisition of the assets on May 24, 2012 and its related party predecessor, were combined for presentation purposes;

• the Cardinal acquisition for $598.3 million in cash, which was partially funded through (i) the issuance of 10.5 million of APL’s common limited partner units in a public offering, (ii) the issuance of $175.0 million of 6.625% APL Senior Notes, and (iii) borrowings under APL’s revolving credit facility; and

• the TEAK acquisition for $1.0 billion, which was partially funded through (i) the issuance of 11.8 million of APL’s common limited partner units in a public offering, (ii) the issuance of $400.0 million of APL’s Class D convertible preferred units, and (iii) the issuance of $400.0 million of APL’s 4.75% APL Senior Notes.

The unaudited pro forma consolidated balance sheet and the unaudited pro forma consolidated statements of operations were derived by adjusting the Partnership’s historical consolidated financial statements. However, management of the Partnership believes that the adjustments provide a reasonable basis for presenting the significant effects of the transactions described above. The unaudited pro forma financial data presented is for informational purposes only and is based upon available information and assumptions that management of the Partnership believes are reasonable under the circumstances. The allocation of the fair value of the assets acquired and liabilities assumed is based upon their estimated fair values, which are subject to adjustment and could change significantly as the Partnership continues to evaluate the preliminary allocations related to the DTE, EP Energy, Cardinal and TEAK acquisitions. This unaudited pro forma financial information is not necessarily indicative of what the financial position or results of operations of the Partnership would have been had the transactions been consummated on the dates assumed, nor are they necessarily indicative of any future operating results or financial position. The Partnership may have performed differently had the transactions actually occurred on the dates assumed.

Consolidated supplemental oil and gas disclosures as of December 31, 2012, which were presented inclusive of the Carrizo, Titan and DTE acquisitions, were included with the Partnership’s annual filing on Form 10-K for the year ended December 31, 2012 specifically in Item 8: Financial Statements and Supplementary Data – Footnote 21 “Supplemental Oil and Gas Disclosures (Unaudited)”.

2

In February 2012, the board of directors of the Partnership’s General Partner (“the Board”) 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 5.2 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.

3

ATLAS ENERGY, L.P. AND SUBSIDIARIES

PRO FORMA CONSOLIDATED BALANCE SHEET

June 30, 2013

(in thousands)

(Unaudited)

			Acquisition
	Historical		EP Energy			Adjustments			Pro Forma
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	70,430	$	—		$	705,900	(b)	$	70,430
							(705,900	)(d)
Accounts receivable		250,755		—			—			250,755
Current portion of derivative asset		64,402		—			—			64,402
Subscriptions receivable		11,036		—			—			11,036
Prepaid expenses and other		72,595		—			—			72,595
Total current assets		469,218		—			—			469,218
PROPERTY, PLANT AND EQUIPMENT, NET		4,036,187		722,803	(a,hh)		—			4,758,990
INTANGIBLE ASSETS, NET		570,999		—			—			570,999
INVESTMENT IN JOINT VENTURE		232,090		—			—			232,090
GOODWILL, NET		534,105		—			—			534,105
LONG-TERM DERIVATIVE ASSET		26,759		—			—			26,759
OTHER ASSETS, NET		92,721		—			15,057	(c)		113,278
							5,500	(c)
	$	5,962,079	$	722,803		$	20,557		$	6,705,439
LIABILITIES AND PARTNERS’ CAPITAL/EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt	$	522	$	—		$	—		$	522
Accounts payable		94,270		—			—			94,270
Accrued producer liabilities		140,505		—			—			140,505
Current portion of derivative liability		167		—			—			167
Current portion of derivative payable to Drilling Partnerships		5,969		—			—			5,969
Accrued interest		35,281		—			—			35,281
Accrued well drilling and completion costs		52,425		—			—			52,425
Accrued liabilities		118,006		—			—			118,006
Total current liabilities		447,145		—			—			447,145
LONG-TERM DEBT, LESS CURRENT PORTION		1,944,297		—			371,034	(b)		2,589,739
							248,241	(b)
							26,167	(c)

