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): December 20, 2012

Atlas Resource Partners, L.P.

(Exact name of registrant as specified in its charter)

Delaware	1-35317	45-3591625
(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: 800-251-0171

(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

On December 26, 2012, Atlas Resource Partners, L.P. (“ARP”) filed a Current Report on Form 8-K (the “Original 8-K”) to report the completion by Atlas Barnett, LLC, an indirect wholly owned subsidiary of ARP, of the acquisition of DTE Gas Resources, LLC. This Current Report on Form 8-K/A amends Item 9.01 of the Original 8-K to present certain financial statements for DTE Gas Resources, LLC 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.

• DTE Gas Resources, LLC unaudited balance sheets as of September 30, 2012 and December 31, 2011, statements of operations, equity and cash flows for the nine months ended September 30, 2012 and 2011, and notes to the financial statements are filed as Exhibit 99.1 to this Current Report on Form 8-K/A and are incorporated by reference herein.

• DTE Gas Resources, LLC audited balance sheet as of December 31, 2011, statements of operations, equity and cash flows and notes to the financial statements for the year ended December 31, 2011, together with independent auditors’ report thereon, are filed as Exhibit 99.2 to this Current Report on Form 8-K/A and are incorporated by reference herein.

(b) Pro Forma Financial Information

The unaudited pro forma consolidated combined balance sheet of ARP as of September 30, 2012, and the related pro forma consolidated combined statements of operations for the nine months ended September 30, 2012 and the year ended December 31, 2011 are filed as Exhibit 99.3 to this Current Report on Form 8-K/A and are incorporated by reference herein.

(d) Exhibits

23.1 Consent of Grant Thornton, LLP

99.1 DTE Gas Resources, LLC unaudited balance sheets as of September 30, 2012 and December 31, 2011, statements of operations, equity and cash flows for the nine months ended September 30, 2012 and 2011, and notes to the financial statements

99.2 DTE Gas Resources, LLC audited balance sheet as of December 31, 2011, statements of operations, equity and cash flows for the year ended December 31, 2011 and notes to the financial statements

99.3 Unaudited pro forma consolidated combined 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: January 9, 2013

ATLAS RESOURCE PARTNERS, L.P.
By: Atlas Resource Partners 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	DTE Gas Resources, LLC unaudited balance sheets as of September 30, 2012 and December 31, 2011, statements of operations, equity and cash flows for the nine months ended September 30, 2012 and 2011, and notes to the financial statements
99.2	DTE Gas Resources, LLC audited balance sheet as of December 31, 2011, statements of operations, equity and cash flows for the year ended December 31, 2011 and notes to the financial statements
99.3	Unaudited pro forma consolidated combined financial statements

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EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

We have issued our report dated January 9, 2013, with respect to the financial statements of DTE Gas Resources, LLC as of and for the year ended December 31, 2011 included in the Current Report of Atlas Resource Partners, L.P. on Form 8-K/A, dated December 20, 2012. We hereby consent to the incorporation by reference of said report in the Registration Statements of Atlas Resource Partners, L.P. on Forms S-3 (File No. 333-180477, effective April 13, 2012, File No. 333-182616, effective August 28, 2012 and File No. 333-183995, effective October 2, 2012) and on Form S-8 (File No. 333-180209, effective March 19, 2012).

/s/ GRANT THORNTON LLP

Cleveland, Ohio

January 9, 2013

EX-99.1

Exhibit 99.1

DTE GAS RESOURCES, LLC

BALANCE SHEETS

(in thousands)

(Unaudited)

	September 30, 2012		December 31, 2011
ASSETS
Current assets:
Current portion of accounts receivable	$	7,571	$	4,728
Inventory		2,894		2,319
Other current assets		78		72
Total current assets		10,543		7,119
Property, plant and equipment, net		336,609		310,075
Long-term accounts receivable		329		485
	$	347,481	$	317,679
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	13,365	$	6,989
Accounts payable – DTE Energy Co.		644		1,000
Total current liabilities		14,009		7,989
Notes payable – DTE Energy Co.		156,637		135,774
Asset retirement obligation		3,038		2,891
Other long-term liabilities		—		795
Commitments and contingencies
Equity:
Equity		173,797		170,230
Total equity		173,797		170,230
	$	347,481	$	317,679

See accompanying notes to the financial statements.

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DTE GAS RESOURCES, LLC

STATEMENTS OF OPERATIONS

(in thousands)

(Unaudited)

	Nine Months Ended			Nine Months Ended
	September 30, 2012			September 30, 2011
Revenues:
Gas production	$	16,430		$	18,004
Oil production		21,787			10,642
Other, net		(187	)		(404	)
Total revenues		38,030			28,242
Costs and expenses:
Gas and oil production		15,584			10,746
General and administrative		2,427			2,536
General and administrative – DTE Energy Co.		3,262			3,727
Depreciation, depletion and amortization		16,460			13,409
Total costs and expenses		37,733			30,418
Operating income (loss)		297			(2,176	)
Interest expense		(4,464	)		(4,827	)
Net loss	$	(4,167	)	$	(7,003	)

See accompanying notes to the financial statements.

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DTE GAS RESOURCES, LLC

STATEMENTS OF EQUITY

(in thousands)

(Unaudited)

	Equity
Balance at January 1, 2012	$	170,230
Net investment from DTE Energy Co.		7,734
Net loss		(4,167	)
Balance at September 30, 2012	$	173,797

See accompanying notes to the financial statements.

