Atlas Energy Resources 10Q 2009 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2009

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _________ to __________

Commission file number: 1-33193

ATLAS ENERGY RESOURCES, LLC

(Exact name of registrant as specified in its charter)

Delaware	75-3218520
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

Westpointe Corporate Center One
1550 Coraopolis Heights Road
Moon Township, PA	15108
(Address of principal executive offices)	(Zip code)

Registrant's telephone number, including area code: (412) 262-2830

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes ¨ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer,” “non-accelerated” filer and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ¨ No x

The number of common units of the registrant outstanding on July 28, 2009 was 63,381,249.

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT ON FORM 10-Q

		Page
PART I	FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)

	Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008	3

	Consolidated Statements of Income for the Three Months and Six Months Ended June 30, 2009 and 2008	4

	Consolidated Statement of Changes in Members’ Equity for the Six Months Ended June 30, 2009	5

	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2009 and 2008	6

	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	53

Item 4.	Controls and Procedures	56

PART II	OTHER INFORMATION

Item 1.	Legal Proceedings	57

Item 1A.	Risk Factors	58

Item 6.	Exhibits	60

SIGNATURES		62

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

	June 30,		December 31,
	2009		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.

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per unit data)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						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.

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY

SIX MONTHS ENDED JUNE 30, 2009

(in thousands, except unit data)

(Unaudited)

											Accumulated
											Other					Total
	Class A Units					Class B Common Units					Comprehensive		Non-controlling			Members’
	Units		Amount			Units		Amount			Income		Interest			Equity
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.

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.

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.

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 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						Six Months Ended
	June 30,						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				Six Months Ended
	June 30,				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.

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						Six Months Ended
	June 30,						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,			December 31,
	2009			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

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

	June 30,			December 31,
	2009			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 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 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						Six Months Ended
	June 30,						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.

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.

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.

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,		December 31,
	2009		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.

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,			December 31,
	2009			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					Six Months Ended
	June 30,					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.

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 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:

	Asset Derivatives					Liability Derivatives
Derivatives in		Fair Value					Fair Value
SFAS 133 Cash Flow	Balance Sheet	June 30,		December 31,		Balance Sheet	June 30,			December 31,
Hedging Relationships	Location	2009		2008		Location	2009			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:

	Gain/(Loss)							Location of	Gain/(Loss)
	Recognized in OCI on Derivative							Gain/(Loss)	Reclassified from OCI into Income
	(Effective Portion)							Reclassified from	(Effective Portion)
Derivatives in	For the Three Months Ended							Accumulated	For the Three Months Ended
SFAS 133 Cash Flow	June 30,			June 30,				OCI into Income	June 30,			June 30,
Hedging Relationships	2009			2008				(Effective Portion)	2009			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	)

	Gain/(Loss)							Location of	Gain/(Loss)
	Recognized in OCI on Derivative							Gain/(Loss)	Reclassified from OCI into Income
	(Effective Portion)							Reclassified from	(Effective Portion)
Derivatives in	For the Six Months Ended							Accumulated	For the Six Months Ended
SFAS 133 Cash Flow	June 30,			June 30,				OCI into Income	June 30,			June 30,
Hedging Relationships	2009			2008				(Effective Portion)	2009			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

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			Average		Fair Value
December 31,	Volumes		Fixed Price		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

Natural Gas Costless Collars

Production
Period Ending				Average		Fair Value
December 31,	Option Type	Volumes		Floor and Cap		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			Average		Fair Value
December 31,	Volumes		Fixed Price		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				Average		Fair Value
December 31,	Option Type	Volumes		Floor and Cap		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 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,			December 31,
	2009			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

				Contract
	Notional			Period Ended	Fair Value
Term	Amount		Option Type	December 31,	(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.

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				Six Months Ended
	June 30, 2009				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.

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 captioned CNX 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 action In 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. 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.

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,		December 31,
	2009		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 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				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008

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

	Three Months Ended						Six Months Ended
	June 30,						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				Six Months Ended
	June 30,				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,		December 31,
	2009		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

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				Six Months Ended
	June 30,				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:

				Weighted
				Average
				Grant Date
	Units			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.

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

						Weighted
						Average
				Weighted		Remaining		Aggregate
				Average		Contractual		Intrinsic
				Exercise		Term		Value
	Units			Price		(in years)		(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:

		Cash
		Distribution		Total Cash		Total
Date Cash		Per		Distribution		Cash
Distribution		Common		to Common		Distribution
Paid or Payable	For Quarter Ended	Unit		Unitholders		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

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.

ITEM 2: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

When used in this Form 10-Q, the words “believes” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties more particularly described in Item 1A, under the caption “Risk Factors”, in our annual report on Form 10-K for fiscal 2008 and Part II, Item 1A of this report. These risks and uncertainties could cause actual results to differ materially. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

GENERAL

The following discussion provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with our consolidated financial statements and related notes thereto appearing elsewhere in this report. Unless otherwise indicated, references in this report to we, our or us include Atlas Energy Resources, LLC, our wholly-owned subsidiaries and our interests in sponsored drilling programs.

We are a publicly-traded Delaware limited liability Company (NYSE: ATN) and an independent developer and producer of natural gas and oil, with operations in the Appalachian Basin, the Michigan Basin, and the Illinois Basin. Within these Basins we focus our drilling and production in four established shale plays; namely, the Marcellus Shale of western Pennsylvania, the Antrim Shale of northern Michigan, the Chattanooga Shale of northeastern Tennessee, and the New Albany Shale of west central Indiana. Our Appalachian Basin operations are primarily located in eastern Ohio, western Pennsylvania, and north central Tennessee. We have additional operations in New York, West Virginia and Kentucky. We specialize in the development of these natural gas basins because they provide us with repeatable, low-risk drilling opportunities. We are a leading sponsor and manager of tax-advantaged, direct investment natural gas and oil partnerships in the United States. Our focus is to increase our reserves, production, and cash flows through a balanced mix of generating new opportunities of geologic prospects, natural gas and oil exploitation and development, and sponsorship of investment partnerships. We generate both upfront and ongoing fees from the drilling, production, servicing, and administration of our wells in these partnerships.

Our business is conducted through three reportable business segments:

Two gas and oil production segments, in Appalachia and Michigan/Indiana, which consist of our interests in oil and gas properties; and

Our partnership management segment, which consists of well construction and completion, administration and oversight, well services and gathering activities.

RECENT DEVELOPMENTS

Formation of Atlas Resources Public #18-2009(B) L.P.

On June 29, 2009, we completed fundraising for Atlas Resources Public #18-2008 Drilling Program, raising $122.8 million representing the second partnership (Atlas Resources Public #18-2009(B) L.P.) in the program. Atlas Resources, LLC, our wholly-owned subsidiary, serves as the managing general partner.

Sale of Natural Gas Gathering and Processing Assets

On June 1, 2009, we 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 our 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 our indirect parent company, Atlas America, Inc. (NASDAQ: ATLS), (“Atlas America”). Laurel Mountain owns and operates all of Atlas Pipeline’s previously owned northern Appalachian assets, excluding its northern Tennessee operations, of which we will be the largest customer. We recorded a loss on the sale of the two natural gas processing plants and associated pipelines of $4.3 million which is recorded as “Loss on asset sale” on our consolidated statements of income for the three and six months ended June 30, 2009. We used the net proceeds to reduce borrowings under our revolving credit facility.

Upon completion of the transaction with Laurel Mountain, we entered into new gas gathering agreements with Laurel Mountain which superseded the existing master natural gas gathering agreement and omnibus agreement between us and Atlas Pipeline. Under the new gas gathering agreement, we are obligated to pay Laurel Mountain all of the gathering fees we collect 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.

Early Termination of Derivative Instruments

Merger with Atlas America, Inc.

On April 27, 2009, we and Atlas America executed a definitive merger agreement, pursuant to which a newly formed subsidiary of Atlas America will merge with and into us, with us surviving as a wholly-owned subsidiary of Atlas America. In the merger, each Class B common unit of ours 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. Our board of directors and a special committee of our directors comprised entirely of independent directors have also approved the merger agreement and have resolved to recommend that our unitholders vote in favor of the merger. Pending consummation of the merger, we have suspended distributions to our 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 our outstanding Class B units and other customary closing conditions.

Credit Agreement Amendment

Effective April 9, 2009, we entered into a second amendment to our credit agreement with a syndicate of banks, which among other things, adjusted our credit facility borrowing base to $650.0 million (see “Subsequent Events”). The amendment also modified the definition of applicable margin above adjusted LIBOR or the base rate (as defined in the credit agreement) upon which borrowings under the credit facility bear interest by adjusting the Eurodollar Loans rate (as defined in the credit agreement) 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, subject to amounts drawn against the credit facility.

SUBSEQUENT EVENTS

Senior Unsecured Notes

On July 16, 2008, we 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. We used the net proceeds of $191.7 million, net underwriting fees of $4.5 million, to repay outstanding borrowings under our revolving credit facility.Under the terms of our credit facility (see “Credit Facility”), the credit facility borrowing base is automatically reduced by 25% of the stated principal amount of any senior unsecured notes offering by us. As such, the borrowing base of our 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, we 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 our secured debt, including our obligations under the revolving credit facility. The indenture governing the 12.125% Senior Notes contains covenants, including limitations of our 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 our assets.

