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 September 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 November 6, 2009 was -0-.

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT ON FORM 10-Q


		Page
PART I	FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)	3

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

	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2009 and 2008	4

	Consolidated Statement of Owner’s/Members’ Equity for the Nine Months Ended September 30, 2009	5

	Consolidated Statements of Cash Flows for the Nine Months Ended September 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	32

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	53

Item 4.	Controls and Procedures	56

PART II	OTHER INFORMATION

Item 1.	Legal Proceedings	56

Item 1A.	Risk Factors	57

Item 4	Submission of Matters to a Vote of the Securities Holders	58

Item 6.	Exhibits	59

SIGNATURES		61

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)


	September 30, 2009		December 31, 2008
ASSETS
Current assets:
Cash and cash equivalents	$	2,447	$	5,655
Accounts receivable		73,161		69,411
Current portion of derivative receivable from Partnerships		345		3,022
Current portion of derivative asset		84,446		107,766
Prepaid expenses and other		12,698		14,714

Total current assets		173,097		200,568

Property, plant and equipment, net		2,010,163		1,963,891
Other assets, net		26,840		18,403
Long-term derivative asset		40,425		69,451
Intangible assets, net		3,059		3,838
Goodwill, net		35,166		35,166

	$	2,288,750	$	2,291,317

LIABILITIES AND OWNER’S/MEMBERS’ EQUITY
Current liabilities:
Accounts payable	$	86,442	$	74,262
Accrued interest		12,654		19,878
Accrued liabilities		15,889		5,872
Liabilities associated with drilling contracts		16,590		96,883
Accrued well drilling and completion costs		68,055		43,946
Current portion of derivative payable to Partnerships		23,173		34,932
Current portion of derivative liability		5,105		12,829

Total current liabilities		227,908		288,602

Long-term debt		872,455		873,655
Other long-term liabilities		—		6,337
Long-term derivative payable to Partnerships		17,021		22,581
Advances from affiliates		—		1,712
Long-term derivative liability		24,591		10,771
Asset retirement obligations		50,907		48,136

Commitments and contingencies

Owner’s/members’ equity:
Class B members’ interests		—		932,804
Class A member’s interest		—		6,257
Owner’s equity		1,006,227		—
Accumulated other comprehensive income		89,472		100,275

		1,095,699		1,039,336
Non-controlling interest		169		187

Total owner’s/members’ equity		1,095,868		1,039,523

	$	2,288,750	$	2,291,317

See accompanying notes to consolidated financial statements.

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Revenues:
Well construction and completion	$	81,496		$	116,987		$	257,231		$	343,466
Gas and oil production		65,986			81,234			207,908			236,417
Administration and oversight		3,150			5,216			9,644			15,370
Well services		5,012			5,298			14,911			15,362
Gathering		6,098			4,886			16,210			15,151
Other income, net		201			325			280			844

Total revenues		161,943			213,946			506,184			626,610


Costs and expenses:
Well construction and completion		69,138			101,727			218,236			298,666
Gas and oil production		12,127			16,315			39,421			44,601
Well services		2,378			2,753			6,922			7,815
Gathering		7,973			4,625			18,951			14,358
General and administrative		20,573			11,952			47,390			36,030
Depreciation, depletion and amortization		24,563			23,586			79,866			68,344
Loss on asset sale		1,444			—			5,694			—

Total costs and expenses		138,196			160,958			416,480			469,814


Operating income		23,747			52,988			89,704			156,796


Interest expense		(19,162	)		(14,798	)		(47,270	)		(42,666	)


Net income		4,585			38,190			42,434			114,130
Income attributable to non-controlling interests		(14	)		(10	)		(44	)		(48	)

Net income attributable to owner’s/members’ interests	$	4,571		$	38,180		$	42,390		$	114,082


Allocation of net income attributable to owner’s/members’ interests:
Portion allocable to members’ interests (period prior to merger on September 29, 2009)	$	4,521		$	38,180		$	42,340		$	114,082
Portion allocable to owner’s interest (period subsequent to merger on September 29, 2009)		50			—			50			—

	$	4,571		$	38,180		$	42,390		$	114,082


Allocation of net income (loss) attributable to members’ interests:
Class A member’s units	$	90		$	2,417		$	(7,109	)	$	6,836
Class B members’ units		4,431			35,763			49,449			107,246

Net income attributable to members’ interests	$	4,521		$	38,180		$	42,340		$	114,082


Net income attributable to Class B members per unit:
Basic	$	0.07		$	0.56		$	0.77		$	1.71

Diluted	$	0.07		$	0.55		$	0.77		$	1.70

Weighted average Class B members’ units outstanding:
Basic		63,381			63,381			63,381			62,083

Diluted		63,452			63,844			63,405			62,561

See accompanying notes to consolidated financial statements.

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OWNER’S/MEMBERS’ EQUITY

NINE MONTHS ENDED SEPTEMBER 30, 2009

(in thousands, except unit data)

(Unaudited)


	Members’ Equity										Owner’s Equity		Accumulated Other Comprehensive Income			Non- controlling Interest			Total Owner’s/ Members’ Equity
	Class A Members’ Interests					Class B Members’ Interests
	Units		Amount			Units		Amount
Balance, January 1, 2009	1,293,486		$	6,257		63,380,749		$	932,804		$	—	$	100,275		$	187		$	1,039,523
Units issued	10			—		500			(53	)		—		—			—			(53	)
Distributions paid on unissued units under incentive plan	—			—		—			(443	)		—		—			—			(443	)
Distributions paid to members	—			(2,476	)	—			(38,663	)		—		—			—			(41,139	)
Unit-based compensation	—			—		—			3,387			—		—			—			3,387
Distributions to non-controlling interests	—			—		—			—			—		—			(62	)		(62	)
Reversal of management incentive distribution	—			8,024		—			—			—		—			—			8,024
Net income (loss) attributable to members’ interests prior to merger on September 29, 2009	—			(7,109	)	—			49,449			—		—			44			42,384
Net assets contributed by members	(1,293,496	)		(4,696	)	(63,381,249	)		(946,481	)		951,177		—			—			—
Contribution by Parent	—			—		—			—			55,000		—			—			55,000
Net income attributable to owner’s subsequent to merger on September 29, 2009	—			—		—			—			50		—			—			50
Other comprehensive (loss)	—			—		—			—			—		(10,803	)		—			(10,803	)

Balance, September 30, 2009	—		$	—		—		$	—		$	1,006,227	$	89,472		$	169		$	1,095,868

See accompanying notes to consolidated financial statements.

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)


	Nine Months Ended September 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	42,434		$	114,130
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of deferred finance costs		2,897			2,182
Depreciation, depletion and amortization		79,866			68,344
Adjustment to reflect cash impact of derivatives		30,976			10,508
Non-cash compensation expense		3,387			4,021
Equity (income) of unconsolidated subsidiary		(316	)		(171	)
Distributions paid to noncontrolling interests		(62	)		(104	)
Loss on assets sales and dispositions		5,597			(32	)
Changes in operating assets and liabilities:
Accounts receivable and prepaid expenses		(1,001	)		(22,637	)
Accounts payable and accrued expenses		6,550			17,044
Liabilities associated with drilling contracts		(80,293	)		(105,084	)
Liabilities associated with well drilling and completion costs		24,109			24,523
Other operating assets and liabilities		—			11

Net cash provided by operating activities		114,144			112,735

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(130,785	)		(224,970	)
Proceeds from sales of assets		10,289			63
Other		(13	)		(201	)

Net cash used in investing activities		(120,509	)		(225,108	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility		295,000			326,000
Repayments under credit facility		(492,000	)		(604,025	)
Net proceeds from issuance of debt		196,232			407,125
Net proceeds from Class B members’ units issued		—			107,714
Distributions paid to members		(39,452	)		(112,680	)
Contribution from owner		55,000			—
Advances to affiliates		(2,165	)		(7,313	)
Other		(9,458	)		(10,406	)

Net cash provided by financing activities		3,157			106,415


Net change in cash and cash equivalents		(3,208	)		(5,958	)
Cash and cash equivalents, beginning of period		5,655			25,258

Cash and cash equivalents, end of period	$	2,447		$	19,300

See accompanying notes to consolidated financial statements.

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION

Atlas Energy Resources, LLC (the “Company”) is a single-member Delaware limited liability company 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 (the “Partnerships”), in which it coinvests to finance the exploitation and development of its acreage.

On September 29, 2009, the Company completed its merger with Atlas America, Inc. (“Atlas America”) (NASDAQ: ATLS) pursuant to the definitive merger agreement previously executed between the Company and Atlas America on April 27, 2009, with the Company surviving as a wholly-owned subsidiary of Atlas America (the “Merger”). In the Merger, 33.4 million Class B common units of the Company not previously held by Atlas America were exchanged for 38.8 million shares of Atlas America common stock (a ratio of 1.16 shares of Atlas America common stock for each Class B common unit of the Company) and 30.0 million Class B common units held by Atlas America were cancelled. Additionally, Atlas America changed its name to “Atlas Energy, Inc.” (“Atlas Energy”). Prior to the Merger, the Company had 63,381,249 Class B common units and 1,293,496 Class A units outstanding, with Atlas Energy and its affiliates owning 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 Class A units (which continue to remain outstanding after the Merger) were 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. Subsequent to the Merger, net income allocable to the Class A units and management incentive interests owned by Atlas Energy Management, Inc. are combined with and shown as “owner’s equity” in the consolidated financial statements. The Company’s Class B common units are no longer listed on the NYSE and have been deregistered under the Exchange Act.

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 November 9, 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 operations for the three and nine month periods ended September 30, 2009 may not necessarily be indicative of the statements of operations 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.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In addition to matters discussed further within this note, a more thorough discussion of the Company’s significant accounting policies is included in its audited consolidated financial statements and notes thereto in its annual report on Form 10-K for the year ended December 31, 2008.

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Transactions between the Company and Atlas Energy and its affiliates have been identified in the consolidated financial

statements as transactions between affiliates (see Note 5). The non-controlling ownership interest in net income of the Company is reflected as non-controlling interest on the Company’s consolidated statement of operations, and the non-controlling interests in the assets and liabilities of the Company are shown as a separate component of owner’s/members’ equity on the Company’s consolidated balance sheets.

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

As a result of the Merger on September 29, 2009, there are no Class B Member common units outstanding. As such, net income attributable to Class B member units is only presented for the periods through September 29, 2009. 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”), 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 Energy executed a definitive merger agreement (see Note 1). Due to the anticipation of the Merger, the Company suspended distributions to the Class A and Class B members’ interests effective April 1, 2009. 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 were no longer payable to Atlas Energy.

The Company presents net income (loss) per unit by applying the two-class method for master limited partnerships in the calculation of earnings per share. Under this method, the Company must consider whether the incentive distributions represent a participating security when considered in the calculation of earnings per unit. The Company must also consider whether its 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 Company’s limited liability company agreement, undistributed earnings in excess of available cash should not be allocated to the MIIs. The Company believes that its limited liability agreement contractually limits cash distributions to available cash and, therefore, undistributed earnings will not be allocated to the MIIs.

