Exhibit 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Atlas Energy, Inc.

We have audited the accompanying combined statements of assets acquired and liabilities assumed of Atlas Energy, Inc.’s Upstream Oil and Gas Business (“Upstream Oil and Gas Business”) as of December 31, 2009 and 2008, pursuant to the Transaction Agreement by and among Atlas Energy, Inc., Atlas Energy Resources, LLC, Atlas Pipeline Holdings, L.P. and Atlas Pipeline Holdings GP, LLC dated November 8, 2010 as described in Note 1, and the related combined statements of revenues and direct expenses for each of the years in the three year period ended December 31, 2009. These combined financial statements are the responsibility of Atlas Energy, Inc.’s management. Our responsibility is to express an opinion on these combined financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the combined financial statements are free of material misstatement. We were not engaged to perform an audit of the Upstream Oil and Gas Business’ internal control over financial reporting. Our audit included 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 Upstream Oil and Gas Business’ 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 combined financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

The accompanying combined financial statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 1, and are not intended to be a complete financial presentation of the Upstream Oil and Gas Business.

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the combined assets acquired and liabilities assumed of Atlas Energy, Inc.’s Upstream Oil and Gas Business as of December 31, 2009 and 2008, and the related combined revenues and direct expenses for each of the years in the three year period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.

 

/s/ GRANT THORNTON LLP

Cleveland, Ohio

February 15, 2011

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UPSTREAM OIL AND GAS BUSINESS

COMBINED STATEMENTS OF ASSETS ACQUIRED AND LIABILITIES ASSUMED

(in thousands)

 

		December 31,
		2009				2008
ASSETS ACQUIRED
Current assets:
Accounts receivable		$	29,476			$	27,748
Current portion of derivative receivable from Partnerships			270				3,022
Current portion of derivative asset			34,123				56,600
Subscriptions receivable from Partnerships			46,884				44,250
Prepaid expenses and other			10,298				11,741
Total current assets			121,051				143,361
Property, plant and equipment, net			475,178				547,984
Intangible assets, net			2,873				3,615
Goodwill, net			31,784				31,784
Long-term derivative asset			28,667				36,524
Long-term derivative receivable from Partnerships			2,841				2,719
Investment in Lightfoot			11,528				9,742
Other assets, net			62				—
		$	673,984			$	775,729
LIABILITIES ASSUMED
Current liabilities:
Accounts payable		$	49,107			$	40,710
Liabilities associated with drilling contracts			122,532				141,133
Current portion of derivative payable to Partnerships			22,382				34,933
Current portion of derivative liability			412				4,904
Accrued well drilling and completion costs			68,138				25,216
Accrued liabilities			12,876				10,869
Total current liabilities			275,447				257,765
Long-term derivative payable to Partnerships			22,380				22,581
Long-term derivative liability			4,591				4,412
Asset retirement obligations			32,016				29,890
Commitments and contingencies
		$	334,434			$	314,648

See accompanying notes to the combined statements of assets acquired and liabilities assumed

and the related revenues and direct expenses.

 

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UPSTREAM OIL AND GAS BUSINESS

COMBINED STATEMENTS OF REVENUES AND DIRECT EXPENSES

(in thousands)

 

		Years Ended December 31,
		2009				2008				2007
Revenues:
Gas and oil production		$	108,821			$	117,396			$	88,402
Well construction and completion			372,045				415,036				321,471
Gathering and processing			17,432				15,113				11,284
Administration and oversight			15,554				19,277				17,955
Well services			19,016				18,547				15,439
Other, net			(1,502	)			469				(10	)
Total revenues			531,366				585,838				454,541
Direct expenses:
Gas and oil production			22,107				24,366				16,779
Well construction and completion			315,546				359,609				279,540
Gathering and processing			19,245				18,540				13,881
Well services			8,745				8,533				7,936
Depreciation, depletion and amortization			37,509				29,946				23,867
Asset impairment			156,359				—				—
Total direct expenses			559,511				440,994				342,002
Revenues in excess of (less than) direct expenses		$	(28,145	)		$	144,844			$	112,538

See accompanying notes to the combined statements of assets acquired and liabilities assumed

and the related revenues and direct expenses.

 

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UPSTREAM OIL AND GAS BUSINESS

NOTES TO COMBINED STATEMENTS OF ASSETS ACQUIRED AND LIABILITIES

ASSUMED AND THE RELATED REVENUES AND DIRECT EXPENSES

NOTE 1 — BASIS OF PRESENTATION

On November 8, 2010, Atlas Pipeline Holdings, L.P. (“AHD”) (NYSE: AHD) entered into an agreement with Atlas Energy, Inc (“ATLS”) (NASDAQ: ATLS) whereby AHD would acquire ATLS’ investment partnership management business and certain natural gas reserves and other energy assets (the “Upstream Oil and Gas Business” or the “Business”) for 23.38 million new AHD common limited partner units (which had a value of approximately $220 million as of November 8, 2010) and $30 million in cash (the “AHD Transaction”). The agreement between AHD and ATLS is contingent upon the closing of ATLS’s definitive merger agreement dated November 8, 2010 with Chevron Corporation (“Chevron”), pursuant to which Chevron agreed to acquire ATLS through a merger of a newly formed wholly owned subsidiary of Chevron with and into ATLS (the “Merger”). In the Merger, each share of ATLS common stock will receive $38.25 in cash, and each share of outstanding ATLS common stock will also receive a pro rata share of common units of AHD held by ATLS as of immediately prior to the transaction.

Concurrent with entering into the merger agreement and the AHD transaction agreement, ATLS and Atlas Pipeline Partners, L.P. (“APL”) have agreed that, prior to the Merger, ATLS will acquire APL’s 49% interest in Laurel Mountain Midstream, LLC for $403 million in cash payable to APL (the “LMM Sale”), pursuant to an agreement dated November 8, 2010.