4

LONG-TERM DERIVATIVE LIABILITY		130		—			—			130
LONG-TERM DERIVATIVE PAYABLE TO DRILLING PARTNERSHIPS		38		—			—			38
DEFERRED INCOME TAXES, NET		35,513		—			—			35,513
ASSET RETIREMENT OBLIGATIONS AND OTHER		77,890		16,903	(a)		—			94,793
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL/EQUITY:
Common limited partners’ interests		448,808		—			86,625	(b)		533,369
							(2,064	)(c)
Equity		—		705,900	(a)		(705,900	)(d)		—
Accumulated other comprehensive income (loss)		13,927		—			—			13,927
		462,735		705,900			(621,339	)		547,296
Non-controlling interests		2,994,331		—			(3,546	)(c)		2,990,785
Total partners’ capital/equity		3,457,066		705,900			(624,885	)		3,538,081
	$	5,962,079	$	722,803		$	20,557		$	6,705,439

5

ATLAS ENERGY, L.P. AND SUBSIDIARIES

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE SIX MONTHS ENDED JUNE 30, 2013

(in thousands)

(Unaudited)

				For the Period January 1 to May 7, 2013			For the Period January 1 to June 30, 2013
	Historical			TEAK			EP Energy		Adjustments			Pro Forma
REVENUES:
Gas and oil production	$	93,158		$	—		$	77,701	$	—		$	170,859
Well construction and completion		81,329			—			—		—			81,329
Gathering and processing		956,009			34,605			—		—			990,614
Administration and oversight		4,476			—			—		—			4,476
Well services		9,680			—			—		—			9,680
Loss on mark-to-market derivatives		15,024			—			—		—			15,024
Other, net		6,221			(2,729	)		—		119	(e)		3,611
Total revenues		1,165,897			31,876			77,701		119			1,275,593
COSTS AND EXPENSES:
Gas and oil production		34,251			—			35,615		—			69,866
Well construction and completion		70,721			—			—		—			70,721
Gathering and processing		805,609			29,125			—		—			834,734
Well services		4,623			—			—		—			4,623
General and administrative		94,532			1,575			—		(18,161	)(f)		71,466
										(6,480	)(g)
Depreciation, depletion and amortization		120,246			2,391			15,207		8,068	(e)		145,912
Total costs and expenses		1,129,982			33,091			50,822		(16,573	)		1,197,322
OPERATING INCOME (LOSS)		35,915			(1,215	)		26,879		16,692			78,271
Interest expense		(53,341	)		(2,499	)		—		2,499	(h)		(71,950	)
										(5,340	)(i)
										(339	)(j)
										(1,359	)(k)
										(11,673	)(l)
										(1,303	)(m)
										(1,506	)(n)
										(344	)(o)
										3,255	(p)
Gain (loss) on asset sales and disposal		(2,893	)		269			—		—			(2,624	)
Loss on early extinguishment of debt		(26,601	)		—			—		—			(26,601	)
NET INCOME (LOSS) BEFORE TAX		(46,920	)		(3,445	)		26,879		582			(22,904	)

6

Income tax benefit		37			—			—		—			37
NET INCOME (LOSS)		(46,883	)		(3,445	)		26,879		582			(22,867	)
(Income) loss attributable to non-controlling interests		26,040			—			—		(5,646	)(q)		9,970
										(10,424	)(r)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON LIMITED PARTNERS	$	(20,843	)	$	(3,445	)	$	26,879	$	(15,488	)	$	(12,897	)
NET LOSS ATTRIBUTABLE TO COMMON LIMITED PARTNERS PER UNIT:
Basic	$	(0.41	)									$	(0.25	)
Diluted	$	(0.41	)									$	(0.25	)
WEIGHTED AVERAGE COMMON LIMITED PARTNER UNITS OUTSTANDING:
Basic		51,375											51,375
Diluted		51,375											51,375

7

ATLAS ENERGY, L.P. AND SUBSIDIARIES

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2012

(in thousands, except per unit data)

(Unaudited)