Effective January 1, 2009, the Company was required to determine if any of its share-based payment awards with rights to dividends or dividend equivalents qualify as participating securities. 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 net income per Class B Member unit pursuant to the two-class method. Prior to

the Merger, the Company had a long-term incentive plan that contained previously granted phantom unit awards, which consisted of Class B member units issuable under the terms of the long-term incentive plan (see Note 11) and contained nonforfeitable rights to distribution equivalents of the Company. The participation rights of the phantom unit awards resulted in a non-contingent transfer of value each time the Company declared a distribution or distribution equivalent during the award’s vesting period. As such, the net income utilized in the calculation of net income per Class B member unit was after the allocation of income to the phantom unit awards on a pro-rata basis. The Company’s net income per Class B member computations in its consolidated statement of operations prior to January 1, 2009 have been retroactively adjusted to conform to the current period presentation.

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):


	Period From July 1, 2009 to September 29, 2009			Three Months Ended September 30, 2008			Period From January 1, 2009 to September 29, 2009			Nine Months Ended September 30, 2008
Net income attributable to members’ interests	$	4,521		$	38,180		$	42,340		$	114,082
Income allocable to Class A member’s actual cash incentive distributions reserved⁽¹⁾		—			1,687			(8,024	)		4,588
Income allocable to Class A member’s 2% ownership interest		90			730			915			2,248

Net income attributable to Class A member’s ownership interest		90			2,417			(7,109	)		6,836

Net income attributable to Class B members’ ownership interests		4,431			35,763			49,449			107,246
Less: Net income attributable to participating securities – phantom units⁽²⁾		(50	)		(401	)		(558	)		(1,052	)

Net income utilized in the calculation of net income attributable to Class B members per unit	$	4,381		$	35,362		$	48,891		$	106,194

⁽¹⁾	The amount for the period from January 1, 2009 to September 29, 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 to be no longer payable by the Company to the Managing Member .

⁽²⁾	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):


	Period From July 1, 2009 to September 29, 2009	Three Months Ended September 30, 2008	Period From January 1, 2009 to September 29, 2009	Nine Months Ended September 30, 2008
Weighted average number of Class B members’ units – basic	63,381	63,381	63,381	62,083
Add: effect of dilutive unit incentive awards	71	463	24	478

Weighted average number of Class B members’ units diluted	63,452	63,844	63,405	62,561

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 September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Net income	$	4,585		$	38,190		$	42,434		$	114,130
Income attributable to non-controlling interests		(14	)		(10	)		(44	)		(48	)

Net income attributable to owner’s/members’ interests		4,571			38,180			42,390			114,082
Other comprehensive income (loss):
Unrealized holding gain (loss) on derivative contracts		5,017			282,906			68,298			(25,821	)
Less reclassification adjustment for (gains) losses realized in net income		(34,051	)		27,925			(79,101	)		26,304

Total other comprehensive income (loss)		(29,034	)		310,831			(10,803	)		483

Comprehensive income (loss) attributable to owner’s/members’ interests	$	(24,463	)	$	349,011		$	31,587		$	114,565

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


	September 30, 2009			December 31, 2008
Unrealized gain on commodity derivatives	$	94,170		$	106,117
Unrealized loss on interest rate derivatives		(4,698	)		(5,842	)

	$	89,472		$	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):


	September 30, 2009			December 31, 2008
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,237,331		$	1,214,991
Predevelopment costs		14,750			18,772
Wells and related equipment		970,063			872,128

		2,222,144			2,105,891
Unproved properties		43,279			43,749
Support equipment		8,605			9,527

		2,274,028			2,159,167
Pipelines, processing and compression facilities		29,050			22,541
Rights-of-way		47			149
Land, buildings and improvements		6,689			6,484
Other		7,571			7,827

		2,317,385			2,196,168
Accumulated depreciation, depletion and amortization:		(307,222	)		(232,277	)

	$	2,010,163		$	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 operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

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 nine months ended September 30, 2009 and 2008.

Goodwill

The Company has $35.2 million of goodwill as of September 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. 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. In addition, 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 on a stand-alone basis. 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 nine months ended September 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, lease acquisition 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 September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Weighted average interest rate		8.7	%		4.1	%		7.4	%		4.5	%

Interest capitalized (in thousands)	$	1,619		$	831		$	5,343		$	2,012

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 September 30, 2009 and December 31, 2008 of

$23.7 million and $43.7 million, respectively, which are included in accounts receivable on its consolidated balance sheets.

Recently Adopted Accounting Standards

In August 2009, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2009-05, “Fair Value Measurements and Disclosures (Topic 820) – Measuring Liabilities at Fair Value” (“Update 2009-05”). Update 2009-05 amends subtopic 820-10, “Fair Value Measurements and Disclosures- Overall” and provides clarification for the fair value measurement of liabilities in circumstances where quoted prices for an identical liability in an active market are not available. The amendments also provide clarification for not requiring the reporting entity to include separate inputs or adjustments to other inputs relating to the existence of a restriction that prevents the transfer of a liability when estimating the fair value of a liability. Additionally, these amendments clarify that both the quoted price in an active market for an identical liability at the measurement date and the quoted price for an identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are considered Level 1 fair value measurements. These requirements are effective for financial statements issued after the release of Update 2009-05. The Company adopted the requirements on September 30, 2009 and it did not have a material impact on its financial position, results of operations or related disclosures.

In August 2009, the FASB issued Accounting Standards Update 2009-04, “Accounting for Redeemable Equity Instruments – Amendment to Section 480-10-S99” (“Update 2009-04”). Update 2009-04 updates Section 480-10-S99, “Distinguishing Liabilities from Equity”, to reflect the SEC staff’s views regarding the application of Accounting Series Release No. 268, “Presentation in Financial Statements of ‘Redeemable Preferred Stocks’“ (“ASR No. 268”). ASR No. 268 requires preferred securities that are redeemable for cash or other assets to be classified outside of permanent equity if they are redeemable (1) at a fixed or determinable price on a fixed or determinable date, (2) at the option of the holder, or (3) upon the occurrence of an event that is not solely within the control of the issuer. The Company adopted the requirements of FASB Update 2009-04 on August 1, 2009 and it did not have a material impact on its financial position, results of operations or related disclosures.

In June 2009, the FASB issued Accounting Standards Update 2009-01, “Topic 105- Generally Accepted Accounting Principles Amendments Based on Statements of Financial Accounting Standards No. 168- The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“Update 2009-01”). Update 2009-01 establishes the FASB Accounting Standards Codification (“ASC”) as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The ASC supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following the ASC, 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 ASC. ASC 105 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. Entities are not required to include specific references to the ASC in their financial statements and, therefore, the Company has removed all previous references to FASB authoritative guidance and describes its accounting policies using a “plain English” approach. The Company adopted the requirements of Update 2009-01 to its financial statements on September 30, 2009 and it did not have a material impact to the Company’s financial statement disclosures.

In May 2009, the FASB issued ASC 855-10, “Subsequent Events” (“ASC 855-10”). ASC 855-10 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. The provisions require 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. ASC 855-10 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. The Company adopted the requirements of this standard on June 30, 2009 and it did not have a material impact to its financial position or results of operations or related disclosures. The adoption of these provisions does not change the Company’s current practices with respect to evaluating, recording and disclosing subsequent events.

estimating fair value when the market activity for an asset has declined significantly. ASC 820-10-65-4 also require an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. ASC 820-10-65-4 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 ASC 820-10-65-4 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 ASC 320-10-65-1, “Recognition and Presentation of Other-Than-Temporary Impairments” (“ASC 320-10-65-1”), which changes previously existing guidance for determining whether an impairment is other than temporary for debt securities. ASC 320-10-65-1 replaces the previously existing requirement that an entity’s management assess if 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. ASC 320-10-65-1 also requires 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. ASC 320-10-65-1 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 these requirements 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 ASC 825-10-65-1, “Interim Disclosures about Fair Value of Financial Instruments” (“ASC 825-10-65-1”), which requires 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. ASC 825-10-65-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted these requirements 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 ASC 805-20-30-23, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“ASC 805-20-30-23”), which 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 previous requirements. ASC 805-20-30-23 eliminates the requirement to disclose an estimate of the range of outcomes of recognized contingencies at the acquisition date. ASC 805-20-30-23 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 on January 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

In June 2008, the FASB issued ASC 260-10-45-61A, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“ASC 260-10-45-61A”). ASC 260-10-45-61A applies to the calculation of earnings per share (“EPS”) described in previous guidance, for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain non-forfeitable 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. ASC 260-10-45-61A is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption was prohibited. The Company adopted the requirements on January 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

expected cash flows used to measure the fair value of the asset. The Company adopted the requirements of ASC 350-30-65-1 on January 1, 2009 and its adoption did not have a material impact on its financial position and results of operations.

In March 2008, the FASB issued ASC 260-10-55-103 through 55-110, “Application of the Two-Class Method” (“ASC 260-10-55-103”), which 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. ASC 260-10-55-103 considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. The Company’s adoption of ASC 260-10-55-103 on January 1, 2009 impacted its presentation of net income (loss) per common limited partner unit as the Company previously presented net income (loss) per common limited partner unit as though all earnings were distributed each quarterly period (see “—Net Income (Loss) Per Common Unit”). The Company adopted the requirements of ASC 260-10-55-103 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 ASC 815-10-50-1, “Disclosures about Derivative Instruments and Hedging Activities” (“ASC 815-10-50-1”), to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for 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 this section of ASC 815-10-50-1 on January 1, 2009 and it did not have a material impact on its financial position or results of operations (see Note 10).

In December 2007, the FASB issued ASC 810-10-65-1, “Non-controlling Interests in Consolidated Financial Statements” (“ASC 810-10-65-1”). ASC 810-10-65-1 establishes 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. It 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, ASC 810-10-65-1 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 and adjust its remaining investment, if any, at fair value. The Company adopted the requirements of ASC 810-10-65-1on 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 these provisions.

In December 2007, the FASB issued ASC 805, “Business Combinations” (“ASC 805”). ASC 805 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. ASC 805 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, it 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 these requirements on January 1, 2009 and it did not have a material impact on its financial position and results of operations.

Recently Issued Accounting Standards

interim periods within those fiscal years for arrangements outstanding as of the beginning of those years, with retrospective application required for such arrangements that meet the criteria. These requirements are also effective for arrangements entered into on (not outstanding) or after the beginning of the first reporting period that begins on or after June 15, 2009. The Company will apply these requirements 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.