The closing of the Merger is subject to approval by ATLS’s shareholders and other customary closing conditions, as well as the completion of the AHD Transaction and the LMM Sale. Completion of each of the AHD Transaction and the LMM Sale are also conditioned on the subsequent completion of the Merger.

ATLS is a publicly traded Delaware corporation, which is an independent developer and producer of natural gas and oil, with operations in the Appalachian, Michigan, and Illinois Basins. In addition to its natural gas development and production operations, ATLS also maintains ownership interests in the following entities:

 

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APL, a publicly traded Delaware limited partnership and midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions. At December 31, 2009, ATLS had a 2.2% direct ownership interest in APL;

 

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AHD, a publicly traded Delaware limited partnership and owner of the general partner of APL. Through ATLS’s ownership of AHD’s general partner, it manages AHD. AHD’s cash generating assets currently consist solely of its interests in APL. At December 31, 2009, ATLS owned approximately 64.3% of the outstanding common units of AHD. At December 31, 2009, AHD owned a 2% general partner interest, all of the incentive distribution rights, an approximate 11.4% common limited partner interest, and 15,000 $1,000 par value 12.0% Class B cumulative preferred limited partner units in APL (representing an approximately 2.3% ownership). The Class B preferred units subsequently have been redeemed.

The accompanying historical combined statements of assets acquired and liabilities assumed together with the combined statements of revenues and direct expenses are presented using the accrual basis of accounting, and represent the historical carrying value of assets acquired and liabilities assumed as well as revenues and direct expenses attributable to ATLS’s interest in the following:

 

•

Certain natural gas reserves located primarily in Indiana, New York, Ohio, Pennsylvania and Tennessee;

 

•

ATLS’s investor sponsored energy partnerships management business (the “Partnerships”); and

 

•

certain other energy assets, including an approximate direct and indirect 18% ownership interest in Lightfoot Capital Partners GP LLC (“Lightfoot GP”), the general partner of Lightfoot Capital Partners, LP (“Lightfoot LP”; collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs.

 

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ATLS did not prepare separate, stand-alone historical financial statements for the Business in accordance with accounting principles generally accepted in the United States of America. Accordingly, it is not practicable to identify all assets and liabilities, or other indirect operating costs applicable to the Business, other than those presented in the accompanying combined statements of assets acquired and liabilities assumed and the related combined statements of revenues and direct expenses. The accompanying combined statements of assets acquired and liabilities assumed and the related combined statements of revenues and direct expenses were prepared from the historical accounting records of ATLS.

Certain indirect expenses were not allocated to the Business’ historical financial records. Any attempt to allocate these expenses would require significant and judgmental allocations (see Note 10).

The accompanying statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and are not intended to represent a complete set of financial statements reflecting financial position, results of operations, shareholders’ equity, and cash flows of the Upstream Oil and Gas Business, and are not indicative of the results of operations for the Upstream Oil and Gas Business going forward.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Combination and Use of Estimates

The combined statements of assets acquired and liabilities assumed at December 31, 2009 and 2008 and the related combined statements of revenues and direct expenses for the years ended December 31, 2009, 2008 and 2007 were derived from the accounts of ATLS and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated in the combination of the combined statements of assets acquired and liabilities assumed and related combined statements of revenues and direct expenses. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the statements of assets acquired and liabilities assumed and the related revenues and direct expenses. Such estimates included allocations made from the historical accounting records of ATLS, based on management’s best estimates, in order to derive the financial statements of the Business. Actual balances and results could be different from those estimates.

Receivables

Accounts receivable on the combined statements of assets acquired and liabilities assumed consists solely of the trade accounts receivable associated with the Business. In evaluating the realizability of the Business’ accounts receivable, ATLS management performed ongoing credit evaluations of the Business’ customers and adjusted credit limits based upon payment history and the customer’s current creditworthiness, as determined by ATLS management’s review of the customers’ credit information. ATLS extends credit on sales on an unsecured basis to many of the Business’ customers. At December 31, 2009 and 2008, there was no allowance for uncollectible accounts receivable related to the Business on its combined statements of assets acquired and liabilities assumed.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired (see Note 3). Depreciation and amortization expense of the Business was based on the historical cost of such assets. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized. Property, plant and equipment related to the Business was determined based on the historical cost of such assets included within the Business.

The Business 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 equals 6 Mcf.

Depletion expense was determined by ATLS management on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs were based on estimated proved reserves and depletion rates for well and related equipment costs were based on proved developed reserves associated with each field. Depletion rates were 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 were aggregated to include the Business’ costs of property

 

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interests in proportionately consolidated investment partnerships, joint venture wells, wells drilled solely by the Business for

its interests, properties purchased and working interests with other outside operators. Depletion expense related to the Business was determined based on the historical cost of the natural gas and oil properties included within the Business.

Upon the sale or retirement of a complete field of a proved property, the Business eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Business’ combined statements of revenues and direct expenses. Upon the sale of an individual well, the Business credits the proceeds to accumulated depreciation and depletion within its combined statements of assets acquired and liabilities assumed. Upon the Business’ sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the the Business’ combined statements of revenues and direct expenses. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Impairment of Long-Lived Assets

ATLS management reviews the Business’ 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 oil and gas properties related to the Business was 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 was less than the estimated expected undiscounted future cash flows. The expected future cash flows were estimated based on ATLS management’s plans to continue to produce and develop the Business’ proved reserves. Expected future cash flow from the sale of production was calculated based on estimated future prices. ATLS management estimated 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 was based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, ATLS management’s reserve estimates for the Business’ investment in the Partnerships were based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include the Business’ actual capital contributions, an additional carried interest (generally 7% to 10%), a disproportionate share of salvage value upon plugging of the wells and lower operating costs.