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DTE GAS RESOURCES, LLC

STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Nine Months  Ended September 30, 2012			Nine Months  Ended September 30, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(4,167	)	$	(7,003	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		16,460			13,409
Changes in operating assets and liabilities:
Accounts receivable, inventory and other current assets		(3,424	)		(617	)
Accounts payable		8,554			2,080
Net cash provided by operating activities		17,423			7,869
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(45,554	)		(23,468	)
Other		(110	)		45
Net cash used in investing activities		(45,664	)		(23,423	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net investment received from DTE Energy Co.		7,734			13,571
Net borrowings from DTE Energy Co.		20,507			1,983
Net cash provided by financing activities		28,241			15,554
Net change in cash and cash equivalents		—			—
Cash and cash equivalents, beginning of period		—			—
Cash and cash equivalents, end of period	$	—		$	—

See accompanying notes to the financial statements.

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DTE GAS RESOURCES, LLC

NOTES TO THE FINANCIAL STATEMENTS

(Unaudited)

NOTE 1—BASIS OF PRESENTATION

Corporate Structure

DTE Gas Resources, LLC (the “Company”), is a single-member Delaware limited liability company and independent developer and producer of natural gas and oil, with operations in the Fort Worth basin of North Texas. At September 30, 2012, the Company was a wholly-owned subsidiary of DTE Energy Co. (“DTE”; NYSE: DTE). On December 20, 2012, Atlas Resource Partners, L.P. (“ARP”; NYSE: ARP), a publicly-traded Delaware limited partnership, acquired the Company for $257.4 million in cash (see Note 6).

Basis of Presentation

The preparation of the Company’s financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Company’s financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Company’s financial statements are based on a number of significant estimates, including the revenue and expense accruals and depletion, depreciation and amortization. Such estimates included estimated allocations made from the historical accounting records of DTE in order to derive the historical period financial statements of the Company. Actual results could differ from those estimates.

The accompanying financial statements, which are unaudited except that the balance sheet at December 31, 2011 is derived from audited financial statements, are presented in accordance with the accounting principles generally accepted in the United States for interim reporting. They do not include all disclosures normally made in annual financial statements. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto. The results of operations for the nine months ended September 30, 2012 may not necessarily be indicative of the results of operations for the full year ending December 31, 2012.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Relationship with DTE

DTE provides centralized corporate functions on behalf of the Company, including certain legal, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering functions. These costs are reflected within general and administrative expenses – DTE Energy Co. in the Company’s statements of operations. The employees supporting these Company operations are employees of DTE. The costs of these operations are allocated to the Company based on estimates made by DTE. This allocation of costs may fluctuate from period to period based upon the level of activity of the Company. Management believes the method used to allocate these expenses is reasonable.

Cash and Cash Equivalents

The Company participates in DTE’s cash management program and accordingly does not maintain independent cash and cash equivalent balances. Accordingly, cash flows generated through revenues are subsequently funded by the Company to DTE, while cash requirements for expenses and capital expenditures are funded by DTE on behalf of the Company. The combined effects of these transactions are reflected within notes payable – DTE Energy Co. on the Company’s balance sheets. Notes payable – DTE Energy Co. bears an allocated interest expense payable to DTE at DTE’s approximate corporate borrowings rate. For the nine months ended September 30, 2012 and 2011, the Company’s weighted average allocated interest rate was 5.6% and 6.6%, respectively. Cash payments for interest for the Company were $6.1 million and $6.6 million for the nine months ended September 30, 2012 and 2011, respectively.

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Receivables

Accounts receivable on the Company’s balance sheets consisted solely of the trade accounts receivable associated with the Company’s operations. In evaluating the realizability of the Company’s accounts receivable, management performs ongoing credit evaluations of the Company’s customers and adjusted credit limits based upon payment history and the customer’s current creditworthiness, as determined by the Company’s management’s review of the customers’ credit information. The Company extends credit on sales on an unsecured basis to many of the Company’s customers. At September 30, 2012 and December 31, 2011, the Company concluded that no allowance for uncollectible accounts receivable was required.

Inventory

Inventory on the Company’s balance sheets consisted of materials, pipes, supplies and other inventories, which were principally determined using the average cost method, and produced oil volumes in tanks prior to gathering, which were valued at prevailing market prices as of the reporting dates. The Company values inventories at the lower of cost or market.

Property, Plant and Equipment

Property, plant and equipment are stated at cost. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property 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.

The Company 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 is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to 6 Mcf of natural gas.

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

Upon the sale or retirement of a complete field of a proved property, the Company eliminates the cost from the property accounts, and the resultant gain or loss is reclassified to the Company’s statements of operations. Upon the sale of an individual well, the Company credits the proceeds to accumulated depreciation and depletion within its balance sheets. Upon the Company’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 its 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.

Capitalized Interest

The Company capitalizes interest on borrowed funds from DTE related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rate used to capitalize interest on borrowed funds by the Company was 5.6% and 6.6% for the nine months ended September 30, 2012 and 2011, respectively. The aggregate amounts of interest capitalized by the Company was $1.6 million and $1.8 million for the nine months ended September 30, 2012 and 2011, respectively.

Impairment of Long-Lived Assets

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

The review of the Company’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company 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

6

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. These estimates are based on assumptions including the Company’s capital expenditures, reserve estimates, future lease operating and administrative costs and the salvage value upon plugging of the wells. Reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Company cannot predict what reserve revisions may be required in future periods.

Unproved properties are reviewed at least annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate the Company does not intend to drill 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 proved oil and gas properties recorded by the Company for the nine months ended September 30, 2012 and 2011. During the nine months ended September 30, 2012 and 2011, the Company recognized $0.9 million and $0.4 million of charges within other, net on its statements of operations related to the expiration of certain unproved leasehold positions that the Company did not intend to drill.

