ARKHAN 8-K Atlas America Stockholders and Atlas Energy Unitholders Approve

Exhibit 99.3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Atlas Energy Resources, LLC

We have audited the accompanying consolidated balance sheets of Atlas Energy Resources, LLC (a Delaware limited liability company) and subsidiaries as of December 31, 2008 and 2007, and the related combined and consolidated statements of income, comprehensive income, members’ equity, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our 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 financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the combined and consolidated financial statements referred to above present fairly, in all material respects, the financial position of Atlas Energy Resources, LLC and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Atlas Energy Resources, LLC’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)and our report dated March 2, 2009 (not separately included herein), expressed an unqualified opinion on the effectiveness of internal control over financial reporting.

Discussed in Note 2 to the combined and consolidated financial statements, the Company recorded a cumulative effect adjustment in 2006 in connection with the adoption of FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.”

/s/ GRANT THORNTON LLP

Cleveland, Ohio

March 2, 2009

1

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,
	2008		2007
ASSETS
Current assets:
Cash and cash equivalents	$	5,655	$	25,258
Accounts receivable		70,573		57,524
Current portion of derivative asset		107,766		38,181
Prepaid expenses and other		14,714		8,265
Total current assets		198,708		129,228
Property, plant and equipment, net		1,945,119		1,693,467
Other assets, net		18,403		21,430
Long-term derivative asset		69,451		6,882
Intangible assets, net		3,838		5,061
Goodwill		35,166		35,166
	$	2,270,685	$	1,891,234
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	—	$	30
Accounts payable		74,262		55,051
Accrued liabilities – interest		19,878		3,816
Accrued liabilities – other		29,369		21,706
Liabilities associated with drilling contracts		96,700		132,517
Derivative payable to Partnerships – short-term		34,932		9,013
Current portion of derivative liability		12,829		356
Total current liabilities		267,970		222,489
Long-term debt, less current portion		873,655		740,000
Other long-term liabilities		6,524		1,024
Derivative payable to Partnerships – long-term		22,581		1,348
Advances from affiliates		1,712		8,696
Long-term derivative liability		10,771		39,204
Asset retirement obligations		48,136		42,358
Commitments and contingencies
Members’ equity:
Class B members’ interests		932,804		835,447
Class A member’s interest		6,257		5,770
Accumulated other comprehensive income (loss)		100,275		(5,102	)
Total members’ equity		1,039,336		836,115
	$	2,270,685	$	1,891,234

See accompanying notes to combined and consolidated financial statements

2

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

COMBINED AND CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per unit data)

	Years Ended December 31,
	2008			2007			2006
REVENUES
Well construction and completion	$	415,036		$	321,471		$	198,567
Gas and oil production		311,850			180,125			88,449
Administration and oversight		19,362			18,138			11,762
Well services		20,482			17,592			12,953
Gathering		20,670			14,314			9,251
Gain on mark-to-market derivatives		—			26,257			—
Total revenues		787,400			577,897			320,982
COSTS AND EXPENSES
Well construction and completion		359,609			279,540			172,666
Gas and oil production		59,579			32,193			13,881
Well services		10,654			9,062			7,337
Gathering		441			214			—
Gathering fee – Atlas Pipeline		19,098			13,781			29,545
General and administrative		44,659			39,414			23,367
Net expense reimbursement – affiliate		—			—			1,237
Depreciation, depletion and amortization		95,434			56,942			22,491
Total operating expenses		589,474			431,146			270,524
OPERATING INCOME		197,926			146,751			50,458
OTHER INCOME (EXPENSE)
Interest expense		(56,306	)		(30,096	)		—
Other – net		1,159			849			1,369
Total other income		(55,147	)		(29,247	)		1,369
Net income before cumulative effect of accounting change		142,779			117,504			51,827
Cumulative effect of accounting change		—			—			6,355
Net income	$	142,779		$	117,504		$	58,182
Allocation of net income attributable to members’ interests/owners:
Portion applicable to owner’s interest (period prior to the initial public offering on December 18, 2006)	$	—		$	—		$	55,375
Portion applicable to members’ interests (period subsequent to the initial public offering on December 18, 2006)		142,779			117,504			2,807
	$	142,779		$	117,504		$	58,182
Allocation of net income attributable to members’ interests:
Class A member’s interests	$	9,062		$	4,099		$	56
Class B members’ interests		133,717			113,405			2,751
Net income attributable to members’ interests	$	142,779		$	117,504		$	2,807
Net income attributable to Class B members per unit:
Basic	$	2.14		$	2.32		$	.08
Diluted	$	2.12		$	2.29		$	.08
Weighted average Class B members’ units outstanding:
Basic		62,409			48,909			36,627
Diluted		63,023			49,449			36,638

See accompanying notes to combined and consolidated financial statements

3

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

COMBINED AND CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

	Years Ended December 31,
	2008		2007			2006
Net income	$	142,779	$	117,504		$	58,182
Other comprehensive income:
Unrealized holding gains (losses) on hedging contracts		79,478		(8,582	)		31,834
Less: reclassification adjustment for losses (gains) realized in net income		25,899		(17,608	)		(7,082	)
		105,377		(26,190	)		24,752
Comprehensive income	$	248,156	$	91,314		$	82,934

See accompanying notes to combined and consolidated financial statements

4

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

COMBINED AND CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

(in thousands, except unit data)

	Owner’s Equity			Class A Units				Class B Common Units				Class D Units					Accumulated Other Comprehensive Income (Loss)			Net Affiliate Investment			Total Owner’s Equity/ Members’ Equity
				Units	Amount			Units	Amount			Units		Amount
Balance, January 1, 2006	$	158,183		—	$	—		—	$	—		—		$	—		$	(3.664	)	$	158,183		$	154,519
Net income attributable to owner prior to IPO on December 18, 2006		55,375		—		—		—		—		—			—			—			55,375			55,375
Net assets retained by owner		(25,108	)	—		—		—		—		—			—			—			(25,108	)		(25,108	)
Net assets contributed by owner		(188,450	)	748,456		3,769		29,352,996		184,681		—			—			—			(188,450	)		—
Issuance of common units in IPO		—		—		—		7,273,750		139,944		—			—			—			—			139,944
Distribution to owner		—		—		—		—		(139,944	)	—			—			—			—			(139,944	)
Stock-based compensation		—		—		—		—		337		—			—			—			—			337
Other compensation income		—		—		—		—		—		—			—			24,752			—			24,752
Net income attributable to unitholders subsequent to IPO		—		—		56		—		2,751		—			—			—			—			2,807
Balance, December 31, 2006	$	—		748,456	$	3,825		36,626,746	$	187,769		—		$	—		$	21,088		$	—		$	212,682
Units issued		—		490,530		—		7,380,800		181,179		16,702,828			416,316			—			—			597,495
Distributions to members		—		—		(2,154	)	—		(57,941	)	—			(9,187	)		—			—			(69,282	)
Distributions paid on unissued units under incentive plan		—		—		—		—		(778	)	—			—			—			—			(778	)
Stock-based compensation		—		—		—		—		4,684		—			—			—			—			4,684
Other comprehensive income		—		—		—		—		—		—			—			(26,190	)		—			(26,190	)
Conversion of Class D units		—		—		—		16,702,828		415,845		(16,702,828	)		(415,845	)		—			—			—
Net income		—		—		4,099		—		104,689		—			8,716			—			—			117,504
Balance, December 31, 2007	$	—		1,238,986	$	5,770		60,710,374	$	835,447		—		$	—		$	(5,102	)	$	—		$	836,115
Units issued		—		54,500		—		2,670,375		107,697		—			—			—			—			107,697
Distribution to members		—		—		(8,575	)	—		(148,104	)	—			—			—			—			(156,679	)
Distributions paid on unissued units under incentive plan		—		—		—		—		(1,438	)	—			—			—			—			(1,438	)
Stock-based compensation		—		—		—		—		5,485		—			—			—			—			5,485
Other comprehensive income		—		—		—		—		—		—			—			105,377			—			105,377
Net income		—		—		9,062		—		133,717		—			—			—			—			142,779
Balance, December 31, 2008	$	—		1,293,486	$	6,257		63,380,749	$	932,804		—		$	—		$	100,275		$	—		$	1,039,336

See accompanying notes to combined and consolidated financial statements

5

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Years Ended December 31,
	2008			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	142,779		$	117,504		$	58,182
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of deferred finance costs		2,823			3,040			—
Depreciation, depletion and amortization		95,434			56,942			22,491
Non-cash compensation expense		5,485			4,684			337
Loss (gain) on asset sales and dispositions		(32	)		111			(39	)
Cumulative effect of accounting change		—			—			(6,355	)
Non-cash loss (gain) on derivative value		12,430			(14,000	)		—
Equity (income) loss of unconsolidated subsidiary		(233	)		158			—
Minority interest		(55	)		32			—
Changes in operating assets and liabilities, net of effects of acquisition
Accounts receivable, prepaid expenses and other		(16,461	)		3,239			(8,862	)
Accounts payable		19,211			6			(3,229	)
Liabilities associated with drilling contracts		(35,817	)		45,752			16,251
Other operating assets and liabilities		24,359			13,514			1,760
Net cash provided by operating activities		249,923			230,982			80,536
CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash paid for acquisition		—			(1,272,518	)		—
Capital expenditures		(340,975	)		(196,735	)		(75,635	)
Proceeds from sale of assets		62			1,092			47
Other		(195	)		(273	)		—
Net cash used in investing activities		(341,108	)		(1,468,434	)		(75,588	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility		493,000			951,891			—
Repayments under credit facility		(766,030	)		(211,929	)		(88	)
Net proceeds from issuance of debt		407,125			—
Distributions paid to members		(151,126	)		(69,282	)		—
Distributions net of capital contributions to Atlas America		—			—			(139,944	)
Net proceeds from issuance of Class B members units		107,697			597,495			139,944
Advances to affiliates, net of repayments		(6,984	)		(3,806	)		(16,748	)
Other		(12,100	)		(10,492	)		(197	)
Net cash provided by (used in) financing activities		71,582			1,253,877			(17,033	)
Net change in cash and cash equivalents		(19,603	)		16,425			(12,085	)
Cash and cash equivalents, beginning of year		25,258			8,833			20,918
Cash and cash equivalents, end of year	$	5,655		$	25,258		$	8,833

See accompanying notes to combined and consolidated financial statements

6

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – NATURE OF OPERATIONS

Atlas Energy Resources, LLC (“the Company”) is a publicly-traded Delaware limited liability company (NYSE: ATN) and an independent developer and producer of natural gas and, to a lesser extent, oil in Northern Michigan’s Antrim Shale, Indiana’s New Albany Shale and the Appalachian Basin. The Company is also a leading sponsor of and manages tax-advantaged direct investment partnerships, in which it coinvests to finance the exploitation and development of its acreage (“the Partnerships”).

On December 18, 2006, Atlas America, Inc. and its affiliates (“Atlas America”), a publicly-traded company (NASDAQ: ATLS), contributed all of the stock of its natural gas and oil development and production subsidiaries and its development and production assets in exchange for 29,352,996 Class B common units and 748,456 Class A units. Concurrent with this transaction, the Company completed an initial public offering of 7,273,750 units of its Class B common units, representing a 19.4% interest at that moment, at a price of $21.00 per common unit. The net proceeds from the offering of $139.9 million, after deducting underwriting discounts and costs, were distributed to Atlas America Class A units. The Class A units are entitled to 2% of all quarterly cash distributions by the Company, without any requirement for future capital contributions by the holder of such Class A units, even if the Company issues additional Class B common units or other equity securities in the future. The Company is managed by Atlas Energy Management, Inc. (the “Managing Member”), a wholly-owned subsidiary of Atlas America. At December 31, 2008, the Company has 63,380,749 Class B common units and 1,293,486 Class A units outstanding. At December 31, 2008, Atlas America owns 49.4% of the Company.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Combination and Consolidation

The consolidated financial statements subsequent to the Company’s initial public offering on December 18, 2006 include the accounts of the Company and its subsidiaries. Prior to the Company’s initial public offering, at which date Atlas America contributed its ownership interests in its natural gas and oil development and production assets to the Company, the combined financial statements have been prepared from the separate records maintained by Atlas America and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Company had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various entities that comprised the assets contributed by Atlas America to the Company, Atlas America’s net investment in these entities was shown as combined equity in the combined financial statements. Transactions between the Company and other Atlas America operations have been identified in the combined and consolidated financial statements as transactions between affiliates (see Note 6).

In accordance with established practice in the oil and gas industry, the Company includes its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the investment partnerships in which it has an interest. Such interests typically range from 15% to 35%. The Company’s financial statements do not include proportional consolidation of the depletion or impairment expenses of the Partnerships. Rather, the Company calculates these items specific to its own economics as further explained under the heading “Oil and Gas Properties” below. All material intercompany transactions have been eliminated.

Use of Estimates

Preparation of the combined and consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and costs and expenses during the reporting period. The Company’s consolidated financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, depreciation and amortization, fair value of derivative instruments, the probability of forecasted transactions, and the allocation of purchase price to the fair value of assets acquired. Actual results could differ from these estimates.

7

Reclassifications

Certain amounts in the prior year’s combined and consolidated financial statements have been reclassified to conform to the current year presentation.

Cash Equivalents

The Company considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.

Stock-Based Compensation

The Company applies the provisions of SFAS No. 123(R), “Share-Based Payment,” as revised (“SFAS No. 123(R)”), to its share-based payments. Generally, the approach to accounting for SFAS No. 123(R) requires all unit-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.

Net Income Per Common Unit

Basic net income per unit for Class B common units is computed by dividing net income attributable to the Class B members, which is determined after the deduction of the Class A member’s interests, by the weighted average number of Class B common units outstanding during the period. The Class A management incentive interests (“MIIs” – see Note 13) in net income is calculated on a quarterly basis based upon its 2% ownership interest, represented by its 1,293,486 Class A units, and its member’s incentive interests, with a priority allocation of net income to the Class A member’s MIIs in accordance with the Company’s limited liability agreement, and the remaining net income or loss allocated with respect to the Class A’s and Class B’s ownership interests. Diluted net income per unit for Class B common units is calculated by dividing net income or loss attributable to the Class B members by the sum of the weighted average number of Class B common units outstanding and the dilutive effect, if any, of the Company’s restricted unit and unit option awards, as calculated by the treasury stock method. Restricted units and unit options consist of Class B common units issuable under the terms of the Company’s long-term incentive plan (See Note 11).

Prior to the closing of the Company’s initial public offering on December 18, 2006, there were no common units outstanding. As such, the Company’s net income attributable to Class B common units is only presented for the years ended December 31, 2008 and 2007 and the period from December 18, 2006 to December 31, 2006.

In March 2004, the FASB ratified the Emerging Issue Task Force (“EITF”) consensus on EITF Issue No. 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128” (“EITF No. 03-6”), which addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitles the holder of those securities to participate in dividends and earnings of the entity when, and if, the entity declares dividends on its common stock. In quarterly accounting periods where net income does not exceed the Company’s aggregate cash distributions to its members, EITF No. 03-6 does not have any impact on the Company’s net income per Class B common unit calculation as net income is allocated to its members with a priority allocation to actual MIIs paid to the Class A member for the quarterly period, with the remaining net income allocated with respect to relative ownership interests. However, EITF No. 03-6 provides that if the Company has net income which exceeds the aggregate cash distributions to its members during a quarterly period, it is required to present net income per Class B common unit as if all of the earnings for the quarterly period were distributed in a manner consistent with the Company’s limited liability agreement, regardless of whether those earnings would actually be distributed during a quarterly period from an economic probability standpoint. The allocation of net income for net income per Class B common unit purposes under EITF No. 3-06 will result in an increased allocation of net income to the Class A member’s MIIs and a reduction of net income allocated to Class B members. On January 1, 2009, the Company will adopt EITF No. 07-4, “Application of the Two-Class Method Under FASB Statement No. 128, Earnings Per Share, to Master Limited Partnerships” (see “Recently Issued Accounting Standards”).

8

The following table sets forth the reconciliation of the Company’s weighted average number of Class B common units used to compute basic net income attributable to Class B members’ interests per unit with those used to compute diluted net income attributable to Class B members’ per unit (in thousands):

	Years Ended December 31,		Period from December 18, 2006 to December 31 2006
	2008	2007
Weighted average number of Class B units – basic	62,409	48,909	36,627
Add effect of dilutive unit incentive awards	614	540	11
Weighted average number of Class B units – diluted	63,023	49,449	36,638

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States, have not been recognized in the calculation of net income. These changes, other than net income, are referred to as “other comprehensive income (loss)” and for the Company include only changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.

Components of Accumulated other comprehensive income (loss) at the dates indicated are as follows (in thousands):

	December 31,
	2008			2007
Unrealized gain (loss) on commodity derivatives	$	106,117		$	(5,102	)
Unrealized loss on interest rate derivatives		(5,842	)		—
	$	100,275		$	(5,102	)

Accounts Receivable and Allowance for Possible Losses

In evaluating its allowance for possible losses, the Company performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by the Company’s review of its customer’s credit information. The Company extends credit on an unsecured basis to many of its customers. At December 31, 2008 and 2007, the Company’s credit evaluation indicated that it had no need for an allowance for possible losses.

Property, Plant and Equipment

Property, plant and equipment are stated at cost. Depreciation, depletion and amortization are based on cost less estimated salvage value primarily using the units-of-production or straight-line method over the assets estimated useful lives. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.