The Business’ lower operating costs result from the limited partners in the Partnerships paying to the Business their proportionate share of these expenses plus a profit margin. These assumptions could result in the Business’ calculation of depletion and impairment being different than its proportionate share of the Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. ATLS management cannot predict what reserve revisions may be required by the Business in future periods.

ATLS management’s method of calculating the Business’ reserves may result in reserve quantities and values which are greater than those which would be calculated by the Partnerships, which the Business sponsors and owns an interest in but does not control. Reserve quantities related to the Business include reserves in excess of its proportionate share of reserves in a Partnership which the Business may be unable to recover due to the Partnership legal structure. The Business may have to pay additional consideration in the future as a well or Partnership becomes uneconomic under the terms of the partnership agreement in order to recover these excess reserves and to acquire any additional residual interests in the wells held by other partnership investors. The acquisition of any well interest from the Partnership by the Business is governed under the partnership agreement and in general, must be at fair market value supported by an appraisal of an independent expert selected by ATLS management for the Business. There were no impairments of proved oil and gas properties recorded related to the Business for the years ended December 31, 2008 and 2007.

 

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During the year ended December 31, 2009, the Business recorded a $156.4 million asset impairment related to oil and gas properties within property, plant and equipment on its combined statement of assets acquired and liabilities assumed for shallow natural gas wells in the Upper Devonian shale. This impairment related to the carrying amount of these oil and gas properties being in excess of ATLS management’s estimate of their fair value at December 31, 2009. The estimate of fair value of these oil and gas properties was impacted by, among other factors, the deterioration of natural gas prices.

Intangible Assets

The Business has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through consummated acquisitions. The Business amortizes contracts acquired on a declining balance and straight-line method over their respective estimated useful lives. The following table reflects the components of intangible assets being amortized at December 31, 2009 and 2008 (in thousands):

 

		December 31,								Estimated Useful Lives
		2009				2008				In Years
Partnership management and operating contracts:
Gross Carrying Amount		$	14,343			$	14,343				2 – 13
Accumulated Amortization			(11,470	)			(10,728	)
Net Carrying Amount		$	2,873			$	3,615

Amortization expense on intangible assets was $0.8 million, $0.8 million and $0.8 million for the years ended December 31, 2009, 2008 and 2007, respectively. Estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2010-$0.7 million; 2011-$0.7 million; 2012-$0.2 million; 2013-$0.2 million; and 2014-$0.1 million.

Goodwill

At December 31, 2009 and 2008, the Business had $31.8 million of goodwill recorded in connection with consummated acquisitions. There have been no changes in the carrying amount of goodwill for the years ended December 31, 2009, 2008 and 2007.

ATLS management tests the Business’ goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, ATLS management must apply judgment in determining the estimated fair value of these reporting units. ATLS management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the Business’ assets. The fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in its industry to determine whether those valuations appear reasonable in ATLS management’s judgment. ATLS management will continue to evaluate the goodwill at least annually or when impairment indicators arise.

There were no goodwill impairments related to the Business during the years ended December 31, 2009, 2008 and 2007.

Derivative Instruments

The Business had certain financial contracts to manage its exposure to movement in commodity (see Note 6). The derivative instruments recorded in the combined statements of assets acquired and liabilities assumed was measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value were recognized currently in the Business’ combined statements of revenues and direct expenses unless specific hedge accounting criteria were met.

Accounts Payable

Accounts payable was determined based on an allocation of the amounts related to the operations of the Business.

Asset Retirement Obligations

Pursuant to prevailing accounting literature, the Business recognized an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities (see Note 4). The Business recognizes a liability for future asset

 

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retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Business is

required to consider estimated salvage value in the calculation of depreciation, depletion and amortization. Asset retirement obligations and the related assets of the Business were determined based on the historical cost of the natural gas and oil properties included within the Business.

Environmental Matters

The Business is subject to various federal, state and local laws and regulations relating to the protection of the environment. ATLS management has established procedures for the ongoing evaluation of the Business’ 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. The Business maintains insurance which may cover in whole or in part certain environmental expenditures. At December 31, 2009 and 2008, the Business had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

Revenue Recognition

Certain energy activities are conducted by the Business through, and a portion of its revenues are attributable to, sponsored investment partnerships. The Business contracts with the Partnerships to drill partnership wells. The contracts require that the Partnerships must pay the Business the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed between 60 and 180 days. On an uncompleted contract, the Business classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Liabilities Associated with Drilling Contracts” on the combined statements of assets acquired and liabilities assumed. The Business recognizes well services revenues at the time the services are performed. The Business is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned and includes them in administration and oversight revenues within the combined statements of revenues and direct expenses.

The Business generally sells natural gas and crude oil at prevailing market prices. Revenue is 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 Business has an interest with other producers are recognized on the basis of its percentage ownership of working interest and/or overriding royalty. Generally, sales contracts related to the Business are based on pricing provisions that are tied to a market index, with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas.

The Business accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil and the receipt of a delivery statement. These revenues are determined based upon subsequent months cash receipts data from the Business’ records and ATLS management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “–Use of Estimates” accounting policy for further description). The Business generated unbilled revenues at December 31, 2009 and 2008 of $29.5 million and $27.7 million, respectively, which were included in accounts receivable within the Business’ combined statements of assets acquired and liabilities assumed.

Direct Expenses

Direct expenses are recognized when incurred and consist of direct expenses related to the Business. The direct expenses are comprised of operating expenses, including production expenses, well construction expenses, gathering fees and well service expenses; as well as non-operating charges, including depreciation, depletion and amortization and asset impairment. Operating expenses include costs incurred in the extraction of gas and oil, the constructing and servicing of wells included within the Partnerships, and the gathering and processing of gas and oil.