Derivative Instruments

The Company engages with DTE Energy Trading, Inc. (“DTE Energy Trading”) to enter into financial instruments to hedge forecasted crude oil sales against the variability in expected future cash flows attributable to changes in market prices. The Company uses a number of different derivative instruments, principally swaps, in connection with their commodity risk management activities. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying crude oil is sold. Under its commodity-based swap agreements, the Company receives or pays a fixed price and receives or remits a floating price to DTE Energy Trading based on certain indices for the relevant contract period. Upon settlement of the underlying crude oil transaction, DTE allocates the realized cash gains or losses to the Company. The Company has no relationship with external counter parties and does not apply hedge accounting to its derivative instruments with DTE Energy Trading. For the nine months ended September 30, 2012 and 2011, the Company realized hedge gains of $1.1 million and $0.1 million within oil production revenue on its statements of operations.

Revenue Recognition

The Company generally sells natural gas, crude oil and natural gas liquids (“NGL”s) at prevailing market prices. Generally, the Company’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 5 business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil, in which the Company has an interest with other producers, are recognized on the basis of its percentage ownership of working interest and/or overriding royalty.

The Company accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’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 “–Basis of Presentation” accounting policy for further description). The Company had unbilled revenues at September 30, 2012 and December 31, 2011 of $7.1 million and $4.6 million, respectively, which were included in accounts receivable within its balance sheets.

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NOTE 3—PROPERTY, PLANT AND EQUIPMENT

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

	September 30, 2012			December 31, 2011			Estimated Useful  Lives in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	53,839		$	53,899
Pre-development costs		34			81
Wells and related equipment		290,208			250,412
Total proved properties		344,081			304,392
Unproved properties		54,217			54,278
Support equipment		1,240			1,208
Total natural gas and oil properties		399,538			359,878
Pipelines, processing and compression facilities		19,640			16,661			2 – 40
Land, buildings and improvements		569			613			3 – 40
Other		2,335			2,349			3 – 10
		422,082			379,501
Less—accumulated depreciation, depletion and amortization		(85,473	)		(69,426	)
	$	336,609		$	310,075

NOTE 4—ASSET RETIREMENT OBLIGATIONS

The Company recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset.

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

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

	Nine Months Ended September 30,		Nine Months Ended September 30,
	2012		2011
Asset retirement obligations, beginning of year	$	2,891	$	2,389
Accretion expense		147		126
Asset retirement obligations, end of period	$	3,038	$	2,515

The above accretion expense was included in depreciation, depletion and amortization in the Company’s statements of operations and the asset retirement obligation liabilities were included within asset retirement obligation on the Company’s balance sheets.

NOTE 5—COMMITMENTS AND CONTINGENCIES

General Commitments

As of September 30, 2012, the Company had no unrecorded commitments related to its drilling and completion operations.

Legal Proceedings

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

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NOTE 6—SUBSEQUENT EVENTS

On December 20, 2012, ARP completed its acquisition of the Company for gross cash consideration of $257.4 million, including $2.4 million of adjustments for working capital, which remains subject to final post-closing adjustments. In connection with the closing of the transaction, DTE contributed capital of $221.4 million to satisfy the Company’s obligations to DTE. Further the Company settled all of its derivative instruments with DTE Energy Trading.

The Company has evaluated subsequent events through January 9, 2013 and no additional events requiring disclosure have occurred.

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EX-99.2

Exhibit 99.2

REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

Board of Directors and Member

DTE Gas Resources, LLC

We have audited the accompanying balance sheet of DTE Gas Resources, LLC (a Delaware limited liability company) (the “Company”) as of December 31, 2011, and the related statements of operations, equity, and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States of America established by the American Institute of Certified Public Accountants. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of DTE Gas Resources, LLC as of December 31, 2011, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

January 9, 2013

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DTE GAS RESOURCES, LLC

BALANCE SHEET

(in thousands)

	December 31, 2011
ASSETS
Current assets:
Current portion of accounts receivable	$	4,728
Inventory		2,319
Other current assets		72
Total current assets		7,119
Property, plant and equipment, net		310,075
Long-term accounts receivable		485
	$	317,679
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	6,989
Accounts payable – DTE Energy Co.		1,000
Total current liabilities		7,989
Notes payable – DTE Energy Co.		135,774
Asset retirement obligation		2,891
Other long-term liabilities		795
Commitments and contingencies
Equity:
Equity		170,230
Total equity		170,230
	$	317,679

See accompanying notes to the financial statements.

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DTE GAS RESOURCES, LLC

STATEMENT OF OPERATIONS

(in thousands)

	Year Ended December 31,
	2011
Revenues:
Gas production	$	23,633
Oil production		15,091
Other, net		(584	)
Total revenues		38,140
Costs and expenses:
Gas and oil production		14,850
General and administrative		3,458
General and administrative – DTE Energy Co.		4,980
Depreciation, depletion and amortization		18,038
Total costs and expenses		41,326
Operating loss		(3,186	)
Interest expense		(6,468	)
Net loss	$	(9,654	)

See accompanying notes to the financial statements.

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DTE GAS RESOURCES, LLC

STATEMENT OF EQUITY

(in thousands)

	Equity
Balance at January 1, 2011	$	166,486
Net investment from DTE Energy Co.		13,398
Net loss		(9,654	)
Balance at December 31, 2011	$	170,230

See accompanying notes to the financial statements.

4

DTE GAS RESOURCES, LLC

STATEMENT OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(9,654	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		18,038
Changes in operating assets and liabilities:
Accounts receivable, inventory and other current assets		(1,316	)
Accounts payable		972
Net cash provided by operating activities		8,040
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(28,498	)
Other		102
Net cash used in investing activities		(28,396	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net investment received from DTE Energy Co.		13,398
Net borrowings from DTE Energy Co.		6,958
Net cash provided by financing activities		20,356
Net change in cash and cash equivalents		—
Cash and cash equivalents, beginning of year		—
Cash and cash equivalents, end of year	$	—

See accompanying notes to the financial statements.