			For the Period from January 1 to April 30, 2012		For the Period from January 1 to July 25, 2012		For the Period from January 1 to December 20, 2012			For the Period from January 1 to December 20, 2012		For the Year Ended December 31, 2012			For the Year Ended December 31, 2012
	Historical		Carrizo		Titan		DTE			Cardinal		Teak			EP Energy		Adjustments			Pro Forma
REVENUES:
Gas and oil production	$	92,901	$	6,878	$	10,938	$	53,060		$	—	$	—		$	129,097	$	—		$	292,874
Well construction and completion		131,496		—		—		—			—		—			—		—			131,496
Gathering and processing		1,219,815		—		—		—			66,062		27,353			—		197,773	(s)		1,511,003
Administration and oversight		11,810		—		—		—			—		—			—		—			11,810
Well services		20,041		—		—		—			—		—			—		—			20,041
Gain on mark-to-market derivatives		31,940		—		—		—			—		—			—		—			31,940
Other, net		13,440		—		68		(187	)		1,769		(1,351	)		—		337	(t)		14,076
Total revenues		1,521,443		6,878		11,006		52,873			67,831		26,002			129,097		198,110			2,013,240
COSTS AND EXPENSES:
Gas and oil production		26,624		4,278		4,470		21,295			—		—			74,250		—			130,917
Well construction and completion		114,079		—		—		—			—		—			—		—			114,079
Gathering and processing		1,009,100		—		—		—			26,175		22,728			—		197,773	(s)		1,255,776
Well services		9,280		—		—		—			—		—			—		—			9,280
General and administrative		165,777		—		3,284		7,091			5,719		4,167			—		(15,372	)(f)		149,191
																		(21,475	)(g)
Chevron transaction expense		7,670		—		—		—			—		—			—		—			7,670
Depreciation, depletion and amortization		142,611		—		11,511		22,438			14,837		3,164			68,449		5,491	(u)		300,029
																		69	(v)
																		31,459	(t)
Asset impairment		9,507		—		—		—			—		—			—		—			9,507
Total costs and expenses		1,484,648		4,278		19,265		50,824			46,731		30,059			142,699		197,945			1,976,449

8

OPERATING INCOME (LOSS)		36,795		2,600	(8,259	)	2,049		21,100		(4,057	)	(13,602	)	165			36,791
Interest expense		(46,520	)	—	(1,683	)	(5,565	)	(2,955	)	(4,849	)	—		(551	)(w)		(146,144	)
															(5,441	)(x)
															(265	)(y)
															(7,058	)(z)
															(836	)(aa)
															551	(bb)
															265	(bb)
															7,058	(bb)
															(21,314	)(cc)
															7,804	(dd)
															(29,395	)(ee)
															(1,504	)(ff)
															(3,587	)(k)
															(23,345	)(l)
															(3,011	)(n)
															(688	)(o)
															(3,255	)(p)
Loss on asset sales and disposal		(6,980	)	—	—		—		—		—		—		—			(6,980	)
Loss on early extinguishment of debt		—		—	(810	)	—		—		—		—		—			(810	)
NET INCOME (LOSS) BEFORE TAX		(16,705	)	2,600	(10,752	)	(3,516	)	18,145		(8,906	)	(13,602	)	(84,407	)		(117,143	)
Income tax expense (benefit)		176		—	—		—		845		—		—		(2,238	)(gg)		(1,217	)
NET INCOME (LOSS)		(16,881	)	2,600	(10,752	)	(3,516	)	17,300		(8,906	)	(13,602	)	(82,169	)		(115,926	)
(Income) loss attributable to non-controlling interests		(35,532	)	—	—		—		(993	)	—		—		1,757	(t)		29,111
															48,304	(r)
															15,575	(q)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON LIMITED PARTNERS		(52,413	)	2,600	(10,752	)	(3,516	)	16,307		(8,906	)	(13,602	)	(16,533	)		(86,815	)
NET LOSS ATTRIBUTABLE TO COMMON LIMITED PARTNERS PER UNIT:
Basic	$	(1.02	)														$	(1.69	)
Diluted	$	(1.02	)														$	(1.69	)
WEIGHTED AVERAGE COMMON LIMITED PARTNER UNITS OUTSTANDING:
Basic		51,327																51,327
Diluted		51,327																51,327

9

ATLAS ENERGY, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

(a) To reflect the preliminary purchase price allocation of the EP Energy Acquisition. Due to the recent date of the EP Energy Acquisition, the purchase price allocation for the assets acquired and liabilities assumed is based upon estimated fair values, which are subject to adjustment and could change significantly as ARP continues to evaluate this preliminary allocation.