NOTE 3 — PROPERTY, PLANT AND EQUIPMENT

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

 

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										Estimated
		December 31,								Useful Lives
		2009				2008				in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests		$	34,391			$	29,657
Wells and related equipment			672,827				563,961
Total proved properties			707,218				593,618
Unproved properties			40,189				42,362
Support equipment			4,839				5,248
Total natural gas and oil properties			752,246				641,228
Pipelines, processing and compression facilities			23,993				21,238				2 – 40
Rights of way			—				148				20 – 40
Land, buildings and improvements			4,939				2,873				3 –  40
Other			4,916				5,301				3 – 10
			786,094				670,787
Less – accumulated depreciation, depletion and amortization			(310,916	)			(122,803	)
		$	475,178			$	547,984

During the year ended December 31, 2009, the Business recognized a $156.4 million asset impairment related to oil and gas properties within property, plant and equipment on its combined statement of assets acquired and liabilities assumed for shallow natural gas wells in the Upper Devonian shale. This impairment related to the carrying amount of the Business’ oil and gas properties being in excess of ATLS management’s estimate of their fair value at December 31, 2009. The estimate of fair value of these oil and gas properties was impacted by, among other factors, the deterioration of natural gas prices.

NOTE 4 — ASSET RETIREMENT OBLIGATIONS

The Business is required to recognize a liability for future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Business is required to consider estimated salvage value in the calculation of depreciation, depletion and amortization.

The Business recognized an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities at December 31, 2009 and 2008 on its combined statements of assets acquired and liabilities assumed. The estimated liability was based on ATLS management’s historical experience in plugging and abandoning wells for the Business, 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. No assets legally restricted for purposes of settling asset retirement obligations are included within the Business’ combined statements of assets acquired and liabilities assumed. Except for the Business’ oil and gas properties, ATLS management has determined that there are no other material retirement obligations associated with the Business’ tangible long-lived assets.

A reconciliation of the Business’ liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):

 

		Years Ended December 31,
		2009				2008				2007
Asset retirement obligations, beginning of year		$	29,890			$	27,994			$	24,937
Liabilities acquired			—				—				—
Liabilities incurred			573				463				1,667
Liabilities settled			(245	)			(227	)			(91	)
Accretion expense			1,798				1,660				1,481
Asset retirement obligations, end of year		$	32,016			$	29,890			$	27,994

 

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The above accretion expense was included in depreciation, depletion and amortization in the Business’ combined statements of revenues and direct expenses and the asset retirement obligation liabilities were included in other long-term liabilities on the Business’ combined statements of assets acquired and liabilities assumed.

NOTE 5 — INVESTMENT IN LIGHTFOOT

At December 31, 2009, the Business had a $11.5 million net investment balance in Lightfoot Capital Partners, LP (“Lightfoot LP”) and Lightfoot Capital Partners GP LLC (“Lightfoot GP”) the general partner of Lightfoot (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. At December 31, 2009, the Business had an approximate direct and indirect 18% ownership interest in Lightfoot GP, an entity for which Jonathan Cohen, Vice Chairman of ATLS’s Board of Directors, is the Chairman of the Board. The Business also had a direct and indirect ownership interest in Lightfoot LP of approximately 13% at December 31, 2009. The Business has certain co-investment rights until such point as Lightfoot LP raises additional capital through a private offering to institutional investors or a public offering. The Business accounts for its investment in Lightfoot under the equity method of accounting. The Business recorded losses associated with its equity ownership interest in Lightfoot of $1.4 million, $0.6 million and $0.3 million for the years ended December 31, 2009, 2008 and 2007, respectively, which were included within other, net on the combined statements of revenues and direct expenses.

NOTE 6 — DERIVATIVE INSTRUMENTS

The Business uses a number of different derivative instruments, principally swaps, collars and options, in connection with its commodity price risk management activities. ATLS management enters into financial instruments to hedge the Business’ forecasted natural gas and crude oil sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas and crude oil is sold. Under swap agreements, the Business receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not the obligation, to purchase or sell natural gas and crude oil at a fixed price for the relevant contract period.

ATLS management formally documents all relationships between the Business’ hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity derivative contracts to the forecasted transactions. ATLS management assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the Business’ forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Business will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by ATLS management for the Business through the utilization of market data, will be recognized immediately within other, net in the Business’ combined statements of revenues and direct expenses. For derivatives qualifying as hedges, the Business recognizes the effective portion of changes in fair value of derivative instruments as accumulated other comprehensive income and reclassifies the portion relating to commodity derivatives to gas and oil production revenues within the Business’ combined statements of revenues and direct expenses as the underlying transactions are settled. With regard to the Business’ balance within accumulated other comprehensive income at December 31, 2009 and 2008, the Business has only presented the accompanying combined statements of assets acquired and liabilities assumed and, as such, equity, including accumulated other comprehensive income, has not been presented.