The estimated service lives of property, plant and equipment excluding natural gas and oil properties are as follows:

Pipelines, processing and compression facilities	15-40 years
Rights-of-way – Appalachia	20-40 years
Buildings and improvements	10-40 years
Furniture and equipment	3-7 years
Other	3-10 years

9

Property, plant and equipment consists of the following at the dates indicated (in thousands):

	December 31,
	2008			2007
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,214,991		$	1,043,687
Wells and related equipment		872,128			752,184
		2,087,119			1,795,871
Unproved properties		43,749			16,380
Support equipment		9,527			6,936
		2,140,395			1,819,187
Pipelines, processing and compression facilities		22,541			—
Rights-of-way		149			—
Land, buildings and improvements		6,484			5,881
Other		7,827			9,653
		2,177,396			1,834,721
Accumulated depreciation, depletion and amortization:		(232,277	)		(141,254	)
	$	1,945,119		$	1,693,467

Oil and Gas Properties

The Company follows the successful efforts method of accounting for oil and gas producing activities. Acquisition costs of leases and development activities are capitalized. 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 and delay rentals are expensed. Oil is converted to gas equivalent basis (“Mcfe”) at the rate one barrel equals 6 Mcf. Depletion is provided on the units-of-production method.

Depletion depreciation and amortization expense is determined on a field-by-field basis using the units-of-production method, with depletion, depreciation and amortization rates for leasehold acquisition costs based on estimated proved reserves and depletion, depreciation and amortization rates for well and related equipment costs 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 uncontrolled but proportionately consolidated from investment partnerships, wells drilled solely by the Company, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to income. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion. Upon the 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 statements of income. 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.

Goodwill

The Company has recorded goodwill of $35.2 million in connection with several acquisitions of assets. Goodwill and intangibles with infinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. Under the principles of SFAS No. 142, an impairment loss should be recognized if the carrying value of an entity’s reporting units exceeds its estimated fair value. Because quoted market prices for the Company’s reporting units are not available, the Company must apply judgment in determining the estimated fair value of these reporting units. The Company 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 assets. A key component of these fair value determinations is a reconciliation of the sum of the fair

10

value calculations to our market capitalization. The principles of SFAS No. 142 and its interpretations acknowledge that the observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity’s individual equity securities. In most industries, including the Company’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, the Company also considers a control premium to the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in our industry. The resultant fair values calculated for the reporting units are then compared to observable metrics on large mergers and acquisitions in the Company’s industry to determine whether those valuations appear reasonable in the Company’s judgment. The Company’s evaluation of goodwill at December 31, 2008, 2007 and 2006, respectively, indicated there was no impairment loss.

Impairment of Oil and Gas Properties and Long-Lived Assets

The Company’s oil and gas properties and long-lived assets are reviewed annually or whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets.

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 at December 31, 2008, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. If the carrying value exceeds such 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, the Company’s reserve estimates for its investment in its limited partnerships are based on its own assumptions rather than its proportionate share of the limited partnership’s reserves. These assumptions include the Company’s 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 and administrative costs.

The Company’s lower operating and administrative costs result from the limited partners paying to the Company their proportionate share of these expenses plus a profit margin. These assumptions could result in the Company’s calculation of depletion and impairment being different than its proportionate share of the limited partnership 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. The Company cannot predict what reserve revisions may be required in future periods.

The Company’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the investment partnerships which the Company sponsors and owns an interest in but does not control. The Company’s reserve quantities include reserves in excess of its

11

proportionate share of reserves in a partnership which the Company may be unable to recover due to the partnership legal structure. The Company may have to pay additional consideration in the future as a well or investment partnership becomes uneconomic under the terms of the partnership agreement in order for the Company 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 Company is governed under the partnership agreement and must be at fair market value supported by an appraisal of an independent expert selected by the Company.

Unproved properties are reviewed 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 will not explore 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 oil and gas properties or unproved properties recorded by the Company for the years ended December 31, 2008, 2007, or 2006, respectively.

Capitalized Interest

The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and gas wells and other capital projects. Interest is capitalized only during the periods in which these assets are brought to their intended use. The weighted average interest rate used to capitalize interest was 7.3% and 6.7% for the years ended December 31, 2008 and 2007, respectively, which resulted in interest capitalized of $5.0 million and $2.7 million, respectively. There was no interest capitalized for the year ended December 31, 2006.

Asset Retirement Obligations

The Company accounts for asset retirement obligations as required under SFAS No. 143, “Accounting for Retirement Asset Obligations” (“SFAS No. 143”). SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, with the associated asset retirement costs being capitalized as a part of the carrying amount of the long-lived asset. The Company has asset retirement obligations related to the plugging and abandonment of its oil and gas wells. SFAS No. 143 requires the Company to consider estimated salvage value in the calculation of depreciation, depletion and amortization.

In March 2005, the Financial Accounting Standards Board (“FASB”) issued FIN 47. FIN 47 clarified that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset obligation should be recognized if that fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation under FAS No. 143.

Under SFAS No.143, the Company had recorded its asset retirement obligation based on a probability factor which considered the Company’s history of selling its wells or otherwise disposing of them without incurring a disposal cost.

FIN 47 requires the Company to record its retirement obligation without regard to its prior practice and accrue for obligations for all wells owned by the Company without regard to their probability of being sold or otherwise disposed of without incurring a disposal cost. Accordingly, the Company adopted FIN 47 as of December 31, 2006 and recognized a $6.4 million cumulative effect of an accounting change during the year ended December 31, 2006 and a $8.0 million increase in its asset retirement obligation and a $14.4 million increase in property, plant and equipment as of December 31, 2006.

12

Had the Company implemented FIN 47 retroactively to October 1, 2002, the following pro forma information summarizes the impact for the periods presented (in thousands):

	December 31, 2006
Net income as reported	$	51,827
Proforma asset retirement obligation adjustment		1,414
Proforma net income as adjusted		53,241
Proforma asset retirement obligation	$	26,726

Fair Value of Financial Instruments

The carrying amount of the Company’s financial instruments, including cash and cash equivalents, accounts receivables and accounts payables approximate fair values because of their short maturities and are represented in the Company’s consolidated balance sheets. For further information with regard to the Company’s financial instruments, see “Recently Adopted Accounting Standards” and Note 7, “Fair Value of Financial Instruments” and Note 9 “Long-Term Debt”.

Derivative Instruments

The Company enters into certain financial contracts to manage its exposure to movement in commodity prices and interest rate movements. The Company applies the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No.133”). SFAS No. 133 requires each derivative instrument to be recorded in the balance sheet as either an asset or liability measured at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Company’s consolidated statements of income unless specific hedge accounting criteria are met (see Note 7).

Concentration of Credit Risk

Financial instruments, which potentially subject the Company to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Company places its temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At December 31, 2008 and 2007, the Company had $25.1 million and $41.8 million, respectively, in deposits at various banks, of which $23.6 million and $40.9 million, respectively, was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date.

Environmental Matters

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. The Company accounts for environmental contingencies in accordance with SFAS No. 5 “Accounting for Contingencies.” Environmental expenditures that relate to current operations are expensed as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are also expensed. Liabilities for environmental contingencies are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. The Company maintains insurance which may cover in whole or in part certain types of environmental contingencies. At December 31, 2008 and 2007, the Company had no environmental contingencies requiring specific disclosure or the recording of a liability.

Revenue Recognition

The Company conducts certain energy activities through, and a portion of its revenues are attributable to sponsored investment partnerships. The Company contracts with the investment partnerships to drill partnership wells. The contracts require that the investment partnerships pay the Company 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.

13

The contracts are typically completed in less than 60 days. On an uncompleted contract, the Company 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 its consolidated balance sheets. The Company recognizes gathering revenues at the time the natural gas is delivered, and recognizes well services revenues at the time the services are performed. The Company is also entitled to receive administration and oversight fees according to the respective partnership agreements. The Company recognizes such fees as income when services are performed.

The Company 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 Company has an interest with other producers are recognized on the basis of the Company’s percentage ownership of working interest or overriding royalty. Generally, the Company’s sales contracts 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.

Because there are timing differences between the delivery of natural gas and oil and the Company’s receipt of a delivery statement, the Company has unbilled revenues. These revenues are accrued based upon volumetric data from the Company’s records and the Company’s estimates of the related transportation and compression fees which are, in turn, based upon applicable product prices. The Company had unbilled trade receivables at December 31, 2008 and 2007 of $43.7 million and $44.9 million, respectively, which are included in accounts receivable on its consolidated balance sheets.

Income Taxes

The Company is a limited liability company and has elected to be treated as a partnership for income tax purposes. As a result, the Company is not subject to U.S. federal and most state income taxes. The unitholders of the Company are liable for income taxes in regards to their distributive share of the Company’s taxable income. Such taxable income may vary substantially from net income reported in the accompanying combined and consolidated financial statements. Certain corporate subsidiaries of the Company are subject to federal and state income tax. The federal and state income taxes related to the Company and these corporate subsidiaries were immaterial to the combined and consolidated financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the accompanying combined and consolidated financial statements.

In June 2006, the FASB released FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes”, an Interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 provides guidance for how uncertain tax positions should be recognized, measured, presented and disclosed in the financial statements. FIN 48 requires the evaluation of tax positions taken or expected to be taken in the course of preparing the Company’s tax returns to determine whether the tax positions have met a “more-likely-than-not” threshold of being sustained by the applicable tax authority. Tax benefits related to tax positions not deemed to meet the more-likely-than-not threshold are not permitted to be recognized in the financial statements. The provisions of FIN 48 were adopted by the Company effective January 1, 2007. Implementation of FIN 48 had no impact on the combined and consolidated financial statements of the Company for the years ended December 31, 2008 and 2007. The Company’s policy is to reflect interest and penalties related to uncertain tax positions as part of income tax expense, when and if they become applicable.

The Company files income tax returns in the U.S. federal and various state jurisdictions. With limited exceptions, the Company is no longer subject to income tax examinations by major tax authorities for years before 2006.

Recently Issued Financial Accounting Standards

The Financial Accounting Standards Board, (“FASB”) recently issued the following standards which were reviewed by the Company to determine the potential impact on its financial statements upon adoption.

In June 2008, the FASB issued Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-6-1 applies to the

14

calculation of earnings per share (“EPS”) described in paragraphs 60 and 61 of FASB Statement No. 128, “Earnings per Share” for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. All prior-period EPS data presented should be adjusted retrospectively to conform to the provisions of this FSP. The Company will apply the requirements of FSP EITF 03-6-1 upon its adoption on January 1, 2009 and it does not believe the adoption of FSP EITF 03-6-1 will have a material impact on its financial position or results of operations.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Policies” (“SFAS No. 162”). SFAS No. 162 identifies sources of accounting principles and the framework for selecting such principles used in the preparation of financial statements of nongovernmental entities presented in conformity with U.S. generally accepted accounting principles. SFAS No. 162 is effective beginning November 15, 2008. The Company adopted the provisions of SFAS No. 162 on November 15, 2008 and it had no impact on its financial position and results of operations.

In April 2008, the FASB issued Staff Position No. 142-3, “Determination of Useful Life of Intangible Assets” (“FSP FAS 142-3”). FSP FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”). The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141(R), “Business Combinations” (“SFAS No. 141(R)”). FSP FAS 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. The guidance for determining the useful life of a recognized intangible asset should be applied prospectively to intangible assets acquired after the effective date. The disclosure requirements should be applied prospectively to all intangible assets recognized as of, and subsequent to, the effective date. The Company will apply the requirements of FSP FAS 142-3 upon its adoption on January 1, 2009 and it does not believe the adoption of FSP FAS 142-3 will have a material impact on its financial position or results of operations.

In March 2008, the FASB ratified the Emerging Issues Task Force (“EITF”) reached consensus on EITF Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF No. 07-4”), an update of EITF No. 03-6 “Participating Securities and the Two-Class Method under FASB Statement No. 128”. EITF No. 07-4 requires the calculation of a Master Limited Partnership’s (“MLPs”) net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings as if all of the earnings for that period had been distributed. In periods with undistributed earnings above specified levels, the calculation per the two-class method results in an increased allocation of such undistributed earnings to the general partner and a dilution of earnings to the limited partners. EITF No. 07-4 is effective for fiscal periods beginning on of after December 15, 2008. The Company does not expect the application of EITF 07-4 to have a material effect on its earnings per unit calculation. The Company’s net earnings per unit of the Class B unitholders calculated under the requirements of EITF No. 03-6 would not have materially differed under the requirements of EITF No. 07-04.

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”), an amendment of FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). SFAS No. 161 requires entities to provide qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in their hedged positions. The standard is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged but not required. SFAS No. 161 also requires entities to disclose more information about the location and amounts of derivative instruments in financial statements; how derivatives and related hedges are accounted for under SFAS No. 133, and how the hedges affect the entity’s financial position, financial performance, and cash flows. The Company will apply the requirements of SFAS No. 161 on its adoption on January 1, 2009 and does not expect it to have an impact on its financial position or results of operations.

15

In January 2008, the FASB issued Statement 133 Implementation Issue No. E23, “Hedging – General Issues Involving the Application of the Shortcut Method under Paragraph 68” (“Implementation Issue E23”). Implementation Issue E23 is effective for hedging relationships designated on or after January 1, 2008, and amends SFAS No. 133 to explicitly permit use of the “shortcut” method for those hedging relationships in which: the interest rate swap has a nonzero fair value at the inception of the hedging relationship attributable solely to differing prices within the bid-ask spread; or the hedged item has a trade date that differs from its settlement date because of generally established conventions in the marketplace in which the transaction to acquire or issue the hedging item is executed. The Company uses the “long-haul” method by applying the change in variable cash flow method (See Note 7) to measure ineffectiveness on its interest rate swaps under SFAS No. 133 and therefore Implementation Issue E23 did not have a significant impact on its financial position or results of operations.

In December 2007, the FASB issued Statement of Financial Accounting Standards No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS No. 160”). This statement amends Accounting Research Bulletin 51, “Consolidated Financial Statements”, to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This statement is effective for fiscal periods beginning on or after December 15, 2008. The Company does not expect the adoption of SFAS No. 160 to have a significant impact on its financial position and results of operations.

In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) replaces SFAS No. 141, “Business Combinations”; however it retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS No. 141(R) requires an acquirer to recognize the assets acquired, liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date, be measured at their fair values as of that date, with specified limited exceptions. Changes subsequent to that date are to be recognized in earnings, not goodwill. Additionally, SFAS No. 141 (R) requires costs incurred in connection with an acquisition be expensed as incurred. Restructuring costs, if any, are to be recognized separately from the acquisition. The acquirer in a business combination achieved in stages must also recognize the identifiable assets and liabilities, as well as the noncontrolling interests in the acquiree, at the full amounts of their fair values. SFAS No. 141(R) is effective for business combinations occurring in fiscal years beginning on or after December 15, 2008. Early adoption is not permitted. The Company will apply the requirements of SFAS No. 141(R) upon its adoption on January 1, 2009 and is currently evaluating whether SFAS No. 141(R) does not expect the adoption to have a significant impact on its financial position and results of operations.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. By electing the fair value option in conjunction with a derivative, an entity can achieve an accounting result similar to a fair value hedge without having to comply with complex hedge accounting rules. The statement was effective for the Company as of January 1, 2008. The Company adopted SFAS No. 159 at January 1, 2008, and has elected not to apply the fair value option to any of its financial instruments not already carried at fair value in accordance with other accounting standards, and therefore the adoption of SFAS No. 159 did not impact the Company’s consolidated financial statements for the year ended December 31, 2008.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurement” (“SFAS No. 157”). SFAS No. 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements. In February 2008, the FASB issued FSP FAS 157-2, “Effective Date of FASB Statement No. 157”, (“FSP FAS 157-2”). FSP FAS 157-2, which was effective upon issuance, delays the effective date of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value at least once a year, to fiscal years beginning after November 15, 2008. On January 1, 2009, the Company will adopt SFAS No. 157 for nonfinancial assets and liabilities that are not measured at fair value on a recurring basis.

16

For the Company, the nonfinancial assets and liabilities will be limited to the initial recognition of asset retirement obligations. FSP FAS 157-2 also covers interim periods within the fiscal years for items within its scope. The delay is intended to allow the FASB and its constituents the time to consider the various implementation issues associated with SFAS No. 157. The Company adopted SFAS No. 157 as of January 1, 2008 with respect to its commodity and interest rate swap derivative instruments which are measured at fair value within its consolidated financial statements. See Note 7 and Note 9 for disclosures pertaining to the provisions of SFAS No. 157 with regard to the Company’s fair value measurements.

NOTE 3 – ACQUISITION OF DTE GAS & OIL COMPANY

In June 2007, the Company acquired all of the outstanding equity interests of DTE Gas & Oil Company (“DGO”) from DTE Energy Company (NYSE:DTE) and MCN Energy Enterprises for $1.273 billion, including adjustments for working capital of $15.0 million and current year capital expenditures of $19.0 million. Subsequently, the Company changed DGO’s name to Atlas Gas and Oil Company, LLC (“AGO”).

To fund the acquisition, the Company borrowed $713.9 million on its credit facility (see Note 9) and received net proceeds of $597.5 million from a private placement of its Class B common and new Class D units (see Note 12) of which $52.5 million was used to pay the outstanding balance of the Company’s then existing credit facility. The acquisition was accounted for using the purchase method of accounting under SFAS No. 141, Business Combinations (“SFAS No. 141”). The table on the following page presents the purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed based on their estimated fair market value at the date of acquisition (in thousands):

	Non-Cash Investing Transaction
Accounts receivable	$	33,764
Prepaid expenses		515
Other assets		890
Leaseholds, wells and related equipment		1,267,901
Total assets acquired		1,303,070
Accounts payable and accrued liabilities		(19,233	)
Other liabilities		(210	)
Asset retirement obligations		(11,109	)
		(30,552	)
Net assets acquired	$	1,272,518

AGO’s operations are included within the Company’s combined and consolidated financial statements from the date of the acquisition.