In June 2009, the FASB issued ASC 810-10-25-20 through 25-59, “Consolidation of Variable Interest Entities” (“ASC 810-10-25-20”), which 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. ASC 810-10-25-20 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. These requirements are 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 is currently evaluating the impact of these requirements 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):


	September 30, 2009		December 31, 2008
Deferred finance costs, net of accumulated amortization of $8,428 and $5,531 at September 30, 2009 and December 31, 2008, respectively	$	20,652	$	15,018
Long-term derivative receivable from Partnerships		4,740		2,719
Other		1,448		666

	$	26,840	$	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. 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 $0.2 million and $0.3 million for the three months ended September 30, 2009 and 2008, respectively, and $0.8 million and $0.9 million for the nine months ended September 30, 2009 and 2008, respectively. The aggregate estimated annual amortization expense the remainder of 2009, and for each of the next five calendar years is as follows: 2009—$0.2 million; 2010-2011—$1.0 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):


	September 30, 2009			December 31, 2008
Management and operating contracts	$	14,343		$	14,343
Non-compete agreement		890			890

Total costs		15,233			15,233
Accumulated amortization		(12,174	)		(11,395	)

	$	3,059		$	3,838

NOTE 4—ASSET RETIREMENT OBLIGATIONS

The Company recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Company also considers the 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 its oil and gas

properties, the Company has determined that there are no other material retirement obligations associated with tangible long-lived assets.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Asset retirement obligations, beginning of period	$	50,142		$	45,334		$	48,136		$	42,358
Liabilities incurred		125			975			721			2,615
Liabilities settled		(113	)		(36	)		(198	)		(38	)
Accretion expense		753			687			2,248			2,025

Asset retirement obligations, end of period	$	50,907		$	46,960		$	50,907		$	46,960

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

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 Energy. Atlas Energy 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 operations. The employees supporting these Company operations are employees of Atlas Energy. 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 Energy’s cash management program. Any transaction performed by Atlas Energy 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.

On September 30, 2009, Atlas Energy contributed $55.0 million to the Company. The proceeds were used to reduce outstanding borrowings under the Company’s revolving credit facility.

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 parent company, Atlas Energy. 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 $1.4 million and $5.7 million, which is recorded as “Loss on asset sale” on its consolidated statements of operations for the three and nine months ended September 30, 2009, respectively. 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 agreements contain additional provisions which define certain obligations and options of each party to build and connect newly drilled wells to any Laurel Mountain gathering system.

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

Fair Value of Derivative Instruments:


Derivatives in Cash Flow Hedging Relationships	Asset Derivatives					Liability Derivatives
		Fair Value					Fair Value
	Balance Sheet Location	September 30, 2009		December 31, 2008		Balance Sheet Location	September 30, 2009			December 31, 2008
		(in thousands)					(in thousands)
Commodity contracts:	Current assets	$	84,446	$	107,766	Current liabilities	$	(1,273	)	$	(9,348	)
	Long-term assets		40,425		69,451	Long-term liabilities		(23,725	)		(8,410	)

			124,871		177,217			(24,998	)		(17,758	)

Interest rate contracts:	Current assets		—		—	Current liabilities		(3,832	)		(3,481	)
	Long-term assets		—		—	Long-term liabilities		(866	)		(2,361	)

			—		—			(4,698	)		(5,842	)


Total derivatives		$	124,871	$	177,217		$	(29,696	)	$	(23,600	)

Effects of Derivative Instruments on Consolidated Statements of Operations for the three months and nine months ended September 30, 2009 and 2008 is as follows:


Derivatives in Cash Flow Hedging Relationships	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) For the Three Months Ended						Location of Gain/(Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) For the Three Months Ended
	September 30, 2009			September 30, 2008				September 30, 2009			September 30, 2008
	(in thousands)							(in thousands)
Commodity contracts	$	5,983		$	284,075		Gas and oil production	$	35,134		$	(27,613	)
Interest rate contracts		(966	)		(1,169	)	Interest expense		(1,083	)		(312	)


	$	5,017		$	282,906			$	34,051		$	(27,925	)


Derivatives in Cash Flow Hedging Relationships	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) For the Nine Months Ended						Location of Gain/(Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) For the Nine Months Ended
	September 30, 2009			September 30, 2008				September 30, 2009			September 30, 2008
	(in thousands)							(in thousands)
Commodity contracts	$	70,269		$	(26,447	)	Gas and oil production	$	82,216		$	(25,969	)
Interest rate contracts		(1,971	)		626		Interest expense		(3,115	)		(335	)


	$	68,298		$	(25,821	)		$	79,101		$	(26,304	)

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 operations in the same periods in which the hedged production revenues would have been recognized in earnings.

The Company has a $94.2 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 September 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 $60.1 million of unrealized gains to its consolidated statements of operations over the next twelve-month period as these contracts settle and $34.1 million of unrealized gains will be reclassified in later periods.

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

Natural Gas Fixed Price Swaps


Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset⁽²⁾
	(MMBtu)⁽¹⁾	(per MMBtu)⁽¹⁾		(in thousands)
2009	10,340,000	$	8.242	$	36,116
2010	31,880,000	$	7.708		47,682
2011	20,720,000	$	7.040		3,403
2012	19,680,000	$	7.223		4,119
2013	13,260,000	$	7.082		235

				$	91,555

Natural Gas Costless Collars


Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset/(Liability)⁽²⁾
		(MMBtu)⁽¹⁾	(per MMBtu)⁽¹⁾		(in thousands)
2009	Puts purchased	60,000	$	11.000	$	370
2009	Calls sold	60,000	$	15.350		—
2010	Puts purchased	3,360,000	$	7.839		6,021
2010	Calls sold	3,360,000	$	9.007		—
2011	Puts purchased	9,540,000	$	6.523		808
2011	Calls sold	9,540,000	$	7.666		—
2012	Puts purchased	4,020,000	$	6.514		—
2012	Calls sold	4,020,000	$	7.718		(249	)
2013	Puts purchased	5,340,000	$	6.516		—
2013	Calls sold	5,340,000	$	7.811		(579	)

					$	6,371

Crude Oil Fixed Price Swaps


Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset/(Liability)⁽³⁾
	(Bbl)⁽¹⁾	(per Bbl)⁽¹⁾		(in thousands)
2009	14,600	$	99.319	$	424
2010	48,900	$	97.400		1,134
2011	42,600	$	77.460		11
2012	33,500	$	76.855		(74	)
2013	10,000	$	77.360		(29	)

				$	1,466

Crude Oil Costless Collars


Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset/(Liability)⁽³⁾
		(Bbl)⁽¹⁾	(per Bbl)⁽¹⁾		(in thousands)
2009	Puts purchased	9,000	$	85.000	$	134
2009	Calls sold	9,000	$	116.561		—
2010	Puts purchased	31,000	$	85.000		468
2010	Calls sold	31,000	$	112.918		—
2011	Puts purchased	27,000	$	67.223		—
2011	Calls sold	27,000	$	89.436		(27	)
2012	Puts purchased	21,500	$	65.506		—
2012	Calls sold	21,500	$	91.448		(70	)
2013	Puts purchased	6,000	$	65.358		—
2013	Calls sold	6,000	$	93.442		(24	)

					$	481

				Total net asset	$	99,873

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

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

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

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 September 30, 2009 and December 31, 2008, net unrealized derivative liabilities of $35.1 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):


	September 30, 2009			December 31, 2008
Current portion of derivative receivable from Partnerships	$	345		$	3,022
Other assets – long-term		4,740			2,719
Current portion of derivative payable to Partnerships		(23,173	)		(34,932	)
Long-term derivative payable to Partnerships		(17,021	)		(22,581	)

	$	(35,109	)	$	(51,772	)

Interest Rate Risk Hedging Program

At September 30, 2009, the Company had $270.0 million of borrowings under its revolving credit facility (see Note 9). At September 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 prevailing accounting standards.

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

Interest Fixed Rate Swap


Term	Notional Amount	Option Type	Contract Period Ended December 31,	Fair Value (Liability)
				(in thousands)
January 2008 – January 2011	$150,000,000	Pay 3.11% - Receive LIBOR	2009	$	(1,009	)
			2010		(3,495	)
			2011		(194	)

			Total net liability	$	(4,698	)

NOTE 7 – FAIR VALUE OF FINANCIAL INSTRUMENTS

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

Level 1– 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 September 30, 2009 and December 31, 2008 is as follows (in thousands):


	September 30, 2009						December 31, 2008
	Level 2			Total			Level 2			Total
Commodity-based derivatives	$	99,873		$	99,873		$	159,459		$	159,459
Interest rate swap-based derivatives		(4,698	)		(4,698	)		(5,842	)		(5,842	)

Total	$	95,175		$	95,175		$	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).

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


	Three Months Ended September 30, 2009				Nine Months Ended September 30, 2009
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	125	$	125	$	721	$	721

Total	$	125	$	125	$	721	$	721

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 benefit of the investor partners for an amount equal to at least 10% of their subscriptions determined on a cumulative basis, in accordance with the terms of the partnership agreements. For the three and nine months ended September 30, 2009, $1.4 million and $2.3 million, 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 nine months ended September 30, 2008 with regard to the Partnerships.

Atlas Energy 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 September 30, 2009, the Company is a guarantor of 50.0% ($11.4 million) of Crown Drilling of Pennsylvania, LLC’s $22.9 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 Atlas America, LLC 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, LLC 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, etal., C.A. No. 4553-VCN (Del. Ch. filed 4/30/09);

Operating Engineers Constructions Industry and Miscellaneous Pension Fund v. Atlas America, Inc., etal., C.A.

No. 4589-VCN (Del. Ch. filed 5/13/09);

•

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

•

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

•

Montgomery County Employees’ Retirement Fund v. Atlas Energy Resources, LLC, etal., 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 they are not pursuing their motion for preliminary injunction and requested that the preliminary injunction hearing date be removed from the court’s calendar. Around that time, plaintiffs advised counsel for the defendants that they intended to continue to pursue the case after the Merger as a claim for monetary damages. The Chancery Court approved the briefing schedule in mid-September and the defendants filed a brief in support of their motion to dismiss on October 16, 2009. 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. 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):


	September 30, 2009		December 31, 2008
Revolving credit facility	$	270,000	$	467,000
10.75% Senior Unsecured Notes – due 2018		406,105		406,655
12.125% Senior Unsecured Notes – Due 2017		196,350		—

		872,455		873,655
Less current maturities		—		—

	$	872,455	$	873,655

Revolving Credit Facility. At September 30, 2009, the Company had a credit facility with a syndicate of banks with a borrowing base of $600.0 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 Notes issued by the Company. 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 September 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. The applicable margin on Eurodollar Loans ranges between 200 and 300 basis points and the applicable margin for base rate loans ranges between 112.5 and 212.5 basis points based on outstanding borrowings. 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. At September 30, 2009 and December 31, 2008, the weighted average interest rate on the credit facility’s outstanding borrowings was 2.7% and 2.8%, respectively.

On July 10, 2009, the Company’s credit agreement was amended to, among other things, permit the Merger with Atlas Energy and to allow the Company to distribute (a) amounts equal to Atlas Energy’s income tax liability attributable to the Company’s net income at the highest marginal rate and (b) 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 distribution in the next year.

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 Company was in compliance with these covenants as of September 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 2.1 to 1.0 and its ratio of total debt to EBITDA was 3.0 to 1.0 at September 30, 2009.