The Business’ derivatives were recorded on the combined statements of assets acquired and liabilities assumed as assets or liabilities at fair value. The Business reflected net derivative assets on its combined statements of assets acquired and liabilities assumed of $57.8 million and $83.8 million at December 31, 2009 and 2008, respectively. The following table summarizes the fair value of the Business’ derivative instruments as of December 31, 2009 and 2008, as well as the gain or loss recognized in the combined statements of revenues and direct expenses for effective derivative instruments for the years ended December 31, 2009 and 2008:

 

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Fair Value of Derivative Instruments:

 

		Asset Derivatives										Liability Derivatives
Derivatives in Cash Flow Hedging Relationships		Combined Statement of Assets Acquired and Liabilities Assumed		Fair Value December 31,								Combined Statement of Assets Acquired and Liabilities Assumed		Fair Value December 31,
		Location		2009				2008				Location		2009				2008
				(in thousands)										(in thousands)
Commodity contracts:		Current assets		$	34,123			$	56,600			Current liabilities		$	(412	)		$	(4,904	)
		Long-term assets			28,667				36,524			Long-term liabilities			(4,591	)			(4,412	)
Total derivatives				$	62,790			$	93,124					$	(5,003	)		$	(9,316	)

Effects of Derivative Instruments on Combined Statements of Revenues and Direct Expenses:

 

Derivatives in Cash Flow Hedging Relationships		Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) for the Years Ended December 31,								Location of Gain/(Loss) Reclassified from Accumulated OCI into Income (Effective Portion)		Gain/(Loss) Reclassified from OCI into Income (Effective Portion) for the Years Ended December 31,
												2009				2008
		2009				2008
		(in thousands)										(in thousands)
Commodity contracts		$	27,846			$	23,956			Gas and oil production		$	43,745							$	(4,934	)

ATLS management enters into natural gas and crude oil future option contracts and collar contracts for the Business to achieve more predictable cash flows by hedging its exposure to changes in natural gas prices and oil prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

Gains of $43.7 million and $10.8 million for years ended December 31, 2009 and 2007, respectively, and a loss of $4.9 million for the year ended December 31, 2008 on settled contracts covering natural gas and oil production were recognized within gas and oil production revenue on the Business’ combined statements of revenues and direct expenses. As the underlying prices and terms in the Business’ derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the years ended December 31, 2009 and 2008 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

At December 31, 2009, the Business had the following commodity derivatives:

Natural Gas Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Asset
		(mmbtu)(1)				(per mmbtu) (1)				(in thousands) (2)
2010			22,890,300			$	7.337			$	30,337
2011			13,042,100			$	6.982				9,142
2012			8,919,200			$	7.223				6,961
2013			6,536,400			$	7.082				1,990
										$	48,430

Natural Gas Costless Collars

 

Production Period Ending December 31,		Option Type				Volumes				Average Floor and Cap				Fair Value Asset
						(mmbtu)(1)				(per mmbtu) (1)				(in thousands)(2)
2010			Puts purchased				1,621,000			$	7.839			$	3,377
2010			Calls sold				1,621,000			$	9.007				—
2011			Puts purchased				6,462,000			$	6.449				3,881
2011			Calls sold				6,462,000			$	7.630				—
2012			Puts purchased				3,872,000			$	6.512				1,462
2012			Calls sold				3,872,000			$	7.714				—
2013			Puts purchased				3,626,000			$	6.584				890
2013			Calls sold				3,626,000			$	7.792				—
														$	9,610

 

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Crude Oil Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Asset/(Liability)
		(Bbl) (1)				(per Bbl) (1)				(in thousands) (3)
2010			48,900			$	97.400			$	766
2011			42,600			$	77.460				(353	)
2012			33,500			$	76.855				(354	)
2013			10,000			$	77.360				(108	)
										$	(49	)

Crude Oil Costless Collars

 

Production Period Ending December 31,		Option Type		Volumes				Average Floor and Cap				Fair Value Asset/(Liability)
				(Bbl) (1)				(per Bbl) (1)				(in thousands) (3)
2010		Puts purchased			31,000			$	85.000			$	253
2010		Calls sold			31,000			$	112.218				—
2011		Puts purchased			27,000			$	67.223				—
2011		Calls sold			27,000			$	89.436				(201	)
2012		Puts purchased			21,500			$	65.506				—
2012		Calls sold			21,500			$	91.448				(200	)
2013		Puts purchased			6,000			$	65.358				—
2013		Calls sold			6,000			$	93.442				(56	)
												$	(204	)
					Total Company net asset							$	57,787

 

(1)	“Mmbtu” represents million British Thermal Units; “Bbl” represents barrels.

(2)	Fair value based on forward NYMEX natural gas prices, as applicable.

(3)	Fair value based on forward WTI crude oil prices, as applicable.

ATLS management’s commodity price risk management for the Business includes estimated future natural gas and crude oil production of the Partnerships. Therefore, a portion of any unrealized derivative gain or loss is allocable to the limited partners of the Partnerships based on their share of estimated gas and oil production related to the derivatives not yet settled. At December 31, 2009 and 2008, net unrealized derivative assets of $41.7 million and $51.8 million, respectively, are payable to the limited partners in the Partnerships and were included on the Business’ combined statements of assets acquired and liabilities assumed as follows (in thousands):

 

		December 31,
		2009				2008
Current portion of derivative receivable from Partnerships		$	270			$	3,022
Long-term derivative receivable from Partnerships			2,841				2,719
Current portion of derivative payable to Partnerships			(22,382	)			(34,933	)
Long-term portion of derivative payable to Partnerships			(22,380	)			(22,581	)
		$	(41,651	)		$	(51,773	)

NOTE 7 — FAIR VALUE OF FINANCIAL INSTRUMENTS

ATLS management has established a hierarchy to measure the Business’ financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1 – Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

 

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Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Business uses a fair value methodology to value its outstanding derivative contracts (see Note 6) based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements.