17

The following data presents pro forma revenues, net income and basic and diluted net income per unit for the Company as if the AGO acquisition, Class B common unit and Class D unit equity offerings (see Note 12) and new revolving credit facility (see Note 9) had occurred on January 1, 2006. The Company has prepared these unaudited pro forma financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the Company had completed the acquisition at January 1, 2006 or the results that will be attained in the future. Net income for the year ended December 31, 2006 includes periods prior to the Company’s initial public offering on December 18, 2006, and therefore, no earnings per unit has been presented (in thousands, except per unit amounts):

	Year Ended December 31, 2007
	As Reported		Pro Forma Adjustments			Pro Forma
Revenues	$	577,897	$	15,888		$	593,785
Net income	$	117,504	$	(57,877	)	$	59,627
Net income attributable to Class B unitholders	$	113,405	$	(54,971	)	$	58,434
Net income per Class B common unit outstanding – basic	$	2.32	$	(1.36	)	$	0.96
Weighted average Class B common units outstanding – basic		48,909		11,801			60,710
Net income per Class B common unit – diluted	$	2.29	$	(1.34	)	$	0.95
Weighted average Class B common units outstanding – diluted		49,449		11,740			61,189
	Year Ended December 31, 2006
	As Reported		Pro Forma Adjustments			Pro Forma
Revenues	$	320,982	$	291,346		$	612,328
Net income before cumulative effect of accounting change		51,827		145,923			197,750
Net income		58,182		145,923			204,105

Pro forma adjustments to revenues include substantial losses and gains on derivatives realized by AGO of $54.1 million and $149.5 million in fiscal 2007 and 2006, respectively. All existing derivatives were canceled upon the acquisition of AGO by the Company and the Company entered into new derivative contracts covering future AGO production. Pro forma adjustments include financial hedges between AGO and its affiliate. In addition, pro forma adjustments include depreciation, depletion and amortization related to assets acquired and interest expense associated with debt entered into to acquire such assets.

NOTE 4 – OTHER ASSETS AND INTANGIBLE ASSETS

Other Assets

The following is a summary of other assets (in thousands):

	At December 31,
	2008		2007
Long-term derivative receivable from partnerships	$	2,719	$	13,542
Deferred finance costs, net of accumulated amortization of $5,531 and $2,708 at December 31, 2008 and 2007, respectively		15,018		7,650
Other		666		238
	$	18,403	$	21,430

Long-term hedge receivable from Partnerships represents the portion of the long-term unrealized derivative liability on contracts that has been allocated to them based on their share of total production volumes sold. Deferred finance costs related to the Company’s credit facility and senior unsecured notes (see Note 9) are recorded at cost and amortized over their respective lives (5 to 10 years).

18

Intangible Assets

Included in intangible assets are partnership management and operating contracts acquired through previous acquisitions which were recorded at fair value on their acquisition dates. In addition, the Company entered into a two-year non-compete agreement in connection with the acquisition of AGO during the year ended December 31, 2007. The Company amortizes these contracts on the declining balance and straight-line methods, over their respective estimated lives, ranging from two to thirteen years. Amortization expense for these contracts for the years ended December 31, 2008, 2007, and 2006 was $1.2 million, $1.0 million and $1.0 million, respectively. The aggregate estimated annual amortization expense of partnership management and operating contracts and the non-compete agreement for the next five years ending December 31 is as follows: 2009—$964,000; 2010—$710,000; 2011—$664,000; 2012—$180,000 and 2013—$158,000.

The following table provides information about intangible assets at the dates indicated (in thousands):

	At December 31,
	2008			2007
Management and operating contracts	$	14,343		$	14,343
Non-compete agreement		890			890
Total costs		15,233			15,233
Accumulated amortization		(11,395	)		(10,172	)
	$	3,838		$	5,061

NOTE 5 – ASSET RETIREMENT OBLIGATIONS

The Company follows SFAS No. 143 and FIN 47 “Accounting for Conditional Asset Retirement Obligations,” which require the Company to recognize an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. Under SFAS No. 143, the Company must currently recognize 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. SFAS No. 143 requires the Company to consider estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability is based on 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.

The Company has no assets legally restricted for purposes of settling asset retirement obligations. Except for the item previously referenced, 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 abandonment costs for the periods indicated is as follows (in thousands):

	Years Ended December 31,
	2008			2007			2006
Asset retirement obligations, beginning of period	$	42,358		$	26,726		$	18,499
Cumulative effect of adoption of FIN 47		—			—			8,042
Liabilities acquired		—			11,109			—
Liabilities incurred		3,305			2,582			1,570
Liabilities settled		(253	)		(91	)		(194	)
Revision in estimates		—			—			(2,411	)
Accretion expense		2,726			2,032			1,220
Asset retirement obligations, end of period	$	48,136		$	42,358		$	26,726

19

The accretion expense is included in depreciation, depletion and amortization in the Company’s combined and consolidated statements of income.

NOTE 6 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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

Relationship with Atlas America. Atlas America provides centralized corporate functions on behalf of the Company, including 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. These costs are reflected in general and administrative expense in the Company’s combined and consolidated statements of income. The employees supporting these Company operations are employees of Atlas America. The compensation costs of these employees, and rent for the offices out of which they operate, are allocated to the Company based on estimates of the time spent by such employees in performing services for the Company. This allocation of costs may fluctuate from period to period based upon the level of activity by the Company of any acquisitions, equity or debt offerings, or other non-recurring transactions, which requires additional management time. Management believes the method used to allocate these expenses is reasonable.

The Company participates in Atlas America’s cash management program. Any cash activity performed by Atlas America on behalf of the Company has been recorded as a long-term liability as parent advances and included in advances from affiliates on the Company’s consolidated balance sheets.

Relationship with Company Sponsored Investment Partnerships. The Company conducts certain activities through, and a substantial portion of its revenues are attributable to, the Partnerships. The Company serves as managing general partner of the Partnerships and assumes customary rights and obligations for the Partnerships. As a general partner, the Company is liable for Partnership liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Partnerships. The Company 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 Atlas Pipeline. The Company has a master gas gathering agreement with Atlas Pipeline which governs the transportation of substantially all of the natural gas the Company produces from the wells it operates. This agreement generally provides for the Company to pay Atlas Pipeline 16% of the sales price received for natural gas produced from wells located on Atlas Pipeline’s gathering systems. These fees are shown as Gathering fee—Atlas Pipeline on the Company’s combined and consolidated statements of income. Atlas America agreed to assume the Company’s obligation to pay gathering fees to Atlas Pipeline after the Company’s initial public offering.

The Company charges rates to wells connected to these gathering systems, substantially all of which are owned by the Partnerships, generally ranging from $.35 per Mcf to 13% of the sales price received for the natural gas transported. Under the terms of its contribution agreement with Atlas America, the Company remits this amount to Atlas America. Therefore, after the closing of its initial public offering, the gathering revenues and costs within the partnership management segment net to $0.

NOTE 7 – DERIVATIVE AND FINANCIAL INSTRUMENTS

Commodity Risk Hedging Program

From time to time, the Company enters into natural gas and crude oil future option contracts and collar contracts 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.

20

The Company has a $106.1 million unrealized net asset related to financial derivatives on its gas and oil production shown as a component of accumulated other comprehensive loss at December 31, 2008, compared to a net unrealized liability of $5.1 million at December 31, 2007. If the fair values of the instruments remain at current market values, the Company will reclassify $63.7 million of unrealized gains to its consolidated statements of income over the next twelve-month period as these contracts settle and $42.4 million of unrealized gains will be reclassified in later periods.

The Company recognized a loss of $25.1 million and gains of $17.6 million and $7.1 million on settled contracts covering natural gas production for the years ended December 31, 2008, 2007 and 2006, respectively. The Company recognized a loss of $312,000 on settled oil production for the year ended December 31, 2008, and there were no gains or (losses) on oil settlements for the years ended December 31, 2007 and 2006. These gains and losses are included with gas and oil production in the Company’s combined and consolidated statements of income. As the underlying prices and terms in the Company’s 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, 2008, 2007 and 2006 for derivative ineffectiveness or as a result of the discontinuance of any cash flow hedges.

On May 18, 2007, the Company signed a definitive agreement to acquire AGO (see Note 3). In connection with the financing of this transaction, the Company agreed as a condition precedent to closing that it would hedge 80% of its projected natural gas volumes for no less than three years from the closing date of the transaction. During May 2007, the Company entered into derivative instruments to hedge 80% of the projected production of the assets to be acquired as required under the financing agreement. The production volume of the assets to be acquired was not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the assets had not yet been completed. Accordingly, the Company recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within revenues in its consolidated statements of income. The Company recognized a non-cash gain on mark-to-market derivatives of $26.3 million related to the change in value of these derivatives from May 22, 2007 through June 28, 2007. Upon closing of the acquisition on June 29, 2007, the production volume of the assets acquired was considered “probable forecasted production” under SFAS No. 133 and the Company evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133.

As of December 31, 2008, the Company had the following natural gas and oil volumes hedged:

Natural Gas Fixed Price Swaps

Twelve Month Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset(1)
	(MMBtu)	(per MMBtu)		(in thousands)
2009	38,120,000	$	8.55	$	93,246
2010	26,360,000	$	8.11		25,537
2011	18,680,000	$	7.84		9,670
2012	13,800,000	$	8.05		10,851
2013	1,500,000	$	8.73		2,098
				$	141,402

21

Natural Gas Costless Collars

Twelve Month Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset(1)
		(MMBtu)	(per MMBtu)		(in thousands)
2009	Puts purchased	240,000	$	11.00	$	1,182
2009	Calls sold	240,000	$	15.35		—
2010	Puts purchased	3,360,000	$	7.84		3,340
2010	Calls sold	3,360,000	$	9.01		—
2011	Puts purchased	7,500,000	$	7.48		3,708
2011	Calls sold	7,500,000	$	8.44		—
2012	Puts purchased	1,020,000	$	7.00		223
2012	Calls sold	1,020,000	$	8.32		—
2013	Puts purchased	300,000	$	7.00		72
2013	Calls sold	300,000	$	8.25		—
					$	8,525

Crude Oil Fixed Price Swaps

Twelve Month Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset(2)
	(Bbl)	(per Bbl)		(in thousands)
2009	59,900	$	100.14	$	2,790
2010	48,900	$	97.40		1,624
2011	42,600	$	96.44		1,141
2012	33,500	$	96.00		785
2013	10,000	$	96.06		221
				$	6,561

22

Crude Oil Costless Collars

Twelve Month Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset(2)
		(Bbl)	(per Bbl)		(in thousands)
2009	Puts purchased	36,500	$	85.00	$	1,200
2009	Calls sold	36,500	$	118.63		—
2010	Puts purchased	31,000	$	85.00		754
2010	Calls sold	31,000	$	112.92		—
2011	Puts purchased	27,000	$	85.00		538
2011	Calls sold	27,000	$	110.81		—
2012	Puts purchased	21,500	$	85.00		379
2012	Calls sold	21,500	$	110.06		—
2013	Puts purchased	6,000	$	85.00		100
2013	Calls sold	6,000	$	110.09		—
					$	2,971
				Total Net Asset	$	159,459

⁽¹⁾ Fair value based on forward NYMEX natural gas prices, as applicable.

⁽²⁾ Fair value based on forward WTI crude oil prices, as applicable.

23

The fair value of the derivatives related to commodities included in the consolidated balance sheets are as follows (in thousands):

	December 31,
	2008			2007
Current portion of derivative asset	$	107,766		$	38,181
Long-term derivative asset		69,451			6,882
Current portion of derivative liability		(9,348	)		(356	)
Long-term derivative liability		(8,410	)		(39,204	)
	$	159,459		$	5,503

In addition, an unrealized derivative liability of $(51.8) million and an unrealized derivative asset of $3.4 million have been allocated to the limited partners in the Partnerships at December 31, 2008 and 2007, respectively, based on the Partnerships’ share of estimated future gas and oil production related to the hedges not yet settled and are included in the consolidated balance sheets as follows (in thousands):

	December 31,
	2008			2007
Unrealized derivative loss – short-term	$	3,022		$	213
Other assets – long-term		2,719			13,542
Accrued liabilities – short-term		(34,932	)		(9,013	)
Unrealized derivative gain – long-term		(22,581	)		(1,348	)
	$	(51,772	)	$	3,394

Interest Rate Risk Hedging Program

At December 31, 2008, the Company had debt outstanding of $467.0 million under its revolving credit facility. During the year ended December 31, 2008, the Company entered into derivative contracts in the form of interest rate swaps to reduce the impact of volatility of changes in the London interbank offered rate (“LIBOR”). The Company has LIBOR interest rate swaps at a three-year fixed swap rate of 3.11% on $150.0 million of outstanding debt through January 2011. The swaps have been designated as cash flow hedges to minimize the risk associated with changes in the designated benchmark interest rate (in this case, LIBOR) related to forecasted payments associated with interest on the credit facility. The Company has accounted for the interest rate swaps under the “long-haul” method to measure ineffectiveness under SFAS No. 133. Using the change in variable cash flow method, no hedge ineffectiveness was identified. The value of the Company’s cash flow derivatives related to interest rate swaps included in accumulated other comprehensive income was a net unrecognized loss of approximately $5.8 million at December 31, 2008. The Company recognized a loss on settled swaps of $520,000 for the year ended December 31, 2008. The fair value of the derivatives related to interest rate swaps are included in the consolidated balance sheet as follows:

	December 31,
	2008			2007
Current portion of derivative liability	$	(3,481	)	$	—
Long-term derivative liability		(2,361	)		—
	$	(5,842	)	$	—

Fair Value of Financial Instruments

Derivative Instruments

The Company adopted the provisions of SFAS No. 157 at January 1, 2008. SFAS No. 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS No. 157’s hierarchy defines three levels of inputs that may be used to measure fair value:

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

24

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 assumptions that 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.

The Company uses the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities for its outstanding derivative contracts. All of the Company’s derivative contracts are defined as Level 2. The Company’s natural gas and crude oil derivative contracts are valued based on prices quoted on the NYMEX or WTI and adjusted by the respective counterparty using various assumptions including quoted forward prices, time value, volatility factors, and contractual prices for the underlying instruments. The Company’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model. In accordance with SFAS No. 157, the following table represents the Company’s fair value hierarchy for its financial instruments at December 31, 2008 (in thousands):

	Level 2			Total
Commodity-based derivatives	$	159,459		$	159,459
Interest rate swap-based derivatives		(5,842	)		(5,842	)
Total	$	153,617		$	153,617

Other Financial Instruments

The estimated fair value of the Company’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Company could realize upon the sale or refinancing of such financial instruments. The Company’s other current assets and liabilities on its consolidated balance sheets are financial instruments and their estimated fair values approximate their carrying amounts due to their short-term nature. The estimated fair values of the Company’s long-term debt at December 31, 2008 and 2007, which consists principally of the Company’s senior unsecured notes and borrowings under its credit facilities, were $712.2 million and $740.0 million, respectively, compared with the carrying amounts of $873.7 million and $740.0 million, respectively. The senior unsecured notes were valued based upon recent trading activity. The carrying value of outstanding borrowings under the credit facility, which bears interest at a variable interest rate, approximates their estimated fair value.

NOTE 8 – COMMITMENTS AND CONTINGENCIES

General Commitments

The Company leases office space and equipment under leases with varying expiration dates through 2014. Rental expense was approximately $1.6 million, $1.0 million and $670,000, for the years ended December 31, 2008, 2007 and 2006, respectively. Future minimum rental commitments for the next five annual periods are as follows (in thousands):

Years Ended December 31,
2009	$	3,178
2010		2,770
2011		2,071
2012		1,427
2013		1,069
Thereafter		3,853
	$	14,368

The Company 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

25

partners in certain Partnerships have the right to present their interests for purchase by the Company, as managing general partner. The Company is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on past experience, the Company believes that any liability incurred would not be material. The Company may be required to subordinate a part of its net partnership revenues from the Partnerships to the receipt by investor partners of cash distributions from the investment partnerships equal to at least 10% of their subscriptions determined on a cumulative basis, in accordance with the terms of the partnership agreements.

Atlas America is party to employment agreements with certain executives that provide compensation, severance and certain other benefits. Some of these obligations may be allocable to the Company.

Legal Proceedings

On June 20, 2008, the Company’s wholly-owned subsidiary, Atlas America, LLC, was named as a co-defendant in the matter captionedCNX Gas Company, LLC (“CNX”) v. Miller Petroleum, Inc. (“Miller”), et al. (Chancery Court, Campbell County, Tennessee). In its complaint, CNX alleged that Miller breached a contract to assign to CNX certain leasehold rights (“Leases”) representing approximately 30,000 acres in Campbell County, Tennessee and that the Company and another defendant, Wind City Oil & Gas, LLC, interfered with the closing of this assignment on June 6, 2008. The Company purchased the Leases from Miller for approximately $19.1 million. On December 15, 2008, the Chancery Court dismissed the matter in its entirety, holding that there had been no breach of the contract by Miller and, therefore, that Atlas America could not have tortuously interfered with the contract. The Chancery Court dismissed all claims against Atlas America, LLC; however, CNX has appealed this decision.

One of the Company’s subsidiaries, Resource Energy, LLC, together with Resource America, Inc., (the former parent of Atlas America), was a defendant in a class action originally filed in February 2000 in the New York Supreme Court, Chautauqua County, by individuals, putatively on their own behalf and on behalf of similarly situated individuals, who leased property to the Company. The complaint alleged that the Company was not paying landowners the proper amount of royalty revenues with respect to natural gas produced from the leased properties. The complaint was seeking damages in an unspecified amount for the alleged difference between the amount of royalties actually paid and the amount of royalties that allegedly should have been paid. In April 2007, a settlement of this lawsuit was approved by the court. Pursuant to the settlement terms, the Company paid $300,000 in May 2007, upgraded certain gathering systems and capped certain transportation expenses chargeable to the landowners. The Company was indemnified by Atlas America for this matter.