Amendment to Revolving Credit Facility

On July 10, 2009, we received the requisite consent from our lenders to amend our 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 our ability to make payments with respect to our equity interests will be revised to permit us to make distributions to Atlas America in an amount equal to the income tax liability at the highest marginal rate attributable to our net income. In addition, we will be permitted to make distributions to Atlas America of up to $40.0 million per year and, to the extent that we distribute 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, we entered into certain natural gas derivative contracts for calendar 2013 production volume of 220,000 MMbtu per month with an average fixed price of $6.90 per MMbtu.

Key Performance Indicators as of and for the three and six months ended June 30, 2009:

In our Appalachia gas and oil operations:

we own direct and indirect working interests in approximately 8,631 gross productive gas and oil wells;

we own overriding royalty interests in approximately 629 gross productive gas and oil wells;

our net daily production was 43.6 Mmcfe per day and 42.9 Mmcfe per day for the three months and six months ended June 30, 2009;

we lease approximately 935,300 gross (889,700 net) acres, of which approximately 623,300 gross (616,400 net) acres are undeveloped;

included in our undeveloped acreage are approximately 531,950 Marcellus acres in Pennsylvania, New York and West Virginia, of which approximately 266,100 acres are located in our core Marcellus Shale position in southwestern Pennsylvania;

we drilled 126 gross wells (including 42 Marcellus Shale wells), during the six months ended June 30, 2009, on behalf of our investment partnerships;

we have drilled 153 vertical and 10 horizontal gross Marcellus Shale wells to date, of which 140 vertical and 5 horizontal Marcellus Shale wells have been successfully completed and have been turned on line and are producing;

of the 153 Marcellus Shale wells we drilled to date, we have completed 42 wells using the multi-frac technique we developed with successful results;

	·	we connected 179 gross wells to gathering systems during the six months ended June 30, 2009; and

	·	we drilled and participated in 21 horizontal wells in the Chattanooga Shale of eastern Tennessee to date. We have leased approximately 137,000 gross acres (106,000 net undeveloped) in this shale area.

In our Michigan gas and oil operations:

	·	we own direct and indirect working interests in approximately 2,488 gross producing gas and oil wells;

	·	we own overriding royalty interests in approximately 93 gross producing gas and oil wells;

	·	our net daily production was 57.9 Mmcfe per day and 58.0 Mmcfe per day for the three months and six months ended June 30, 2009;

	·	we have leased approximately 344,400 gross (272,200 net) acres, of which approximately 35,800 gross (28,100 net) acres are undeveloped; and

	·	we drilled 24 gross wells (19 net wells) during the six months ended June 30, 2009.

In our Indiana gas and oil operations:

	·	we own direct and indirect working interests in approximately 16 gross producing gas and oil wells;

	·	our net daily production was 0.2 Mmcfe per day for both the three months and six months ended June 30, 2009;

	·	we have leased approximately 244,100 gross (118,200 net) acres, of which approximately 239,100 gross (114,400 net) acres are undeveloped; and

	·	we drilled 16 gross wells (14 net wells) during the six months ended June 30, 2009.

In our partnership management business:

our investment partnership business includes equity interests in 95 investment partnerships and a registered broker-dealer which acts as the dealer manager of our investment partnership offerings.

since July 2008, we have raised $560.0 million in investor funds, including $122.8 million raised in the three months ended June 30, 2009 for our most recent investment partnership, Atlas Resources Public #18-2009(B) L.P.

How We Evaluate our Operations

Non-GAAP Financial Measures

We use a variety of financial and operations measures to assess our performance, including non-GAAP financial measures, such as EBITDA, Adjusted EBITDA and distributable cash flow. These measures are not calculated or presented in accordance with generally accepted accounting principles, or GAAP. EBITDA, Adjusted EBITDA and distributable cash flow are significant performance metrics used by our management to indicate the cash distributions we expect to pay to our unitholders, prior to the establishment of any cash reserves (see “Recent Developments” and “Cash Distributions”). Specifically, these financial measures assist our investors in their assessment of whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. EBITDA, Adjusted EBITDA and distributable cash flow are also used as quantitative standards by our management and by external users of our financial statements such as investors, research analysts and others to assess:

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and

our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure.

Our EBITDA, Adjusted EBITDA and distributable cash flow should not be considered as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our EBITDA, Adjusted EBITDA and distributable cash flow excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our EBITDA, Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies.

The following table presents a reconciliation of netincome, our most directly comparable GAAP performance

Measure, to EBITDA, Adjusted EBITDA and distributable cash flow for each of the periods presented:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Reconciliation of net income to non-GAAP measures:
Net income	$	12,246		$	38,376		$	37,849		$	75,940
Income attributable to non-controlling interests		(15	)		(17	)		(30	)		(38	)
Depreciation and amortization		27,275			22,948			55,303			44,758
Interest expense		15,124			14,563			28,108			27,868
EBITDA		54,630			75,870			121,230			148,528
Adjustment to reflect cash impact of derivatives(1)		29,019			2,920			30,623			7,948
Non-cash loss on sale of assets		4,250			—			4,250			—
Non-cash compensation expense		1,453			1,339			2,981			2,659
Adjusted EBITDA	$	89,352		$	80,129		$	159,084		$	159,135
Interest expense		(15,124	)		(14,563	)		(28,108	)		(27,868	)
Amortization of deferred financing costs (included within interest expense)		1,002			742			1,667			1,512
Maintenance capital expenditures		(12,975	)		(12,975	)		(25,950	)		(25,950	)
Distributable cash flow	$	62,255		$	53,333		$	106,693		$	106,829

________________

(1)

Consists of (i) $28.5 million of cash proceeds received in May 2009 from the early settlement of natural gas and oil derivative positions and (ii) cash proceeds received from the settlement of ineffective derivative gains recognized in fiscal 2007 associated with the acquisition of our Michigan operations during the three and six months ended June 30, 2009 and 2008, but not reflected in the consolidated statements of income for the respective periods.

GENERAL TRENDS AND OUTLOOK

We expect our business to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Financial Markets

Currently, there is unprecedented uncertainty in the financial markets. This uncertainty presents additional potential risks to us. These risks include the availability and costs associated with our borrowing capabilities, our ability to raise additional capital, and an increase in the volatility of the market price of our common units. While we have no immediate plans to access additional debt or equity in the capital markets (see “Subsequent Events”), should we decide to do so in the near future, the terms, size, and cost of new debt or equity could be less favorable than in previous transactions. We do not believe our liquidity has been materially affected by recent events in the financial markets and we will continue to monitor events and circumstances which may affect it in the near future.

Commodity Prices

Significant factors that may impact future commodity prices include developments in the issues currently impacting Iraq and Iran and the Middle East in general; the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas; and overall North American gas supply and demand fundamentals, including the impact of increasing liquefied natural gas deliveries to the United States. Although we cannot predict the occurrence of events that will affect future commodity prices or the degree to which these prices will be affected, the prices for commodities that we produce will generally approximate market prices in the geographic region of the production.

Commodity prices for natural gas continued to decline during the three months ended June 30, 2009 from year-end commodity prices at December 31, 2008. This decline may cause some of our oil and gas properties to become uneconomic to develop or operate. Please read “Part II, Item 1A: — Risk Factors” included in this report.

In order to address volatility in commodity prices, we have implemented a hedging program that is intended to reduce the volatility in our revenues. This program mitigates, but does not eliminate, our sensitivity to short-term changes in commodity prices. Please read Part I, Item 3, “— Quantitative and Qualitative Disclosures About Market Risk.”

Natural Gas Supply and Outlook

While commodity prices for natural gas have declined during the three months ended June 30, 2009, we believe that the current development of the Marcellus Shale and the New Albany Shale, and new horizontal drilling techniques will likely cause relatively high levels of natural gas-related drilling in these geological areas as producers seek to increase their level of natural gas production. Although the number of natural gas wells drilled in the United States has increased overall in recent years, a corresponding increase in production has not been realized, primarily as a result of smaller discoveries and the decline in production from existing wells. However, we believe that an increase in United States drilling activity, additional sources of supply such as liquefied natural gas, and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for, and to compensate for the slowing production of, natural gas in the United States. However, the areas in which we operate are experiencing a decline in the development of shallow wells, but a significant increase in drilling activity related to new and increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques, including horizontal and multiple fracturing techniques.

While we anticipate continued high levels of exploration and production activities over the long term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas reserves. Drilling activity generally decreases as natural gas prices decrease. We have no control over the level of drilling activity in the areas of our operations.

Reserve Outlook

Our future oil and gas reserves, production, cash flow and our ability to make payments on our debt and distributions (see “Recent Developments” and “Subsequent Events”) depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. We face the challenge of natural production declines and volatile natural gas and oil prices. As initial reservoir pressures are depleted, natural gas production from particular well decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. In order to sustain and grow our level of distributions, we may need to make acquisitions that are accretive to distributable cash flow per unit. In addition, we intend to reserve a portion of our cash flow from operations to allow us to develop our oil and gas properties at a level that will allow us to maintain a flat production profile and reserve levels.

