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.

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DTE GAS RESOURCES, LLC

BALANCE SHEET

(in thousands)

See accompanying notes to the financial statements.

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DTE GAS RESOURCES, LLC

STATEMENT OF OPERATIONS

(in thousands)

See accompanying notes to the financial statements.

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DTE GAS RESOURCES, LLC

STATEMENT OF EQUITY

(in thousands)

See accompanying notes to the financial statements.

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DTE GAS RESOURCES, LLC

STATEMENT OF CASH FLOWS

(in thousands)

See accompanying notes to the financial statements.

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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

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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):

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):

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):

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:

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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):

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):

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):

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:

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