(b) To reflect (i) $248.2 million of gross proceeds from the offering of 9.25% ARP Senior Notes in a private placement transaction at a discount of 99.297%; (ii) net borrowings of $371.1 million under ARP’s revolving credit facility; and (iii) net proceeds of $86.6 million of ARP’s Class C Preferred Units to the Partnership.

(c) To reflect the partial application of borrowings under ARP’s revolving credit facility for (i) the payment of $15.1 million of revolving credit facility fees, which will be amortized over the remaining term of ARP’s respective debt instrument; (ii) the payment of $5.5 million of fees related to issuance of the 9.25% ARP Senior Notes; and (iii) ARP’s payment of costs of $5.6 million related to the EP Energy Acquisition, which are expensed as incurred and are allocated between common limited partners’ interests and non-controlling interests.

(d) To reflect the consummation of the EP Energy Acquisition by ARP through the transfer to EP Energy of cash consideration of $705.9 million.

(e) To reflect incremental depreciation and amortization expense related to the fair value assessment of the assets acquired in the TEAK acquisition, including the basis difference in the fair value of equity method investments acquired.

(f) To reflect the adjustment to general and administrative expense to exclude APL’s acquisition-related costs incurred related to the acquisitions consummated per the pro forma financial statements.

(g) To reflect the adjustment to general and administrative expense to exclude ARP’s acquisition-related costs incurred related to the acquisitions consummated per the pro forma financial statements.

(h) To reflect the adjustment to interest expense for TEAK’s repayment of debt from the net proceeds received on the sale of assets.

(i) To reflect the adjustment to interest expense to partially finance the TEAK acquisition with the issuance of $400.0 million of APL’s 4.75% Senior Notes offset by the reduction in borrowings of $154.5 million on APL’s revolving credit facility at an interest rate of 2.5% with funds from APL’s 4.75% Senior Notes.

(j) To reflect the amortization of deferred financing costs incurred related to (i) the issuance of APL’s 4.75% Senior Notes; and (ii) the amendment to APL’s revolving credit facility to provide for (a) the TEAK acquisition to be a permitted investment; (b) for the joint ventures owned by TEAK to not be required to be guarantors nor provide security interests in their assets; and (c) for the revision of the calculation of the compliance calculations.

(k) To reflect the adjustment to interest expense related to the borrowings under ARP’s revolving credit facility to partially fund the acquisition of assets from EP Energy based on the interest rate of 2.0%.

(l) To reflect the adjustment to interest expense from the issuance of the 9.25% ARP Senior Notes and the amortization of the debt discount associated with the 9.25% ARP Senior Notes.

(m) To reflect the adjustment to interest expense on the 7.75% ARP Senior Notes issued on January 23, 2013.

(n) To reflect the amortization of deferred financing costs incurred as a result of the EP Acquisition related to ARP’s revolving credit facility over the remainder of the facility’s respective term.

(o) To reflect the amortization of deferred financing costs related to the 9.25% ARP Senior Notes.

(p) To reflect the adjustment to interest expense for the accelerated amortization of deferred financing costs associated with the retirement of ARP’s term loan facility and a portion of the outstanding indebtedness under ARP’s revolving credit facility with a portion of the proceeds from the issuance of the 7.75% ARP Senior Notes.

(q) To reflect the adjustment of non-controlling interests in the net income (loss) of APL as a result of the pro forma statement of operations adjustments previously noted. The allocation of APL net income (loss) to non-controlling interests is based upon the general partner’s and limited partners’ relative ownership interests in APL.

(r) To reflect the adjustment of non-controlling interests in the net income (loss) of ARP as a result of the pro forma statement of operations adjustments previously noted. The allocation of ARP net income (loss) to non-controlling interests is based upon the general partner’s and limited partners’ relative ownership interests subsequent to the transfer of assets to ARP on March 5, 2012, as well as required minimum distributions to preferred limited partners.