RESULTS OF OPERATIONS

GAS AND OIL PRODUCTION

Production Profile. The gas and oil wells in each geological basin in which we operate share a relatively predictable production profile, producing high quality natural gas at low pressures from several pay zones. Wells in each region generally demonstrate moderate annual production declines throughout their economic life, which may continue for 30 years or more without significant remedial work or the use of secondary recovery techniques.

Production Volumes. The following table shows our total net gas and oil production volumes and production per day during the three months and six months ended June 30, 2009 and 2008, respectively (in thousands, except for production per day):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Production:(1)
Appalachia:(2)
Natural gas (MMcf)		3,710		2,936		7,302		5,692
Oil (000’s Bbls)		43		38		78		74
Total (MMcfe)		3,968		3,164		7,770		6,136
Michigan/Indiana:
Natural gas (MMcf)		5,284		5,439		10,526		10,813
Oil (000’s Bbls)		1		1		2		2
Total (MMcfe)		5,290		5,445		10,538		10,825
Total:
Natural gas (MMcf)		8,994		8,374		17,828		16,504
Oil (000’s Bbls)		44		39		80		76
Total (MMcfe)		9,258		8,608		18,308		16,960

Production per day: (1)
Appalachia:(2)
Natural gas (Mcf/d)		40,770		32,259		40,341		31,272
Oil (Bbl)		471		419		432		409
Total (Mcfe/d)		43,596		34,773		42,933		33,726
Michigan/Indiana:
Natural gas (Mcf/d)		58,058		59,767		58,154		59,411
Oil (Bbl)		11		15		9		11
Total (Mcfe/d)		58,124		59,857		58,208		59,477
Total:
Natural gas (Mcf/d)		98,828		92,026		98,495		90,683
Oil (bpd)		482		434		441		420
Total (Mcfe/d)		101,720		94,630		101,141		93,203

______________

(1)

Production quantities consist of the sum of (i) our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells, and (ii) our proportionate share of production from wells owned by the investment partnerships in which we have an interest, based on our equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells.

(2)	Appalachia includes our production located in Pennsylvania, Ohio, New York, West Virginia, and Tennessee.

Production Revenues, Prices and Costs. Our production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised 99% of our proved reserves on an energy equivalent basis at December 31, 2008. The following table shows our production revenues and average sales prices for our oil and gas production during the three and six months ended June 30, 2009 and 2008, along with our average production costs, taxes, and transmission and compression costs in each of the reported periods:

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Production Revenues (in thousands):
Appalachia:
Natural gas revenue	$	29,527	$	29,404	$	57,071	$	55,010
Oil revenue		3,029		4,584		5,079		7,886
Total revenues	$	32,556	$	33,988	$	62,150	$	62,896
Michigan/Indiana:
Natural gas revenue	$	37,370	$	44,813	$	79,700	$	92,082
Oil revenue		53		156		72		205
Total revenues	$	37,423	$	44,969	$	79,772	$	92,287
Total:
Natural gas revenue	$	66,897	$	74,217	$	136,771	$	147,092
Oil revenue		3,082		4,740		5,151		8,091
Total revenues	$	69,979	$	78,957	$	141,922	$	155,183

Average Sales Price:
Appalachia:
Natural gas (per Mcf)
Total realized price, after hedge	$	7.96	$	10.02	$	7.82	$	9.67
Total realized price, before hedge	$	3.32	$	11.82	$	4.44	$	10.35
Michigan/Indiana:
Natural gas (per Mcf)
Total realized price, after hedge(1)	$	7.16	$	8.78	$	7.77	$	9.25
Total realized price, before hedge	$	3.63	$	10.88	$	4.29	$	9.49
Total:
Natural gas (per Mcf)
Total realized price, after hedge(1)	$	7.49	$	9.21	$	7.79	$	9.39
Total realized price, before hedge	$	3.50	$	11.21	$	4.35	$	9.79
Appalachia:
Oil (per Bbl)
Total realized price, after hedge	$	70.59	$	120.27	$	68.35	$	106.01
Total realized price, before hedge	$	57.06	$	126.48	$	46.27	$	109.19
Michigan/Indiana:
Oil (per Bbl)
Total realized price, after hedge	$	50.50	$	112.61	$	45.81	$	106.59
Total realized price, before hedge	$	50.50	$	112.61	$	45.81	$	106.59
Total:
Oil (per Bbl)
Total realized price, after hedge	$	70.23	$	120.00	$	67.66	$	106.02
Total realized price, before hedge	$	57.16	$	125.99	$	46.26	$	109.12

______________________

(1)

Includes cash proceeds of $0.5 million and $2.9 million for the three months ended June 30, 2009 and 2008, respectively and $2.1 million and $7.9 million for the six months ended June 30, 2009 and 2008, respectively, received from the settlement of ineffective derivative gains associated with the acquisition of our Michigan operations during the three and six months ended June 30, 2009 and 2008, but not reflected in the consolidated statements of income for the respective periods.

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008

Production Costs (per Mcfe):
Appalachia:
Lease operating expenses	$	0.98	$	0.98	$	1.01	$	0.92
Production taxes		0.02		0.03		0.03		0.04
Transportation and compression		0.73		0.84		0.80		0.81
	$	1.73	$	1.85	$	1.84	$	1.77
Michigan/Indiana:
Lease operating expenses	$	0.62	$	0.77	$	0.71	$	0.76
Production taxes		0.23		0.67		0.27		0.57
Transportation and compression		0.25		0.28		0.25		0.27
	$	1.10	$	1.72	$	1.23	$	1.60
Total:
Lease operating expenses	$	0.78	$	0.83	$	0.84	$	0.81
Production taxes		0.14		0.43		0.17		0.38
Transportation and compression		0.45		0.50		0.48		0.48
	$	1.37	$	1.76	$	1.49	$	1.67

Three Months Ended June 30, 2009 Compared to the Three Months Ended June 30, 2008

Our natural gas revenues were $66.9 million for the three months ended June 30, 2009, a decrease of $7.3 million (10%) from $74.2 million for the three months ended June 30, 2008. The $7.3 million decrease consisted of a $7.9 million decrease resulting from lower realized natural gas sales prices and $1.0 million of subordinated gas revenues to our investment partnerships, partially offset by a $1.6 million increase attributable to increases in natural gas production volumes In accordance with the terms of our investment partnerships, we may be required to subordinate a part of our net revenues from the investment partnerships to the investor partners’ cash distributions from the investment partnerships equal to at least 10% of their subscriptions determined on a cumulative basis.

We had an increase in Appalachian production volumes of 8,511Mcf/day for the three months ended June 30, 2009 when compared with the prior year comparable period which was principally attributable to the increase in production we received from our Marcellus Shale wells and an increase in wells drilled in the most recent six-month period as they were connected to gas gathering facilities and transportation pipelines.

Our oil revenues were $3.1 million for the three months ended June 30, 2009, a decrease of $1.6 million (34%) from $4.7 million for the three months ended June 30, 2008. The decrease resulted primarily from a 41% decrease in the average realized sales price of oil ($1.9 million), partially offset by an 11% ($0.3 million) increase in production volumes.

Our Appalachia production costs were $6.9 million for the three months ended June 30, 2009, an increase of $1.0 million (18%) from $5.9 million for the three months ended June 30, 2008. This increase principally consists of a $0.8 million increase in water hauling and disposal costs associated with an increase in the number of Marcellus Shale wells we drilled.

Our Michigan/Indiana production costs were $5.8 million for the three months ended June 30, 2009, a decrease of $3.5 million (37%) from $9.3 million for the three months ended June 30, 2008. This decrease is primarily attributable to a decrease in production taxes of $3.0 million due to a state reduction in the production tax rate beginning January 1, 2009, and a decrease of $0.4 million attributable to lower well treating and water disposal costs compared with the prior year comparable period.

Six Months Ended June 30, 2009 Compared to the Six Months Ended June 30, 2008

Our natural gas revenues were $136.8 million for the six months ended June 30, 2009, a decrease of $10.3 million (7%) from $147.1 million for the six months ended June 30, 2008. The $10.3 million decrease consisted of $16.5 million attributable to decreases in realized natural gas sales prices and $1.0 million of subordinated gas revenues to our investment partnerships, partially offset by $7.2 million attributable to increases in natural gas production volumes.

We had an increase in Appalachian production volumes of 9,069 Mcf/day for the six months ended June 30, 2009 when compared to the prior year comparable period which was principally attributable to the increase in production we received from our Marcellus Shale wells and as wells drilled in the most recent six-month period were connected to gas gathering facilities and transportation pipelines.

Our oil revenues were $5.1 million for the six months ended June 30, 2009, a decrease of $2.9 million (36%) from $8.0 million for the six months ended June 30, 2008. The decrease resulted primarily from a 38% decrease in the average realized sales price of oil ($3.1 million), partially offset by a 4% increase in production volumes.

Our Appalachia production costs were $14.3 million for the six months ended June 30, 2009, an increase of $3.4 million (32%) from $10.9 million for the six months ended June 30, 2008. This increase is principally due to a $1.2 million increase in transportation and compressor costs, a $1.7 million increase in water hauling and disposal costs, and a $0.4 million increase in labor costs associated with an increase in the number of Marcellus Shale wells we drilled from the prior year comparable period.