Information for assets and liabilities measured at fair value at December 31, 2009 and 2008 was as follows (in thousands):

 

		Level 1				Level 2				Level 3				Total
December 31, 2009
Company commodity-based derivatives		$	—			$	57,787			$	—			$	57,787
Total		$	—			$	57,787			$	—			$	57,787
December 31, 2008
Company commodity-based derivatives		$	—			$	83,808			$	—			$	83,808
Total		$	—			$	83,808			$	—			$	83,808

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

ATLS management estimates the fair value of the Business’ asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Business, and estimated inflation rates. Information for assets that are measured at fair value on a nonrecurring basis for the years ended December 31, 2009 and 2008 was as follows (in thousands):

 

		Year Ended December 31,
		2009								2008
		Level 3				Total				Level 3				Total
Asset retirement obligations		$	573			$	573			$	463			$	463
Total		$	573			$	573			$	463			$	463

NOTE 8 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

In the ordinary course of its business operations, the Business has ongoing relationships with several related entities:

Relationship with Sponsored Investment Partnerships. The Business conducts certain activities through, and a portion of its revenues are attributable to, the Partnerships. The Business serves as general partner and operator of the Partnerships and assumes customary rights and obligations for the Partnerships. As the general partner, the Business is liable for the Partnerships’ liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Partnerships. The Business is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Partnerships’ revenue, and costs and expenses according to the respective partnership agreements.

Relationship with Laurel Mountain. Upon completion of APL’s formation of the Laurel Mountain joint venture in April 2009, ATLS, on its own and on behalf of the Business, entered into new gas gathering agreements with Laurel Mountain which superseded the existing master natural gas gathering agreement and omnibus agreement between ATLS and APL. Under the new gas gathering agreements, the Business is obligated to pay Laurel Mountain all of the gathering fees it collects from the Partnerships, which generally ranges from $0.35 per Mcf to the amount of the competitive gathering fee (which is currently defined as 13% of the gross sales price received for the Partnerships’ gas) plus any excess amount of the gathering fees collected up to an amount equal to approximately 16% of the natural gas sales price. The new gathering

 

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agreements contain additional provisions which define certain obligations and options of each party to build and connect newly drilled wells to any Laurel Mountain gathering system.

NOTE 9 — COMMITMENTS AND CONTINGENCIES

General Commitments

The Business leases equipment under leases with varying expiration dates through 2020. Rental expense was $0.7 million, $0.8 million and $0.6 million for the years ended December 31, 2009, 2008 and 2007, respectively. Future minimum rental commitments for the next five years are as follows (in thousands):

 

Years Ended December 31:
2010		$	1,298
2011			720
2012			482
2013			282
2014			141
Thereafter			—
		$	2,923

The Business is the managing general partner of the Partnerships and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Partnership assets. Subject to certain conditions, investor partners in certain Partnerships have the right to present their interests for purchase by the Business, as managing general partner. The Business is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on past experience, ATLS management believes that any liability incurred by the Business would not be material. ATLS may be required to subordinate a part of its net partnership revenues from the Partnerships to the benefit of the investor partners for an amount equal to at least 10% of their subscriptions, determined on a cumulative basis, in accordance with the terms of the partnership agreements. For the year ended December 31, 2009, $3.9 million of the Business’ revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the investment partnerships. There was no subordination of the Business’ net revenues for the years ended December 31, 2008 and 2007.

Legal Proceedings

Following the announcement of the Merger on November 9, 2010, the following actions were filed in the Delaware Court of Chancery, the Court of Common Pleas of Allegheny County, Pennsylvania and the U.S. District Court for the Western District of Pennsylvania, challenging the Merger (other than Ussach, which challenges the LMM Sale, as described below): Muir v. Atlas Energy, Inc. et al., C.N. G.D. 10-20988 (Pa. Ct. Com. Pl. filed 11/9/10); Hansz v. Atlas Energy, Inc. et al., C.N. G.D. 10-21055 (Pa. Ct. Com. Pl. filed 11/10/10); Katsman v. Atlas Energy, Inc. et al., C.N. 5990-VCL (Del. Ch. filed 11/15/10); Nishihara v. Atlas Energy, Inc. et al., Case No. 2:10-cv-01526 (W.D. Pa. filed 11/15/10); Jacobs v. Cohen, et al., C.N. G.D. 10-21370 (Pa. Ct. Com. Pl. filed 11/16/10); Ussach v. Atlas Energy, Inc. et al., Case No. 2:10-cv-01533 (W.D. Pa. filed 11/16/10); and, Weber v. Atlas Energy, Inc. et al., C.N. 6006-VCL (Del. Ch. filed 11/19/10). The Pennsylvania state court actions were consolidated as In re Atlas Energy, Inc. Shareholders Class Action Litigation, Case No. G.D. 10-20988. The Delaware actions were consolidated as In re Atlas Energy, Inc. Shareholders Litigation, C.A. No. 5990-VCL (the “Consolidated Delaware Action”).

The complaints in the Pennsylvania and Delaware state courts and in the Nishihara action in federal court all raise substantially the same claims. All are purported class actions filed on behalf of ATLS’s public stockholders (other than those affiliated in any way with ATLS) and assert claims of breaches of fiduciary duty in connection with the merger agreement by the various directors and officers of ATLS and aiding and abetting of those breaches by ATLS. Several of these actions additionally assert aiding and abetting claims against Chevron and Arkhan Corporation (“Merger Sub”) and/or affiliates of ATLS, including, in the Katsman action, AHD. The Ussach complaint is a purported derivative action on behalf of APL challenging the LMM Sale and claiming unjust enrichment by ATLS and breaches of fiduciary duty by APL GP, the members of its managing board and ATLS. All of the actions seek injunctive relief against the Merger (other than Ussach, where the plaintiff is seeking damages, disgorgement and rescission) and rescission of any portion thereof already consummated. Some of the actions seek monetary damages as well. On December 10, 2010, the Pennsylvania state court stayed the actions before it in favor of the Delaware actions.