5

DTE GAS RESOURCES, LLC

NOTES TO THE FINANCIAL STATEMENTS

NOTE 1—BASIS OF PRESENTATION

Corporate Structure

DTE Gas Resources, LLC (the “Company”), is a single-member Delaware limited liability company and independent developer and producer of natural gas and oil, with operations in the Fort Worth basin of North Texas. At December 31, 2011, the Company was a wholly-owned subsidiary of DTE Energy Co. (“DTE”; NYSE: DTE). On December 20, 2012, Atlas Resource Partners, L.P. (“ARP”; NYSE: ARP), a publicly-traded Delaware limited partnership, acquired the Company for $257.4 million in cash (see Note 6).

Basis of Presentation

The preparation of the Company’s financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Company’s financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Company’s financial statements are based on a number of significant estimates, including the revenue and expense accruals and depletion, depreciation and amortization. Such estimates included estimated allocations made from the historical accounting records of DTE in order to derive the historical period financial statements of the Company. Actual results could differ from those estimates.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Relationship with DTE

DTE provides centralized corporate functions on behalf of the Company, including certain legal, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering functions. These costs are reflected within general and administrative expenses – DTE Energy Co. in the Company’s statement of operations. The employees supporting these Company operations are employees of DTE. The costs of these operations are allocated to the Company based on estimates made by DTE. This allocation of costs may fluctuate from period to period based upon the level of activity of the Company. Management believes the method used to allocate these expenses is reasonable.

Cash and Cash Equivalents

The Company participates in DTE’s cash management program and accordingly does not maintain independent cash and cash equivalent balances. Accordingly, cash flows generated through revenues are subsequently funded by the Company to DTE, while cash requirements for expenses and capital expenditures are funded by DTE on behalf of the Company. The combined effects of these transactions are reflected within notes payable – DTE Energy Co. on the Company’s balance sheet. Notes payable – DTE Energy Co. bear an allocated interest expense payable to DTE at DTE’s approximate corporate borrowings rate. For the year ended December 31, 2011, the Company’s weighted average allocated interest rate was 6.6%. Cash payments for interest for the Company were $8.9 million for the year ended December 31, 2011.

Receivables

Accounts receivable on the Company’s balance sheet consisted solely of the trade accounts receivable associated with the Company’s operations. In evaluating the realizability of the Company’s accounts receivable, management performs ongoing credit evaluations of the Company’s customers and adjusted credit limits based upon payment history and the customer’s current creditworthiness, as determined by the Company’s management’s review of the customers’ credit information. The Company extends credit on sales on an unsecured basis to many of the Company’s customers. At December 31, 2011, the Company concluded that no allowance for uncollectible accounts receivable was required.

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Inventory

Inventory on the Company’s balance sheet consisted of materials, pipes, supplies and other inventories, which were principally determined using the average cost method, and produced oil volumes in tanks prior to gathering, which were valued at prevailing market prices as of the reporting dates. The Company values inventories at the lower of cost or market.

Property, Plant and Equipment

Property, plant and equipment are stated at cost. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property 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.

The Company 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 is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to 6 Mcf of natural gas.

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

Upon the sale or retirement of a complete field of a proved property, the Company eliminates the cost from the property accounts, and the resultant gain or loss is reclassified to the Company’s statement of operations. Upon the sale of an individual well, the Company credits the proceeds to accumulated depreciation and depletion within its combined balance sheets. Upon the Company’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 its statement 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.

Capitalized Interest

The Company capitalizes interest on borrowed funds from DTE related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rate used to capitalize interest on borrowed funds by the Company was 6.6% for the year ended December 31, 2011. The aggregate amounts of interest capitalized by the Company was $2.4 million for the year ended December 31, 2011.

Impairment of Long-Lived Assets

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

The review of the Company’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company 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

7

and assumptions that are difficult to predict and may vary considerably from actual results. These estimates are based on assumptions including the Company’s capital expenditures, reserve estimates, future lease operating and administrative costs and the salvage value upon plugging of the wells. Reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Company cannot predict what reserve revisions may be required in future periods.

Unproved properties are reviewed at least annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate the Company does not intend to drill 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 proved oil and gas properties recorded by the Company for the year ended December 31, 2011. During the year ended December 31, 2011, the Company recognized $0.6 million of charges within other, net on its statement of operations related to the expiration of certain unproved leasehold positions that the Company did not intend to drill.

Derivative Instruments

The Company engages with DTE Energy Trading, Inc. (“DTE Energy Trading”) to enter into financial instruments to hedge forecasted crude oil sales against the variability in expected future cash flows attributable to changes in market prices. The Company uses a number of different derivative instruments, principally swaps, in connection with their commodity risk management activities. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying crude oil is sold. Under its commodity-based swap agreements, the Company receives or pays a fixed price and receives or remits a floating price to DTE Energy Trading based on certain indices for the relevant contract period. Upon settlement of the underlying crude oil transaction, DTE allocates the realized cash gains or losses to the Company. The Company has no relationship with external counter parties and does not apply hedge accounting to its derivative instruments with DTE Energy Trading. For the year ended December 31, 2011, the Company realized hedge gains of $0.2 million within oil production revenue on its statement of operations.

Environmental Matters

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Company’s operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. At December 31, 2011, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

Revenue Recognition

The Company generally sells natural gas, crude oil and natural gas liquids (“NGL”s) at prevailing market prices. Generally, the Company’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 5 business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil, in which the Company has an interest with other producers, are recognized on the basis of its percentage ownership of working interest and/or overriding royalty.