Senior Unsecured Notes. At September 30, 2009, the Company had $400.0 million principal amount outstanding of 10.75% Senior Unsecured Notes (“10.75% Senior Notes”) due on February 1, 2018 and $200.0 million principal amount outstanding of 12.125% Senior Unsecured Notes due August 1, 2017 (“12.125% Senior Notes”; collectively, the “Senior Notes”). The 12.125% Senior Notes were issued on July 13, 2009 in a public offering at a price of 98.116% to par value for a yield 12.5% at maturity. Net proceeds from the offering were used to reduce outstanding borrowings under the Company’s revolving credit facility. Interest on the Senior Notes in the aggregate is payable semi-annually in arrears on February 1 and August 1 of each year. The 10.75% Senior Notes are redeemable on or after February 1, 2013, and the 12.125% Senior Notes are redeemable on or after August 1, 2013, at specified redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, before February 1, 2011 for the 10.75% Notes and before August 1, 2012 for the 12.125% Senior Notes, 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 stated redemption prices (101% of their principal amount for the 10.75% Senior Notes and 112.125% of their principal amount for the 12.125% Senior Notes), 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 indentures governing the Senior Notes contain 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 these covenants as of September 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.

Operating segment data for the periods indicated are as follows (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Operating segment data (in thousands):
Gas and oil production
Appalachia:
Revenues	$	25,988	$	34,297	$	88,138	$	97,193
Costs and expenses		5,995		7,541		20,311		18,422

Segment profit	$	19,993	$	26,756	$	67,827	$	78,771


Michigan/Indiana:
Revenues	$	39,998	$	46,937	$	119,770	$	139,224
Costs and expenses		6,132		8,774		19,110		26,179

Segment profit	$	33,866	$	38,163	$	100,660	$	113,045


Partnership management
Revenues	$	94,659	$	131,496	$	295,170	$	386,796
Costs and expenses		79,261		108,982		243,520		320,523

Segment profit	$	15,398	$	22,514	$	51,650	$	66,273


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Reconciliation of segment profit to net income
Segment profit
Gas and oil production-Appalachia	$	19,993		$	26,756		$	67,827		$	78,771
Gas and oil production-Michigan/Indiana		33,866			38,163			100,660			113,045
Partnership management		15,398			22,514			51,650			66,273

Total segment profit		69,257			87,433			220,137			258,089
General and administrative expense		(20,573	)		(11,952	)		(47,390	)		(36,030	)
Depreciation, depletion and amortization		(24,563	)		(23,586	)		(79,866	)		(68,344	)
Loss on asset sale		(1,444	)		—			(5,694	)		—
Interest expense⁽¹⁾		(19,162	)		(14,798	)		(47,270	)		(42,666	)
Other – net⁽²⁾		1,070			1,093			2,517			3,081

Net income	$	4,585		$	38,190		$	42,434		$	114,130

⁽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 Michigan/Indiana well services and transportation of $0.9 and $0.8 million for the three months ended September 30, 2009 and 2008, respectively, and $2.2 million for both the nine months ended September 30, 2009 and 2008 do not meet the quantitative threshold for reporting segment information. These amounts have been included in “Other – net” above.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Capital expenditures:
Gas and oil production
Appalachia	$	21,421	$	68,349	$	90,412	$	167,970
Michigan		3,517		19,769		14,913		53,962
Partnership management		8,886		1,047		24,493		2,247
Corporate		548		135		967		791

	$	34,372	$	89,300	$	130,785	$	224,970


					September 30, 2009		December 31, 2008
Balance sheets:
Goodwill
Gas and oil production – Appalachia					$	21,527	$	21,527
Partnership management						13,639		13,639

					$	35,166	$	35,166

Total assets:
Gas and oil production
Appalachia					$	833,114	$	794,521
Michigan/Indiana						1,368,061		1,416,042
Partnership management						56,487		53,031
Corporate						31,088		27,723

					$	2,288,750	$	2,291,317

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Revenues:
Gas & oil production – Appalachia	$	25,988	$	34,297	$	88,138	$	97,193
Gas & oil production – Michigan/Indiana		39,998		46,937		119,770		139,224
Partnership management		94,659		131,496		295,170		386,796
Other		1,298		1,216		3,106		3,397

	$	161,943	$	213,946	$	506,184	$	626,610

NOTE 11 – BENEFIT PLANS

Prior to the Merger on September 29, 2009, the Company had a Long-Term Incentive Plan (“LTIP”), which provided performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners. Subsequent to the Merger, Atlas Energy assumed the Company’s LTIP pursuant to the Atlas Energy, Inc. Assumed Long-Term Incentive Plan (“Assumed LTIP”) and each outstanding unit option, phantom unit and restricted unit granted under the LTIP was converted to an equivalent stock option, phantom share or restricted share of Atlas Energy at a ratio of 1.0 unit to 1.16 common shares.

Following the consummation of the Merger, the LTIP is no longer in existence and the Assumed LTIP applies to all awards outstanding at the time of the Merger. All of the terms related to the previous LTIP remain unchanged, except for the conversion of the number of options and other grants and their related exercise price, and no new grant awards will be issued pursuant to the Assumed LTIP. Awards granted after 2006 vest 25% after three years and 100% upon the four-year anniversary of grant, except for awards 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 grant or phantom stock grant entitles a grantee to receive a common share of Atlas Energy upon vesting of the grant or, at the discretion of Atlas Energy’s compensation committee, cash equivalent to the then fair market value of an Atlas Energy common share.

Restricted Stock and Phantom Units. Under the LTIP, 28,523 restricted and phantom units were awarded during the period from January 1, 2009 to September 29, 2009. During the nine months ended September 30, 2008, 35,793 restricted units were awarded under the LTIP. The fair value of the grants was based on the closing unit 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 and phantom units for the period from January 1, 2009 to September 29, 2009 and lists the number and average grant date fair value of Company units underlying the converted Atlas Energy phantom and restricted stock:


	Units		Weighted Average Grant Date Fair Value
Non-vested units outstanding at December 31, 2008	768,829		$	23.86
Granted	28,523			16.48
Vested	(13,073	)		21.70
Forfeited	(46,000	)		31.12

Non-vested units outstanding at September 29, 2009	738,279		$	23.16

Converted non-vested Atlas Energy phantom and restricted stock outstanding at September 29, 2009	856,404		$	19.97

Unit Options. There were 5,000 unit options granted during the period from January 1, 2009 to September 29, 2009. During the nine months ended September 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 period from January 1, 2009 to September 29, 2009 and lists the number of Company units and weighted average exercise price underlying the converted Atlas Energy stock options:


	Units		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding at December 31, 2008	1,902,902		$	24.17
Granted	5,000			25.78
Exercised	—			—
Forfeited or expired	(123,300	)		31.96

Outstanding at September 29, 2009	1,784,602		$	23.64	7.15	$	11,692,914

Converted non-vested Atlas Energy stock options outstanding at September 29, 2009	2,070,138		$	20.38	7.15

The following table summarizes information about unit options outstanding and exercisable at September 29, 2009 and lists the number of Atlas Energy common shares and weighted average exercise price underlying the converted Atlas Energy stock options:


	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 – 25.18	1,635,302	7.1	$	22.60	280,314	$	21.00
$30.24 – 35.00	141,800	7.8	$	34.78	—		—
$37.79 and above	7,500	8.3	$	39.79	—		—

	1,784,602	7.15	$	23.64	280,314	$	21.00

Converted Atlas Energy stock options	2,070,138	7.15	$	20.38	325,164	$	18.10

The Company recognized $.4 million and $1.4 million in compensation expense related to restricted stock units, phantom units and unit options for the three months ended September 30, 2009 and 2008, respectively. The Company recognized $3.4 million and $4.0 million in related compensation expense for the nine months ended September 30, 2009 and 2008, respectively. The Company paid $-0- and $0.4 million with respect to its LTIP distribution equivalent rights (“DER”) for the three months ended September 30, 2009 and 2008, respectively. The Company paid $0.4 million and $1.0 million with respect to its LTIP DER’s for the nine months ended September 29, 2009 and 2008, respectively. These amounts were recorded as a reduction of members’ equity on the Company’s consolidated balance sheet during the respective period.

NOTE 12 – CASH DISTRIBUTIONS

Prior to the Merger, the Company was 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. Effective April 1, 2009, the Company suspended further distributions due to the announcement of its intent to merge with Atlas Energy (see Note 2).

NOTE 13 – SUBSEQUENT EVENTS

Credit Agreement Amendment

Effective October 14, 2009, in conjunction with a regularly scheduled borrowing base redetermination, the Company’s borrowing base under its revolving credit facility of $575.0 million was approved.

Natural Gas Derivative Contracts

In October 2009, the Company entered into the following natural gas derivative contracts:


Production Period Ending December 31,	Volumes	Average Fixed Price
	(MMBtu)	(per MMBtu)
2010	5,520,000	$	6.15
2011	1,260,000	$	6.86

Natural Gas Costless Collars


Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap
		(MMBtu)	(per MMBtu)
2011	Puts purchased	3,300,000	$	6.23
2011	Calls sold	3,300,000	$	7.53
2012	Puts purchased	5,760,000	$	6.51
2012	Calls sold	5,760,000	$	7.71
2013	Puts purchased	5,400,000	$	6.65
2013	Calls sold	5,400,000	$	7.77

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 single-member Delaware limited liability company 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.

KEY PERFORMANCE INDICATORS

In our Appalachia gas and oil operations:

•

we own direct and indirect working interests in approximately 8,658 gross productive gas and oil wells;

•

we own overriding royalty interests in approximately 624 gross productive gas and oil wells;

•

our net daily production was 41.3 million cubic feet equivalents per day (“Mmcfed”) and 42.4 Mmcfed for the three and nine months ended September 30, 2009, respectively;

•

we lease approximately 919,200 gross (873,600 net) acres, of which approximately 606,800 gross (599,800 net) acres are undeveloped;

•

included in our undeveloped acreage are approximately 215,600 Marcellus acres in Pennsylvania, New York and West Virginia, of which approximately 160,400 acres are located in our core Marcellus Shale position in southwestern Pennsylvania;

•

we drilled 153 gross wells (including 73 Marcellus Shale wells), during the nine months ended September 30, 2009, on our own behalf and that of our investment partnerships;

•

we have drilled 184 vertical and 15 horizontal gross Marcellus Shale wells to date, of which 159 vertical and 7 horizontal Marcellus Shale wells have been successfully completed and have been turned on-line and are producing;

•

of the 159 vertical completed Marcellus Shale wells we drilled to date, we have utilized the multi-frac technique on 68 wells, with successful results;

•

we turned on-line 274 gross wells during the nine months ended September 30, 2009; and

•

we drilled and participated in 25 horizontal wells in the Chattanooga Shale of eastern Tennessee to date. We have leased approximately 130,700 gross acres (128,200 net undeveloped) in this shale area.

In our Michigan gas and oil operations:

•

we own direct and indirect working interests in approximately 2,498 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 57.8 Mmcfed and 58.3 Mmcfed for the three and nine months ended September 30, 2009, respectively;

•

we have leased approximately 345,000 gross (271,900 net) acres, of which approximately 34,900 gross (26,400 net) acres are undeveloped; and

•

we drilled 32 gross wells (27 net wells) during the nine months ended September 30, 2009.