On December 28, 2010, the plaintiffs in the Consolidated Delaware Action filed an amended complaint (the “Amended Complaint”). The Amended Complaint names as defendants ATLS, Chevron, Merger Sub and the directors of ATLS and

 

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alleges breaches of fiduciary duties in connection with the Merger by the individual defendants and aiding and abetting of those breaches by ATLS, Chevron and Merger Sub. It also claims that the proxy statement filed by Atlas Energy contains material misstatements and omissions. Among other things, the Amended Complaint alleges that the proxy statement fails to disclose material information concerning the discussions and negotiations between ATLS and Chevron as well as material information ATLS’s board relied upon in recommending the Merger, and that the proxy statement omits material information regarding the financial analyses performed by ATLS’s financial advisors and the advisory fees received by those investment banks. It also claims that the proxy statement filed by ATLS contains material misstatements and omissions. AHD is not named as a defendant in the Amended Complaint. The Amended Complaint seeks, among other things, declaratory and injunctive relief enjoining the Merger. On February 1, 2011, the parties in the Consolidated Delaware Action reached an agreement-in-principle to settle, dismiss and release all claims which were or could have been asserted in that action. On February 3, 2011, the parties executed a memorandum of understanding (the “MOU”) memorializing that agreement and presented the MOU to the Delaware state court. The MOU provides, among other things, that ATLS or its successor(s) will make a cash payment of $0.10 per share of ATLS common stock to the stockholders of ATLS, subject to certain limitation, following the consummation of the Merger and final approval of the settlement by the Delaware state court. Additional information about the MOU and the settlement is publicly available in a Current Report on Form 8-K filed by ATLS on February 7, 2011.

On December 21, 2010, the plaintiff in the Nishihara action filed an amended complaint (the “Amended Federal Complaint”). The Amended Federal Complaint names as defendants ATLS, Chevron, Merger Sub and various directors and officers and alleges breaches of fiduciary duties in connection with the Merger by the individual defendants and aiding and abetting of those breaches by ATLS, Chevron and Merger Sub. It also alleges violations of the Securities Exchange Act of 1934, as amended, arising out of ATLS’s disclosures in its proxy statement, which it claims, among other things, omits and/or misrepresents information about the merger process and omits material information regarding the financial analyses provided by ATLS’s financial advisors and the advisory fees received by those financial advisors. It seeks, among other things, declaratory and injunctive relief enjoining the Merger. On January 18, 2011, the defendants moved to dismiss the Amended Federal Complaint and to stay the action. On February 9, 2011, the court extended the deadline for the plaintiff to respond to the defendants’ motions to dismiss and to stay the action to February 22, 2011.

On January 26, 2011, the court hearing the Ussach derivative action entered an order providing that the defendants must respond to the complaint by March 2, 2011.

Predicting the outcome of these lawsuits is difficult. A preliminary injunction or an adverse judgment granting permanent injunctive relief could delay, jeopardize or indefinitely enjoin completion of the Merger or the LMM Sale, which could in turn delay, jeopardize or indefinitely prevent the consummation of the AHD Transaction, because ATLS’s obligation to consummate the AHD Transaction is subject to the satisfaction or waiver of the conditions to the consummation of the Merger and the satisfaction or waiver of the conditions to the consummation of the LMM Sale. The defendants in these cases believe that the claims asserted against them in these lawsuits are without merit, and that they intend to defend themselves vigorously against the claims.

In addition to the foregoing proceedings, certain subsidiaries of ATLS are defendants in two other litigations. The plaintiffs in In re Atlas Energy Resources, LLC Unitholder Litigation, C.A. No. 4589-VCN (Del. Ch.), allege violations of fiduciary duties in connection with the merger of Atlas America, Inc. and Atlas Energy Resources, LLC. Atlas America filed its Answer and Affirmative Defenses on December 20, 2010. The plaintiff in CNX Gas Co., LLC v. Miller Petroleum, Inc. (Ch. Ct., Campbell Cnty., Tenn.) alleges that Atlas America, LLC and another defendant interfered with the closing of an assignment by Miller to CNX of certain leasehold rights representing approximately 30,000 acres in Campbell County, Tennessee. The court dismissed all claims against Atlas America, LLC, however, CNX appealed the decision. The appeal was argued on May 18, 2010 before the Tennessee Court of Appeals, and the parties are awaiting the court’s decision.

The Business 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 Business’s financial condition or results of operations.

NOTE 10 — EXCLUDED EXPENSES (UNAUDITED)

The Business is part of ATLS and, consequently, indirect general and administrative expenses, interest, income taxes and other indirect expenses were not allocated to the Business and have therefore been excluded from the accompanying combined statements. In addition, ATLS management believes such indirect expenses are not indicative of future costs that may be incurred by AHD.

 

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NOTE 11 — SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Gas Reserve Information. In accordance with the modernization of oil and gas accounting, the Business changed its calculation of proved reserves. Under the current accounting literature, the proved reserves quantities and future net cash flows were estimated using a 12-month average pricing at December 31, 2009 based on the prices on the first day of each month. Using this calculation resulted in the use of lower prices at December 31, 2009 than would have resulted using year-end prices as required by the previous rules.

The preparation of the Business’ natural gas and oil reserve estimates were completed in accordance with its prescribed internal control procedures by ATLS’s reserve engineers. The accompanying reserve information included below is attributable only to the reserves of the assets acquired by AHD, and were derived from the reserve reports prepared for ATLS’s annual Form 10-K for the years ended December 31, 2009, 2008 and 2007. For these periods, independent third-party reserve engineers were retained to prepare a report of proved reserves related to ATLS. The reserve information for the Business includes natural gas and oil reserves which are all located in the United States, primarily in Colorado, Indiana, New York, Ohio, Pennsylvania and Tennessee. The independent reserves engineer’s evaluation was based on more than 35 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions and government regulations. The independent reserves engineer’s report was prepared in accordance with generally accepted petroleum engineering and evaluation principles. The Business’ 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 natural gas liquids owned at year end and changes in proved reserves during the last three years. Proved oil and gas reserves are those quantities of oil and gas which can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. 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 can only 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.