The Company accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’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 “–Basis of Presentation” accounting policy for further description). The Company had unbilled revenues at December 31, 2011 of $4.6 million, which were included in accounts receivable within its balance sheet.

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For the year ended December 31, 2011, the Company had three customers that respectively accounted for approximately 39%, 35% and 19% of its revenues and its accounts receivable. No other single customer exceeded ten percent of revenues or accounts receivable for the year ended December 31, 2011.

Income Taxes

The Company is a limited liability company and has elected to be treated as a partnership for income tax purposes. As a result, the Company is not subject to U.S. federal income taxes or state income taxes in the states where it operates. DTE is liable for income taxes in regards to its distributive share of the Company’s taxable income. Such taxable income may vary substantially from net income reported in the accompanying financial statements. State income taxes related to the Company are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the accompanying financial statements.

The Company evaluates tax positions taken or expected to be taken in the course of preparing the Company’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 Company’s management does not believe it has any tax positions taken within its financial statements that would not meet this threshold.

The Company’s policy is to reflect interest and penalties related to uncertain tax positions within other, net, when and if they become applicable. However, the Company has not recognized any potential interest or penalties in its financial statements as of December 31, 2011.

The Company files income tax returns in the U.S. and Texas jurisdictions. The Company is no longer subject to income tax examinations by major tax authorities for years before 2008. The Company is not currently being examined in any jurisdiction and is not aware of any potential examinations as of December 31, 2011.

NOTE 3—PROPERTY, PLANT AND EQUIPMENT

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

	December 31, 2011			Estimated Useful Lives in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	53,899
Pre-development costs		81
Wells and related equipment		250,412
Total proved properties		304,392
Unproved properties		54,278
Support equipment		1,208
Total natural gas and oil properties		359,878
Pipelines, processing and compression facilities		16,661			2 – 40
Land, buildings and improvements		613			3 – 40
Other		2,349			3 – 10
		379,501
Less—accumulated depreciation, depletion and amortization		(69,426	)
	$	310,075

NOTE 4—ASSET RETIREMENT OBLIGATIONS

The Company recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset.

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

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

	Year Ended December 31, 2011
Asset retirement obligations, beginning of year	$	2,389
Liabilities incurred		334
Accretion expense		168
Asset retirement obligations, end of year	$	2,891

The above accretion expense was included in depreciation, depletion and amortization in the Company’s statement of operations and the asset retirement obligation liabilities were included within asset retirement obligation on the Company’s balance sheet.

NOTE 5—COMMITMENTS AND CONTINGENCIES

General Commitments

The Company leases equipment under leases with varying expiration dates through 2012. Rental expense was $2.9 million for the year ended December 31, 2011. Future minimum rental commitments for the next five years are as follows (in thousands):

Years Ended December 31:
2012	$	923
2013		—
2014		—
2015		—
2016		—
Thereafter		—
	$	923

As of December 31, 2011, the Company had no unrecorded commitments related to its drilling and completion operations.

Legal Proceedings

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

NOTE 6—SUBSEQUENT EVENTS

On December 20, 2012, ARP completed its acquisition of the Company for gross cash consideration of $257.4 million, including $2.4 million of adjustments for working capital, which remains subject to final post-closing adjustments. Immediately preceding the closing of the transaction, DTE contributed capital of $221.4 million to satisfy the Company’s obligations to DTE. Further, the Company settled all of its derivative instruments with DTE Energy Trading.

The Company has evaluated subsequent events through January 9, 2013 and no additional events requiring disclosure have occurred.

NOTE 7—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Gas Reserve Information. The preparation of the Company’s natural gas and oil reserve estimates were completed in accordance with its prescribed internal control procedures by the Company’s reserve engineers. The accompanying reserve information included below is attributable to the reserves of the Company and was derived from the reserve reports prepared for the Company for the year ended December 31, 2011. For the period, an independent third-party reserve engineer was retained to prepare a report of proved reserves. The reserve information for the Company includes

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natural gas, NGLs and oil reserves which are all located in the Fort Worth basin in North Texas. The independent reserves engineer’s primarily responsible for overseeing the preparation of the reserve estimates is a Registered Petroleum Engineer in the State of Texas with more than 36 years of experience in oil and gas reservoir studies and reserve evaluations. The Company’s internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review.

The reserve disclosures that follow reflect estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of royalty interests, of natural gas, crude oil, condensate and NGLs owned at year end and changes in proved reserves during the last year. Proved oil and gas reserves are those quantities of oil and gas, 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-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of where deterministic or probabilistic methods are used for the estimation. Proved developed reserves are those proved reserves, which can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves cannot be assigned to acreage for which improved recovery technology is contemplated unless such techniques have been proven effective by actual tests in the area and in the same reservoir. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. The proved reserves quantities and future net cash flows as of December 31, 2011 were estimated using a 12-month average pricing based on the prices on the first day of each month during the year ended December 31, 2011.

There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of oil and gas reserves included within the Company or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors, for their effects have not been proved.

Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Company is as follows:

	Oil (Bbls)			Gas (Mcfs)			NGL (Bbls)
Balance, January 1, 2011		1,821,771			108,122,070			13,694,874
Extensions, discoveries and other additions(1)		1,912,747			13,219,100			1,645,591
Sales of reserves in-place		—			—			—
Purchase of reserves in-place		—			—			—
Revisions(2)		(161,444	)		(26,017,517	)		(2,876,738	)
Production		(160,484	)		(3,069,097	)		(294,648	)
Balance, December 31, 2011		3,412,590			92,254,556			12,169,079
Proved developed reserves at:
January 1, 2011		533,730			28,309,753			3,627,127
December 31, 2011		891,390			28,572,281			3,792,398
Proved undeveloped reserves at:
January 1, 2011		1,288,041			79,812,317			10,067,747
December 31, 2011		2,521,200			63,682,275			8,376,681

(1) Principally includes increases of proved reserves due to the addition of wells drilled during the year ended December 31, 2011.