Atlas Gas & Oil Company LLC, as successor to DTE Gas & Oil Company, was one of four defendants in a personal injury action filed in Antrim County Circuit Court in northern Michigan in August 2006. The complaint alleged that plaintiff suffered serious personal injuries as a result of the defendants’ negligence. The Company paid $125,000 to the plaintiff in October 2007 in full settlement of this action.

The Company is also a party to various routine legal proceedings arising in 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’s financial condition or results of operations.

NOTE 9 – LONG-TERM DEBT

Total debt consists of the following at the dates indicated (in thousands):

	December 31,
	2008		2007
Revolving credit facility	$	467,000	$	740,000
10.75% senior unsecured notes – due 2018		400,000		—
Unamortized notes premium		6,655		—
Other debt		—		30
	$	873,655	$	740,030
Less current maturities		—		(30	)
	$	873,655	$	740,000

26

Revolving Credit Facility. At December 31, 2008, the Company had a credit facility with a syndicate of banks with a borrowing base of $697.5 million that matures in June 2012. The borrowing base will be redetermined semiannually on April 1 and October 1 subject to changes in the Company’s oil and gas reserves. Up to $50.0 million of the facility may be in the form of standby letters of credit, of which $1.2 million was outstanding at December 31, 2008, which are not reflected as borrowings on the Company’s consolidated balance sheets. The facility is secured by substantially all of the Company’s assets and is guaranteed by each of the company’s subsidiaries and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at the Company’s option. At December 31, 2008 and 2007, the weighted average interest rate on outstanding borrowings was 2.8% and 7.2%, respectively. The base rate for any day equals the higher of the federal funds rate plus 0.50% or the J.P. Morgan prime rate. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for Eurocurrency liabilities. The applicable margin ranges from 0.0% to 0.75% for base rate loans and 1.00% to 1.75% for LIBOR loans.

The events which constitute an event of default for the Company’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against the Company in excess of a specified amount, and a change of control. In addition, the agreement limits sales, leases or transfers of assets and the incurrence of additional indebtedness. The agreement limits the distributions payable by the Company if an event of default has occurred and is continuing or would occur as a result of such distribution. The Company was in compliance with these covenants as of December 31, 2008 and 2007. The credit facility also requires the Company to maintain ratios of current assets (as defined in the credit facility) to current liabilities (as defined in the credit facility) of not less than 1.0 to 1.0 and a ratio of total debt (as defined in the credit facility) to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”, as defined in the credit facility) of 4.0 to 1.0, decreasing to 3.75 to 1.0 commencing January 1, 2009, and decreasing to 3.5 to 1.0 commencing January 1, 2010 and thereafter. According to the definitions contained in the Company’s credit facility, the Company’s ratio of current assets to current liabilities was 1.60 to 1.0 and its ratio of total debt to EBITDA was 2.89 to 1.0 at December 31, 2008.

Senior Unsecured Notes. In January 2008, the Company completed a private placement of $250.0 million of its 10.75% senior unsecured notes (“Senior Notes”) due 2018 to institutional buyers pursuant to rule 144A under the Securities Act of 1933. In May 2008, the Company issued an additional $150.0 million of Senior Notes at 104.75% to par to yield 9.85% to the par call on February 1, 2016. The Company intends to treat these issuances as a single class of debt securities which were subsequently registered for resale on September 19, 2008. The Company received proceeds of approximately $398.0 million from these offerings, including a $7.1 million premium and net of $9.2 million in underwriting fees. In addition, the Company received approximately $4.7 million related to accrued interest. The Company used the net proceeds to reduce the balance outstanding on its revolving credit facility. Interest on the Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year. The Senior Notes are redeemable at any time at specified redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, before February 1, 2011, the Company may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of equity offerings at a stated redemption price. The Senior Notes are also subject to repurchase by the Company at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if the Company does not reinvest the net proceeds within 360 days. The Senior Notes are junior in right of payment to the Company’s secured debt, including its obligations under its credit facility. The indenture governing the Senior Notes contains covenants, including limitations of the Company’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. The Company is in compliance with the covenants as of December 31, 2008.

Annual principal debt payments over the next five years ending December 31 are as follows (in thousands)

2009	$	—
2010		—
2011		—
2012		467,000
2013		—
Thereafter		406,655
	$	873,655

27

Cash payments for interest related to debt were $42.4 million and $23.2 million for the years ended December 31, 2008 and 2007, respectively. There were no cash payments for interest related to debt for the year ended December 31, 2006.

NOTE 10 – OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS

The Company’s operations include three reportable operating segments. These operating segments reflect the way the Company manages its operations and makes business decisions. The Company organizes its oil and gas production segments by geographic location. The Appalachia segment represents the Company’s well interests in the states of Pennsylvania, Ohio, New York, West Virginia and Tennessee. The Michigan/Indiana segment represents the Company’s well interests in the Antrim Shale, located in Michigan’s northern, lower peninsula and the New Albany shale located in southwestern Indiana.

Operating segment data (in thousands):

	Years Ended December 31,
	2008			2007			2006
Gas and oil production
Appalachia:
Revenues	$	127,935		$	99,015		$	88,449
Costs and expenses		25,176			17,638			13,881
Segment profit	$	102,759		$	81,377		$	74,568
Michigan/Indiana:
Revenues(1)	$	183,915		$	107,367		$	—
Costs and expenses		34,403			14,555			—
Segment profit	$	149,512		$	92,812		$	—
Partnership management:
Revenues	$	472,008		$	370,053		$	232,533
Costs and expenses		389,361			302,382			209,548
Segment profit	$	82,647		$	67,671		$	22,985
	Years Ended December 31,
	2008			2007			2006
Reconciliation of segment profit to net income
Segment profit
Gas and oil production-Appalachia	$	102,759		$	81,377		$	74,568
Gas and oil production-Michigan/Indiana		149,512			92,812			—
Partnership management		82,647			67,671			22,985
Total segment profit		334,918			241,860			97,553
General and administrative expense		(44,659	)		(39,414	)		(23,367	)
Compensation reimbursement – affiliate		—			—			(1,237	)
Depreciation, depletion and amortization		(95,434	)		(56,942	)		(22,491	)
Interest expense		(56,306	)		(30,096	)		—
Other – net(2)		4,260			2,096			1,369
Net income before cumulative effect of accounting change	$	142,779		$	117,504		$	51,827

28

	Years Ended December 31,
	2008		2007		2006
Capital expenditures
Gas and oil production
Appalachia	$	258,941	$	146,605	$	74,075
Michigan/Indiana		77,884		40,878		—
Partnership management		2,890		4,499		1,042
Corporate		1,260		4,753		518
	$	340,975	$	196,735	$	75,635

⁽¹⁾ Revenues for the twelve months ended December 31, 2007 include non-cash gains of $26.3 million related to non-qualifying hedges associated with the acquisition of AGO.

⁽²⁾ Includes revenues of $3.5 million and $1.5 million and expenses of $441,000 and $214,000 for the years ended December 31, 2008 and 2007, respectively for AGO well services and transportation. These amounts do not meet the quantitative threshold for reporting segment information. The following table reconciles revenue shown for each operating segment to total revenues shown on the combined and consolidated statements of income:

	Years Ended December 31,
	2008		2007		2006
Revenues:
Gas and oil production – Appalachia	$	127,935	$	99,015	$	88,449
Gas and oil production – Michigan/Indiana		183,915		107,367		—
Partnership Management		472,008		370,053		232,533
Other		3,542		1,462		—
	$	787,400	$	577,897	$	320,982

	December 31,
	2008		2007
Balance sheets
Goodwill
Gas and oil production – Appalachia	$	21,527	$	21,527
Partnership management		13,639		13,639
	$	35,166	$	35,166
Total assets
Gas and oil production
Appalachia	$	773,889	$	491,199
Michigan/Indiana		1,416,042		1,330,432
Partnership management		53,031		30,359
Corporate		27,723		39,244
	$	2,270,685	$	1,891,234

Segment profit per segment represents total revenues less costs and expenses attributable thereto. Amounts for interest, provision for possible losses and depreciation, depletion and amortization and general corporate expenses are shown in the aggregate because these measures are not significant drivers in deciding how to allocate resources and assessing performance of each defined segment.

Major Customer Information:

For the year ended December 31, 2008, gas sales to DTE Gas & Oil Company accounted for 12% of total revenues. No other fiscal period or operating segment had revenues from a single customer which exceeded 10% of total revenues.

29

NOTE 11 – BENEFIT PLANS

Unit Incentive Plan.In December 2006, the Company adopted a Long-Term Incentive Plan (“LTIP”), which provides performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners. The LTIP is administered by the Company’s compensation committee, which may grant awards of either restricted stock units, phantom units or unit options for an aggregate of 3,742,000 common units. Awards granted in 2008 and 2007 vest 25% after three years and 100% upon the four year anniversary of grant, except for awards of 1,500 units to board members which vest 25% per year over four years. Awards granted in 2006 vest 25% per year over four years. Upon termination of service by a grantee, all unvested awards are forfeited. A restricted stock or phantom unit entitles a grantee to receive a common unit of the Company upon vesting of the unit or, at the discretion of the Company’s compensation committee, cash equivalent to the then fair market value of a common unit of the Company. In tandem with phantom unit grants, the Company’s compensation committee may grant a distribution equivalent right (“DER”), which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions the Company makes on a common unit during the period such phantom unit is outstanding.

Restricted Stock and Phantom Units. Under the LTIP, 156,793, 590,950 and 47,619 units of restricted stock and phantom units were awarded in 2008, 2007 and 2006, respectively. The fair value of the grants is based on the closing stock price on the grant date, and is being charged to operations over the requisite service periods using a straight-line attribution method.

The following table summarizes the activity of restricted stock and phantom units for the periods indicated:

	Units		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2005	—		$	—
Granted	47,619		$	21.00
Non-vested shares outstanding at December 31, 2006	47,619		$	21.00
Granted	590,950		$	24.63
Vested	(11,904	)	$	21.00
Forfeited	(2,000	)	$	23.06
Non-vested shares outstanding at December 31, 2007	624,665		$	24.42
Granted	156,793		$	21.43
Vested	(12,279	)	$	21.06
Forfeited	(350	)	$	26.47
Non-vested shares outstanding at December 31, 2008	768,829		$	23.86

Unit Options. For the years ended December 31, 2008, 2007 and 2006, 14,000, 1,532,000 and 373,752 unit options, respectively, were awarded under the LTIP. Option awards expire 10 years from the date of grant and are generally granted with an exercise price equal to the market price of the Company’s stock at the date of grant. The Company uses the Black-Scholes option pricing model to estimate the weighted average fair value per option granted with the following assumptions:

	Years Ended December 31,
	2008			2007			2006
Expected life (years)		6.25			6.25			6.25
Expected volatility		27-34	%		25	%		25	%
Risk-free interest rate		2.8-4.0	%		4.7	%		4.4	%
Expected dividend yield		6.2-7.0	%		5.1-8.0	%		8.0	%
Weighted average fair value of stock options granted	$	5.69		$	2.96		$	2.14

30

The following table sets forth option activity for the periods indicated:

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding at December 31, 2005	—		$	—
Granted	373,752		$	21.00
Outstanding at December 31, 2006	373,752		$	21.00
Granted	1,532,000		$	24.84
Exercised	—			—
Forfeited or expired	(10,700	)	$	23.06
Outstanding at December 31, 2007	1,895,052		$	24.09
Granted	14,000		$	35.36
Exercised	—			—
Forfeited or expired	(6,150	)	$	25.97
Outstanding at December 31, 2008	1,902,902		$	24.17	7.9	$	—
Options exercisable at December 31, 2008	186,876		$	21.00	7.25
Available for grant at December 31, 2008	1,046,086

The following tables summarize information about stock options outstanding and exercisable at December 31, 2008:

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number of Shares Outstanding	Weighted Average Remaining Contractual Life in Years	Weighted Average Exercise Price		Number of Shares Exercisable	Weighted Average Exercise Price
$21.00 - 23.06	1,654,802	7.9	$	22.59	186,876	$	21.00
$30.24 - 35.00	240,600	8.5	$	34.53	—		—
$39.00 & above	7,500	9.0	$	39.79	—		—
	1,902,902	7.9	$	24.17	186,876	$	21.00

The Company recognized $5.5 million, $4.7 million and $337,000 in compensation expense related to restricted stock units, phantom units and unit options for the years ended December 31, 2008, 2007 and 2006, respectively. The Company paid $1.4 million with respect to its LTIP DERs for the year ended December 31, 2008. This amount was recorded as a reduction of members’ equity on the Company’s consolidated balance sheet. At December 31, 2008, the Company had approximately $13.7 million of unrecognized compensation expense related to the unvested portion of the restricted stock units, phantom units and options.

NOTE 12 – COMMON EQUITY OFFERINGS

Public Common Unit Purchase

On May 16, 2008, the Company sold 2,070,000 of its Class B common units in a public offering at $41.50 per common unit with UBS Investment Bank and Wachovia Securities acting as joint book-running managers and underwriters. The net proceeds of approximately $82.5 million (after underwriting expenses of $3.4 million) were used to repay a portion of the Company’s outstanding balance under its revolving credit facility.

31

Atlas America Common Unit Purchase

On May 7, 2008, the Company sold 600,000 of its Class B common units to Atlas America in a private placement at $42.00 per common unit, increasing Atlas America’s ownership of ATN’s common units to 29,952,996 common units. The proceeds of $25.2 million were used to repay a portion of the Company’s outstanding balance under its revolving credit facility.

Private Placement of Class B Common and Class D Units

To partially fund the acquisition of AGO in June 2007, the Company completed a private placement of 7,298,181 Class B common units and 16,702,828 Class D units at a weighted average price of $25.00 per unit for net proceeds of $597.5 million. The private placement of the Class B common and Class D units was exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. The Class D units were a new class of equity security, which automatically converted to common units on a one-to-one basis upon the receipt of the consent of the Company’s unitholders, which the Company obtained in November 2007. The Company entered into a registration rights agreement in connection with the sale of the units. The agreement required the Company to prepare and file a registration statement covering the resale of such units by January 31, 2008 and have such registration statement declared effective by May 30, 2008. The Company filed this registration statement, which was declared effective on February 20, 2008.

NOTE 13 – CASH DISTRIBUTIONS

The Company is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its limited liability company agreement) for that quarter in accordance with their respective percentage interests. If Class A and Class B common unit distributions in any quarter exceed specified target levels, the Managing Member will receive MIIs between 15% and 50% of such distributions in excess of the specified target levels as defined in our limited liability company agreement. Distributions declared by the Company from inception are as follows:

Date Cash Distribution Paid or Payable	For Quarter Ended	Cash Distribution Per Common Unit			Total Cash Distribution to Common Unitholders		Total Cash Distribution to the Manager		Manager Incentive Distribution Payable
					(in thousands)		(in thousands)		(in thousands)
February 14, 2007	December 31, 2006	$	0.06	(1)	$	2,198	$	45
May 15, 2007	March 31, 2007	$	0.43		$	15,770	$	322
August 14, 2007	June 30, 2007	$	0.43		$	15,770	$	322
November 14, 2007	September 30, 2007	$	0.55		$	33,391	$	681	$	784
February 14 , 2008	December 31, 2007	$	0.57		$	34,605	$	706	$	965
May 15, 2008	March 31, 2008	$	0.59		$	36,173	$	738	$	1,214
August 14, 2008	June 30, 2008	$	0.61		$	38,663	$	789	$	1,687
November 14, 2008	September 30, 2008	$	0.61		$	38,663	$	789	$	1,687
February 13, 2009(2)	December 31, 2008	$	0.61	(2)	$	38,663	$	789	$	1,687

⁽¹⁾ Represents a prorated distribution of $0.42 per unit for the period from December 18, 2006, the date of the Company’s initial public offering through December 31, 2006.

⁽²⁾ On January 28, 2009, the Company declared a quarterly cash distribution for the quarter ended December 31, 2008, of $0.61 per common unit. The distribution is payable February 13, 2009 to holders of record as of February 9, 2009.

NOTE 14 – SUBSEQUENT EVENTS

On January 29, 2009, the Company declared a quarterly cash distribution for the quarter ended December 31, 2008, of $0.61 per common unit. The distribution was paid on February 13, 2009 to unitholders of record as of February 9, 2009.

32

NOTE 15 – SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Results of operations from oil and gas producing activities for the periods indicated are as follows (in thousands):

	Years Ended December 31,
	2008			2007			2006
Revenues	$	311,850		$	206,382	(1)	$	88,449
Production costs		(59,579	)		(32,193	)		(13,881	)
Exploration expenses(2)		(6,029	)		(4,065	)		(3,016	)
Depreciation, depletion and amortization		(91,991	)		(54,383	)		(20,600	)
Results of operations from oil and gas producing activities		154,251		$	115,741		$	50,952

⁽¹⁾ Includes unrealized gains from mark-to-market derivatives of $26.3 million.

⁽²⁾ Represents the Company’s land and leasing activities.

Capitalized Costs Related to Oil and Gas Producing Activities.The components of capitalized costs related to the Company’s oil and gas producing activities at the dates indicated are as follows (in thousands):

	At December 31,
	2008			2007
Natural gas and oil properties:
Proved properties	$	2,087,119		$	1,795,871
Unproved properties		43,749			16,380
Support equipment		9,527			6,936
		2,140,395			1,819,187
Accumulated depreciation, depletion and amortization(1)		(221,356	)		(136,603	)
Net capitalized costs	$	1,919,039		$	1,682,584

⁽¹⁾ Costs related to unproved properties are excluded from amortization as they are assessed for impairment.