10

(s) To reclassify natural gas and liquids costs associated to the Cardinal acquisition revenues. Based upon APL’s portfolio of contracts, APL expects to report the revenues and costs under the acquired contracts on a gross basis. Under guidance in the Financial Accounting Standards Board’s Accounting Standards Codification (“ASC”) 605 – Revenue Recognition, APL presents sales of natural gas, natural gas liquids and condensate and the related cost of goods sold as gross values on its consolidated statements of operations, based upon the assessment that APL acts as a “Principal” as defined by the ASC; while Cardinal presented revenues net of costs based upon the assessment that Cardinal acted as an “Agent”, as defined by the ASC. There is no impact on the reported net income (loss) as a result of this adjustment.

(t) To reflect incremental depreciation and amortization expense related to the fair value assessment of the assets acquired, in the TEAK acquisition and the Cardinal acquisition, including a fair value assessment of the non-controlling interest in the property, plant and equipment and intangible assets and the basis difference in equity method investments.

(u) To reflect incremental depreciation, depletion and amortization expense, using the units-of-production method, related to the oil and natural gas properties acquired by ARP.

(v) To reflect incremental accretion expense related to $3.9 million of asset retirement obligations on oil and natural gas properties acquired by ARP.

(w) To reflect the adjustment to interest expense to finance the $67.5 million of borrowings under ARP’s revolving credit facility to partially fund ARP’s acquisition of assets from Carrizo based on the interest rate of 2.5%.

(x) To reflect the amortization of deferred financing costs incurred as a result of the Carrizo and DTE acquisitions related to ARP’s revolving credit facility and term loan credit facility over the remainder of the respective terms.

(y) To reflect the adjustment to interest expense to finance the $18.8 million of borrowings under ARP’s revolving credit facility to partially fund ARP’s acquisition of Titan based on the interest rate of 2.5%.

(z) To reflect the adjustment to interest expense resulting from borrowings of $75.4 million under ARP’s term loan credit facility and $18.3 million under ARP’s revolving credit facility, both of which were used by ARP to finance the DTE acquisition and related acquisition and financing costs, at a current interest rate of 7.8%.

(aa) To reflect the amortization of deferred financing costs related to the 7.75% ARP Senior Notes.

(bb) To reflect the adjustment to interest expense resulting from the retirement of ARP’s term loan credit facility and repayment of amounts outstanding under ARP’s revolving credit facility with proceeds from the 7.75% ARP Senior Notes.

(cc) To reflect the adjustment to interest expense from the issuance of the 7.75% ARP Senior Notes.

(dd) To reflect the adjustment to interest expense and other costs for Cardinal’s and TEAK’s repayment of debt from the net proceeds received on the sale of assets.

(ee) To reflect the adjustment to interest expense to (i) partially finance the Cardinal acquisition with the issuance of $175.0 million of APL’s 6.625% Senior Notes and the additional borrowings of $105.8 million on APL’s revolving credit facility at an interest rate of 2.46%, less the accretion of the $5.3 million premium received on the issuance of APL’s 6.625% Senior Notes and (ii) partially finance the TEAK acquisition with the issuance of $400.0 million of APL’s 4.75% Senior Notes offset by the reduction in borrowings of $154.5 million on APL’s revolving credit facility at an interest rate of 2.5% with funds from APL’s 4.75% Senior Notes.

(ff) To reflect the amortization of deferred financing costs incurred related to (i) the issuance of APL’s 6.625% Senior Notes; (ii) the issuance of APL’s 4.75% Senior Notes; (iii) the amendment to APL’s revolving credit facility to provide for the Cardinal acquisition to be a permitted investment and for Centrahoma to not be required to be a guarantor nor provide a security interest in its assets; and (iv) the amendment to APL’s revolving credit facility to provide for (a) the TEAK acquisition to be a permitted investment; (b) for the joint ventures owned by TEAK to not be required to be guarantors nor provide security interests in their assets; and (c) for the revision of the calculation of the compliance calculations.

(gg) To reflect APL’s income tax impact of the incremental depreciation and amortization expense recognized related to APL Arkoma, Inc., (previously known as Cardinal Arkoma, Inc.), a corporate subsidiary acquired through the Cardinal acquisition.