Our Michigan/Indiana production costs were $13.0 million for the six months ended June 30, 2009, a decrease of $4.4 million (25%) from $17.4 million for the six months ended June 30, 2008. This decrease is primarily attributable to a decrease in production taxes of $3.4 million due to a state reduction in the production tax rate beginning January 1, 2009, and a decrease of $0.8 million attributable to well treating and water disposal compared with the prior year comparable period.

PARTNERSHIP MANAGEMENT

Well Construction and Completion

Drilling Program Results. The number of wells we drill will vary depending on the amount of money we raise through our investment partnerships, the cost of each well, the depth or type of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table shows the number of gross and net development wells we drilled exclusively for us and for our investment partnerships during the three and six months ended June 30, 2009 and 2008. We did not drill any exploratory wells during the three and six months ended June 30, 2009 and 2008.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008

Gross:
Appalachia		21		241		126		491
Michigan/Indiana		13		40		40		86
		34		281		166		577
Net:
Appalachia		20		212		100		430
Michigan/Indiana		10		40		33		86
		30		252		133		516

Our well construction and completion revenues and costs and expenses incurred represent the billings and costs associated with the completion of wells for investment partnerships we sponsor. The following table sets forth information relating to these revenues and the related costs and number of net wells drilled and completed during the periods indicated (dollars in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Average construction and completion:	2009		2008		2009		2008
Revenue per well	$	2,044	$	577	$	1,273	$	527
Cost per well		1,732		502		1,080		458
Gross profit per well	$	312	$	75	$	193	$	69

Gross profit margin	$	9,666	$	15,957	$	26,637	$	29,540

Net wells drilled and completed:
Marcellus Shale		18		38		42		42
Chattanooga Shale		—		—		5		1
Michigan/Indiana		10		—		33		—
Other – shallow		2		174		53		387
		30		212		133		430

Three Months Ended June 30, 2009 Compared to the Three Months Ended June 30, 2008

Our well construction and completion segment margin was $9.7 million for the three months ended June 30, 2009, a decrease of $6.3 million (39%) from $16.0 million for the three months ended June 30, 2008. The decrease of $6.3 million in segment margin due to the decrease in the number of wells drilled ($56.4 million), partially offset by an increase in the gross profit per well ($50.1 million). Since our drilling contracts are on a “cost-plus” basis (typically cost-plus 18%), an increase in our average cost per well also results in a proportionate increase in our average revenue per well which directly affects the number of wells we drill. Our average cost and revenue per well have increased due to a shift from drilling less expensive shallow wells to more expensive deep or horizontal shale wells in Appalachia and in Michigan/Indiana during the three and six months ended June 30, 2009 in comparison to the prior year comparable periods.

Six Months Ended June 30, 2009 Compared to the Six Months Ended June 30, 2008

Our well construction and completion segment margin was $26.6 million for the six months ended June 30, 2009, a decrease of $2.9 million (10%) from $29.5 million for the six months ended June 30, 2008. The decrease in segment margin was due to the decrease in the number of wells drilled ($56.4 million), partially offset by an increase in the gross profit per well ($53.5 million).

Our consolidated balance sheet at June 30, 2009 includes $88.9 million of “liabilities associated with drilling contracts” for funds raised by our investment partnerships that have not been applied to the completion of wells due to the timing of drilling operations, and thus had not been recognized as well construction and completion revenue on our consolidated statements of income. We expect to recognize this amount as revenue during the third quarter of fiscal 2009.

Administration and Oversight

Administration and oversight represents supervision and administrative fees earned for the drilling and subsequent ongoing management of wells for our investment partnerships.

Our administration and oversight fees were $2.6 million for the three months ended June 30, 2009, a decrease of $2.5 million (49%) from $5.1 million for the three months ended June 30, 2008. This decrease principally resulted from $2.6 million associated with fewer wells drilled during the period in comparison to the prior year.

Our administration and oversight fees were $6.5 million for the six months ended June 30, 2009, a decrease of $3.7 million (36%) from $10.2 million for the six months ended June 30, 2008. This decrease resulted from a $3.9 million decrease associated with fewer wells drilled during the period in comparison to the prior year and an increase of $0.2 million from partnership management fees due to an increase in the number of wells we managed for our investment partnerships.

Well Services

Well service revenue and expenses represent the monthly operating fees we charge and the work our service company performs for our investment partnership wells during the drilling and completing phase as well as ongoing maintenance of these wells and other wells in which we serve as operator.

Our well services revenues were $4.8 million for the three months ended June 30, 2009, a decrease of $0.5 million (10%) from $5.3 million for the three months ended June 30, 2008. This decrease was partially attributable to the slowdown in drilling for shallow wells for our investment partnerships of $0.9 million, partially offset by an increase of $0.4 million in well operating revenues for the investment partnership wells put into operation during the twelve months ended June 30, 2009.

Our well services expenses were $2.1 million for the three months ended June 30, 2009, a decrease of $0.6 million (20%) from $2.7 million for the three months ended June 30, 2008. This decrease of $0.6 million is primarily attributable to a decrease in labor costs associated with drilling a large number of shallow wells in prior periods to fewer, but more productive, wells for our investment partnerships during the current period.

Our well services revenues were $9.9 million for the six months ended June 30, 2009, a decrease of $0.2 million (2%) from $10.1 million for the six months ended June 30, 2008. This decrease was partially attributable to the slowdown in drilling for shallow wells for our investment partnerships of $1.0 million, partially offset by an increase of $0.9 million in well operating revenues for the investment partnership wells put into operation during the twelve months ended June 30, 2009.

Our well services expenses were $4.5 million for the six months ended June 30, 2009, a decrease of $0.6 million (10%) from $5.1 million for the six months ended June 30, 2008. The decrease of $0.6 million was primarily attributable to a decrease in labor costs associated with drilling a large number of shallow wells in prior periods to fewer, but more productive, wells for our investment partnerships during the current period.

Gathering

We charge gathering fees to our investment partnership wells that are connected to Laurel Mountain‘s Appalachian gathering systems. On May 31, 2009, Atlas Pipeline contributed its Appalachian gathering systems to Laurel Mountain, a joint venture in which Atlas Pipeline retained a 49% ownership interest (see “Recent Developments”). Under new gas gathering agreements with Laurel Mountain entered into upon formation of the joint venture, we are obligated to pay to Laurel Mountain all of the gathering fees we collect from the partnerships. During the period from January 1, 2009 to May 31, 2009, we were required to remit these gathering fees to Atlas America.

The gathering fee generally ranges from $0.35 per Mcf to the amount of the competitive gathering fee currently defined as 13% of the gross sales price. Pursuant to our new agreements with Laurel Mountain, we must also pay an additional amount equal to the excess of the gathering fees collected from the investment partnerships up to an amount equal to approximately 16% of the natural gas sales price. As a result of our agreements with Laurel Mountain, our Appalachian gathering expenses within our partnership management segment will generally exceed the revenues collected from the investment partnerships by approximately 3%. We also pay our proportionate share of gathering fees based on our percentage interest in the well, which is included in gas and oil production expense.

As a result of our new agreements with Laurel Mountain, our net gathering fee expense in Appalachia was $1.4 million for the three months ended June 30, 2009. This amount represents $4.7 million we received in gathering fees collected from our investment partnerships, less $4.7 million we were obligated to remit as gathering expense plus an additional $1.4 million due to Laurel Mountain calculated as the excess of the gathering fees collected to bring the gathering expense to an amount equal to approximately 16% of the natural gas sales price.

For the six months ended June 30, 2009, we received $9.0 million in gathering fees collected from our investment partnerships and were obligated to remit $10.4 million in gathering expense during the six months ended June 30, 2009.

As part of our Michigan operations , we own a small gas gathering and processing system .. We received $0.4 million and $0.3 million of transportation and natural gas liquid revenues for the three months ended June 30, 2009 and 2008, respectively, and $0.8 million and $0.7 million for the six-month periods ended June 30, 2009 and 2008, respectively.

OTHER COSTS AND EXPENSES

General and Administrative

Three Months Ended June 30, 2009 Compared to the Three Months Ended June 30, 2008

Our general and administrative expenses were $12.3 million for both the three months ended June 30, 2009 and 2008. These expenses include, among other things, salaries and benefits not allocated to a specific segment, partnership syndication activities and other miscellaneous costs of managing our business. We experienced a decrease of $0.7 million in the three months ended June 30, 2009, principally attributable to a decrease in salaries and wages, partially offset by a $0.6 million increase in professional fees related to our anticipated merger with Atlas America (see “Recent Developments”).

Six Months Ended June 30, 2009 Compared to the Six Months Ended June 30, 2008

Our general and administrative expenses were $26.8 million for the six months ended June 30, 2009, an increase of $2.7 million (11%) from $24.1 million for the six months ended June 30, 2008. The increase of $2.7 million was principally attributable to a $1.1 million increase in salaries and wages, a $0.6 million increase in professional fees related to our anticipated merger with Atlas America, a $0.5 million increase in land and leasing costs, and a $0.6 million increase in office operations and legal and accounting fees related to increased regulatory compliance activities and overall growth.