Costs Incurred in Oil and Gas Producing Activities. The costs incurred by the Company in its oil and gas activities for the periods indicated are as follows (in thousands):

	Years Ended December 31,
	2008		2007		2006
Property acquisition costs:
Proved properties	$	63,146	$	1,243,877	$	5,153
Unproved properties		27,064		50,100		—
Exploration costs		6,029		4,065		3,016
Development costs		229,687		168,253		76,687
	$	325,926	$	1,466,295	$	84,856

⁽¹⁾ Represents the Company’s land and leasing activities.

The development costs above were substantially all incurred for the development of proved undeveloped properties.

Oil and Gas Reserve Information. The estimates of the Company’s proved and unproved gas and oil reserves are based upon evaluations made by management and verified by an independent petroleum engineering firm. All reserves are generally located in the Appalachian Basin in Michigan’s Lower Peninsula and in southwestern Indiana. Reserves are estimated in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board which require that reserve estimates be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

33

Proved oil and gas reserves are the estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

• Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

• Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

• Estimates of proved reserves do not include the following: (a) oil that may become available from known reservoirs but is classified separately as “indicated additional reservoirs”; (b) crude oil and natural gas, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (c) crude oil and natural gas, that may occur in undrilled prospects; and natural gas, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operation methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

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. Additionally, the standardized measure of discounted future net cash flows may not represent the fair market value of the Company’s oil and gas reserves 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 effects have not been proved. The increase in the Company’s reserves for the year ended December 31, 2007, is primarily due to the purchase of reserves in place as a result of the acquisition of DTE Gas & Oil Company on June 29, 2007.

34

The Company’s reconciliation of changes in proved reserve quantities is as follows:

	Gas (Mcf)		Oil (Bbls)
Balance December 31, 2005	157,924,350		2,257,211
Extensions, discoveries and other additions	46,205,382		12,920
Sales of reserves in-place	(127,472	)	(703	)
Purchase of reserves in-place	305,433		1,675
Transfers to limited partnerships	(6,671,754	)	(19,235	)
Revisions	(20,147,989	)(3)	(33,594	)
Production	(8,946,376	)	(150,628	)
Balance December 31, 2006	168,541,574		2,067,646
Extensions, discoveries and other additions	126,613,549	(1)	23,358
Sales of reserves in-place	(62,699	)	(625	)
Purchase of reserves in-place	622,851,730	(2)	48,634
Transfers to limited partnerships	(11,507,307	)	—
Revisions	(714,501	)	(2,517	)
Production	(20,963,436	)	(153,465	)
Balance December 31, 2007	884,758,910		1,983,031
Extensions, discoveries and other additions	210,824,798	(1)	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	)	—
Revisions	(68,276,626	)(3)	(203,166	)
Production	(33,901,975	)	(158,529	)
Balance December 31, 2008	990,805,385		1,733,941
Proved developed reserves at:
December 31, 2005	108,674,675		2,122,568
December 31, 2006	107,683,343		2,064,276
December 31, 2007	594,708,965		1,977,446
December 31, 2008	586,655,301		1,685,771

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

⁽²⁾ Represents the reserves purchased from the acquisition of AGO on June 29, 2007.

⁽³⁾ Represents a decrease of the year-end price of natural gas and oil compared to the price of natural gas and oil at the beginning of the year.

The following schedule presents the standardized measure of estimated discounted future net cash flows relating to proved oil and gas reserves. The estimated future production is priced at year-end prices, adjusted only for fixed and determinable increases in natural gas and oil prices provided by contractual agreements. The resulting estimated future cash inflows are 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 are 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 December 31, 2006, 2007 and 2008 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. Since the Company is a limited liability company that allocates taxable income to the individual unitholders, no provisions for federal or state income taxes have been included in the calculation of standardized measure.

35

	Years Ended December 31,
	2008			2007			2006
	(in thousands)
Future cash inflows	$	6,333,935		$	6,408,367		$	1,262,161
Future production costs		(2,297,091	)		(1,804,199	)		(334,062	)
Future development costs		(618,604	)		(388,111	)		(149,610	)
Future income tax expense		—			—			—
Future net cash flows		3,418,240			4,216,057			778,489
Less 10% annual discount for estimating timing of cash flows		(2,286,299	)		(2,734,879	)		(495,048	)
Standardized measure of discounted future net cash flows	$	1,131,941		$	1,481,178		$	283,441

The future cash flows estimated to be spent to develop proved undeveloped properties in the years ended December 31, 2009, 2010, 2011 and 2012 are $200.7 million, $192.5 million, $192.0 million and $33.5 million, respectively.

The following table (in thousands) summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves for the years ended December 31, 2006, 2007 and 2008. Since the Company allocates taxable income to unitholders, no recognition has been given to income taxes.

	Years Ended December 31,
	2008			2007			2006
Balance, beginning of year	$	1,481,178		$	283,441		$	597,137
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs		(252,270	)		(147,982	)		(74,567	)
Net changes in prices and production costs		(316,970	)		45,261			(273,631	)
Revisions of previous quantity estimates		(46,767	)		(1,208	)		(30,058	)
Development costs incurred		48,092			98,424			3,426
Changes in future development costs		(35,662	)		(14,128	)		(8,505	)
Transfers to limited partnerships		(615	)		(13,998	)		(8,449	)
Extensions, discoveries, and improved recovery less related costs		41,020			170,349			44,820
Purchases of reserves in place		5,170			957,137			660
Sales of reserves in place, net of tax effect		(97	)		(105	)		(572	)
Accretion of discount		147,781			74,685			59,714
Net changes in future income taxes		—			—			—
Estimated settlement of asset retirement obligations		(5,778	)		(4,523	)		(8,226	)
Estimated proceeds on disposals of well equipment		6,329			5,168			10,007
Changes in production rates (timing) and other		60,530			28,657			(28,315	)
Balance, end of year	$	1,131,941		$	1,481,178		$	283,441

36

NOTE 16 – QUARTERLY RESULTS (UNAUDITED)

	March 31,		June 30,		September 30,		December 31,
	(in thousands, except unit data)
Year ended December 31, 2008
Revenues	$	194,589	$	217,556	$	213,621	$	161,634
Net income	$	37,543	$	38,359	$	38,180	$	28,697
Net income per Class B common unit:
Basic	$	0.59	$	0.58	$	0.56	$	0.42
Diluted	$	0.58	$	0.57	$	0.56	$	0.42
Year ended December 31, 2007
Revenues	$	105,191	$	128,055	$	180,269	$	164,382
Net income	$	19,941	$	41,665	$	31,612	$	24,286
Net income per Class B common unit:
Basic	$	0.53	$	1.10	$	0.50	$	0.38
Diluted	$	0.53	$	1.08	$	0.49	$	0.37
Year ended December 31, 2006
Revenues	$	82,111	$	63,608	$	81,193	$	94,070
Income from continuing operations before cumulative effect of accounting change:
Portion applicable to owner’s interest	$	12,469	$	12,599	$	11,466	$	12,486
Portion applicable to Class B members		—		—		—		2,751
Portion applicable to Class A members		—		—		—		56
Net income before cumulative effect of accounting change	$	12,469	$	12,599	$	11,466	$	15,293
Net income before cumulative effect of accounting change per Class B common unit – basic and diluted	$	—	$	—	$	—	$	0.08
Cumulative effect of accounting change		—		—		—		6,355
Net income	$	12,469	$	12,599	$	11,466	$	21,648

37

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

	June 30, 2009		December 31, 2008
ASSETS
Current assets:
Cash and cash equivalents	$	4,849	$	5,655
Accounts receivable		70,317		69,411
Current portion of derivative receivable from Partnerships		105		3,022
Current portion of derivative asset		116,977		107,766
Prepaid expenses and other		12,089		14,714
Total current assets		204,337		200,568
Property, plant and equipment, net		1,988,375		1,963,891
Other assets, net		19,226		18,403
Long-term derivative asset		54,465		69,451
Intangible assets, net		3,244		3,838
Goodwill		35,166		35,166
	$	2,304,813	$	2,291,317

LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable	$	77,144	$	74,262
Accrued liabilities – interest		19,318		19,878
Accrued liabilities – other		4,787		5,872
Liabilities associated with drilling contracts		88,909		96,883
Accrued well drilling and completion costs		47,430		43,946
Current portion of derivative payable to Partnerships		32,839		34,932
Current portion of derivative liability		3,985		12,829
Total current liabilities		274,412		288,602
Long-term debt		862,289		873,655
Other long-term liabilities		—		6,337
Long-term derivative payable to Partnerships		19,965		22,581
Advances from affiliates		2,735		1,712
Long-term derivative liability		30,333		10,771
Asset retirement obligations		50,142		48,136
Commitments and contingencies (Note 8)
Members’ equity:
Class B members’ interests		941,649		932,804
Class A member’s interest		4,606		6,257
Accumulated other comprehensive income		118,506		100,275
		1,064,761		1,039,336
Non-controlling interest		176		187
Total members’ equity		1,064,937		1,039,523
	$	2,304,813	$	2,291,317

See accompanying notes to consolidated financial statements.

38

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per unit data)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Revenues
Well construction and completion	$	63,367		$	122,341		$	175,735		$	226,479
Gas and oil production		69,979			78,957			141,922			155,183
Administration and oversight		2,642			5,137			6,494			10,154
Well services		4,806			5,266			9,899			10,064
Gathering		5,388			5,855			10,112			10,265
Total revenues		146,182			217,556			344,162			412,145
Costs and expenses
Well construction and completion		53,701			106,384			149,098			196,939
Gas and oil production		12,712			15,205			27,294			28,286
Well services		2,120			2,650			4,544			5,062
Gathering		6,485			5,610			10,978			9,733
General and administrative expense		12,268			12,286			26,817			24,078
Depreciation, depletion and amortization		27,275			22,948			55,303			44,758
Loss on asset sale		4,250			—			4,250			—
Total costs and expenses		118,811			165,083			278,284			308,856
Operating income		27,371			52,473			65,878			103,289
Other income (expense)
Interest expense		(15,124	)		(14,563	)		(28,108	)		(27,868	)
Other, net		(1	)		466			79			519
Total other expense, net		(15,125	)		(14,097	)		(28,029	)		(27,349	)
Net income		12,246			38,376			37,849			75,940
Income attributable to non-controlling interests		(15	)		(17	)		(30	)		(38	)
Net income attributable to members’ interests	$	12,231		$	38,359		$	37,819		$	75,902
Allocation of net income attributable to members’ interests:
Class A member’s units	$	245		$	2,465		$	(7,199	)	$	4,419
Class B members’ units		11,986			35,894			45,018			71,483
Net income attributable to members’ interests	$	12,231		$	38,359		$	37,819		$	75,902
Net income attributable to Class B members per unit:
Basic	$	0.19		$	0.57		$	0.70		$	1.15
Diluted	$	0.19		$	0.57		$	0.70		$	1.14
Weighted average Class B members’ units outstanding:
Basic		63,381			62,144			63,381			61,427
Diluted		63,381			62,819			63,381			61,912

See accompanying notes to consolidated financial statements.

39

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY

SIX MONTHS ENDED JUNE 30, 2009

(in thousands, except unit data)

(Unaudited)

	Class A Units				Class B Common Units				Accumulated Other Comprehensive Income		Non-controlling Interest			Total Members’ Equity
	Units	Amount			Units	Amount
Balance, January 1, 2009	1,293,486	$	6,257		63,380,749	$	932,804		$	100,275	$	187		$	1,039,523
Units issued	10		—		500		(48	)		—		—			(48	)
Distributions paid on unissued units under incentive plan	—		—		—		(443	)		—		—			(443	)
Distributions to members	—		(2,476	)	—		(38,663	)		—		—			(41,139	)
Stock-based compensation	—		—		—		2,981			—		—			2,981
Reversal of management incentive distribution	—		8,024		—		—			—		—			8,024
Distributions to non-controlling interests	—		—		—		—			—		(41	)		(41	)
Net income	—		(7,199	)	—		45,018			—		30			37,849
Other comprehensive income	—		—		—		—			18,231		—			18,231
Balance, June 30, 2009	1,293,496	$	4,606		63,381,249	$	941,649		$	118,506	$	176		$	1,064,937

See accompanying notes to consolidated financial statements.

40

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Six Months Ended June 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	37,849		$	75,940
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of deferred finance costs		1,667			1,512
Depreciation, depletion and amortization		55,303			44,758
Adjustment to reflect cash impact of derivatives		30,623			7,948
Non-cash compensation expense		2,981			2,659
Equity (income) of unconsolidated subsidiary		(174	)		(44	)
Distributions paid to noncontrolling interests		(41	)		(81	)
Loss on assets sales and dispositions		4,242			(12	)
Changes in operating assets and liabilities:
Accounts receivable and prepaid expenses		1,808			(16,101	)
Accounts payable and accrued expenses		5,974			7,368
Liabilities associated with drilling contracts		(7,974	)		(81,497	)
Liabilities associated with well drilling and completion costs		3,483			23,734
Other operating assets and liabilities		—			10
Net cash provided by operating activities		135,741			66,194
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(96,413	)		(135,670	)
Proceeds from sales of assets		10,158			34
Other		66			(128	)
Net cash used in investing activities		(86,189	)		(135,764	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility		200,000			140,000
Repayments under credit facility		(211,000	)		(520,016	)
Net proceeds from issuance of debt		—			407,021
Net proceeds from Class B members’ units issued		—			107,733
Distributions paid to members		(39,452	)		(72,876	)
Advances from (to) affiliates		1,023			(3,075	)
Other		(929	)		(10,103	)
Net cash (used in) provided by financing activities		(50,358	)		48,684
Net change in cash and cash equivalents		(806	)		(20,886	)
Cash and cash equivalents, beginning of period		5,655			25,258
Cash and cash equivalents, end of period	$	4,849		$	4,372

See accompanying notes to consolidated financial statements.

41

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION

Atlas Energy Resources, LLC (the “Company”) is a publicly-traded Delaware limited liability company (NYSE: ATN) and an independent developer and producer of natural gas and, to a lesser extent, oil in Northern Michigan’s Antrim Shale, Indiana’s New Albany Shale and the Appalachian Basin. The Company is also a leading sponsor and manager of tax-advantaged direct investment partnerships, in which it coinvests to finance the exploitation and development of its acreage (the “Partnerships”).

At June 30, 2009, the Company had 63,381,249 Class B common units and 1,293,496 Class A units outstanding. The Class A units are entitled to 2% of all quarterly cash distributions by the Company without any requirement for future capital contributions by the holder of such Class A units, even if the Company issues additional Class B common or other equity securities in the future. The Company is managed by Atlas Energy Management, Inc. (the “Managing Member”), a wholly-owned subsidiary of Atlas America, Inc. and its affiliates (“Atlas America”), a publicly-traded company (NASDAQ: ATLS). At June 30, 2009, Atlas America owned 29,952,996 of the Company’s Class B common units and all of the Class A units outstanding, representing a 48.3% ownership interest in the Company.

The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2008 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. 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. Management has evaluated subsequent events through August 10, 2009, the date the financial statements were issued. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008. The statements of income for the three- and six-month periods ended June 30, 2009 may not necessarily be indicative of the statements of income for the full year ending December 31, 2009. Certain amounts in the prior year’s consolidated financial statements have been reclassified to conform to the current year presentation, including $18.8 million of pre-development costs shown as a component of “Property, plant, and equipment, net” which was previously combined with “Liabilities associated with drilling contracts” on the Company’s consolidated balance sheets at December 31, 2008.

Merger with Atlas America, Inc.

On April 27, 2009, the Company and Atlas America executed a definitive merger agreement, pursuant to which a newly formed subsidiary of Atlas America will merge with and into the Company, with the Company surviving as a wholly-owned subsidiary of Atlas America. In the merger, each Class B common unit of the Company not currently held by Atlas America will be converted into 1.16 shares of Atlas America common stock, and Atlas America will be renamed “Atlas Energy, Inc.” The Atlas America board of directors has approved the merger agreement and has resolved to recommend that the Atlas America stockholders vote in favor of the transactions contemplated by the merger agreement. The Company’s board of directors and a special committee of its directors comprised entirely of independent directors have also approved the merger agreement and have resolved to recommend that the Company’s unitholders vote in favor of the merger. Pending consummation of the merger, the Company has suspended distributions to its Class A and Class B members’ interests. The transaction will be subject to approval by holders of a majority of the outstanding Atlas America common stock and a majority of the Company’s outstanding Class B units and other customary closing conditions.

42

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Transactions between the Company and other Atlas America affiliates and operations have been identified in the consolidated financial statements as transactions between affiliates (see Note 5).

In accordance with established practice in the oil and gas industry, the Company includes in its consolidated financial statements its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the investment partnerships in which it has an interest. Such interests typically range from 15% to 35%. The Company’s consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of the Partnerships. Rather, the Company calculates these items specific to its own economics as further explained under the heading “Oil and Gas Properties” below. All material intercompany transactions have been eliminated.

Use of Estimates

Preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and costs and expenses during the reporting period. The Company’s consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, fair value of derivative instruments, the probability of forecasted transactions, and the allocation of purchase price to the fair value of assets acquired. Actual results could differ from these estimates.

Net Income Per Class B Member Unit

Basic net income per unit for Class B common units is computed by dividing net income attributable to the Class B members, which is determined after the deduction of the Class A member’s interests and participating securities, by the weighted average number of Class B common units outstanding during the period. The Class A management incentive interests in net income is calculated on a quarterly basis based upon its 2% ownership interest, represented by its 1,293,496 Class A units, and its member’s incentive interests (“MII’s” – see Note 12), with a priority allocation of net income to the Class A member’s MIIs in accordance with the Company’s limited liability company agreement, and the remaining net income or loss allocated with respect to the Class A’s and Class B’s ownership interests.