In our Indiana gas and oil operations:

•

we own direct and indirect working interests in approximately 20 gross producing gas and oil wells;

•

our net daily production was 0.8 Mmcfed and 0.4 Mmcfed for the three and nine months ended September 30, 2009, respectively;

•

we have leased approximately 249,600 gross (122,800 net) acres, of which approximately 242,600 gross (117,200 net) acres are undeveloped; and

•

we drilled 19 gross wells (17 net wells) during the nine months ended September 30, 2009.

In our partnership management business:

•

our investment partnership business includes equity interests in 96 investment partnerships and a registered broker-dealer which acts as the dealer manager of our investment partnership offerings.

•

during 2009, we have raised $122.6 million in investor funds for Atlas Resources Public #18B-2009(B) L.P., and have begun raising funds for our most recent investment partnership, Atlas Resources Public #18-2009(C) L.P.in which we have registered subscriptions of up to $275.7 million^(1).

•

⁽¹⁾Atlas Energy’s subsidiary serves as managing general partner of the Partnership. A written prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended, may be obtained from Anthem Securities, Inc. (a subsidiary of Atlas Energy), 1550 Coraopolis Heights Rd. – 3^rd Floor, Moon Township, PA 15108.

RECENT DEVELOPMENTS

Merger with Atlas Energy, Inc.

On September 29, 2009, we completed our merger with Atlas America, Inc. (“Atlas America”) (NASDAQ: ATLS) pursuant to the definitive merger agreement executed between us and Atlas America on April 27, 2009, with us surviving as a wholly-owned subsidiary of Atlas America (the “Merger”). In the Merger, 33.4 million of our Class B common units not previously held by Atlas America were exchanged for 38.8 million shares of Atlas America common stock (a ratio of 1.16 shares of Atlas America common stock for each Class B common unit) and 30.0 million Class B common units held by Atlas America were cancelled. Additionally, Atlas America changed its name to “Atlas Energy, Inc.” (“Atlas Energy”). Prior to the Merger, we had 63,381,249 Class B common units and 1,293,496 Class A units outstanding, with Atlas Energy and its affiliates owning 29,952,996 of our Class B common units and all of our Class A units outstanding, representing a 48.3% ownership interest in us. The Class A units were entitled to 2% of all our quarterly cash distributions without any requirement for future capital contributions by the holder of such Class A units.

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

On September 7, 2009, we began fundraising for Atlas Resources Public #18-2008 Drilling Program, in which we have the capacity to raise approximately $275.7 million, representing the third partnership (Atlas Resources Public #18-2009(C) L.P.) in the program. During the first nine months of 2009, we raised $122.6 million for our second partnership (Atlas Resources Public #18-2009 (B) L.P.)⁽¹⁾ Atlas Resources, LLC, our wholly-owned subsidiary, serves as the managing general partner for each partnership.

⁽¹⁾

Atlas Energy’s subsidiary serves as managing general partner of the Partnership. A written prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended, may be obtained from Anthem Securities, Inc. (a subsidiary of Atlas Energy), 1550 Coraopolis Heights Rd. – 3^rd Floor, Moon Township, PA 15108.

Senior Unsecured Notes

On July 13, 2009, 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 on or after August 1, 2013 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.

Credit Agreement Amendment

On July 10, 2009, we amended our credit agreement to, among other things, permit the Merger with us and Atlas Energy and to allow us to distribute (a) amounts equal to Atlas Energy’s income tax liability attributable to our net income at the highest marginal rate and (b) up to $40.0 million per year and, to the extent that we distribute less than that amount in any year, we may carry over an amount up to $20.0 million for use in the next year.

SUBSEQUENT EVENTS

Credit Agreement Amendment

Effective October 14, 2009, in conjunction with a regularly scheduled borrowing base redetermination, our borrowing base under our revolving credit facility of $575.0 million was approved.

Natural Gas Derivative Contracts

In October 2009, we entered into the following natural gas derivative contracts:


Production Period Ending December 31,	Volumes	Average Fixed Price
	(MMBtu)⁽¹⁾	(per MMBtu)⁽¹⁾
2010	5,520,000	$	6.15
2011	1,260,000	$	6.86

Natural Gas Costless Collars


Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap
		(MMBtu)⁽¹⁾	(per MMBtu)⁽¹⁾
2011	Puts purchased	3,300,000	$	6.23
2011	Calls sold	3,300,000	$	7.53
2012	Puts purchased	5,760,000	$	6.51
2012	Calls sold	5,760,000	$	7.71
2013	Puts purchased	5,400,000	$	6,65
2013	Calls sold	5,400,000	$	7.77

⁽¹⁾	“MMbtu” represents million British Thermal Units.

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.

Natural Gas Supply and Outlook

While commodity prices for natural gas were at lower levels during the three months ended September 30, 2009 when compared with the prior year, 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 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 cash flow, we may need to make acquisitions.

RESULTS OF OPERATIONS

GAS AND OIL PRODUCTION

Production Profile. Currently, we have focused our natural gas production operations in various shale plays in the northeastern and midwestern United States. Notably, we are one of the leading producers in the Marcellus Shale, a rich, organic shale located in the Appalachia basin. The portion of the Marcellus Shale in southwestern Pennsylvania in which we focus our drilling, is high-pressured and generally contains dry, pipeline-quality natural gas. In addition, we also are a leading natural gas producer in Michigan through our activity in the Antrim Shale, a biogenic shale play with a long-lived and shallow decline profile, and have recently established a position in the New Albany Shale in southwestern Indiana, where we produce out of the biogenic region of the shale similar to the Antrim. We also produce from the Chattanooga Shale in northeastern Tennessee, which enables us to access other formations in that region such as the Monteagle and Ft. Payne Limestone.

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2009	2008	2009	2008
Production:^{(1) (2)}
Appalachia:⁽³⁾
Natural gas (MMcf)	3,549	3,057	10,851	8,748
Oil (000’s Bbls)	42	39	120	112
Total (MMcfe)	3,801	3,291	11,571	9,420
Michigan/Indiana:
Natural gas (MMcf)	5,384	5,561	15,910	16,373
Oil (000’s Bbls)	1	1	3	3
Total (MMcfe)	5,390	5,567	15,928	16,391
Total:
Natural gas (MMcf)	8,933	8,618	26,761	25,121
Oil (000’s Bbls)	43	40	123	115
Total (MMcfe)	9,191	8,858	27,499	25,811

Production per day:^{(1) (2)}
Appalachia:⁽³⁾
Natural gas (Mcfd)	38,579	33,228	39,749	31,929
Oil (Bpd)	460	413	442	410
Total (Mcfed)	41,339	35,706	42,401	34,389
Michigan/Indiana:
Natural gas (Mcfd)	58,519	60,436	58,277	59,755
Oil (Bpd)	9	11	9	11
Total (Mcfed)	58,573	60,502	58,331	59,821
Total:
Natural gas (Mcfd)	97,098	93,664	98,026	91,684
Oil (Bpd)	469	424	451	421
Total (Mcfed)	99,912	96,208	100,732	94,210

⁽⁽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⁾	“MMcf” represents million cubic feet; “MMcfe” represent million cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day.

⁽³⁾	Appalachia includes our production located in Pennsylvania, Ohio, New York, West Virginia, and Tennessee.

Production Revenues, Prices and Costs. 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 nine months ended September 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 September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Production Revenues (in thousands):
Appalachia:
Natural gas	$	22,802	$	30,430	$	79,873	$	85,440
Oil		3,185		3,868		8,265		11,753

Total	$	25,987	$	34,298	$	88,138	$	97,193

Michigan/Indiana:
Natural gas	$	39,946	$	46,823	$	119,646	$	138,905
Oil		52		113		124		319

Total	$	39,998	$	46,936	$	119,770	$	139,224

Total:
Natural gas	$	62,748	$	77,253	$	199,519	$	224,345
Oil		3,237		3,981		8,389		12,072

Total	$	65,985	$	81,234	$	207,908	$	236,417


Average Sales Price:
Natural Gas:
Appalachia:
Total realized price, after hedge⁽²⁾	$	7.00	$	9.95	$	7.67	$	9.76
Total realized price, before hedge⁽²⁾	$	2.92	$	11.13	$	4.06	$	10.62
Michigan/Indiana:
Total realized price, after hedge⁽¹⁾	$	7.49	$	8.88	$	7.67	$	9.13
Total realized price, before hedge	$	3.38	$	10.15	$	3.98	$	9.71
Total:
Total realized price, after hedge^{(1) (2)}	$	7.29	$	9.26	$	7.67	$	9.35
Total realized price, before hedge⁽²⁾	$	3.20	$	10.49	$	4.01	$	10.03

Oil:
Appalachia:
Total realized price, after hedge	$	75.26	$	101.07	$	68.49	$	104.04
Total realized price, before hedge	$	62.81	$	106.81	$	52.33	$	108.09
Michigan/Indiana:
Total realized price, after hedge	$	63.00	$	111.72	$	50.72	$	108.36
Total realized price, before hedge	$	63.00	$	111.72	$	50.72	$	108.36
Total:
Total realized price, after hedge	$	75.03	$	101.34	$	68.13	$	104.15
Total realized price, before hedge	$	62.81	$	106.94	$	52.30	$	108.09

⁽¹⁾

Includes cash proceeds of $0.3 million and $2.6 million for the three months ended September 30, 2009 and 2008, respectively and $2.4 million and $10.5 million for the nine months ended September 30, 2009 and 2008, respectively, received from the settlement of ineffective derivative gains associated with the acquisition of our Michigan operations, but not reflected in the consolidated statements of operations for the respective periods.

⁽²⁾

Excludes the impact of certain allocation of production revenue to investor partners within our investment partnerships. Including the effect of these allocations, average realized gas sales prices for the three and nine months ended September 30, 2009 for Appalachia were $6.42 per Mcf ($2.34 per Mcf before the effects of financial hedging) and $7.36 per Mcf ($3.75 per Mcf before the effects of financial hedging), respectively, and in total were $7.06 per Mcf ($2.97 per Mcf before the effects of financial hedging) and $7.55 per Mcf ($3.89 per Mcf before the effects of financial hedging), respectively.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Production Costs (per Mcfe):
Appalachia:
Lease operating expenses⁽¹⁾	$	0.97	$	1.08	$	1.03	$	0.98
Production taxes		0.01		0.04		0.03		0.04
Transportation and compression		0.77		1.18		0.79		0.94

	$	1.75	$	2.30	$	1.85	$	1.96

Michigan/Indiana:
Lease operating expenses	$	0.69	$	0.67	$	0.70	$	0.73
Production taxes		0.22		0.63		0.25		0.59
Transportation and compression		0.23		0.28		0.24		0.27

	$	1.14	$	1.58	$	1.19	$	1.59

Total:
Lease operating expenses⁽¹⁾	$	0.81	$	0.82	$	0.89	$	0.82
Production taxes		0.14		0.41		0.16		0.39
Transportation and compression		0.45		0.61		0.47		0.52

	$	1.40	$	1.84	$	1.47	$	1.73

⁽¹⁾

Excludes the effects of our proportionate share of lease operating expenses associated with certain allocations of production revenue to investor partners within our investment partnerships. Including the effects of these costs, lease operating expenses for the three and nine months ended September 30, 2009 for Appalachia were $0.80 per Mcfe (total production costs per Mcfe were $1.58 per Mcfe) and $0.94 per Mcfe (total production costs per Mcfe were $1.76 per Mcfe), respectively, and in total they were $0.73 per Mcfe (total production costs per Mcfe were $1.32 per Mcfe) and $0.80 per Mcfe (total production costs per Mcfe were $1.43 per Mcfe), respectively.