(2) Represents a decrease in the price of natural gas, natural gas liquids and oil compared from the year ended December 31, 2010 to the year ended December 31, 2011.

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Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of the Company during the period indicated were as follows (in thousands):

	Year Ended December 31, 2011
Natural gas and oil properties:
Proved properties	$	304,392
Unproved properties		54,278
Support equipment		1,208
		359,878
Accumulated depreciation, depletion and amortization	$	(68,540	)
Net capitalized costs	$	291,338

Results of Operations from Oil and Gas Producing Activities. The results of operations related to the Company’s oil and gas producing activities during the period indicated were as follows (in thousands):

	Year Ended December 31, 2011
Revenues	$	38,525
Production costs		(14,850	)
Depreciation, depletion and amortization		(18,038	)
	$	5,637

The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Company’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the year ended December 31, 2011. The resulting estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the date presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (in thousands):

	Year Ended December 31, 2011
Future cash inflows	$	1,276,692
Future production costs		(480,971	)
Future development costs		(347,310	)
Future net cash flows		448,411
Less 10% annual discount for estimated timing of cash flows		(305,956	)
Standardized measure of discounted future net cash flows	$	142,455

The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves (in thousands). Since the Company allocates taxable income to its owner, no recognition has been given to income taxes:

	Year Ended December 31, 2011
Balance, beginning of year	$	152,952
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs		(23,675	)
Net changes in prices and production costs		13,351
Revisions of previous quantity estimates(1)		(33,633	)

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Development costs incurred		1,033
Changes in future development costs		(3,824	)
Extensions, discoveries, and improved recovery less related costs		26,286
Accretion of discount		15,295
Changes in production rates (timing) and other		(5,330	)
Outstanding, end of year	$	142,455

(1) Represents a decrease in the price of natural gas, natural gas liquids and oil compared from the year ended December 31, 2010 to the year ended December 31, 2011.

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EX-99.3

Exhibit 99.3

UNAUDITED PRO FORMA FINANCIAL INFORMATION

The following unaudited pro forma consolidated combined financial data reflects Atlas Resource Partners, L.P.’s (the “Partnership”) historical results as adjusted on a pro forma basis to give effect to its 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 Partnership common units and 3.8 million convertible Class B preferred units, as well as $15.4 million in cash for closing adjustments, and (iii) DTE Gas Resources, LLC (“DTE”) for gross cash consideration of $257.4 million. The estimated adjustments to effect the acquisitions are described in the notes to the unaudited pro forma financial data.

The unaudited pro forma consolidated combined statements of operations information for the nine months ended September 30, 2012 and the year ended December 31, 2011 assumes the following transactions had occurred as of January 1, 2011. In addition, the pro forma consolidated combined balance sheet data as of September 30, 2012 reflect the following transactions as if they occurred on September 30, 2012:

• the acquisition from Carrizo 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 6,027,945 common units at a negotiated purchase price of $20.00 per unit and (ii) borrowings of $67.5 million under the Partnership’s revolving credit facility;

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

• the sale of 7.9 million of the Partnership’s common units for net proceeds of $174.5 million, the net proceeds of which were used to repay borrowings under the Partnership’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 the Partnership’s revolving credit facility and $77.6 from the Partnership’s term loan credit facility.

The unaudited pro forma consolidated combined balance sheet and the pro forma consolidated combined statements of operations were derived by adjusting the Partnership’s historical consolidated combined 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. 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.

The Partnership was formed in October 2011 by Atlas Energy, L.P. (“ATLS”), a publicly traded master-limited partnership (NYSE: ATLS), to own and operate substantially all of ATLS’s exploration and production assets, which were transferred to the Partnership on March 5, 2012. In February 2012, the board of directors of ATLS’s general partner approved the distribution of 5.24 million of the Partnership’s common limited partner units which were distributed on March 13, 2012 to ATLS’ unitholders using a ratio of 0.1021 of the Partnership’s common limited partner units for each of ATLS’ common units owned on the record date of February 28, 2012.

The Partnership’s historical consolidated combined balance sheet at September 30, 2012 and the portion of its historical consolidated combined statement of operations for the nine months ended September 30, 2012 subsequent to the transfer of assets on March 5, 2012 include its and its wholly-owned subsidiaries accounts. The portion of the Partnership’s historical consolidated combined statements of operations for the nine months ended September 30, 2012 prior to the transfer of assets on March 5, 2012 and the combined statement of operations for the year ended December 31, 2011 were

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derived from the separate records maintained by ATLS and may not necessarily be indicative of the conditions that would have existed if the Partnership had been operated as an unaffiliated entity. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in consolidated combined balance sheets and related consolidated combined statements of operations. Such estimates included allocations made from the historical accounting records of ATLS, based on management’s best estimates, in order to derive the Partnership’s financial statements for the periods presented prior to the transfer of assets. Actual balances and results could be different from those estimates.

On February 17, 2011, ATLS acquired its exploration and production assets (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of ATLS’ general partner. Upon its acquisition, ATLS’ management determined that the acquisition constituted a transaction between entities under common control. In comparison to the acquisition method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital. Also, in comparison to the acquisition method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in ATLS’ consolidated combined financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect of the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, ATLS reflected the impact of the acquisition of the Transferred Business on its consolidated combined financial statements, which are the basis of the Partnership’s consolidated combined financial statements for the period prior to the transfer of assets on March 5, 2012, in the following manner:

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

• Retrospectively adjusted its consolidated combined financial statements for any date prior to February 17, 2011, the date of the Transferred Business acquisition, to reflect its results on a consolidated combined basis with the results of the Transferred Business as of or at the beginning of the respective period. The Transferred Business’ historical financial statements prior to the date of acquisition reflect an allocation of general and administrative expenses determined by AEI to the underlying business segments, including the Transferred Business. ATLS has reviewed AEI’s general and administrative expense allocation methodology, which is based on the relative total assets of AEI and the Transferred Business, for the Transferred Business’ historical financial statements prior to the date of acquisition and believes the methodology is reasonable and reflects the approximate general and administrative costs of its underlying business segments.