On April 27, 2009, the Company and Atlas America executed a definitive merger agreement (see Note 1). Pending consummation of the merger, the Company has suspended distributions to the Class A and Class B members’ interests. Due to the suspension of distributions and in accordance with the limited liability company agreement, the Company determined that previously accrued distributions to MII’s of $8.0 million are no longer payable to Atlas Energy Management, Inc.

The Company presents net income (loss) per unit under the Emerging Issue Task Force’s (“EITF”) Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF No. 07-4”), an update of EITF No. 03-6, “Participating Securities and the Two-Class Method Under FASB Statement No. 128” (“EITF No. 03-6”). EITF No. 07-4 considers whether the incentive distributions of a master limited partnership represent a participating security when considered in the calculation of earnings per unit under the two-class method. EITF No. 07-4 also considers whether the Company’s limited liability company agreement contains any contractual limitations concerning distributions to the MIIs that would impact the amount of earnings to allocate to the MIIs for each reporting period. If distributions are contractually limited to the MIIs’ share of currently designated available cash for distributions as defined under the limited liability company agreement, undistributed earnings in excess of available cash should not be allocated to the MIIs. Under the guidance of EITF 07-4, the Company believes that the limited liability agreement contractually limits cash distributions to available cash and, therefore, undistributed earnings will not be allocated to the MIIs.

On January 1, 2009, the Company adopted Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-6-1 applies to the calculation of earnings per share (“EPS”) described in paragraphs 60 and 61 of FASB Statement No. 128, “Earnings

43

per Share” for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. The Company’s phantom unit awards, which consists of Class B units issuable under the terms of its long-term incentive plan (see Note 11), contain nonforfeitable rights to distribution equivalents of the Company. The participation rights result in a non-contingent transfer of value each time the Company declares a distribution or distribution equivalent during the award’s vesting period. As such, FSP EITF 03-6-1 provides that the net income utilized in the calculation of net income per unit must be after the allocation of income to the phantom units on a pro rata basis. FSP EITF 03-6-1 requires an entity to retroactively adjust all prior period earnings per unit computations per its guidance.

The following table is a reconciliation of net income allocated to the Class A member units and Class B members’ units for purposes of calculating net income per Class B member unit (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Net income attributable to members’ interests	$	12,231		$	38,359		$	37,819		$	75,902
Income allocable to Class A member’s actual cash incentive distributions reserved(1)		—			1,698			(8,024	)		2,901
Income allocable to Class A member’s 2% ownership interest		245			767			825			1,518
Net income attributable to Class A member’s ownership interest		245			2,465			(7,199	)		4,419
Net income attributable to Class B members’ ownership interests		11,986			35,894			45,018			71,483
Less: Net income attributable to participating securities – phantom units(2)		(136	)		(326	)		(508	)		(651	)
Net income utilized in the calculation of net income attributable to Class B members per unit	$	11,850		$	35,568		$	44,510		$	70,832

⁽¹⁾ The amount for the six months ended June 30, 2009 consists of an adjustment to reverse previously recognized estimated income allocable ($0.13 per Class B members unit) to MIIs as the amounts were determined by the Company during the six months ended June 30, 2009 to be no longer payable to the Managing Member (see Note 1).

⁽²⁾ In accordance with FSP EITF 03-6-1, net income attributable to Class B members’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of weighted average phantom units and Class B members’ units outstanding).

Diluted net income attributable to Class B members per unit is calculated by dividing net income attributable to Class B members, less income allocable to participating securities, by the sum of the weighted average number of Class B members’ units outstanding and the dilutive effect of unit option awards, as calculated by the treasury stock method. Unit options consist of Class B member units issuable upon payment of an exercise price by the participant under the terms of the Company’s long-term incentive plan (see Note 11). The following table sets forth the reconciliation of the Company’s weighted average number of Class B member units used to compute basic net income attributable to Class B members per unit with those used to compute diluted net income attributable to Class B members per unit (in thousands):

	Three Months Ended June 30,		Six Months Ended June 30,
	2009	2008	2009	2008
Weighted average number of Class B members’ units – basic	63,381	62,144	63,381	61,427
Add: effect of dilutive unit incentive awards(1)	—	675	—	485
Weighted average number of Class B members’ units – diluted	63,381	62,819	63,381	61,912

⁽¹⁾ For the three months and six months ended June 30, 2009, approximately1.9 million unit options were excluded from the computation of diluted net income attributable to Class B members per unit because the inclusion of such unit options would have been anti-dilutive.

44

Comprehensive Income

Comprehensive income includes net income and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States, have not been recognized in the calculation of net income. These changes, other than net income, are referred to as “other comprehensive income” and for the Company includes changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges. A reconciliation of the Company’s comprehensive income for the periods indicated is as follows (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Net income	$	12,246		$	38,376		$	37,849		$	75,940
Income attributable to non-controlling interests		(15	)		(17	)		(30	)		(38	)
Net income attributable to members’ interests		12,231			38,359			37,819			75,902
Other comprehensive income (loss):
Unrealized holding (loss) gain on hedging contracts		(22,660	)		(208,533	)		63,281			(308,727	)
Less reclassification adjustment for (gains) losses realized in net income		(30,534	)		5,010			(45,050	)		(1,622	)
Total other comprehensive income (loss)		(53,194	)		(203,523	)		18,231			(310,349	)
Comprehensive income (loss) attributable to members’ interests	$	(40,963	)	$	(165,164	)	$	56,050		$	(234,447	)

Components of accumulated other comprehensive income at the dates indicated are as follows (in thousands):

	June 30, 2009			December 31, 2008
Unrealized gain on commodity derivatives	$	123,321		$	106,117
Unrealized loss on interest rate derivatives		(4,815	)		(5,842	)
	$	118,506		$	100,275

Property, Plant and Equipment

Property, plant and equipment are stated at cost. Depreciation, depletion and amortization are based on cost less estimated salvage value primarily using the units-of-production or straight-line method over the assets estimated useful lives. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.

The estimated service lives of property, plant and equipment excluding natural gas and oil properties are as follows:

Pipelines, processing and compression facilities	15-40 years
Rights-of-way – Appalachia	20-40 years
Buildings and improvements	10-40 years
Furniture and equipment	3-7 years
Other	3-10 years

45

Property, plant and equipment consist of the following at the dates indicated (in thousands):

	June 30, 2009			December 31, 2008
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,232,197		$	1,214,991
Predevelopment costs		13,501			18,772
Wells and related equipment		936,566			872,128
		2,182,264			2,105,891
Unproved properties		43,807			43,749
Support equipment		9,081			9,527
		2,235,152			2,159,167
Pipelines, processing and compression facilities		23,252			22,541
Rights-of-way		128			149
Land, buildings and improvements		6,597			6,484
Other		7,269			7,827
		2,272,398			2,196,168
Accumulated depreciation, depletion and amortization:		(284,023	)		(232,277	)
	$	1,988,375		$	1,963,891

Oil and Gas Properties

The Company follows the successful efforts method of accounting for oil and gas producing activities. Acquisition costs of leases and development activities are capitalized. 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 and delay rentals are expensed. Oil is converted to gas equivalent basis (“Mcfe”) at the rate one barrel equals 6 thousand cubic feet (“Mcf”). Depletion is provided on the units-of-production method.

Depletion depreciation and amortization expense is determined on a field-by-field basis using the units-of-production method, with depletion, depreciation and amortization rates for leasehold acquisition costs based on estimated proved reserves and depletion, depreciation and amortization rates for well and related equipment costs 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 uncontrolled but proportionately consolidated investment partnerships, wells drilled solely for the Company’s interest, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to income. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion. Upon the 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 statements of income. 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 Oil and Gas Properties and Long-Lived Assets

The Company’s oil and gas properties and long-lived assets are reviewed for impairment annually or whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets.

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

46

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 levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. If the carrying value exceeds such 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, the Company’s reserve estimates for its investment in its limited partnerships are based on its own assumptions rather than its proportionate share of the limited partnership’s reserves. These assumptions include the Company’s 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 and administrative costs.

The Company’s lower operating and administrative costs result from the limited partners paying to the Company their proportionate share of these expenses plus a profit margin. These assumptions are used in the calculation of the Company’s reserve analysis and could result in the Company’s calculation of depletion and impairment being different than its proportionate share of the limited partnership 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. The Company cannot predict what reserve revisions may be required in future periods.

The Company’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the investment partnerships which the Company sponsors and owns an interest in but does not control. The Company’s reserve quantities include reserves in excess of its proportionate share of reserves in a partnership which the Company may be unable to recover due to the partnership legal structure. The Company may have to pay additional consideration in the future as a well or investment partnership becomes uneconomic under the terms of the partnership agreement in order for the Company 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 Company is governed under the partnership agreement and must be at fair market value supported by an appraisal of an independent expert selected by the Company.

Unproved properties are reviewed 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 will not explore 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 oil and gas properties or unproved properties recorded by the Company for the three and six months ended June 30, 2009 and 2008.

Goodwill

The Company has $35.2 million of goodwill as of June 30, 2009 in connection with several acquisitions of assets. Goodwill and intangibles with infinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. Under the principles of SFAS No. 142, “Goodwill and Other Intangible Assets”, (“SFAS No. 142”), an impairment loss should be recognized if the carrying value of an entity’s reporting units exceeds its estimated fair value. Because quoted market prices for the Company’s reporting units are not available, the Company must apply judgment in determining the estimated fair value of these reporting units. The Company 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 assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to the Company’s market capitalization. The principles of SFAS No. 142 and its interpretations acknowledge that the observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a

47

controlled entity is different from measuring the fair value of that entity’s individual equity securities. In most industries, including the Company’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, the Company also considers a control premium to the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in the Company’s industry. The resultant fair values calculated for the reporting units are then compared to observable metrics on large mergers and acquisitions in the Company’s industry to determine whether those valuations appear reasonable in the Company’s judgment. The Company’s evaluation of goodwill at December 31, 2008, indicated there was no impairment loss and no impairment indicators arose during the six months ended June 30, 2009. The Company will continue to evaluate its goodwill at least annually or when impairment indicators arise, and will reflect the impairment of goodwill, if any, in its consolidated financial statements in that period.

Capitalized Interest

The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and gas wells and other capital projects. Interest is capitalized only during the periods that activities are in progress to bring these assets to their intended use.

The weighted average interest rates used to capitalize interest and the amount of interest capitalized for the following periods were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Weighted average interest rate		6.9	%		4.1	%		6.8	%		4.7	%
Interest capitalized (in thousands)	$	1,747		$	535		$	3,724		$	1,181

Revenue Recognition

Partnership management. The Company conducts certain energy activities through, and a portion of its revenues are attributable to, sponsored investment partnerships. The Company contracts with the investment partnerships to drill partnership wells. The contracts require that the investment partnerships pay the Company 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 Company 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 its consolidated balance sheets. The Company recognizes gathering revenues at the time the natural gas is delivered, and recognizes well services revenues at the time the services are performed. The Company is also entitled to receive administration and oversight fees according to the respective partnership agreements. The Company recognizes such fees as income when services are performed.

Gas and oil production.The Company 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 are 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 the Company’s percentage ownership of working interest or overriding royalty. Generally, the Company’s sales contracts 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.

Because there are timing differences between the delivery of natural gas and oil and its receipt of a delivery statement, the Company has unbilled revenues. These revenues are accrued based upon volumetric data from the Company’s records and estimates of the related transportation and compression fees which are, in turn, based upon applicable product prices. The Company had unbilled trade receivables at June 30, 2009 and December 31, 2008 of $26.8 million and $43.7 million, respectively, which are included in accounts receivable on its consolidated balance sheets.

48

Recently Adopted Accounting Standards

In June 2009, the FASB issued Statement No. 165, “Subsequent Events” (“SFAS No. 165”). SFAS No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS No. 165 requires management of a reporting entity to evaluate events or transactions that may occur after the balance sheet date for potential recognition or disclosure in the financial statements and provides guidance for disclosures that an entity should make about those events. SFAS No. 165 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. The Company adopted the requirements of SFAS No. 165 on April 1, 2009, and its adoption did not have a material impact to its financial position and results of operations.

In April 2009, the FASB issued Staff Position 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP FAS 157-4”). FSP FAS 157-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. FSP FAS 157-4 also requires an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. FSP FAS 157-4 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted the requirements of FSP FAS 157-4 on April 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

In April 2009, the FASB issued Staff Position 115-2 and 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (“FSP FAS 115-2 and FAS 124-2”). FSP FAS 115-2 and FAS 124-2 change existing guidance for determining whether an impairment is other than temporary for debt securities. FSP FAS 115-2 and FAS 124-2 replaces the existing requirement that an entity’s management assess it has both the intent and ability to hold an impaired security until recovery with a requirement that management assess that it does not have the intent to sell the security and that it is more likely than not that it will not have to sell the security before recovery of its cost basis. FSP FAS 115-2 and FAS 124-2 also require that an entity recognize noncredit losses on held-to-maturity debt securities in other comprehensive income and amortize that amount over the remaining life of the security and for the entity to present the total other-than-temporary impairment in the statement of operations with an offset for the amount recognized in other comprehensive income. FSP FAS 115-2 and FAS 124-2 are effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted the requirements of FSP FAS 115-2 and FAS 124-2 on April 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

In April 2009, the FASB issued Staff Position 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP FAS 107-1 and APB 28-1”). FSP FAS 107-1 and APB 28-1 require an entity to provide disclosures about fair value of financial instruments in interim financial information. In addition, an entity shall disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position. FSP FAS 107-1 APB 28-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted the requirements of FSP FAS 107-1 APB 28-1 on April 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

In April 2009, the FASB issued Staff Position 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“FSP 141(R)-1”). FSP 141(R)-1 requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be recognized at fair value if fair value can be reasonably estimated. If fair value of such an asset or liability cannot be reasonably estimated, the asset or liability would generally be recognized in accordance with FASB Statement No. 5, “Accounting for Contingencies” and FASB Interpretation No. 14, “Reasonable Estimation of the Amount of a Loss”. FSP 141(R)-1 also eliminates the requirement to disclose an estimate of the range of outcomes of recognized contingencies at the acquisition date. FSP FAS 141(R)-1 is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for the Company). The Company adopted the requirements of FSP 141(R)-1 on January 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

49

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 amends the requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The Company adopted the requirements of SFAS No. 161 on January 1, 2009 and it did not have a material impact on its financial position or results of operations (see Note 6).

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements-an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 amends ARB No. 51 to establish accounting and reporting standards for the non-controlling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 also requires consolidated net income to be reported and disclosed on the face of the consolidated statement of operations at amounts that include the amounts attributable to both the parent and the non-controlling interest. Additionally, SFAS No. 160 establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated. The Company adopted the requirements of SFAS No. 160 on January 1, 2009 and adjusted its presentation of its financial position and results of operations. Prior period financial position and results of operations have been adjusted retrospectively to conform to the provisions of SFAS No. 160.

In December 2007, the FASB issued SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) replaces SFAS No. 141, “Business Combinations” (“SFAS No. 141”), however retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS No. 141(R) requires an acquirer to recognize the assets acquired, liabilities assumed, and any non-controlling interest in the acquiree at the acquisition date, at their fair values as of that date, with specified limited exceptions. Changes subsequent to that date are to be recognized in earnings, not goodwill. Additionally, SFAS No. 141 (R) requires costs incurred in connection with an acquisition be expensed as incurred. Restructuring costs, if any, are to be recognized separately from the acquisition. The acquirer in a business combination achieved in stages must also recognize the identifiable assets and liabilities, as well as the non-controlling interests in the acquiree, at the full amounts of their fair values. The Company adopted the requirements of SFAS No. 141(R) on January 1, 2009 and it did not have a material impact on its financial position and results of operations.

Recently Issued Accounting Standards

In June 2009, the FASB issued Statement No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – A Replacement of FASB Statement No. 162” (“SFAS No. 168”). SFAS No. 168 establishes the FASB Accounting Standards Codification (“Codification”) as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The Codification supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following SFAS No. 168, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting Standards Updates, which will serve only to update the Codification. SFAS No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Company will apply the requirements of SFAS No. 168 to its financial statements and will update its disclosure references to the new FASB Codification for the interim period ending September 30, 2009 and does not expect it to have a material impact to its financial position or results of operations.

In June 2009, the FASB issued Statement No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS No. 167”). SFAS No. 167 is a revision to FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities” and changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. SFAS No. 167 requires a reporting entity to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. A reporting entity will be required to disclose how its involvement with a variable interest entity affects the reporting entity’s financial statements. SFAS No. 167 is effective at the start of a reporting entity’s first fiscal year beginning after November 15, 2009 (January 1, 2010 for the Company). The Company will apply the requirements of SFAS No. 167 upon its adoption on January 1, 2010 and does not expect it to have a material impact to its financial position or results of operations or related disclosures.

50

Modernization of Oil and Gas Reporting

In December 2008, the Securities and Exchange Commission (“SEC”) announced that it had approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of Regulation S-X and Items 201, 801, and 802 of Regulation S-K. These new disclosure requirements are referred to as “Modernization of Oil and Gas Reporting” and include provisions that:

• Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.

• Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end pricing. This should maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.

• Permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves.

• Update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty”.

• Permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

• Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures are required related to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a company’s reserves preparer or auditor based on Society of Petroleum Engineers criteria.

The Company will begin complying with the disclosure requirements in its annual report on Form 10-K for the year ending December 31, 2009. The new rules may not be applied to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. The Company is currently in the process of evaluating the new requirements.