Total natural gas revenues were $62.8 million for the three months ended September 30, 2009, a decrease of $14.5 million from $77.3 million for the three months ended September 30, 2008. The $14.5 million decrease consisted of a $14.7 million decrease resulting from lower realized natural gas prices, $2.0 million of subordinated gas revenues during the current period to the investment partners within our investment partnerships, and a $2.2 million increase attributable to increases in natural gas production volumes. In accordance with the terms of our investment partnership agreements, we may be required to subordinate a part of our net revenues from the investment partnerships to the benefit of the investor partners in order to provide them with cash distributions in an amount equal to at least 10% of their subscriptions determined on a cumulative basis for the initial 5-year period beginning with the commencement of distributions to the investment partnerships, subject to certain limitations. Appalachian production volumes increased 5.4 MMcfd to 38.6 MMcfd for the three months ended September 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 nine-month period as they were connected to gas gathering facilities and transportation pipelines. Total oil revenues were $3.2 million for the three months ended September 30, 2009, a decrease of $0.7 million from $3.9 million for the three months ended September 30, 2008. The decrease resulted primarily from a $1.0 million decrease from lower average realized oil prices, partially offset by a $0.3 million increase in production volumes.

Appalachia production costs were $6.0 million for the three months ended September 30, 2009, a decrease of $1.5 million from $7.5 million for the three months ended September 30, 2008. This decrease principally consists of a $1.0 million decrease due to the Company’s proportionate share of lease operating expenses associated with its revenue that was subordinated to the investor partners within our investment partnerships and a $1.0 million decrease in transportation expense, partially offset by a $0.8 million increase in water hauling and disposal costs associated with an increase in the number of Marcellus Shale wells we drilled. The decrease in Appalachia transportation expense was related to the decline in natural gas prices, for which our wells are generally charged a percentage of the sales price received for the natural gas transported. Michigan/Indiana production costs were $6.1 million for the three months ended September 30, 2009, a decrease of $2.7 million from $8.8 million for the three months ended September 30, 2008. This decrease was primarily attributable to a $2.3 million decrease in production taxes due to a state reduction in the production tax rate on January 1, 2009.

Total natural gas revenues were $199.5 million for the nine months ended September 30, 2009, a decrease of $24.8 million from $224.3 million for the nine months ended September 30, 2008. This decrease consisted of a $33.7 million decrease attributable to lower realized natural gas prices and $3.3 million of gas revenues subordinated to the investor partners within our investment partnerships, partially offset by a $12.2 million increase attributable to higher natural gas production volumes. Appalachian production volumes increased 7.8 MMcfd to 39.7 MMcfd for the nine months ended September 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 nine-month period as they were connected to gas gathering facilities and transportation pipelines. Total oil revenues were $8.4 million for the nine months ended September 30, 2009, a decrease of $3.6 million from $12.0 million for the nine months ended September 30, 2008. This decrease resulted primarily from a $4.2 million decrease associated with lower average realized oil prices, partially offset by a $0.5 million increase associated with higher production volumes.

Appalachia production costs were $20.3 million for the nine months ended September 30, 2009, an increase of $1.9 million from $18.4 million for the nine months ended September 30, 2008. This increase was principally due to a $2.5 million increase in water hauling and disposal costs and a $0.8 million increase associated with an increase in the number of Marcellus Shale wells we drilled from the prior year comparable period, partially offset by a decrease of $1.4 million associated with the Company’s proportionate share of lease operating expenses associated with its revenue that was subordinated to the investor partners within our investor partnerships. Michigan/Indiana production costs were $19.1 million for the nine months ended September 30, 2009, a decrease of $7.1 million from $26.2 million for the nine months ended September 30, 2008. This decrease was primarily attributable to a $5.7 million decrease in production taxes due to a state reduction in the production tax rate on January 1, 2009 and other production cost decreases when 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 presents the number of gross and net development wells we drilled exclusively for us and for our investment partnerships during the three and nine months ended September 30, 2009 and 2008. We did not drill any exploratory wells during the three and nine months ended September 30, 2009 and 2008.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2009	2008	2009	2008
Gross:
Appalachia	27	242	153	733
Michigan/Indiana	11	49	51	135

	38	291	204	868

Net:
Appalachia	26	242	126	672
Michigan/Indiana	11	49	44	135

	37	291	170	807

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 September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Average construction and completion:
Revenue per well	$	2,328	$	483	$	1,487	$	511
Cost per well		1,975		420		1,261		444

Gross profit per well	$	353	$	63	$	226	$	67


Gross profit margin	$	12,358	$	15,259	$	38,995	$	44,800


Net wells drilled and completed:
Marcellus Shale		22		26		64		68
Chattanooga Shale		4		30		9		75
Michigan/Indiana		11		—		44		—
Other – shallow		—		186		53		529

		37		242		170		672

Well construction and completion segment margin was $12.4 million for the three months ended September 30, 2009, a decrease of $2.9 million from $15.3 million for the three months ended September 30, 2008. The decrease was due to a $73.0 million decrease associated with the decrease in the number of wells drilled, partially offset by a $70.1 million increase associated with an increase in the gross profit per well. 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. 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 nine months ended September 30, 2009 in comparison to the prior year comparable periods.

Well construction and completion segment margin was $39.0 million for the nine months ended September 30, 2009, a decrease of $5.8 million from $44.8 million for the nine months ended September 30, 2008. The decrease in segment margin was due a $112.5 million decrease associated with a decrease in the number of wells drilled, partially offset by a $106.7 increase associated with an increase in the gross profit per well.

Our consolidated balance sheet at September 30, 2009 includes $16.6 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 operations. We expect to recognize this amount as revenue during the fourth quarter of 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. Administration and oversight fees were $3.1 million for the three months ended September 30, 2009, a decrease of $2.1 million from $5.2 million for the three months ended September 30, 2008. This decrease was due to a decrease in the number of wells drilled during the period in comparison to the prior year.

Administration and oversight fees were $9.6 million for the nine months ended September 30, 2009, a decrease of $5.8 million from $15.4 million for the nine months ended September 30, 2008. This decrease was primarily a result of a decrease associated with fewer wells drilled during the period in comparison to the prior year.

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.

Well services revenues were $5.0 million for the three months ended September 30, 2009, a decrease of $0.3 million from $5.3 million for the three months ended September 30, 2008. This decrease was principally attributable to the slowdown in drilling for shallow wells for our investment partnerships. Well services expenses were $2.4 million for the three months ended September 30, 2009, a decrease of $0.4 million from $2.8 million for the three months ended September 30, 2008. This decrease 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.

Well services revenues were $14.9 million for the nine months ended September 30, 2009, a decrease of $0.5 million from $15.4 million for the nine months ended September 30, 2008. This decrease was primarily attributable to the slowdown in drilling for shallow wells for our investment partnerships, partially offset by an increase in well operating revenues for the investment partnership wells put into operation during the twelve months ended September 30, 2009. Well services expenses were $6.9 million for the nine months ended September 30, 2009, a decrease of $0.9 million from $7.8 million for the nine months ended September 30, 2008. The decrease 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.

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 Partners L.P. (“Atlas Pipeline”), our affiliate, contributed its Appalachian gathering systems to Laurel Mountain, a joint venture in which Atlas Pipeline retained a 49% ownership interest. 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 Energy, who in turn remitted them to Atlas Pipeline.

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 $2.8 million for the three months ended September 30, 2009. This amount represents $4.5 million we received in gathering fees collected from our investment partnerships, less $7.3 million we were obligated to remit as gathering expense plus an additional $2.8 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 nine months ended September 30, 2009, we received $13.5 million in gathering fees collected from our investment partnerships and were obligated to remit $17.7 million in gathering expense.

As part of our Michigan operations, we own a small gas gathering and processing system. We received $0.5 million and $0.4 million of transportation and natural gas liquid revenues for the three months ended September 30, 2009 and 2008, respectively, and $1.3 million and $1.1 million for the nine-month periods ended September 30, 2009 and 2008, respectively.

OTHER COSTS AND EXPENSES

General and Administrative

General and administrative expenses, which include, among other things, administrative salaries and benefits, partnership syndication activities and other miscellaneous costs of managing our business, were $20.6 million for the three months ended September 30, 2009, an increase of $8.7 million (72%) from $11.9 million for the three months ended September 20, 2008. The $8.7 million increase was principally attributable to $6.1 million of professional fees incurred related to the Merger with Atlas Energy (see “Recent Developments”) and a $2.6 million increase in expenses related to office operations, regulatory compliance and other corporate activities due to the growth of our business.

General and administrative expenses were $47.4 million for the nine months ended September 30, 2009, an increase of $11.4 million (31%) from $36.0 million for the nine months ended September 30, 2008. The $11.4 million increase was principally attributable to $7.7 million of professional fees incurred related to the Merger with Atlas Energy and a $3.6 million increase in expenses related to office operations, regulatory compliance and other corporate activities due to the growth of our business.

Depletion

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Depletion Expense (in thousands):
Appalachia	$	9,383		$	9,544		$	34,645		$	25,942
Michigan/Indiana		14,103			13,164			41,967			39,886

Total	$	23,486		$	22,708		$	76,612		$	65,828

Depletion expense as a percent of gas and oil production		36	%		28	%		37	%		28	%
Depletion per Mcfe:
Appalachia	$	2.47		$	2.84		$	2.99		$	2.75
Michigan/Indiana	$	2.62		$	2.40		$	2.63		$	2.43
Total	$	2.55		$	2.57		$	2.79		$	2.55

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 36% for the three months ended September 30, 2009, compared with 28% for the three months ended September 30, 2008. Depletion expense per Mcfe was $2.55 for the three months ended September 30, 2009, a decrease of $0.02 per Mcfe from $2.57 for the nine months ended September 30, 2008. Increases in our depletable basis and production volumes caused depletion expense to increase $0.8 million to $23.5 million for the three months ended September 30, 2009 compared with $22.7 million for the three months ended September 30, 2008.

Depletion of oil and gas properties as a percentage of oil and gas revenues was 37% for the nine months ended September 30, 2009, compared with 28% for the nine months ended September 30, 2008. Depletion expense per Mcfe was $2.79 for the nine months ended September 30, 2009, an increase of $0.24 (9%) per Mcfe from $2.55 for the nine months ended September 30, 2008. Increases in our depletable basis and production volumes caused depletion expense to increase $10.8 million to $76.6 million for the nine months ended September 30, 2009 compared with $65.8 million for the nine months ended September 30, 2008.

Interest Expense

Interest expense was $19.2 million for the three months ended September 30, 2009, an increase of $4.4 million (30%) compared with $14.8 million for the three months ended September 30, 2008. The increase was principally attributable to a $5.3 million increase in interest expense associated with our senior unsecured notes due to the issuance of $200.0 million of our 12.125% Senior Notes in July 2009, (see “Recent Developments”), partially offset by a $0.8 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.