(hh) The following tables set forth certain unaudited pro forma information concerning ARP’s proved oil, natural gas and natural gas liquids reserves for the years ended December 31, 2012 and 2011, giving effect to the Properties acquired from EP Energy as if they had occurred on January 1, 2011. There are numerous uncertainties inherent in estimating the quantities of proved reserves and projecting future rates of production and timing of development costs. The following reserve data represent estimates only and should not be construed as being precise.

11

Proved Gas and Oil Reserve Quantities

The pro forma net proved gas and oil reserves and changes in net proved gas and oil reserves attributable to the Properties are summarized below:

	Historical			EP Energy			Pro Forma
	Natural Gas (Mcf)
Balance, January 1, 2011		176,065,003			783,356,000			959,421,003
Extensions, discoveries and other additions		9,966,952			18,780,000			28,746,952
Sales of reserves in-place		(990	)		—			(990	)
Purchase of reserves in-place		586,662			—			586,662
Transfers to limited partnerships		(6,042,432	)		—			(6,042,432	)
Revisions(4)		(11,436,615	)		14,150,000			2,713,385
Production		(11,462,149	)		(50,505,000	)		(61,967,149	)
Balance, December 31, 2011		157,676,431			765,781,000			923,457,431
Extensions, discoveries and other additions		6,756,817			1,705,000			8,461,817
Sales of reserves in-place		—			—			—
Purchase of reserves in-place		462,504,519			—			462,504,519
Transfers to limited partnerships		—			—			—
Revisions(5)		(27,760,192	)		(164,020,000	)		(191,780,192	)
Production		(25,403,318	)		(47,030,000	)		(72,433,318	)
Balance, December 31, 2012		573,774,257			556,436,000			1,130,210,257
Proved developed reserves at:
January 1, 2011		137,393,017			554,906,000			692,299,017
December 31, 2011		138,403,225			545,237,000			683,640,225
December 31, 2012		338,655,324			431,502,000			770,157,324
Proved undeveloped reserves at:
January 1, 2011		38,671,986			228,450,000			267,121,986
December 31, 2011		19,273,206			220,544,000			239,817,206
December 31, 2012		235,118,932			124,934,000			360,052,932

	Historical			EP Energy		Pro Forma
	Oil (Bbl) (1)
Balance, January 1, 2011		1,832,535			—		1,832,535
Extensions, discoveries and other additions		8,217			—		8,217
Sales of reserves in-place		—			—		—
Purchase of reserves in-place		2,216			—		2,216
Transfers to limited partnerships		—			—		—
Revisions(4)		77,661			—		77,661
Production		(274,330	)		—		(274,330	)
Balance, December 31, 2011		1,646,299			—		1,646,299
Extensions, discoveries and other additions		10,688			—		10,688
Sales of reserves in-place		—			—		—
Purchase of reserves in-place		7,485,998			—		7,485,998
Transfers to limited partnerships		—			—		—
Revisions		(153,413	)		—		(153,413	)
Production		(120,736	)		—		(120,736	)
Balance, December 31, 2012		8,868,836			—		8,868,836
Proved developed reserves at:
January 1, 2011		1,832,535			—		1,832,535
December 31, 2011		1,638,083			—		1,638,083
December 31, 2012		3,400,447			—		3,400,447
Proved undeveloped reserves at:
January 1, 2011		—			—		—
December 31, 2011		8,216			—		8,216
December 31, 2012		5,468,389			—		5,468,389

12

	Historical			EP Energy		Pro Forma
	Natural Gas Liquids (Bbl) (1)
Balance, January 1, 2011		—			—		—
Extensions, discoveries and other additions		—			—		—
Sales of reserves in-place		—			—		—
Purchase of reserves in-place		—			—		—
Transfers to limited partnerships		—			—		—
Revisions		—			—		—
Production		—			—		—
Balance, December 31, 2011		—			—		—
Extensions, discoveries and other additions		—			—		—
Sales of reserves in-place		—			—		—
Purchase of reserves in-place		16,212,356			—		16,212,356
Transfers to limited partnerships		—			—		—
Revisions(5)		206,091			—		206,091
Production		(356,550	)		—		(356,550	)
Balance, December 31, 2012		16,061,897			—		16,061,897
Proved developed reserves at:
January 1, 2011		—			—		—
December 31, 2011		—			—		—
December 31, 2012		7,884,778			—		7,884,778
Proved undeveloped reserves at:
January 1, 2011		—			—		—
December 31, 2011		—			—		—
December 31, 2012		8,177,120			—		8,177,120

(1) Oil includes NGL information for the year ended December 31, 2011, which was less than 500 MBbls.