NOTE 3 – OTHER ASSETS AND INTANGIBLE ASSETS

Other Assets

The following is a summary of other assets at the dates indicated (in thousands):

	June 30, 2009		December 31, 2008
Deferred finance costs, net of accumulated amortization of $7,198 and $5,531 at June 30, 2009 and December 31, 2008, respectively	$	13,424	$	15,018
Long-term derivative receivable from Partnerships		5,028		2,719
Other		774		666
	$	19,226	$	18,403

Deferred finance costs related to the Company’s credit facility and senior unsecured notes (see Note 9) are recorded at cost and amortized over their respective lives (5 to 10 years). Long-term derivative receivable from Partnerships represents the portion of the long-term unrealized derivative liability on contracts that have been allocated to them based on their share of total estimated production volumes.

51

Intangible Assets

Included in intangible assets are partnership management, non-compete agreements and operating contracts acquired through previous acquisitions which were recorded at fair value on their acquisition dates. The Company amortizes these contracts on the declining balance and straight-line methods, over their respective estimated lives, ranging from two to thirteen years. Amortization expense for these contracts was $0.3 million for both of the three-month periods ended June 30, 2009 and 2008, and $0.6 million for both of the six-month periods ended June 30, 2009 and 2008. The aggregate estimated annual amortization expense the remainder of 2009, and for each of the next five calendar years is as follows: 2009—$0.4 million; 2010-2011—$0.7 million; 2012-2013—$0.2 million; and 2014—$0.1 million.

The following is a summary of intangible assets at the dates indicated (in thousands):

	June 30, 2009			December 31, 2008
Management and operating contracts	$	14,343		$	14,343
Non-compete agreement		890			890
Total costs		15,233			15,233
Accumulated amortization		(11,989	)		(11,395	)
	$	3,244		$	3,838

NOTE 4 – ASSET RETIREMENT OBLIGATIONS

The Company follows SFAS No. 143 and FIN 47 “Accounting for Conditional Asset Retirement Obligations,” which require the Company to recognize an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. Under SFAS No. 143, the Company must currently recognize 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. SFAS No. 143 requires the Company to consider estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability is based on 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.

The Company has no assets legally restricted for purposes of settling asset retirement obligations. Except for the item previously referenced, 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 abandonment costs for the periods indicated is as follows (in thousands):

	Three Months Ended June 30,					Six Months Ended June 30,
	2009			2008		2009			2008
Asset retirement obligations, beginning of period	$	49,262		$	43,801	$	48,136		$	42,358
Liabilities incurred		166			858		596			1,640
Liabilities settled		(23	)		—		(85	)		(2	)
Accretion expense		737			675		1,495			1,338
Asset retirement obligations, end of period	$	50,142		$	45,334	$	50,142		$	45,334

The accretion expense is included in depreciation, depletion and amortization in the Company’s consolidated statements of income.

52

NOTE 5 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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

Relationship with Atlas America. Atlas America provides centralized corporate functions on behalf of the Company, including 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. These costs are reflected in general and administrative expense in the Company’s consolidated statements of income. The employees supporting these Company operations are employees of Atlas America. The compensation costs of these employees, and rent for the offices out of which they operate, are allocated to the Company based on estimates of the time spent by such employees in performing services for the Company. This allocation of costs may fluctuate from period to period based upon the level of activity by the Company of any acquisitions, equity or debt offerings, or other non-recurring transactions, which requires additional management time. Management believes the method used to allocate these expenses is reasonable.

The Company participates in Atlas America’s cash management program. Any transaction performed by Atlas America on behalf of the Company is not due on demand and has been recorded as a long-term liability in advances from affiliates on the Company’s consolidated balance sheets.

Relationship with Company-Sponsored Investment Partnerships. The Company conducts certain activities through, and a substantial portion of its revenues are attributable to, the Partnerships. The Company serves as managing general partner of the Partnerships and assumes customary rights and obligations for the Partnerships. As a general partner, the Company is liable for Partnership liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Partnerships. The Company 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 and Atlas Pipeline Partners, L.P. On June 1, 2009, the Company completed the sale of two natural gas processing plants and associated pipelines located in southwestern Pennsylvania for cash of $10.0 million to Laurel Mountain Midstream, LLC (“Laurel Mountain”), a newly-formed joint venture between the Company’s affiliate, Atlas Pipeline Partners, L.P. (NYSE: APL) (“Atlas Pipeline”), and The Williams Companies, Inc. (NYSE: WMB). (“Williams”). Upon contribution of its Appalachia Basin natural gas gathering system to Laurel Mountain, Atlas Pipeline received $87.8 million in cash, a preferred equity right to proceeds under a $25.5 million note issued to Laurel Mountain by Williams and a 49.0% ownership interest in Laurel Mountain. Atlas Pipeline is a subsidiary of the Company’s indirect parent company, Atlas America. Laurel Mountain owns and operates all of Atlas Pipeline’s previously owned northern Appalachian assets, excluding its northern Tennessee operations, of which the Company will be the largest customer. The Company recorded a loss on the sale the two natural gas processing plants and associated pipelines of $4.3 million, which is recorded as “Loss on asset sale” on its consolidated statements of income for the three and six months ended June 30, 2009. The Company used the net proceeds from the sale to repay outstanding borrowings under its revolving credit facility.

Upon completion of the transaction with Laurel Mountain, the Company entered into new gas gathering agreements with Laurel Mountain which superseded the existing master natural gas gathering agreement and omnibus agreement between the Company and Atlas Pipeline. Under the new gas gathering agreement, the Company 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 agreement contains additional provisions which define certain obligations and options of each party to build and connect newly drilled wells to any Laurel Mountain gathering system. Unlike the terminated agreements, Atlas America will not assume or guarantee the Company’s obligation to pay gathering fees to Laurel Mountain.

NOTE 6 – DERIVATIVE AND FINANCIAL INSTRUMENTS

The Company is exposed to certain risks relating to its ongoing business operations. These risks are managed by using derivative instruments related to commodity price risk and interest rate risk. Forward contracts on natural gas and oil are entered into to manage the price risk associated with forecasted sales of natural gas and crude oil. Interest rate swaps are entered into to manage interest rate risk associated with the Company’s variable rate borrowings. In accordance with SFAS No. 133, the Company designates these derivatives as cash flow hedges and the derivative instruments have been recorded as either assets or liabilities at fair value in the consolidated balance sheet. The effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified to earnings in the same period during which the hedged transaction affects earnings. The following table summarizes the fair value of derivative instruments as of

53

June 30, 2009 and December 31, 2008, as well as the gain or loss recognized for the six months ended June 30, 2009 and 2008. There were no gains or losses recognized in income for ineffective derivative instruments for the six months ended June 30, 2009 and 2008.

Fair Value of Derivative Instruments:

Derivatives in SFAS 133 Cash Flow Hedging Relationships	Asset Derivatives					Liability Derivatives
		Fair Value					Fair Value
	Balance Sheet Location	June 30, 2009		December 31, 2008		Balance Sheet Location	June 30, 2009			December 31, 2008
		(in thousands)					(in thousands)
Commodity contracts:	Current assets	$	116,977	$	107,766	Current liabilities	$	(383	)	$	(9,348	)
	Long-term assets		54,465		69,451	Long-term liabilities		(29,120	)		(8,410	)
			171,442		177,217			(29,503	)		(17,758	)
Interest rate contracts:	Current assets		—		—	Current liabilities		(3,602	)		(3,481	)
	Long-term assets		—		—	Long-term liabilities		(1,213	)		(2,361	)
			—		—			(4,815	)		(5,842	)
Total derivatives under SFAS No. 133		$	171,442	$	177,217		$	(34,318	)	$	(23,600	)

Effects of Derivative Instruments on Consolidated Statements of Income for the three months and six months ended is as follows:

Derivatives in SFAS 133 Cash Flow Hedging Relationships	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) For the Three Months Ended						Location of Gain/(Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) For the Three Months Ended
	June 30, 2009			June 30, 2008				June 30, 2009			June 30, 2008
	(in thousands)							(in thousands)
Commodity contracts	$	(22,528	)	$	(212,364	)	Gas and oil production	$	31,564		$	(4,896	)
Interest rate contracts		(132	)		3,831		Interest expense		(1,030	)		(114	)
	$	(22,660	)	$	(208,533	)		$	30,534		$	(5,010	)

Derivatives in SFAS 133 Cash Flow Hedging Relationships	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) For the Six Months Ended						Location of Gain/(Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) For the Six Months Ended
	June 30, 2009			June 30, 2008				June 30, 2009			June 30, 2008
	(in thousands)							(in thousands)
Commodity contracts	$	64,286		$	(310,522	)	Gas and oil production	$	47,082		$	1,645
Interest rate contracts		(1,005	)		1,795		Interest expense		(2,032	)		(23	)
	$	63,281		$	(308,727	)		$	45,050		$	1,622

54

Commodity Risk Hedging Program

From time to time, the Company enters into natural gas and crude oil future option contracts and collar contracts 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.

In May 2009, the Company received approximately $28.5 million in proceeds from the early termination of natural gas and oil derivative positions for production periods from 2011 through 2013. In conjunction with the early termination of these derivatives, the Company entered into new derivative positions at prevailing prices at the time of the transaction. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under the Company’s credit facility (see Note 9). The gain recognized upon the early termination of these derivative positions will continue to be reported in accumulated other comprehensive income, and will be reclassified into the Company’s consolidated statements of income in the same periods in which the hedged production revenues would have been recognized in earnings.

The Company has a $123.3 million net unrealized gain related to financial derivatives on its gas and oil production which is shown as a component of accumulated other comprehensive income at June 30, 2009, compared to a net unrealized gain of $106.1 million at December 31, 2008. If the fair values of the instruments remain at current market values, the Company will reclassify $83.0 million of unrealized gains to its consolidated statements of income over the next twelve-month period as these contracts settle and $40.3 million of unrealized gains will be reclassified in later periods.

As of June 30, 2009, the Company had the following natural gas and oil volumes hedged:

Natural Gas Fixed Price Swaps

Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset/(Liability)(1)
	(MMBtu)	(per MMBtu)		(in thousands)
2009	21,790,000	$	8.044	$	79,987
2010	31,880,000	$	7.708		52,270
2011	20,720,000	$	7.040		2,973
2012	19,680,000	$	7.223		1,131
2013	10,620,000	$	7.126		(1,631	)
				$	134,730

55

Natural Gas Costless Collars

Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset/(Liability)(1)
		(MMBtu)	(per MMBtu)		(in thousands)
2009	Puts purchased	120,000	$	11.000	$	795
2009	Calls sold	120,000	$	15.350		—
2010	Puts purchased	3,360,000	$	7.839		6,584
2010	Calls sold	3,360,000	$	9.007		—
2011	Puts purchased	9,540,000	$	6.523		145
2011	Calls sold	9,540,000	$	7.666		—
2012	Puts purchased	4,020,000	$	6.514		—
2012	Calls sold	4,020,000	$	7.718		(978	)
2013	Puts purchased	5,340,000	$	6.516		—
2013	Calls sold	5,340,000	$	7.811		(1,737	)
					$	4,809

Crude Oil Fixed Price Swaps

Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset/(Liability)(2)
	(Bbl)	(per Bbl)		(in thousands)
2009	31,700	$	99.497	$	896
2010	48,900	$	97.400		1,079
2011	42,600	$	77.460		(30	)
2012	33,500	$	76.855		(105	)
2013	10,000	$	77.360		(35	)
				$	1,805

Crude Oil Costless Collars

Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset/(Liability)(2)
		(Bbl)	(per Bbl)		(in thousands)
2009	Puts purchased	19,500	$	85.000	$	289
2009	Calls sold	19,500	$	116.884		—
2010	Puts purchased	31,000	$	85.000		448
2010	Calls sold	31,000	$	112.918		—
2011	Puts purchased	27,000	$	67.223		—
2011	Calls sold	27,000	$	89.436		(45	)
2012	Puts purchased	21,500	$	65.506		—
2012	Calls sold	21,500	$	91.448		(73	)
2013	Puts purchased	6,000	$	65.358		—
2013	Calls sold	6,000	$	93.442		(24	)
					$	595
				Total Net Asset	$	141,939

⁽¹⁾ Fair value based on forward NYMEX natural gas prices, as applicable.

⁽²⁾ Fair value based on forward WTI crude oil prices, as applicable.

The Company’s commodity price risk management 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 June 30, 2009

56

and December 31, 2008, net unrealized derivative liabilities of $47.7 million and $51.8 million, respectively, are payable to the limited partners in the Partnerships and are included in the consolidated balance sheets as follows (in thousands):

	June 30, 2009			December 31, 2008
Current portion of derivative receivable from Partnerships	$	105		$	3,022
Other assets – long-term		5,028			2,719
Current portion of derivative payable to Partnerships		(32,839	)		(34,932	)
Long-term derivative payable to Partnerships		(19,965	)		(22,581	)
	$	(47,671	)	$	(51,772	)

Interest Rate Risk Hedging Program

At June 30, 2009, the Company had $456.0 million of borrowings under its revolving credit facility (see Note 9). At June 30, 2009, the Company had interest rate derivative contracts having an aggregate notional principal amount of $150.0 million through January 2011, which were designated as cash flow hedges. Under the terms of the contract, the Company will pay an interest rate of 3.11%, plus the applicable margin as defined under the terms of its revolving credit facility, and will receive LIBOR, plus the applicable margin, on the notional principal amounts. This derivative effectively converts $150.0 million of the Company’s floating rate debt under the revolving credit facility to fixed-rate debt. The Company has accounted for the interest rate derivative contracts as effective hedge instruments under SFAS No. 133.

At June 30, 2009, the Company’s interest rate derivatives were as follows:

Interest Fixed Rate Swap

Term	Notional Amount		Option Type	Contract Period Ended December 31,	Fair Value (Liability)
					(in thousands)
January 2008 – January 2011	$	150,000,000	Pay 3.11% - Receive LIBOR	2009	$	(1,932	)
				2010		(2,757	)
				2011		(126	)
				Total Net Liability	$	(4,815	)

NOTE 7 – FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company applies the provisions of SFAS No. 157, “Fair Value Measurements”, to its financial instruments. SFAS No. 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS No. 157 hierarchy defines three levels of inputs that may be used to measure fair value:

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

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 assumptions that 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.

57

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Company has certain assets and liabilities that are reported at fair value on a recurring basis in its consolidated balance sheets. The following methods and assumptions were used to estimate fair values.

Derivative Instruments.All of the Company’s derivative contracts are defined as Level 2. The Company’s natural gas and crude oil derivative contracts are valued based on prices quoted on the NYMEX or WTI and adjusted by the respective counterparty using various assumptions including quoted forward prices, time value, volatility factors, and contractual prices for the underlying instruments. The Company’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model. Information for assets and liabilities measured at fair value on a recurring basis at June 30, 2009 and December 31, 2008 is as follows (in thousands):

	June 30, 2009						December 31, 2008
	Level 2			Total			Level 2			Total
Commodity-based derivatives	$	141,939		$	141,939		$	159,459		$	159,459
Interest rate swap-based derivatives		(4,815	)		(4,815	)		(5,842	)		(5,842	)
Total	$	137,124		$	137,124		$	153,617		$	153,617

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The Company has certain assets and liabilities that are reported at fair value on a nonrecurring basis in its consolidated balance sheets. The following methods and assumptions were used to estimate fair values.

Asset Retirement Obligations.The Company estimates the fair value of 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 Company; and estimated inflation rates (see Note 4).

Oil and Gas Property Impairments. In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company reviews its proved oil and gas properties for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties (see Note 2). The Company’s evaluation indicated there was no impairment of its oil and gas properties for the three- and six-month periods ended June 30, 2009 and 2008.

Information for assets that are measured at fair value on a nonrecurring basis for the three- and six-month periods ended June 30, 2009 and 2008 are as follows (in thousands):

	Three Months Ended June 30, 2009				Six Months Ended June 30, 2009
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	166	$	166	$	596	$	596
Total	$	166	$	166	$	596	$	596

NOTE 8 – COMMITMENTS AND CONTINGENCIES

General Commitments

The Company 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 Company, as managing general partner. The Company is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on past experience, the management of the Company believes that any liability incurred would not be material. The Company may be required to subordinate a part of its net partnership revenues from the Partnerships to the receipt of cash distributions to the investor partners from the investment partnerships equal to at least 10% of their subscriptions determined on a cumulative basis, in accordance with the terms of the partnership agreements. For the three- and six-month periods ended June 30, 2009, $699,100 and $871,500, respectively, of the Company’s net revenues were subordinated, which reduced its cash distributions received from the investment partnerships for the respective periods. No subordination of the Company’s net revenues was required for the three- and six-month periods ended June 30, 2008 with regard to the Partnerships.

58

Atlas America is party to employment agreements with certain executives that provide compensation, severance and certain other benefits. Some of these obligations may be allocable to the Company (see Note 5).

As of June 30, 2009, the Company is a guarantor of 50% ($8.7 million) of Crown Drilling of Pennsylvania, LLC’s $17.4 million credit arrangement.

Legal Proceedings

On June 20, 2008, the Company’s wholly-owned subsidiary, Atlas America, LLC, was named as a co-defendant in the matter captionedCNX Gas Company, LLC (“CNX”) v. Miller Petroleum, Inc. (“Miller”), et al. (Chancery Court, Campbell County, Tennessee). In its complaint, CNX alleged that Miller breached a contract to assign to CNX certain leasehold rights (“Leases”) representing approximately 30,000 acres in Campbell County, Tennessee and that the Company and another defendant, Wind City Oil & Gas, LLC, interfered with the closing of this assignment on June 6, 2008. The Company purchased the Leases from Miller for approximately $19.1 million. On December 15, 2008, the Chancery Court dismissed the matter in its entirety, holding that there had been no breach of the contract by Miller and, therefore, that Atlas America could not have tortuously interfered with the contract. The Chancery Court dismissed all claims against Atlas America, LLC; however, CNX has appealed this decision.