Interest expense was $47.3 million for the nine months ended September 30, 2009, an increase of $4.6 million (11%) compared with $42.7 million for the nine months ended September 30, 2008. This increase was principally attributable to a $12.5 million increase in interest expense associated with our senior unsecured notes, partially offset by $4.3 million of lower interest expense associated with our revolving credit facility and a $3.3 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 was $1.4 million and $5.7 million for the three and nine months ended September 30, 2009, respectively, which represents the loss associated with the sale of certain natural gas gathering and processing assets sold on June 1, 2009 to Laurel Mountain for net proceeds of $10.0 million.

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 senior unsecured notes and use of our revolving credit facility. The following table sets forth our sources and uses of cash (in thousands):


	Nine Months Ended September 30,
	2009			2008
Net cash provided by operating activities	$	114,144		$	112,735
Net cash used in investing activities		(120,509	)		(225,108	)
Net cash provided by financing activities		3,157			106,415

Net change in cash and cash equivalents	$	(3,208	)	$	(5,958	)

We had $2.4 million in cash and cash equivalents at September 30, 2009, as compared to $5.7 million at December 31, 2008. We had a working capital deficit of $54.8 million at September 30, 2009, compared with $88.0 million at December 31, 2008. The $32.2 million unfavorable cash flow impact from this change in our working capital deficit was principally attributable to a decrease of $80.3 million in liabilities associated with drilling contracts, partially offset by a $36.3 million increase in accounts payable and accrued well drilling and completion costs, and a $6.5 million decrease in net current unrealized derivative receivables.

At September 30, 2009, we had $328.8 million available committed capacity under our credit facility, subject to covenant limitations, to fund working capital obligations. On July 13, 2009, we issued $200.0 million of 12.125% Senior Notes due 2017 at 98.116% of par value to yield 12.5% at maturity (see “Recent Developments”). We used the net proceeds of $191.7 million, net of 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 $1.4 million for the nine months ended September 30, 2009 to $114.1 million from cash provided of $112.7 million for the nine months ended September 30, 2008, principally as a result of the following:

•

changes in current assets and liabilities increased operating cash flows by $35.5 million for the nine months ended September 30, 2009 compared with the nine months ended September 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 $5.7 million related to our loss on the sale of our natural gas gathering and processing assets to Laurel Mountain; partially offset by

•

a $59.4 million decrease in net income before depreciation, depletion and amortization of $125.2 million for the nine months ended September 30, 2009 as compared with the prior year period amount of $184.6 million, principally due to the decline in natural gas and oil and prices from our production business segments and a decrease of $14.7 million in our partnership management business segment due to the decline in the number of wells we drilled; and

•

for the nine months ended September 30, 2009, we received $2.4 million in proceeds from the settlement of ineffective derivative gains, a decrease of $8.1 million from $10.5 million in proceeds received for the prior year comparable period.

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

•

an increase of $24.8 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; and

•

an increase in cash flows provided by accounts receivable and prepaid expenses of $21.6 million; partially offset by

•

a decrease in cash flows provided by accounts payable and accrued expenses of $10.5 million.

Cash flows from investing activities. Cash used in our investing activities decreased $104.6 million for the nine months ended September 30, 2009 to $120.5 million from $225.1 million for the nine months ended September 30, 2008

primarily due to a $94.2 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 in June 2009.

Cash flows from financing activities. Cash provided by our financing activities was $3.2 million for the nine months ended September 30, 2009, compared with $106.4 million for the nine months ended September 30, 2008. The change between periods was principally the result of the following:

•

a $210.9 million decrease in net proceeds from the issuance of our senior unsecured notes to $196.2 million during the nine months ended September 30, 2009 compared with $407.1 million for the nine months ended September 30, 2009; and

•

the absence in the current period of $107.7 million of net proceeds from the sale of our Class B member units during the nine months ended September 30, 2008; partially offset by

•

a $81.0 million decrease in net repayments of credit facility borrowings to $197.0 million for the nine months ended September 30, 2009 compared with $278.0 million for the prior year comparable period;

•

a $73.2 million decrease in distributions to our unitholders to $39.5 million for the nine months ended September 30, 2009 compared with $112.7 million paid for the nine months ended September 30, 2008; and

•

a capital contribution of $55.0 million from Atlas Energy during the nine months ended September 30, 2009.

Capital Requirements

Our capital requirements consist primarily of capital expenditures we make to expand our capital asset base for longer than the short-term and include new leasehold interests, the development and exploitation of existing leasehold interests through purchase of interests in our drilling partnerships, or the development of additional producing properties for our own amounts and the acquisition or construction of gas processing plants.

The following table summarizes our capital expenditures for the periods indicated (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Capital Expenditures	$	34,372	$	89,300	$	130,785	$	224,970

During the three months ended September 30, 2009, our capital expenditures related primarily to $16.3 million of investments in our investment partnerships compared with $44.2 million for the three months ended September 30, 2008. For the three months ended September 30, 2009, we also invested $3.7 million in leasehold acreage, $4.9 million in wells drilled exclusively for our own account, and we incurred $3.8 million in construction costs related to two gas processing plants in Tennessee. During the nine months ended September 30, 2009, our capital expenditures related primarily to $67.9 million of investments in our investment partnerships compared with $110.6 million for the nine months ended September 30, 2008. For the nine months ended September 30, 2009, we also invested $17.0 million in wells drilled exclusively for our own account, incurred $20.3 million in leasehold acquisition costs, and we incurred $10.2 million in construction costs related to two gas processing plants in Tennessee. 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 capital expenditures with cash flow from our operations,

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 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 September 30, 2009, we had a credit facility with a syndicate of banks with a borrowing base of $600.0 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. 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 September 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. The applicable margin on Eurodollar Loans ranges between 200 and 300 basis points and the applicable margin for base rate loans ranges between 112.5 and 212.5 basis points. 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. At September 30, 2009 and December 31, 2008, the weighted average interest rate on the credit facility’s outstanding borrowings was 2.7% and 2.8%, respectively.

On July 10, 2009, the credit agreement was amended to, among other things, permit the Merger with Atlas Energy and to allow us to distribute (a) amounts equal to Atlas Energy’s income tax liability attributable to our net income at the highest marginal rate and (b) up to $40.0 million per year and, to the extent that we distribute less than that amount in any year, we may carry over up to $20.0 million for distributions in the next year (see “Recent Developments”).

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. We were in compliance with these covenants as of September 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 2.1 to 1.0 and our ratio of total debt to EBITDA was 3.0 to 1.0 at September 30, 2009.

Effective October 14, 2009, in conjunction with a regularly scheduled borrowing base redetermination, our borrowing base under the revolving credit facility of $575 million was approved (see “Subsequent Events”).

Shelf Registration Statement

In May 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 debt securities. In July 2009, we filed an additional shelf registration in connection with our July 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 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.

OFF-BALANCE SHEET ARRANGEMENTS

As of September 30, 2009, our off-balance sheet arrangements are limited to our 50.0% share ($11.4 million) of the guarantee of Crown Drilling of Pennsylvania, LLC’s $22.9 million credit arrangement and our letters of credit outstanding of $1.2 million.

FAIR VALUE OF FINANCIAL INSTRUMENTS

To measure our financial instruments at fair value, we have established hierarchy which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1– 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 to value the assets and liabilities. Assets and liabilities that are required to be measured on a recurring basis consist of 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 our asset retirement obligations (“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 AND ISSUED FINANCIAL ACCOUNTING STANDARDS

In October 2009, the FASB issued Accounting Standards Update 2009-15, “Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing” (“Update 2009-15”). Update 2009-15 includes amendments to Topic 470, “Debt”, and Topic 260, “Earnings per Share”, to provide guidance on share-lending arrangements entered into on an entity’s own shares in contemplation of a convertible debt offering or other financing. These requirements are effective for existing arrangements for fiscal years beginning on or after December 15, 2009, and interim periods within those fiscal years for arrangements outstanding as of the beginning of those years, with retrospective application required for such arrangements that meet the criteria. These requirements are also effective for arrangements entered into on (not outstanding) or after the beginning of the first reporting period that begins on or after June 15, 2009. We will apply these requirements upon our 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.

In August 2009, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2009-05, “Fair Value Measurements and Disclosures (Topic 820) – Measuring Liabilities at Fair Value” (“Update 2009-05”), to amend FASB ASC 820-10, “Fair Value Measurements and Disclosures.” This update provides clarification for the fair value measurement of liabilities in circumstances where quoted prices for an identical liability in an active market are not available. The amendments also provide clarification for not requiring the reporting entity to include separate inputs or adjustments to other inputs relating to the existence of a restriction that prevents the transfer of a liability when estimating the fair value of a liability. Additionally, these amendments clarify that both the quoted price in an active market for an identical liability at the measurement date and the quoted price for an identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are considered Level 1 fair value measurements. These requirements are effective for financial statements issued after the release of Update 2009-05. We adopted the requirements on September 30, 2009 and it did not have a material impact on our financial position, results of operations or related disclosures.

In August 2009, the FASB issued Accounting Standards Update 2009-04, “Accounting for Redeemable Equity Instruments – Amendment to Section 480-10-S99” (“Update 2009-04”). Update 2009-04 updates Section 480-10-S99, “Distinguishing Liabilities from Equity”, to reflect the SEC staff’s views regarding the application of Accounting Series Release No. 268, “Presentation in Financial Statements of Redeemable Preferred Stocks” (“ASR No. 268”). ASR No. 268 requires preferred securities that are redeemable for cash or other assets to be classified outside of permanent equity if they are redeemable (1) at a fixed or determinable price on a fixed or determinable date, (2) at the option of the holder, or (3) upon the occurrence of an event that is not solely within the control of the issuer. We adopted the requirements of FASB Update 2009-04 on August 1, 2009 and it did not have a material impact on our financial position, results of operations or related disclosures.

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. These requirements are effective at the start of a reporting entity’s first fiscal year beginning after November 15, 2009 (January 1, 2010 for the Company). We are currently evaluating the impact of these requirements upon our 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.

In June 2009, the FASB issued Accounting Standards Update 2009-01, “Topic 105 – Generally Acceptable Accounting Principles Amendments Based on Statement of Financial Accounting Standards No. 168 - The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“Update 2009-01”). Update 2009-01 establishes the FASB Accounting Standards Codification (“ASC”) as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The ASC supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following the ASC, 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 ASC. The ASC is effective for financial statements issued for interim and annual periods ending after September 15, 2009. Entities are not required to include specific references to the ASC in their financial statements and therefore, we have removed all previous references to FASB authoritative guidance and describe our accounting policies using a “plain English” approach. We adopted the requirements of Update 2009-01 to our financial statements on September 30, 2009 and it did not have a material impact on our financial statement disclosures.

In May 2009, the FASB issued ASC 855-10, “Subsequent Events” (“ASC 855-10”). ASC 855-10 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. The provisions require 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. ASC 855-10 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. We adopted the requirements of this standard on June 30, 2009 and it did not have a material impact on our financial position or results of operations or related disclosures. The adoption of these provisions does not change our current practices with respect to evaluating, recording and disclosing subsequent events.

