Titan Energy 8-K/A Financial Statements and Exhibits

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

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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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