With regard to the calculation of pro forma net income (loss) per common limited partner unit, the general partner’s Class A unit interest in net income (loss) is calculated on a quarterly basis based upon its 2% Class A ownership interest and incentive distributions, with a priority allocation of net income in an amount equal to the general partner’s actual incentive distributions for the respective period, in accordance with the partnership agreement, and the remaining net income or loss is allocated with respect to the general partner’s and limited partners’ ownership interests.

2

ATLAS RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

PRO FORMA CONSOLIDATED COMBINED BALANCE SHEET

SEPTEMBER 30, 2012

(in thousands)

(Unaudited)

	Historical		Historical DTE		Adjustments			Pro Forma
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	24,266	$	—	$	268,213	(a)	$	24,266
						(10,764	)(b)
						(257,449	)(d)
Accounts receivable		29,743		7,571		—			37,314
Current portion of derivative asset		6,518		—		—			6,518
Subscriptions receivable		8,495		—		—			8,495
Prepaid expenses and other		7,107		2,972		—			10,079
Total current assets		76,129		10,543		—			86,672
PROPERTY, PLANT AND EQUIPMENT, NET		1,016,110		336,609		(73,629	)(c)		1,279,090
GOODWILL AND INTANGIBLE ASSETS, NET		33,149		—		—			33,149
LONG-TERM DERIVATIVE ASSET		5,144		—		—			5,144
OTHER ASSETS, NET		8,410		329		7,264	(b)		16,003
	$	1,138,942	$	347,481	$	(66,365	)	$	1,420,058
LIABILITIES AND PARTNERS’ CAPITAL/EQUITY
CURRENT LIABILITIES:
Accounts payable	$	42,831		13,365	$	—		$	56,196
Liabilities associated with drilling contracts		5,550		—		—			5,550
Current portion of derivative liability		280		—		—			280
Current portion of derivative payable to Drilling Partnerships		13,363		—		—			13,363
Accrued well drilling and completion costs		50,169		—		—			50,169
Payable to DTE		—		157,281		(157,281	)(c)		—
Accrued liabilities		33,039		—		—			33,039
Total current liabilities		145,232		170,646		(157,281	)		158,597
LONG-TERM DEBT		222,000		—		93,742	(a)		315,742
LONG-TERM DERIVATIVE LIABILITY		4,051		—		—			4,051
LONG-TERM DERIVATIVE PAYABLE TO DRILLING PARTNERSHIPS		4,483		—		—			4,483
ASSET RETIREMENT OBLIGATIONS AND OTHER		54,428		3,038		—			57,466
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL/EQUITY:
General partner’s interest		7,646		—		—			7,646
Common limited partners’ interests		596,348		—		174,471	(a)		767,319
						(3,500	)(b)
Preferred limited partners’ interests		96,110		—		—			96,110
Equity		—		173,797		83,652	(c)		—
						(257,449	)(d)
Accumulated other comprehensive income		8,644		—		—			8,644
Total partners’ capital/equity		708,748		173,797		(2,826	)		879,719
	$	1,138,942	$	347,481	$	(66,365	)	$	1,420,058

3

ATLAS RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

PRO FORMA CONSOLIDATED COMBINED STATEMENT OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2012

(in thousands)

(Unaudited)

	Historical			Historical Carrizo		Historical Titan			Historical DTE			Adjustments			Pro Forma
REVENUES:
Gas and oil production	$	61,323		$	6,878	$	9,733		$	38,217		$	—		$	116,151
Well construction and completion		92,277			—		—			—			—			92,277
Gathering and processing		10,311			—		—			—			—			10,311
Administration and oversight		8,586			—		—			—			—			8,586
Well services		15,344			—		—			—			—			15,344
Loss on mark-to-market derivatives		—			—		(1,477	)		—			—			(1,477	)
Other, net		(4,952	)		—		67			(187	)		—			(5,072	)
Total revenues		182,889			6,878		8,323			38,030			—			236,120
COSTS AND EXPENSES:
Gas and oil production		16,247			4,278		3,988			15,584			—			40,097
Well construction and completion		79,882			—		—			—			—			79,882
Gathering and processing		13,185			—		—			—			—			13,185
Well services		7,076			—		—			—			—			7,076
General and administrative		48,427			—		1,532			5,689			—			55,648
Chevron transaction expense		7,670			—		—			—			—			7,670
Depreciation, depletion and amortization		33,848			—		10,170			16,460			4,118	(e)		64,648
													52	(f)
Total costs and expenses		206,335			4,278		15,690			37,733			4,170			268,206
OPERATING INCOME (LOSS)		(23,446	)		2,600		(7,367	)		297			(4,170	)		(32,086	)
Interest expense		(2,529	)		—		(1,520	)		(4,464	)		(413	)(g)		(14,832	)
													(209	)(h)
													(234	)(i)
													(5,463	)(j)
Loss on asset sales and disposal		(7,019	)		—		—			—			—			(7,019	)
NET INCOME (LOSS)		(32,994	)		2,600		(8,887	)		(4,167	)		(10,489	)		(53,937	)
Preferred limited partner dividends		(1,221	)		—		—			—			(3,389	)(k)		(4,610	)
NET INCOME (LOSS) ATTRIBUTABLE TO OWNER’S INTEREST, COMMON LIMITED PARTNERS AND THE GENERAL PARTNER	$	(34,215	)	$	2,600	$	(8,887	)	$	(4,167	)	$	(13,878	)	$	(58,547	)