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 Business 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 Business is as follows (unaudited):

 

		Gas (Mcf)				Oil (Bbls)
Balance, January 1, 2007			168,541,574				2,067,646
Extensions, discoveries and other additions(1)			48,268,222				28,947
Sales of reserves in-place			(62,699	)			(625	)
Purchase of reserves in-place(2)			3,509,605				32,887
Transfers to limited partnerships			(4,695,641	)			(62	)
Revisions			(9,594,082	)			(142,074	)
Production			(15,092,337	)			(14,360	)
Balance, December 31, 2007			190,874,642				1,972,359
Extensions, discoveries and other additions(1)			57,953,670				111,972
Sales of reserves in-place			(34,924	)			(161	)
Purchase of reserves in-place			3,461,987				794
Transfers to limited partnerships			(6,026,785	)			8

 

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Revisions(3)			(30,589,331	)			(204,457	)
Production			(12,002,314	)			(154,681	)
Balance, December 31, 2008			203,636,945				1,725,834
Extensions, discoveries and other additions(1)			58,349,703				25,737
Sales of reserves in-place			(101,295	)			(1,944	)
Purchase of reserves in-place			110,953				302
Transfers to limited partnerships			(22,125,866	)			—
Revisions(4)			(42,117,044	)			265,371
Production			(14,098,432	)			(192,578	)
Balance, December 31, 2009			183,654,964				1,822,722
Proved developed reserves at:
January 1, 2007			107,683,343				2,064,276
December 31, 2007			131,100,466				1,966,774
December 31, 2008			137,014,900				1,677,664
December 31, 2009			43,262,907				37,010
Proved undeveloped reserves at:
January 1, 2007			60,858,231				3,370
December 31, 2007			59,774,179				5,585
December 31, 2008			66,622,045				48,170
December 31, 2009			140,392,057				1,785,712

 

(1)	Includes a significant increase in proved undeveloped reserves both due to the addition of proved undeveloped reserves for Marcellus wells.

(2)	Represents the reserves purchased from the acquisition of AGO in June 2007.

(3)	Represents a decrease in the price of natural gas and oil compared from the year ended December 31, 2007 to the year ended December 31, 2008.

(4)	Represents a decrease in the price of natural gas and oil compared from the year ended December 31, 2008 to the year ended December 31, 2009, based on the change in pricing methodology to a 12-month unweighted average based on the first-day-of-the-month prices for the year ended December 31, 2009.

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

 

		Years Ended December 31,
		2009				2008
Natural gas and oil properties:
Proved properties		$	707,218			$	593,618
Unproved properties			40,189				42,362
Support equipment			4,839				5,248
			752,246				641,228
Accumulated depreciation, depletion and amortization(1)			(301,995	)			(113,851	)
		$	450,251			$	527,376

 

(1)	During the year ended December 31, 2009, the Business recognized a $156.4 million impairment related to its shallow natural gas wells in the Upper Devonian Shale. Costs related to unproved properties are excluded from amortization as they are assessed for impairment.

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

 

		Years Ended December 31,
		2009				2008				2007
Revenues(1)		$	108,821			$	117,396			$	88,402
Production costs			(22,107	)			(24,366	)			(16,779	)
Depreciation, depletion and amortization			(35,291	)			(28,340	)			(22,402	)
Goodwill and other asset impairment(2)			(156,359	)			—				—
		$	(104,936	)		$	64,690			$	49,221

 

(1)	Includes unrealized gains from mark-to-market derivatives of $26.3 million during the year ended December 31, 2007.

 

(2)	During the year ended December 31, 2009, the Business recognized a $156.4 million impairment related to its shallow natural gas wells in the Upper Devonian Shale.

 

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The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Business’ proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the year ended December 31, 2009, and at year-end prices for the years ended December 31, 2008 and 2007, adjusted only for fixed and determinable increases in natural gas and oil prices provided by contractual agreements. The resulting estimated future cash inflows was 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 dates 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):

 

		Years Ended December 31,
		2009				2008				2007
Future cash inflows		$	993,206			$	1,464,734			$	1,714,008
Future production costs			(429,630	)			(550,179	)			(495,156	)
Future development costs			(75,011	)			(155,055	)			(162,281	)
Future net cash flows		$	488,565			$	759,499			$	1,056,571
Less 10% annual discount for estimated timing of cash flows		$	(309,748	)		$	(487,884	)		$	(656,367	)
Standardized measure of discounted future net cash flows		$	178,818			$	271,616			$	400,204

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, net of income taxes (in thousands):

 

		Years Ended December 31,
		2009				2008				2007
Balance, beginning of year		$	271,616			$	400,204			$	280,249
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs			(38,288	)			(58,281	)			(70,779	)
Net changes in prices and production costs			(95,712	)			(120,320	)			109,094
Revisions of previous quantity estimates			22,098				(1,208	)			(4,348	)
Development costs incurred			9,936				14,406				8,290
Changes in future development costs			(43,615	)			(41,136	)			6,971
Transfers to limited partnerships			(9,834	)			(615	)			(159	)
Extensions, discoveries, and improved recovery less related costs			24,882				32,037				64,226
Purchases of reserves in-place			141				5,170				9,664
Sales of reserves in-place, net of tax effect			(303	)			(97	)			(105	)
Accretion of discount			25,298				39,639				27,709
Estimated settlement of asset retirement obligations			(2,252	)			(3,745	)			(3,499	)
Estimated proceeds on disposals of well equipment			2,285				4,440				4,124
Changes in production rates (timing) and other			12,566				1,122				(31,233	)
Outstanding, end of year		$	178,818			$	271,616			$	400,204

 

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