Standardized Measure

The pro forma standardized measure of discounted future net cash flows before income taxes related to the proved gas and oil reserves of the Properties is as follows (in thousands):

	For the Year Ended December 31, 2012
	Historical			EP Energy			Pro Forma
Future cash inflows	$	2,930,514		$	1,321,983		$	4,252,497
Future production costs		(1,185,084	)		(738,248	)		(1,923,332	)
Future development costs		(441,423	)		(163,469	)		(604,892	)
Future net cash flows		1,304,007			420,266			1,724,273
Less 10% annual discount for estimated timing of cash flows		(680,331	)		(201,674	)		(882,005	)
Standardized measure of discounted future net cash flows	$	623,676		$	218,592		$	842,268

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	For the Year Ended December 31, 2011
	Historical			EP Energy			Pro Forma
Future cash inflows	$	949,286		$	2,822,400		$	3,771,686
Future production costs		(425,493	)		(1,204,952	)		(1,630,445	)
Future development costs		(27,266	)		(298,624	)		(325,890	)
Future net cash flows		496,527			1,318,824			1,815,351
Less 10% annual discount for estimated timing of cash flows		(276,668	)		(726,648	)		(1,003,316	)
Standardized measure of discounted future net cash flows	$	219,859		$	592,176		$	812,035

FASB requirements for gas and oil reserve estimation and disclosure require that reserve estimates and future cash flows be based on the average market prices for sales of gas and oil on the first calendar day of each month during the year. The average prices used for 2012 and 2011 under these rules were $2.76 and $4.12 per Mcf.

Changes in Standardized Measure

Pro forma changes in the standardized measure of discounted future net cash flows before income taxes related to the proved gas and oil reserves of the Properties are as follows:

	Year Ended December 31, 2012
	Historical			EP Energy			Pro Forma
Balance, beginning of year	$	219,859		$	592,176		$	812,035
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs		(54,969	)		(78,153	)		(133,122	)
Net changes in prices and production costs		(87	)		(349,076	)		(349,163	)
Revisions of previous quantity estimates		(6,378	)		(94,806	)		(101,184	)
Development costs incurred		575			2,000			2,575
Changes in future development costs		—			73,781			73,781
Transfers to limited partnerships		—			—			—
Extensions, discoveries, and improved recovery less related costs		64			540			604
Purchases of reserves in-place		510,467			—			510,467
Sales of reserves in-place		—			—			—
Accretion of discount		21,986			72,665			94,651
Estimated settlement of asset retirement obligations		(2,823	)		—			(2,823	)
Estimated proceeds on disposals of well equipment		3,806			—			3,806
Changes in production rates (timing) and other		(68,824	)		(535	)		(69,359	)
Outstanding, end of year	$	623,676		$	218,592		$	842,268

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	Year Ended December 31, 2011
	Historical			EP Energy			Pro Forma
Balance, beginning of year	$	236,630		$	660,619		$	897,249
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs		(46,304	)		(137,357	)		(183,661	)
Net changes in prices and production costs		(34	)		(26,668	)		(26,702	)
Revisions of previous quantity estimates		757			16,432			17,189
Development costs incurred		1,842			22,392			24,234
Changes in future development costs		(3,591	)		(15,697	)		(19,288	)
Transfers to limited partnerships		(8,022	)		—			(8,022	)
Extensions, discoveries, and improved recovery less related costs		14,923			10,650			25,573
Purchases of reserves in-place		736			—			736
Sales of reserves in-place		(1	)		—			(1	)
Accretion of discount		23,663			80,681			104,344
Estimated settlement of asset retirement obligations		(3,105	)		—			(3,105	)
Estimated proceeds on disposals of well equipment		3,363			—			3,363
Changes in production rates (timing) and other		(998	)		(18,876	)		(19,874	)
Outstanding, end of year	$	219,859		$	592,176		$	812,035

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