Depletion

Three Months Ended June 30, 2009 Compared to the Three Months Ended June 30, 2008

Depletion expense varies from period to period and is directly affected by changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties. Our depletion (including accretion of our asset retirement obligations) of oil and gas properties as a percentage of oil and gas revenues was 37% for the three months ended June 30, 2009, compared with 28% for the three months ended June 30, 2008. Depletion expense per Mcfe was $2.82 for the three months ended June 30, 2009, an increase of $0.26 (10%) per Mcfe from $2.56 for the three months ended June 30, 2008. Increases in our depletable basis and production volumes caused depletion expense to increase $4.0 million to $26.1 million for the three months ended June 30, 2009 compared with $22.1 million for the three months ended June 30, 2008.

Six Months Ended June 30, 2009 Compared to the Three Months Ended June 30, 2008

Our depletion (including accretion of our asset retirement obligations) of oil and gas properties as a percentage of oil and gas revenues was 37% for the six months ended June 30, 2009, compared with 28% for the six months ended June 30, 2008. Depletion expense per Mcfe was $2.90 for the six months ended June 30, 2009, an increase of $0.36 (14%) per Mcfe from $2.54 for the six months ended June 30, 2008. Increases in our depletable basis and production volumes caused depletion expense to increase $10.0 million to $53.1 million for the six months ended June 30, 2009 compared with $43.1 million for the six months ended June 30, 2008.

The following table shows our depletion expense and depletion expense per Mcfe for our Appalachia and Michigan/Indiana business segments for the three and six months ended June 30, 2009 and 2008 (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Depletion Expense (in thousands):
Appalachia	$	12,159		$	8,582		$	25,261		$	16,398
Michigan/Indiana		13,956			13,502			27,864			26,722
Total		26,115			22,084		$	53,125		$	43,120
Depletion expense as a percent of gas and oil production		37	%		28	%		37	%		28	%
Depletion per Mcfe:
Appalachia	$	3.04		$	2.71		$	3.24		$	2.67
Michigan/Indiana	$	2.66		$	2.48		$	2.65		$	2.47
Total	$	2.82		$	2.56		$	2.90		$	2.54

Interest Expense

Three Months Ended June 30, 2009 Compared to the three Months Ended June 30, 2008

Our interest expense was $15.1 million for the three months ended June 30, 2009, an increase of $0.5 million (4%) compared with $14.6 million for the three months ended June 30, 2008. The increase consists of $0.5 million of higher interest expense associated with our revolving credit facility and a $1.5 million increase in interest expense associated with our senior unsecured notes issued in May 2008, offset by a $1.2 million increase in capitalized interest. The increase in capitalized interest is principally due to higher weighted average borrowings associated with the funding of our acreage expansions and drilling capital expenditures.

Six Months Ended June 30, 2009 Compared to the Six Months Ended June 30, 2008

Our interest expense was $28.1 million for the six months ended June 30, 2009, an increase of $0.2 million (1%) compared with $27.9 million for the six months ended June 30, 2008. This increase is principally attributable to a $7.2 million increase in interest expense associated with our senior unsecured notes issued in May 2008, partially offset by $4.2 million of lower interest expense associated with our revolving credit facility and a $2.5 million increase in capitalized interest. The increase in capitalized interest is principally due to higher weighted average borrowings associated with the funding of our acreage expansions and drilling capital expenditures.

Loss on Asset Sale

Loss on asset sale for both the three months and six months ended June 30, 2009 represents a $4.3 million loss associated with the sale of certain natural gas gathering and processing assets for net proceeds of $10.0 million (see “Recent Developments”).

LIQUIDITY AND CAPITAL RESOURCES

General

We fund our development and production operations with a combination of cash generated by operations, capital raised through investment partnerships, issuance of our common units and senior unsecured notes and use of our revolving credit facility. The following table sets forth our sources and uses of cash (in thousands):

	Six Months Ended
	June 30,
	2009			2008
Net cash provided by operating activities	$	135,741		$	66,194
Net cash used in investing activities		(86,189	)		(135,764	)
Net cash (used in) provided by financing activities		(50,358	)		48,684
Net change in cash and cash equivalents	$	(806	)	$	(20,886	)

We had $4.9 million in cash and cash equivalents at June 30, 2009, as compared to $5.7 million at December 31, 2008. We had a working capital deficit of $70.0 million at June 30, 2009, a favorable decrease of $18.0 million from a working capital deficit of $88.0 million at December 31, 2008. The favorable decrease in our working capital deficit was principally attributable to the following:

a decrease of $8.0 million in liabilities associated with drilling contracts; and

an increase in net current unrealized hedge receivables of $17.2 million; partially offset by

an increase of $2.6 million in accounts payable and accrued well drilling and completion costs;

an increase of $2.1 million in accrued liabilities and interest expense; and

a decrease of $2.6 million in prepaid expenses.

At June 30, 2009, we had $196.0 million available committed capacity under our credit facility, subject to covenant limitations, to fund working capital obligations. On July 16, 2009, we issued $200.0 million of 12.125% senior unsecured notes due 2017 at 98.116% of par value to yield 12.5% at maturity (see “Subsequent Events”). We used the net proceeds of $191.7 million, net underwriting fees of $4.5 million, to repay outstanding borrowings under our revolving credit facility.Under the terms of our credit facility (see “Recent Developments” and “Credit Facility”), the credit facility borrowing base is automatically reduced by 25% of the stated principal amount of any senior unsecured notes offering by us. As such, the borrowing base of our credit facility was reduced by $50.0 million to $600.0 million upon the issuance of the 12.125% Senior Notes.

Our level of liabilities associated with drilling contracts is dependent upon the remaining amount of our drilling obligations at any balance sheet date, which is dependent upon the timing and level of funds raised through our investment partnerships. We are subject to business and operational risks that could adversely affect our cash flow. We may need to supplement our cash generation with proceeds from financing activities, including borrowings under our credit facility and other borrowings, the issuance of additional common units and sales of our assets.

Recent instability in the financial markets, as a result of recession or otherwise, has increased the cost of capital while the availability of funds from those markets has diminished significantly. This may affect our ability to raise capital and reduce the amount of cash available to fund our operations. We rely on our cash flow from operations and our credit facility to execute our growth strategy and to meet our financial commitments and other short-term liquidity needs. We cannot be certain that additional capital will be available to the extent required and on acceptable terms. We believe that we will have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve-month period.

Cash Flows

Cash flows from operating activities. Cash provided by operations is an important source of short-term liquidity for us. It is directly affected by changes in the price of natural gas and oil, interest rates and our ability to raise funds from our drilling investment partnerships. Net cash generated by operating activities increased $69.5 million for the six months ended June 30, 2009 to $135.7 million from cash provided of $66.2 million for the six months ended June 30, 2008, principally as a result of the following:

changes in current assets and liabilities increased operating cash flows by $69.8 million for the six months ended June 30, 2009 compared with the six months ended June 30, 2008;

in May 2009, we received $28.5 million in proceeds from the early settlement of natural gas and oil derivative positions; and

an increase in non-cash items of $4.2 million related to our loss on the sale of our natural gas gathering and processing assets to Laurel Mountain; partially offset by

a decrease of $27.4 million in net income before depreciation, depletion and amortization of $94.8 million for the six months ended June 30, 2009 as compared with the prior year period of $122.2 million, principally due to the decline in natural gas and oil and prices from our production business segments and a decrease of $7.5 million in our partnership management business segment due to the decline in the number of wells we drilled; and

for the six months ended June 30, 2009, we received $2.1 million in proceeds from the settlement of ineffective derivative gains, a decrease of $5.9 million from $8.0 million in proceeds received for the prior year comparable period;

The change in operating assets and liabilities is principally a result of the following:

an increase of $73.5 million in liabilities associated with our drilling contracts. Our level of liabilities associated with drilling contracts is dependent upon the remaining amount of our drilling obligations at any balance sheet date, which is dependent upon the timing and level of funds raised through our investment partnerships;

an increase in cash flows provided by accounts receivable and prepaid expenses of $17.9 million; partially offset by

a decrease in cash flows provided by accounts payable and accrued expenses of $1.4 million; and

a decrease in cash flows provided by accrued well drilling and completion costs of $20.3 million.

Cash flows from investing activities. Cash used in our investing activities decreased $49.6 million for the six months ended June 30, 2009 to $86.2 million from $135.8 million for the six months ended June 30, 2008 primarily due to a $39.3 million decrease in capital expenditures related to the decrease of our share of costs associated with wells drilled compared to the prior year period. We also received $10.0 million in proceeds from the sale of our natural gas gathering and processing assets to Laurel Mountain on June 1, 2009.

Cash flows from financing activities. Cash used in our financing activities was 50.4 million for the six months ended June 30, 2009, compared with cash provided of $48.7 million for the six months ended June 30, 2008. The change between periods was principally the result of the following:

we received proceeds of $407.0 million from the issuance of our senior unsecured notes during the six months ended June 30, 2008, while we had no such issuances during the six months ended June 30, 2009; and

we received $107.7 million from the sale of our Class B member units during the six months ended June 30, 2008, while we had no such sales during the six months ended June 30, 2009; partially offset by

net repayments of credit facility borrowings of $11.0 million during the six months ended June 30, 2009 compared with $380.0 million of net repayments during the prior year comparable period;

we paid $39.5 million in distributions to our unitholders for the six months ended June 30, 2009, a decrease of $33.4 million from $72.9 million paid for the six months ended June 30, 2008;

we paid deferred debt financing costs of $10.1 million during the six months ended June 30, 2008, while no amounts were paid during the current period; and

net monies borrowed from Atlas America increased $4.1 million for the six months ended June 30, 2009, compared to the six months ended June 30, 2008.