4

ALLOCATION OF NET INCOME (LOSS):
Portion applicable to owners’ interest (period prior to the transfer of assets on March 5, 2012)	$	250		$	(5,433	)
Portion applicable to common limited partners and the general partner’s interests (period subsequent to the transfer of assets on March 5, 2012)		(34,465	)		(53,114	)
NET INCOME (LOSS) ATTRIBUTABLE TO OWNER’S INTEREST, COMMON LIMITED PARTNERS AND THE GENERAL PARTNER	$	(34,215	)	$	(58,547	)
ALLOCATION OF NET LOSS ATTRIBUTABLE TO COMMON LIMITED PARTNERS AND THE GENERAL PARTNER:
Common limited partners’ interest	$	(33,776	)	$	(52,052	)
General partner’s interest		(689	)		(1,062	)
Net loss attributable to common limited partners and the general partner	$	(34,465	)	$	(53,114	)
NET LOSS ATTRIBUTABLE TO COMMON LIMITED PARTNERS PER UNIT:
Basic	$	(1.06	)	$	(1.18	)
Diluted	$	(1.06	)	$	(1.18	)
WEIGHTED AVERAGE COMMON LIMITED PARTNER UNITS OUTSTANDING:
Basic and Diluted		31,865			43,973

5

ATLAS RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

PRO FORMA CONSOLIDATED COMBINED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2011

(in thousands)

(Unaudited)

				Historical		Historical			Historical
	Historical			Carrizo		Titan			DTE			Adjustments			Pro Forma
REVENUES:
Gas and oil production	$	66,979		$	47,118	$	30,886		$	38,724		$	—		$	183,707
Well construction and completion		135,283			—		—			—			—			135,283
Gathering and processing		17,746			—		—			—			—			17,746
Administration and oversight		7,741			—		—			—			—			7,741
Well services		19,803			—		—			—			—			19,803
Other, net		(30	)		—		327			(584	)		—			(287	)
Total revenues		247,522			47,118		31,213			38,140			—			363,993
COSTS AND EXPENSES:
Gas and oil production		17,100			13,936		5,330			14,850			—			51,216
Well construction and completion		115,630			—		—			—			—			115,630
Gathering and processing		20,842			—		—			—			—			20,842
Well services		8,738			—		—			—			—			8,738
General and administrative		27,536			—		2,556			8,438			—			38,530
Depreciation, depletion and amortization		30,869			—		26,527			18,038			23,165	(e)		98,809
													210	(f)
Long-lived asset impairment		6,995			—		196,835			—			—			203,830
Total costs and expenses		227,710			13,936		231,248			41,326			23,375			537,595
OPERATING INCOME (LOSS)		19,812			33,182		(200,035	)		(3,186	)		(23,375	)		(173,602	)
Interest expense		—			—		(2,055	)		(6,468	)		(1,650	)(g)		(18,763	)
													(838	)(h)
													(468	)(i)
													(7,284	)(j)
Gain on asset sales and disposal		87			—		—			—			—			87
NET INCOME (LOSS)		19,899			33,182		(202,090	)		(9,654	)		(33,615	)		(192,278	)
Preferred limited partner dividends		—			—		—			—			(6,147	)(k)		(6,147	)
NET INCOME (LOSS) ATTRIBUTABLE TO OWNERS’ INTEREST, COMMON LIMITED PARTNERS AND THE GENERAL PARTNER	$	19,899		$	33,182	$	(202,090	)	$	(9,654	)	$	(39,762	)	$	(198,425	)
ALLOCATION OF NET INCOME (LOSS):
Portion applicable to owners’ interest (period prior to the transfer of assets on March 5, 2012)	$	19,899													$	(198,425	)
Portion applicable to common limited partners and the general partner’s interests (period subsequent to the transfer of assets on March 5, 2012)		—														—
NET INCOME (LOSS) ATTRIBUTABLE TO OWNERS’ INTEREST, COMMON LIMITED PARTNERS AND THE GENERAL PARTNER	$	19,899													$	(198,425	)

6

ATLAS RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS

(a) To reflect the net proceeds of (i) $174.5 million net of $7.3 million of transaction costs, from the public offering of 7.9 million of common limited partner units to investors at a net offering price per unit of $22.09 (net of $0.92 per unit for underwriters’ discount and fees) and (ii) net borrowings of $75.4 million under the Partnership’s term loan credit facility and $18.3 million under the Partnership’s revolving credit facility.

(b) To reflect the partial application of the $268.2 million of net proceeds from the public offering of common limited partner units and borrowings under the Partnership’s term loan credit facility and revolving credit facility for (i) the payment of $7.3 million of term loan credit facility and revolving credit facility fees and other transaction costs, which will be amortized over the remaining term of the respective debt instrument and (ii) the payment of costs of $3.5 million related to the DTE acquisition, which are expensed as incurred.

(c) To reflect the preliminary purchase price allocation of the DTE acquisition. Due to the recent date of the DTE 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 the Partnership continues to evaluate this preliminary allocation.

(d) To reflect the consummation of the DTE acquisition through the transfer to DTE of cash consideration of $257.4 million.

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

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

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

(h) To reflect the amortization of deferred financing costs incurred as a result of the Carrizo acquisition related to the Partnership’s revolving credit facility over the remainder of the facility’s respective term.

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

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

(k) To reflect the Class B preferred unit dividend payment of $0.40 per quarter per Class B preferred unit.