In April 2009, the FASB issued ASC 820-10-65-4, “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” (“ASC 820-10-65-4”). ASC 820-10-65-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. ASC 820-10-65-4 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. ASC 820-10-65-4 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 ASC 820-10-65-4 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 ASC 320-10-65-1, “Recognition and Presentation of Other-Than-Temporary Impairments” (“ASC 320-10-65-1”), which changes previously existing guidance for determining whether an impairment is other than temporary for debt securities. ASC 320-10-65-1 replaces the previously existing requirement that an entity’s management assess if 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. ASC 320-10-65-1 also requires 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. ASC 320-10-65-1 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 these requirements on April 1, 2009 and its adoption did not have a material impact on our financial position and results of operations.

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. ASC 825-10-65-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted these requirements 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 ASC 805-20-30-23, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“ASC 805-20-30-23”), which 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 previous requirements. ASC 805-20-30-23 eliminates the requirement to disclose an estimate of the range of outcomes of recognized contingencies at the acquisition date. ASC 805-20-30-23 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 on January 1, 2009 and its adoption did not have a material impact on our financial position and results of operations.

In June 2008, the FASB issued ASC 260-10-45-61A, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“ASC 260-10-45-61A”). ASC 260-10-45-61A applies to the calculation of earnings per share (“EPS”) described in previous guidance, for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain non-forfeitable 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. ASC 260-10-45-61A is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption was prohibited. We adopted the requirements on January 1, 2009 and its adoption did not have a material impact on our financial position and results of operations.

In April 2008, the FASB issued ASC 350-30-65-1, “Determination of Useful Life of Intangible Assets” (“ASC 350-30-65-1”). ASC 350-30-65-1 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under previous guidance. The intent of ASC 350-30-65-1 is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset. We adopted the requirements of ASC 350-30-65-1 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 ASC 260-10-55-103 through 55-110, “Application of the Two-Class Method” (“ASC 260-10-55-103”), which 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. ASC 260-10-55-103 considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Our adoption of ASC 260-10-55-103 on January 1, 2009 impacted our presentation of net income (loss) per common limited partner unit as we previously presented net income (loss) per common limited partner unit as though all earnings were distributed each quarterly period (see “—Net Income (Loss) Per Common Unit”). We adopted the requirements of ASC 260-10-55-103 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 ASC 815-10-50-1, “Disclosures about Derivative Instruments and Hedging Activities” (“ASC 815-10-50-1”), to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. We adopted the requirements of this section of ASC 815-10-50-1 on January 1, 2009 and it did not have a material impact on our financial position or results of operations (see Note 10).

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. It 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, ASC 810-10-65-1 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 and adjust its remaining investment, if any, at fair value. We adopted the requirements of ASC 810-10-65-1on January 1, 2009 and adjusted its presentation of our financial position and results of operations. Prior period financial position and results of operations have been adjusted retrospectively to conform to these provisions.

In December 2007, the FASB issued ASC 805, “Business Combinations” (“ASC 805”). ASC 805 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. ASC 805 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, it 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 these requirements on January 1, 2009 and it did not have a material impact on our financial position and results of operations.

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 September 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 $7.8 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 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 operations 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 $35.1 million and losses of $27.6 million for the three months ended September 30, 2009 and 2008, respectively and gains of $82.2 million and losses of $26.0 million for the nine months ended September 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 nine months ended September 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 operations during the periods which the physical transactions would have affected earnings.

We have a $94.2 million net unrealized gain related to financial derivatives in accumulated other comprehensive loss associated with commodity derivatives at September 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 $60.1 million of unrealized gains to our consolidated statements of operations over the next twelve-month period as these contracts settle and $34.1 million of unrealized gains will be reclassified in later periods.

The fair value of the derivatives at September 30, 2009 is a net unrealized derivative asset of $99.9 million, of which our portion is $64.8 million and $35.1 million of unrealized gains have been reallocated to our investment partnerships.

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

Natural Gas Fixed Price Swaps


Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset
	(MMBtu)	(per MMBtu)		(in thousands)⁽¹⁾
2009	10,340,000	$	8.242	$	36,116
2010	31,880,000	$	7.708		47,682
2011	20,720,000	$	7.040		3,403
2012	19,680,000	$	7.223		4,119
2013	13,260,000	$	7.082		235

				$	91,555

Natural Gas Costless Collars


Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset/(Liability)
		(MMBtu)	(per MMBtu)		(in thousands)⁽¹⁾
2009	Puts purchased	60,000	$	11.000	$	370
2009	Calls sold	60,000	$	15.350		—
2010	Puts purchased	3,360,000	$	7.839		6,021
2010	Calls sold	3,360,000	$	9.007		—
2011	Puts purchased	9,540,000	$	6.523		808
2011	Calls sold	9,540,000	$	7.666		—
2012	Puts purchased	4,020,000	$	6.514		—
2012	Calls sold	4,020,000	$	7.718		(249	)
2013	Puts purchased	5,340,000	$	6.516		—
2013	Calls sold	5,340,000	$	7.811		(579	)

					$	6,371

Crude Oil Fixed Price Swaps


Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset/(Liability)
	(Bbl)	(per Bbl)		(in thousands)⁽²⁾
2009	14,600	$	99.319	$	424
2010	48,900	$	97.400		1,134
2011	42,600	$	77.460		11
2012	33,500	$	76.855		(74	)
2013	10,000	$	77.360		(29	)

				$	1,466

Crude Oil Costless Collars


Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset/(Liability)


		(Bbl)	(per Bbl)		(in thousands)⁽²⁾
2009	Puts purchased	9,000	$	85.000	$	134
2009	Calls sold	9,000	$	116.561		—
2010	Puts purchased	31,000	$	85.000		468
2010	Calls sold	31,000	$	112.918		—
2011	Puts purchased	27,000	$	67.223		—
2011	Calls sold	27,000	$	89.436		(27	)
2012	Puts purchased	21,500	$	65.506		—
2012	Calls sold	21,500	$	91.448		(70	)
2013	Puts purchased	6,000	$	65.358		—
2013	Calls sold	6,000	$	93.442		(24	)

					$	481

				Total net asset	$	99,873

⁽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 September 30, 2009, we had $270.0 million of borrowings outstanding under our revolving credit facility. At September 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 $1.2 million.

At September 30, 2009, we had the following interest rate derivatives:

Interest Fixed Rate Swap


Term	Notional Amount		Option Type	Contract Period Ended December 31,	Fair Value (Liability)
					(in thousands)
January 2008 – January 2011	$	150,000,000	Pay 3.11% -Receive LIBOR	2009	$	(1,009	)
				2010		(3,495	)
				2011		(194	)

				Total net liability	$	(4,698	)

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 September 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 Atlas America, LLC 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, LLC 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, etal., C.A. No. 553-VCN (Del. Ch. filed 4/30/09);

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

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

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

Montgomery County Employees’ Retirement Fund v. Atlas Energy Resources, LLC, etal., 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 they are not pursuing their motion for preliminary injunction and requested that the preliminary injunction hearing date be removed from the court’s calendar. Around that time, plaintiffs advised counsel for the defendants that they intended to continue to pursue the case after the Merger as a claim for monetary damages. The Chancery Court approved the briefing schedule in mid-September and defendants filed a brief in support of their motion to dismiss on October 16, 2009. 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. 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.

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 in our reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009. The risk factors identified therein have not changed in any material respect, except the additional risk factors added below.

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 Energy, Inc. common stock.

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.

Lawsuits have been filed against us, certain officers and members of our board of directors and Atlas Energy, Inc. challenging the Merger, and any adverse judgment for monetary damages could have a material adverse effect on the operations of the combined company.

We, certain officers and members of our board of directors and Atlas Energy, Inc. are named as defendants in a consolidated purported class action lawsuit brought by our unitholders in Delaware Chancery Court generally alleging claims of breach of fiduciary duty in connection with the Merger transaction. The complaint alleges inadequate disclosures in connection with our unitholder vote on the Merger. Plaintiffs filed a Verified Consolidated Class Action Complaint on July 1, 2009. The lawsuit originally sought monetary damages or injunctive relief, or both. However, on August 7, 2009, plaintiffs advised the Chancery Court by letter that they were not pursuing their motion for a preliminary injunction, and requested that the preliminary injunction hearing date be removed from the Court’s calendar. Around that time, plaintiffs advised counsel for the defendants that plaintiffs intended to continue to pursue the action for monetary damages after the Merger was completed. The Chancery Court approved the briefing schedule in mid-September and defendants filed a brief in support of their motion to dismiss on October 16, 2009. 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.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF THE SECURITY HOLDERS

The 2009 Annual Meeting of unit holders was held on June 4, 2009. The proposal voted on at the meeting was to elect seven directors listed below to serve until the next Annual Meeting. The percentage listed below is based on the total of the units voted For and Against.


Nominees	Votes For	Votes Against or Withheld	Percentage
Edward E. Cohen	55,058,606	822,759	98.53%
Jonathan Z. Cohen	55,038,256	843,109	99.49%
Jessica K. Davis	55,255,212	626,153	98.88%
Richard D. Weber	55,255,252	626,113	98.88%
Walter C. Jones	55,174,311	707,054	98.73%
Ellen F. Warren	55,161,261	720,104	98.71%
Bruce M. Wolf	55,275,017	606,348	98.91%

The following matter (which was approved) was submitted to a vote of security holders at our special meeting of unit holders held on September 25, 2009:

Proposal:

To approve the adoption of the Agreement and Plan of Merger, dated April 27, 2009, by us, Atlas America, Inc., and Atlas Energy Management, Inc. and approve the transactions contemplated thereby, including the Merger.

Class B Common Units


Votes For	Votes Against	Abstentions/Broker Non-Votes
47,710,514	180,682	57,601

Class A Units


Votes For	Votes Against	Abstentions/Broker Non-Votes
1,293,496	—	—

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		Second Amended and Restated Operating Agreement of Atlas Energy Resources, LLC⁽¹²⁾

3.2		Certificate of Formation of Atlas Energy Resources, LLC⁽³⁾

4.1		Form of common unit certificate (included as Exhibit A to the Second Amended and Restated Operating Company Agreement of Atlas Energy Resources, LLC)⁽¹²⁾

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		Atlas Energy, Inc. Assumed Long-Term Incentive Plan⁽¹³⁾

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.⁽¹⁴⁾ 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.⁽¹⁴⁾ 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.

⁽¹²⁾	Previously filed as an exhibit to our Form 8-K filed September 30, 2009.

⁽¹³⁾	Previously filed as an exhibit to Atlas Energy, Inc.’s Form S-8 filed on September 30, 2009.

⁽¹⁴⁾	Previously filed as an exhibit to our Form 10-Q for the quarter ended June 30, 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: November 9, 2009	By:	/s/ Matthew A. Jones
		Matthew A. Jones
		Chief Financial Officer

Date: November 9, 2009	By:	/s/ Sean P. McGrath
		Sean P. McGrath Chief Accounting Officer

Atlas Energy Resources, LLC 10-Q