Capital Expenditures

Our capital expenditures consisted of maintenance capital expenditures and expansion capital expenditures, as defined below:

maintenance capital expenditures are those capital expenditures we made on an ongoing basis to maintain our capital asset base and our current production volumes at a steady level; and

expansion capital expenditures are those capital expenditures we made to expand our capital asset base for longer than the short-term and include new leasehold interests and the development and exploitation of existing leasehold interests through acquisitions of our investments in our drilling partnerships.

The following table summarizes maintenance and expansion capital expenditures for the periods indicated (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008

Maintenance capital expenditures	$	12,975	$	12,975	$	25,950	$	25,950
Expansion capital expenditures		26,231		67,078		70,463		109,720
Total	$	39,206	$	80,053	$	96,413	$	135,670

During the three months ended June 30, 2009, our capital expenditures related primarily to $23.8 million of investments in our investment partnerships compared with $40.7 million for the three months ended June 30, 2008. We also invested $6.5 million in leasehold acreage and $0.4 million in wells drilled exclusively for our own account for the three months ended June 30, 2009.

During the six months ended June 30, 2009, our capital expenditures related primarily to $51.6 million of investments in our investment partnerships compared with $66.4 million for the six months ended June 30, 2008. We also invested $12.1 million in wells drilled exclusively for our own account and incurred $16.9 million in leasehold costs for the six months ended June 30, 2009. We funded and expect to continue to fund these capital expenditures through cash on hand, cash flows from operations and from amounts available under our credit facility.

The level of capital expenditures we devote to our exploration and production operations depends upon any acquisitions made and the level of funds raised through our investment partnerships. We believe cash flows from operations and amounts available under our credit facility will be adequate to fund our capital expenditures. However, the amount of funds we raise and the level of our capital expenditures will vary in the future depending on market conditions for natural gas and other factors.

We expect to fund our maintenance capital expenditures with cash flow from operations and the temporary use of funds raised in our investment partnerships in the period before we invest these funds, as well as funding our investment capital expenditures and any expansion capital expenditures that we might incur with borrowings under our credit facility and with the temporary use of funds raised in our investment partnerships in the period before we invest the funds.

We continuously evaluate acquisitions of gas and oil assets. In order to make any acquisition, we believe we will be required to access outside capital either through debt or equity placements or through joint venture operations with other energy companies. There can be no assurance that we will be successful in our efforts to obtain outside capital.

Credit Facility

At June 30, 2009, we 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 our oil and gas reserves or is automatically reduced by 25% of the stated principal of any senior unsecured notes we issue. On July 16, 2009, we issued $200.0 million of senior unsecured notes, and the borrowing base was reduced by $50.0 million to $600.0 million (see “Recent Developments”). 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 our consolidated balance sheets. The credit facility is secured by substantially all of our assets and is guaranteed by each of our subsidiaries and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at our option. On April 19, 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 events which constitute an event of default for our 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 us 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 us if an event of default has occurred and is continuing or would occur as a result of such distribution. We were in compliance with these covenants as of June 30, 2009. The credit facility also requires us 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 our credit facility, our ratio of current assets to current liabilities was 1.3 to 1.0 and our ratio of total debt to EBITDA was 2.7 to 1.0 at June 30, 2009.

Shelf Registration Statement

On May 1, 2009, our shelf registration statement was declared effective by the Securities and Exchange Commission. The registration statement permits us to periodically issue up to $500.0 million of equity and debt securities. On July 28, 2009, we filed an additional shelf registration in connection with our July 16, 2009 Senior Notes offering (see “Recent Developments”). The amount, type and timing of any additional offerings will depend upon, among other things, our funding requirements, prevailing market conditions and compliance with our credit facility and unsecured senior note covenants.

CHANGES IN PRICES AND INFLATION

Our revenues, the value of our assets, our ability to obtain bank loans or additional capital on attractive terms and our ability to finance our drilling activities through investment partnerships have been and will continue to be affected by changes in oil and gas prices. Natural gas and oil prices are subject to significant fluctuations that are beyond our ability to control or predict.

Although certain of our costs and expenses are affected by general inflation, inflation has not normally had a significant effect on us. However, inflationary trends may occur if the price of natural gas were to increase since such an increase may increase the demand for acreage and for energy equipment and services, thereby increasing the costs of acquiring or obtaining such equipment and services.

ENVIRONMENTAL REGULATION

To date, compliance with environmental laws and regulations has not had a material impact on our capital expenditures, earnings or competitive position. We cannot assure you that compliance with environmental laws and regulations will not, in the future, materially adversely affect our operations through increased costs of doing business or restrictions on the manner in which we conduct our operations.

CASH DISTRIBUTIONS

We do not have a contractual obligation to make distributions to our unitholders. We distribute our “available cash,” to our unitholders each quarter in accordance with their respective percentage interests. “Available cash” is defined in our operating agreement, and it generally means, for each fiscal quarter:

all cash on hand at the end of the quarter;

less the amount of cash that our board of directors determines in its reasonable discretion is necessary or appropriate to:

	·	provide for the proper conduct of our business (including reserves for future capital expenditures and credit needs);

	·	comply with applicable law, any of our debt instruments, or other agreements; or

provide funds for distributions to our unitholders for any one more of the next four quarters or with respect to our management incentive interests;

plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

All cash distributed to unitholders will be characterized as either operating surplus or capital surplus, as defined in our limited liability company agreement and is subject to different distribution rules. We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We do not anticipate distributing any cash from capital surplus.

Available cash is initially distributed 98% to our common unitholders and 2% to Atlas Energy Management, Inc. These distribution percentages are modified to provide for incentive distributions (any distribution paid to Atlas Energy Management, Inc. in excess of 2% of the aggregate amount of cash being distributed) to be paid to Atlas Energy Management, Inc. if quarterly distributions to the common unitholders exceed specified targets as defined in our limited liability company agreement.

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

OFF-BALANCE SHEET ARRANGEMENTS

As of June 30, 2009, our off-balance sheet arrangements are limited to our 50% share ($8.7 million) of the guarantee of Crown Drilling of Pennsylvania, LLC’s $17.4 million credit arrangement and our letters of credit outstanding of $1.2 million.

FAIR VALUE OF FINANCIAL INSTRUMENTS

We have applied the provisions of SFAS No. 157 to our financial assets and liabilities. SFAS No. 157 establishes a single authoritative definition of a fair value and 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 expands disclosure requirements about items measured at fair value but does not change existing accounting rules governing what can or what must be recognized and reported at fair value in our financial statements. As a result, we will not be required to recognize any new assets or liabilities at fair value.

SFAS No. 157’s hierarchy defines three levels of inputs that may be used to measure fair value:

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

We use the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities. Assets and liabilities that are required to be measured on a recurring basis are our outstanding derivative contracts. All of our derivative contracts are defined as Level 2. Our 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. Our interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model.

Liabilities that are required to be measured at fair value on a nonrecurring basis include asset retirement obligations, or ARO’s, that are defined as Level 3. Estimates of the fair value of ARO’s are based on discounted cash flows using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our credit-adjusted risk-free rate and inflation rates.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of our assets, liabilities, revenues and cost and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates, including those related to the provision for possible losses, goodwill and identifiable intangible assets, and certain accrued liabilities. We base our estimates on historical experience and on various other assumptions that we believe reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. A discussion of our significant accounting policies we have adopted and followed in the preparation of our consolidated financial statements is included within “Notes to Consolidated Financial Statements” in Part I, Item 1, “Financial Statements” in this quarterly report and in our Annual Report on Form 10-K for the year ended December 31, 2008.

RECENTLY ADOPTED FINANCIAL 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. We adopted the requirements of SFAS No. 165 on April 1, 2009 and its adoption did not have a material impact on our financial position or 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. We adopted the requirements of FSP FAS 157-4 on April 1, 2009 and its adoption did not have a material impact on our 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 asset 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. We 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 our 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. We 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 our 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 us). We adopted the requirements of FSP 141(R)-1 on January 1, 2009 and its adoption did not have a material impact on our financial position and results of operations.

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. We adopted the requirements of SFAS No. 161 on January 1, 2009 and it did not have a material impact on our 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-an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 amends Accounting Research Bulletin 51, “Consolidated Financial Statements” (“ARB No. 51”) to establish accounting and reporting standards for the noncontrolling interest (minority 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. 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 noncontrolling 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. We adopted the requirements of SFAS No. 160 on January 1, 2009 and adjusted our presentation of our 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. We adopted the requirements of SFAS No. 141(R) on January 1, 2009 and it did not have a material impact on our 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. We will apply the requirements of SFAS No. 168 to our financial statements for the interim period ending September 30, 2009, and we do not expect it to have a material impact on our financial position or results of operations or related disclosures.

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 us). We will apply the requirements of SFAS No. 167 upon its adoption on January 1, 2010 and we do not expect it to have a material impact on our financial position or results of operations or related disclosures.