Following the announcement of the merger agreement on April 27, 2009, the following actions were filed in Delaware Chancery Court purporting to challenge the merger:

• Alonzo v. Atlas Energy Resources, LLC, et al., C.A. No. 4553-VCN (Del. Ch. filed 4/30/09);

• Operating Engineers Constructions Industry and Miscellaneous Pension Fund v. Atlas America, Inc., et al., C.A. No. 4589-VCN (Del. Ch. filed 5/13/09);

• Vanderpool v. Atlas Energy Resources, LLC, et al., C.A. No. 4604-VCN (Del. Ch. filed 5/15/09);

• Farrell v. Cohen, et al., C.A. No. 4607-VCN (Del. Ch. filed 5/19/09); and

• Montgomery County Employees’ Retirement Fund v. Atlas Energy Resources, L.L.C., et al., C.A. No. 4613-VCN (Del. Ch. filed 5/21/09).

On June 15, 2009, Vice Chancellor Noble issued an order consolidating all five lawsuits, renaming the actionIn re Atlas Energy Resources, LLC Unitholder Litigation, C.A. No. 4589-VCN, and appointing as co-lead plaintiffs Operating Engineers Construction Industry and Miscellaneous Pension Fund and Montgomery County Employees Retirement Fund. Plaintiffs filed a Verified Consolidated Class Action Complaint on July 1, 2009, which has superseded all prior complaints. On July 27, 2009, the Chancery Court granted the parties’ scheduling stipulation, setting a preliminary injunction hearing for September 4, 2009. The complaint advances claims of breach of fiduciary duty in connection with the merger agreement, including allegations of inadequate disclosures in connection with the unitholder vote on the merger, and seeks monetary damages or injunctive relief, or both. On August 7, 2009, plaintiffs advised the court by letter that the hearing date be removed from the court’s calendar. Plaintiffs have advised counsel that they intend to continue to pursue the case after the merger as a claim for monetary damages or injunctive relief, or both.

On August 7, 2009, plaintiffs advised the court by letter that the hearing date be removed from the court’s calendar. Plaintiffs have advised counsel that they intend to continue to pursue the case after the merger as a claim for monetary damages. Predicting the outcome of this lawsuit is difficult. An adverse judgment for monetary damages could have a material adverse effect on the operations of the combined company after the merger. A preliminary injunction, had plaintiffs successfully pursued it, could have delayed or jeopardized the completion of the merger, and an adverse judgment granting permanent injunctive relief could have indefinitely enjoined completion of the merger. Based on the facts known to date, the defendants believe that the claims asserted against them in this lawsuit are without merit, and intend to defend themselves vigorously against the claims.

59

The Company is also a party to various routine legal proceedings arising in 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’s financial condition or results of operations.

NOTE 9 – LONG-TERM DEBT

Total debt consists of the following at the dates indicated (in thousands):

	June 30, 2009		December 31, 2008
Revolving credit facility	$	456,000	$	467,000
10.75% senior unsecured notes – due 2018		400,000		400,000
Unamortized notes premium		6,289		6,655
		862,289		873,655
Less current maturities		—		—
	$	862,289	$	873,655

Revolving Credit Facility. At June 30, 2009, the Company had a credit facility with a syndicate of banks with a borrowing base of $650.0 million that matures in June 2012. The borrowing base is redetermined semiannually on April 1 and October 1 subject to changes in the Company’s oil and gas reserves or is automatically reduced by 25% of the stated principal of any senior unsecured notes issued by the Company. On July 16, 2009, the Company issued $200.0 million of senior unsecured notes, and the borrowing base was reduced by $50.0 million to $600.0 million (see Note 13). Up to $50.0 million of the credit facility may be in the form of standby letters of credit, of which $1.2 million was outstanding at June 30, 2009, which are not reflected as borrowings on the Company’s consolidated balance sheets. The credit facility is secured by substantially all of the Company’s assets and is guaranteed by each of the Company’s subsidiaries and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at the Company’s option. On April 9, 2009, the credit agreement was amended to, among other things, increase the applicable margin on Eurodollar Loans from a range of 100 to 175 basis points to a range of 200 to 300 basis points and the applicable margin for base rate loans from a range of 0 to 75 basis points to a range of 112.5 to 212.5 basis points. At June 30, 2009 and December 31, 2008, the weighted average interest rate on the credit facility’s outstanding borrowings was 2.9% and 2.8%, respectively. The base rate for any day equals the higher of the federal funds rate plus 0.50%, the J.P. Morgan prime rate or the Adjusted LIBOR for a 30-day interest period plus 1.0%. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for Eurocurrency liabilities. The credit agreement was amended on July 10, 2009, in anticipation of the merger between the Company and Atlas America (see Note 13).

The events which constitute an event of default for the Company’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against the Company in excess of a specified amount, and a change of control. In addition, the agreement limits sales, leases or transfers of assets and the incurrence of additional indebtedness. The agreement limits the distributions payable by the Company if an event of default has occurred and is continuing or would occur as a result of such distribution. The Company was in compliance with these covenants as of June 30, 2009. The credit facility also requires the Company to maintain ratios of current assets (as defined in the credit facility) to current liabilities (as defined in the credit facility) of not less than 1.0 to 1.0 and a ratio of total debt (as defined in the credit facility) to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”, as defined in the credit facility) of 3.75 to 1.0 commencing January 1, 2009, and decreasing to 3.5 to 1.0 commencing January 1, 2010 and thereafter. According to the definitions contained in the Company’s credit facility, the Company’s ratio of current assets to current liabilities was 1.3 to 1.0 and its ratio of total debt to EBITDA was 2.7 to 1.0 at June 30, 2009.

Senior Unsecured Notes. At June 30, 2009, the Company had $400.0 million principal amount outstanding of 10.75% senior unsecured notes (“Senior Notes”) due on February 1, 2018 (see Note 13). The Senior Notes are presented combined with the $6.3 million unamortized premium received at June 30, 2009. Interest on the Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year. The Senior Notes are redeemable at any time at specified redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, before February 1, 2011, the Company may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of equity offerings at a stated redemption price. The Senior Notes are also subject to repurchase by the Company at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if the

60

Company does not reinvest the net proceeds within 360 days. The Senior Notes are junior in right of payment to the Company’s secured debt, including its obligations under its credit facility. The indenture governing the Senior Notes contains covenants, including limitations of the Company’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. The Company is in compliance with the covenants as of June 30, 2009.

NOTE 10 – OPERATING SEGMENT INFORMATION

The Company’s operations include three reportable operating segments. These operating segments reflect the way the Company manages its operations and makes business decisions. The Company organizes its oil and gas production segments by geographic location. The Appalachia segment represents the Company’s well interests in the states of Pennsylvania, Ohio, New York, West Virginia and Tennessee. The Michigan/Indiana segment represents the Company’s well interests in the Antrim Shale, located in Michigan’s northern, Lower Peninsula and the New Albany Shale located in southwestern Indiana.

Segment profit per segment represents total revenues less costs and expenses attributable thereto. Amounts for interest, provision for possible losses and depreciation, depletion and amortization and general corporate expenses are shown in the aggregate because these measures are not significant drivers in deciding how to allocate resources and assessing performance of each defined segment.

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Operating segment data (in thousands):
Gas and oil production
Appalachia:
Revenues	$	32,556	$	33,988	$	62,150	$	62,896
Costs and expenses		6,902		5,862		14,316		10,881
Segment profit	$	25,654	$	28,126	$	47,834	$	52,015
Michigan/Indiana:
Revenues	$	37,423	$	44,969	$	79,772	$	92,287
Costs and expenses		5,810		9,343		12,978		17,405
Segment profit	$	31,613	$	35,626	$	66,794	$	74,882
Partnership management
Revenues	$	75,342	$	137,789	$	200,511	$	255,300
Costs and expenses		62,122		114,547		164,259		211,541
Segment profit	$	13,220	$	23,242	$	36,252	$	43,759

61

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Reconciliation of segment profit to net income
Segment profit
Gas and oil production-Appalachia	$	25,654		$	28,126		$	47,834		$	52,015
Gas and oil production-Michigan/Indiana		31,613			35,626			66,794			74,882
Partnership management		13,220			23,242			36,252			43,759
Total segment profit		70,487			86,994			150,880			170,656
General and administrative expense		(12,268	)		(12,286	)		(26,817	)		(24,078	)
Depreciation, depletion and amortization		(27,275	)		(22,948	)		(55,303	)		(44,758	)
Loss on asset sale		(4,250	)		—			(4,250	)		—
Interest expense(1)		(15,124	)		(14,563	)		(28,108	)		(27,868	)
Other – net(2)		676			1,179			1,447			1,988
Net income	$	12,246		$	38,376		$	37,849		$	75,940

⁽¹⁾ The Company notes that interest expense has not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.

⁽²⁾ Revenues, net of expenses, for AGO well services and transportation of $0.7 million for both of the three-month periods ended June 30, 2009 and 2008, and $1.4 million and $1.5 million for the six-month periods ended June 30, 2009 and 2008, respectively, do not meet the quantitative threshold for reporting segment information. These amounts have been included in “Other – net” above.

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Capital expenditures:
Gas and oil production
Appalachia	$	26,289	$	60,410	$	68,991	$	99,621
Michigan		4,480		18,930		11,396		34,193
Partnership management		8,180		390		15,607		1,200
Corporate		257		323		419		656
	$	39,206	$	80,053	$	96,413	$	135,670

	June 30, 2009		December 31, 2008
Balance sheets:
Goodwill
Gas and oil production – Appalachia	$	21,527	$	21,527
Partnership management		13,639		13,639
	$	35,166	$	35,166
Total assets:
Gas and oil production
Appalachia	$	834,875	$	794,521
Michigan/Indiana		1,394,929		1,416,042
Partnership management		49,475		53,031
Corporate		25,534		27,723
	$	2,304,813	$	2,291,317

62

The following table reconciles revenues shown for each operating segment to total revenues shown on the consolidated statements of income for the three and six months ended June 30, 2009 and 2008:

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Revenues:
Gas & oil production – Appalachia	$	32,556	$	33,988	$	62,150	$	62,896
Gas & oil production – Michigan/Indiana		37,423		44,969		79,772		92,287
Partnership management		75,342		137,789		200,511		255,300
Other		861		810		1,729		1,662
	$	146,182	$	217,556	$	344,162	$	412,145

NOTE 11 – BENEFIT PLANS

The Company has a Long-Term Incentive Plan (“LTIP”), which provides performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners. The LTIP is administered by the Company’s compensation committee, which may grant awards of restricted stock units, phantom units or unit options. Awards for a total of 3,742,000 common units may be granted under the LTIP. Awards granted after 2006 vest 25% after three years and 100% upon the four-year anniversary of grant, except for awards of 1,500 units to board members which vest 25% per year over four years. Awards granted in 2006 vest 25% per year over four years. Upon termination of service by a grantee, all unvested awards are forfeited. A restricted stock or phantom unit entitles a grantee to receive a common unit of the Company upon vesting of the unit or, at the discretion of the Company’s compensation committee, cash equivalent to the then fair market value of a common unit of the Company. In tandem with phantom unit grants, the Company’s compensation committee may grant a distribution equivalent right (“DER”), which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions the Company makes on a common unit during the period such phantom unit is outstanding.

Restricted Stock and Phantom Units. Under the LTIP, 23,523 and 26,375 units of restricted stock and phantom units were awarded during the six months ended June 30, 2009 and 2008, respectively. The fair value of the grants is based on the closing stock price on the grant date, and is being charged to operations over the requisite service periods using a straight-line attribution method.

The following table summarizes the activity of restricted stock and phantom units for the six months ended June 30, 2009:

	Units		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2008	768,829		$	23.86
Granted	23,523			14.50
Vested	(13,073	)		21.70
Forfeited	(8,000	)		20.78
Non-vested shares outstanding at June 30, 2009	771,279		$	23.65

Unit Options. There were no unit options granted during the six months ended June 30, 2009. During the six months ended June 30, 2008, 14,000 unit options were awarded under the LTIP. Option awards expire 10 years from the date of grant and are generally granted with an exercise price equal to the market price of the Company’s stock at the date of grant. The Company uses the Black-Scholes option pricing model to estimate the weighted average fair value per option granted.

63

The following table sets forth option activity for the six months ended June 30, 2009:

	Units		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding at December 31, 2008	1,902,902		$	24.17
Granted	—			—
Exercised	—			—
Forfeited or expired	(7,500	)		23.06
Outstanding at June 30, 2009	1,895,402		$	24.18	7.4	$	0
Options exercisable at June 30, 2009	280,314		$	21.00	6.8
Available for grant at June 30, 2009	1,038,063

The following tables summarize information about unit options outstanding and exercisable at June 30, 2009:

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number of Shares Outstanding	Weighted Average Remaining Contractual Life in Years	Weighted Average Exercise Price		Number of Shares Exercisable	Weighted Average Exercise Price
$21.00 – 23.06	1,647,302	7.4	$	22.59	280,314	$	21.00
$30.24 – 35.00	240,600	8.0	$	34.53	—		—
$37.79 and above	7,500	8.5	$	39.79	—		—
	1,895,402	7.4	$	24.18	280,314	$	21.00

The Company recognized $1.5 million and $1.3 million in compensation expense related to restricted stock units, phantom units and unit options for the three months ended June 30, 2009 and 2008, respectively. The Company recognized $3.0 million and $2.7 million in related compensation expense for the six months ended June 30, 2009 and 2008, respectively. The Company paid $0.3 million with respect to its LTIP DERs for the three months ended June 30, 2008, and $0.4 million and $0.7 million for the six months ended June 30, 2009 and 2008, respectively. No payment was made with respect to its LTIP DERs for the three months ending June 30, 2009. These amounts were recorded as a reduction of members’ equity on the Company’s consolidated balance sheet during the respective period. At June 30, 2009, the Company had approximately $10.9 million of unrecognized compensation expense related to the unvested portion of the restricted stock units, phantom units and unit options.

NOTE 12 – CASH DISTRIBUTIONS

The Company is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its limited liability company agreement) for that quarter to its Class A and Class B common unitholders in accordance with their respective percentage interests. If Class A and Class B common unit distributions exceed specified target levels in any quarter during or subsequent to the completion of certain tests in accordance with the Company’s limited liability company agreement, the Managing Member will receive MIIs between 15% and 50% of such distributions in excess of the specified target levels as defined in the Company’s limited liability company agreement. The tests within the Company’s limited liability company agreement include a 12-quarter test which requires, among other things, that the Company pay a quarterly cash distribution per unit that, on average, exceeds $0.42 per unit for 12 full, consecutive, non-overlapping calendar quarters and does not have a calendar quarter during which the distribution per unit was not reduced. Effective April 27, 2009, the Company has suspended further distributions due to the announcement of its intent to merge with Atlas America (see Note 1). The Company’s suspension of the quarterly distribution during the three months and six months ended June 30, 2009 means that it has not met the tests within the limited liability company agreement and, as such, the Managing Member will not receive the MIIs that were previously reserved for during previous periods. Distributions declared by the Company from January 1, 2008 to June 30, 2009 are as follows:

Date Cash Distribution Paid or Payable	For Quarter Ended	Cash Distribution Per Common Unit		Total Cash Distribution to Common Unitholders		Total Cash Distribution to the Manager
				(in thousands)		(in thousands)
February 14 , 2008	December 31, 2007	$	0.57	$	34,605	$	706
May 15, 2008	March 31, 2008	$	0.59	$	36,173	$	738
August 14, 2008	June 30, 2008	$	0.61	$	38,663	$	789
November 14, 2008	September 30, 2008	$	0.61	$	38,663	$	789
February 13, 2009	December 31, 2008	$	0.61	$	38,663	$	789

64

NOTE 13 – SUBSEQUENT EVENTS

Issuance of Senior Unsecured Notes

On July 16, 2009, the Company issued $200.0 million of 12.125% senior unsecured notes (“12.125% Senior Notes”) due 2017 at 98.116% of par value to yield 12.5% at maturity. The Company used the net proceeds from the issuance of approximately $191.7 million, net of underwriting fees of $4.5 million, to repay outstanding borrowings under its revolving credit facility. Under the terms of the Company’s credit facility (see Note 9), the credit facility borrowing base is automatically reduced by 25% of the stated principal amount of any senior unsecured notes offering. As such, the borrowing base of the Company’s credit facility was reduced by $50.0 million to $600.0 million upon the issuance of the 12.125% Senior Notes. Interest on the 12.125% Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year. The 12.125% Senior Notes are redeemable at any time at certain redemption prices, together with accrued interest at the date of redemption. In addition, before August 1, 2012, the Company may redeem up to 35% of the aggregate principal amount of the 12.125% Senior Notes with the proceeds of certain equity offerings at a stated redemption price of 112.125% of the principal, plus accrued interest. The 12.125% Senior Notes are junior in right of payment to the Company’s secured debt, including its obligations under its revolving credit facility. The indenture governing the 12.125% Senior Notes contains covenants, including limitations of the Company’s ability to incur certain liens, engage in sale/leaseback transactions, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets.

Amendment to Revolving Credit Facility

On July 10, 2009, the Company received the requisite consent from its lenders to amend its revolving credit facility to permit the merger with Atlas America. The material terms of the amendment are:

• The merger with Atlas America will be permitted,

• Restrictions on the Company’s ability to make payments with respect to its equity interests will be revised to permit it to make distributions to Atlas America in an amount equal to the income tax liability at the highest marginal rate attributable to the Company’s net income. In addition, the Company will be permitted to make distributions to Atlas America of up to $40.0 million per year and, to the extent that it distributes less than that amount in any year, may carry over up to $20.0 million for use in the next year,

• The definition of change of control will be revised to include a change of control of Atlas America.

The amendment will become effective upon consummation of the merger.

Natural Gas Derivative Contracts

On July 20, 2009, the Company entered into certain natural gas derivative contracts for calendar 2013 production volumes of 220,000 MMbtu per month with an average fixed price of $6.90 per MMbtu.

65