MODERNIZATION OF OIL AND GAS REPORTING

In December 2008, the 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:

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.

We will begin complying with the disclosure requirements in our 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. We are currently in the process of evaluating the new requirements.

ITEM 3:

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and oil and gas prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than trading.

General

We are exposed to various market risks, principally changes in commodity prices and fluctuating interest rates. These risks can impact our results of operations, cash flows and financial position. We manage these risks through regular operating and financing activities and periodically use derivative financial instruments such as forward contracts and swap agreements.

Current market conditions elevate our concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us. The counterparties related to our commodity and interest-rate derivative contracts are banking institutions which also participate in our revolving credit facility. The creditworthiness of our counterparties is constantly monitored, and we currently believe them to be financially viable. We are not aware of any inability on the part of our counterparties to perform under our contracts and believe our exposure to non-performance is remote.

Commodity Price Risk

Our major market risk exposure in commodities is fluctuations in the pricing of our gas and oil production. Realized pricing is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production. Pricing for gas and oil production has been volatile and unpredictable for many years. To limit our exposure to changing natural gas prices, we enter into natural gas and oil costless collar, and option contracts. At any point in time, such contracts may include regulated 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. Oil contracts are based on a West Texas Intermediate, or WTI index.

Our risk management objective regarding commodity price risk is to utilize available instruments, including financial derivatives and physical forward contracts, to maximize the value of our production while also reducing our exposure to the volatility of commodity markets. Considering those volumes for which we have entered into financial derivative agreements for the twelve-month period ending June 30, 2010, and current indices, a theoretical 10% upward or downward change in the price of natural gas and crude oil would result in a change in net income of approximately $5.2 million.

We formally document all relationships between derivative instruments and the items being hedged, including the risk management objective and strategy for undertaking the derivative transactions. This includes matching the natural gas and oil futures and options contracts to the forecasted transactions. We assess, both at the inception of the hedge and on an ongoing basis, whether the derivatives are highly effective in offsetting changes in the fair value of hedged items. Historically these contracts have qualified and been designated as cash flow hedges in accordance with SFAS 133, and are recorded at their fair values. Gains or losses on future contracts are determined as the difference between the contract price and a reference price, generally prices on NYMEX or WTI. Changes in fair value are recognized in consolidated equity and recognized within the consolidated statements of income in the month the hedged commodity is sold. If it is determined that a derivative is not highly effective as a hedge or it has ceased to be a highly effective hedge, due to the loss of correlation between changes in reference prices underlying a hedging instrument and actual commodity prices, we will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings.

We recognized gains on settled contracts covering natural gas and oil production of $31.5 million and a loss of $4.9 million for the three months ended June 30, 2009 and 2008, respectively and gains of $47.1 million and $1.6 million for the six months ended June 30, 2009 and 2008, respectively. As the underlying prices and terms in our derivative contracts were consistent with the indices used to sell our natural gas, there were no gains or losses recognized during the three and six months ended June 30, 2009 and 2008 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges.

In May 2009, we received approximately $28.5 million in proceeds from the early settlement of natural gas and oil derivative positions for production periods from 2011 through 2013. In conjunction with the early termination of these derivatives, we 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 our revolving credit facility. The derivative gain recognized upon early termination of these discontinued derivative positions will continue to be reported in accumulated other comprehensive income, and will be reclassified to our consolidated statements of income during the periods which the physical transactions would have affected earnings.

We have a $123.3 million net unrealized gain related to financial derivatives in accumulated other comprehensive loss associated with commodity derivatives 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, we will reclassify $83.0 million of unrealized gains to our 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.

The fair value of the derivatives at June 30, 2009 is a net unrealized derivative asset of $141.9 million, of which our portion is $94.2 million and $47.7 million of unrealized gains have been reallocated to our investment partnerships.

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

Natural Gas Fixed Price Swaps

Production
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset (Liability)
	(MMBtu)		(per MMBtu)		(in thousands) (1)
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

Natural Gas Costless Collars

Production
Period Ending				Average		Fair Value
December 31,	Option Type	Volumes		Floor and Cap		Asset (Liability)
		(MMBtu)		(per MMBtu)		(in thousands) (1)
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			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset (Liability)
	(Bbl)		(per Bbl)		(in thousands) (2)
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				Average		Fair Value
December 31,	Option Type	Volumes		Floor and Cap		Asset (Liability)
		(Bbl)		(per Bbl)		(in thousands) (2)
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.

Interest Rate Risk

At June 30, 2009, we had $456.0 of borrowings outstanding under our revolving credit facility. At June 30, 2009, we 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, we will pay an interest rate of 3.11%, plus the applicable margin as defined under the terms of our revolving credit facility, and will receive LIBOR, plus the applicable margin, on the notional principal amounts. This derivative effectively converts $150.0 million of our floating rate debt under the revolving credit facility to fixed-rate debt.

Holding all other variables constant, including the effect of interest rate derivatives, a hypothetical 100 basis–point, or 1%, change in interest rates would change our consolidated net income by $3.1 million.

At June 30, 2009, the Company had the following interest rate derivatives:

Interest Fixed Rate Swap

				Contract
	Notional			Period Ended	Fair Value
Term	Amount		Option Type	December 31,	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	)

ITEM 4.

CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in Securities and Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our chief executive officer and our chief financial officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our chief executive officer and chief financial officer, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective at the reasonable assurance level at June 30, 2009.

There have been no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially effect, our internal control over financial reporting.

PART II.

OTHER INFORMATION

ITEM 1:

LEGAL PROCEEDINGS

On June 20, 2008, our wholly-owned subsidiary, Atlas America, LLC, was named as a co-defendant in the matter captioned CNX 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 we and another defendant, Wind City Oil & Gas, LLC, interfered with the closing of this assignment on June 6, 2008. We 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).

ITEM 1A:

RISK FACTORS

Our business operations and financial position are subject to various risks. These risks are described elsewhere in this report and in our Form 10-K for the year ended December 31, 2008 and Form 10Q for the three months ended March 31, 2009. The risk factors identified therein have not changed in any material respect, except the additional risk factors added below.

The exchange ratio for the merger is fixed and will not be adjusted in the event of any change in either the price of Atlas America common stock or the price of our common units.

If the merger is completed, each common unit outstanding as of immediately prior to the effective time will be converted into the right to receive 1.16 shares of Atlas America common stock. This exchange ratio was fixed in the merger agreement and will not be adjusted for changes in the market price of either Atlas America common stock or our common units. Changes in the price of Atlas America common stock prior to the effective time will affect the market value of the merger consideration that our unitholders will receive in the merger. Stock price changes may result from a variety of factors (many of which are beyond the control of Atlas America and us), including:

	•	changes in the company’s businesses, operations and prospects;

	•	changes in market assessments of the business, operations and prospects of the company;

	•	market assessments of the likelihood that the merger will be completed, including related considerations regarding regulatory approvals of the merger;

•

interest rates, general market and economic conditions and other factors generally affecting the price of securities; and

•

federal, state and local legislation, governmental regulation and legal developments in the businesses in which we operate.

The price of Atlas America common stock at the closing of the merger may vary from its price on the date the merger agreement was executed. As a result, the market value represented by the exchange ratio will also vary.

There will be material differences between the current rights of our unitholders and the rights they can expect to have as Atlas America stockholders.

Our unitholders will receive Atlas America common stock in the merger and will become Atlas America stockholders. As Atlas America stockholders, their rights as stockholders will be governed by the Atlas America charter and bylaws. In addition, whereas we are currently a Delaware limited liability company, governed by the Delaware Limited Liability Company Act, Atlas America is a Delaware corporation, governed by the Delaware General Corporation Law. As a result, there will be material differences between the current rights of our unitholders and the rights they can expect to have as Atlas America stockholders, as well as differences in how stockholders and unitholders are taxed. For example, our profits flow through us and are taxed once, at the unitholder level, regardless of whether distributions are made to our unitholders. After the merger, profits of the combined company will be subject to tax at the corporation level, and potentially again, if and when distributed to Atlas America stockholders at the stockholder level. In addition, after the merger, the combined company will have a classified board, with directors elected for a three-year term on a staggered basis, whereas all our directors are currently elected every year for an annual term.

The combined company may fail to realize the anticipated cost savings, growth opportunities and synergies and other benefits anticipated from the merger, which could adversely affect the value of Atlas America common stock.

Atlas America and we currently operate as separate public companies. The success of the merger will depend, in part, on our ability to realize the anticipated synergies and growth opportunities from combining the businesses, as well as the projected stand-alone cost savings and revenue growth trends identified by each company. In addition, on a combined basis, we expect to benefit from operational synergies resulting from the consolidation of capabilities and elimination of redundancies as well as greater efficiencies from increased scale. Management also intends to focus on revenue synergies for the combined entity. However, management must successfully combine our businesses in a manner that permits these cost savings and synergies to be realized. In addition, it must achieve the anticipated savings without adversely affecting current revenues and our investments in future growth. If it is not able to successfully achieve these objectives, the anticipated cost savings, revenue growth and synergies may not be realized fully or at all, or may take longer to realize than expected.

The receipt of the merger consideration will be taxable for U.S. federal income tax purposes and our unitholders could recognize tax gain or have tax liability in excess of the merger consideration received.

Our unitholders generally will recognize gain with respect to the exchange of their common units for shares of Atlas America common stock in the merger in an amount equal to the excess of (1) each unitholder’s “amount realized” for U.S. federal income tax purposes, which equals the sum of the fair market value of the shares of Atlas America common stock and any cash received in lieu of fractional shares (including any amounts of cash withheld), plus his or her share of our pre-merger liabilities, over (2) such unitholder’s aggregate adjusted tax basis in his or her common units (including basis attributable to his or her share of our pre-merger liabilities). Unitholders generally will recognize a loss to the extent that the amount of their basis described in clause (2) above exceeds the amount realized described in clause (1) above.

Because the “amount realized” includes the amount of our liabilities allocated to each unitholder immediately prior to the merger, it is possible that the amount of gain unitholders recognize, or even their resulting tax liability, could exceed the fair market value of the shares of Atlas America common stock plus any cash they receive, perhaps by a significant amount. The application of other, complicated tax rules also may give rise to adverse tax consequences to unitholders. Because the tax consequences of the merger to a unitholder will depend on his or her particular factual circumstances and are uncertain in some material respects, unitholders should consult their tax advisors regarding the potential tax consequences of exchanging our common units for shares of Atlas America common stock in the merger.

Our unitholders will be allocated our taxable income and gain through the time of the merger and will not receive any additional distributions attributable to that income.

Our unitholders will be allocated their proportionate share of our taxable income and gain for the period ending at the time of the merger. Unitholders will have to report such income even though they will not receive any additional cash distributions from us attributable to such income. Such income, however, will be included in the tax basis of the units held by unitholders, and thus reduce their gain (or increase their loss) recognized as a result of the merger.

Lawsuits have been filed against us, certain officers and members of our board of directors and Atlas America challenging the merger, and any adverse judgment may prevent the merger from becoming effective or from becoming effective within the expected timeframe.

We, certain officers and members of our board of directors and Atlas America are named as defendants in a consolidated purported class action lawsuit brought by our unitholders in Delaware Chancery Court challenging the proposed merger, seeking, among other things, to enjoin the defendants from consummating the merger on the agreed-upon terms. Plaintiffs initially filed five separate purported class actions, and the Chancery Court issued an order of consolidation on June 15, 2009. 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. Predicting the outcome of this lawsuit is difficult.

One of the conditions to the completion of the merger is that no judgment, order, injunction, decision, opinion or decree issued by a court or other governmental entity that makes the merger illegal or prohibits the consummation of the merger shall be in effect. A preliminary injunction could delay or jeopardize the completion of the merger, and an adverse judgment granting permanent injunctive relief could indefinitely enjoin completion of the merger. An adverse judgment for monetary damages could have a material adverse effect on the operations of the combined company after the merger.

The merger is subject to various closing conditions, and any delay in completing the merger may reduce or eliminate the benefits expected.

The merger is subject to the satisfaction of a number of other conditions beyond the parties’ control that may prevent, delay or otherwise materially adversely affect the completion of the transaction. On May 15, 2009, early termination of the waiting period under the HSR Act was granted. In July 2009, two other conditions to completion of the merger were satisfied. On July 10, 2009, we received the requisite consent from our lenders to amend our credit agreement to permit the merger, and on July 13, 2009, the Atlas America stockholders approved an amendment to the Atlas America charter to increase the number of authorized shares of Atlas America common stock so that Atlas America has sufficient authorized shares to complete the merger. We cannot predict with certainty, however, whether and when any of the other conditions to completion of the merger will be satisfied. Any delay in completing the merger could cause the combined company not to realize, or delay the realization, of some or all of the benefits that the companies expect to achieve from the transaction.

Failure to complete the merger or delays in completing the merger could negatively affect the price of our common units and Atlas America common stock and each company’s future business and operations.

If the merger is not completed for any reason, Atlas America and we may be subject to a number of material risks, including the following:

	•	the individual companies will not realize the benefits expected from the merger, including a potentially enhanced financial and competitive position;

•

the price of the our common units or the Atlas America common stock may decline to the extent that the current market price of these securities reflects a market assumption that the merger will be completed; and

•

some costs relating to the merger must be paid even if the merger is not completed.

The market price of the Atlas America common stock and the results of operations of Atlas America after the merger may be affected by factors different from those affecting us or Atlas America currently.

Our businesses, while similar in many respects, also have some differences, and, accordingly, the results of operations of Atlas America following the merger and the market price of Atlas America common stock following the merger may be affected by factors different from those currently affecting the independent results of operations and market prices of each of Atlas America and us. As a holder of Atlas America common stock following the merger, you will be subject to the risks and liabilities affecting these other businesses, including those of Atlas Pipeline Holdings and Atlas Pipeline, as well as those of ours.

ITEM 6.

EXHIBITS

Exhibit No.		Description

	2.1	Agreement and Plan of Merger dated as of April 27, 2009 among Atlas Energy Resources, LLC, Atlas America, Inc., Atlas Energy Management, Inc. and Merger Sub, as defined therein (5)
	3.1	Amended and Restated Limited Liability Company Agreement of Atlas Energy Resources, LLC (1)
	3.2	Amendment No. 1 to Amended and Restated Operating Agreement of Atlas Energy Resources, LLC (2)
	3.3	Certificate of Formation of Atlas Energy Resources, LLC (3)
	4.1	Form of common unit certificate (included as Exhibit A to the Amended and Restated Limited Liability Company Agreement of Atlas Energy Resources, LLC) (1)
	4.2	Indenture dated as of January 23, 2008 among Atlas Energy Operating Company, LLC, Atlas Energy Finance Corp., as Issuers, the subsidiaries named therein, as Guarantors, and U.S. Bank National Association, as Trustee(9)
	4.3	Form of 10.75% Senior Note due 2018 (included as an exhibit to the Indenture filed as Exhibit 4.2 hereto)
	4.4	Senior Indenture dated July 16, 2009 among Atlas Energy Operating Company, LLC, Atlas Energy Finance Corp., as Issuers, the subsidiaries named therein, as Guarantors, and U.S. Bank National Association, as Trustee(10)
	4.5	First Supplemental Indenture dated July 16, 2009(10)

	4.6		Form of Note for 12.125% Senior Notes due 2017 (contained in Annex A to the First Supplemental Indenture filed as Exhibit 4.5 hereto)
	10.1(a)		Revolving Credit Agreement, dated as of June 29, 2007, among Atlas Energy Operating Company, LLC, its subsidiaries, J.P. Morgan Chase Bank, N.A., as Administrative Agent and the other lenders signatory thereto (2)
	10.1(b)		First Amendment to Credit Agreement, dated as of October 25, 2007 (4)
	10.1(c)		Second Amendment to Credit Agreement dated as of April 9, 2009 (6)
	10.2		Third Amendment to Credit Agreement dated as of July 10, 2009 (11)
	10.3		Management Agreement, dated as of December 18, 2006, among Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC and Atlas Energy Management, Inc (1)
	10.4		Agreement for Services among Atlas America, Inc. and Richard Weber, dated April 5, 2006(3)
	10.5		Amended and Restated Long-Term Incentive Plan (7)
	10.6		ATN Option Agreement dated as of June 1, 2009, by and among APL Laurel Mountain, LLC, Atlas Pipeline Operating Partnership, L.P. and Atlas Energy Resources, LLC(8)
	10.7		Gas Gathering Agreement for Natural Gas on the Legacy Appalachian System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. Specific terms in this exhibit have been redacted, as marked three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
	10.8		Gas Gathering Agreement for Natural Gas on the Expansion Gathering System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. Specific terms in this exhibit have been redacted, as marked three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
	12.1		Ratio of Earnings to Fixed Charges
	31.1		Rule 13(a)-14(a)/15d-14(a) Certification
	31.2		Rule 13(a)-14(a)/15d-14(a) Certification
	32.1		Section 1350 Certification
	32.2		Section 1350 Certification

(1)	Previously filed as an exhibit to our Form 8-K filed December 22, 2006.
(2)	Previously filed as an exhibit to our Form 8-K filed June 29, 2007.
(3)	Previously filed as an exhibit to our registration statement on Form S-1 (Reg. No. 333-136094).
(4)	Previously filed as an exhibit to our Form 8-K filed October 26, 2007.
(5)	Previously filed as an exhibit to our Form 8-K filed April 28, 2009.
(6)	Previously filed as an exhibit to our Form 8-K filed April 17, 2009.
(7)	Previously filed as an exhibit to our Form 10-K for the year ended December 31, 2008 filed March 2, 2009.
(8)	Previously filed as an exhibit to our Form 8-K filed June 5, 2009.
(9)	Previously filed as an exhibit to our Form 8-K filed January 24, 2008.
(10)	Previously filed as an exhibit to our Form 8-K filed July 17, 2009.
(11)	Previously filed as an exhibit to our Form 8-K filed July 24, 2009.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	ATLAS ENERGY RESOURCES, LLC
	(Registrant)

Date: August 10, 2009	By:	/s/ Matthew A. Jones
		Matthew A. Jones
		Chief Financial Officer

Date: August 10, 2009	By:	/s/Sean P. McGrath
		Sean P. McGrath Chief Accounting Officer

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Atlas Energy Resources Inactive 10-Q2009 Q2 Quarterly report

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