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, 2010

OR

¨ 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: 001-33193

ATLAS ENERGY RESOURCES, LLC

(Exact name of registrant as specified in its charter)

Delaware	51-0404430
(State or other jurisdiction or 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 office)	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 the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	x	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

Atlas Energy Resources, LLC meets the conditions set forth in General Instructions H(1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format.

DOCUMENTS INCORPORATED BY REFERENCE: None

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, 2010 and December 31, 2009		3
	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2010 and 2009		4
	Consolidated Statement of Owner’s Equity for the Nine Months Ended September 30, 2010		5
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009		6
	Notes to Consolidated Financial Statements		7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		27
Item 4.	Controls and Procedures		35
PART II.	OTHER INFORMATION		36
Item 1.	Legal Proceedings		36
Item 6.	Exhibits		36
SIGNATURES			38

2

ITEM 1. FINANCIAL STATEMENTS

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)

(Unaudited)

	September  30, 2010		December  31, 2009
ASSETS
Current assets:
Cash and cash equivalents	$	78,907	$	3,640
Accounts receivable		75,936		71,058
Current portion of derivative receivable from Partnerships		56		270
Current portion of derivative asset		103,598		73,066
Subscriptions receivable from Partnerships		—		47,275
Inventory		12,775		12,207
Prepaid expenses and other		3,978		3,414
Total current assets		275,250		210,930
Property, plant and equipment, net		2,004,437		1,871,418
Intangible assets, net		2,341		2,873
Goodwill, net		35,166		35,166
Long-term derivative asset		108,766		58,930
Advances to affiliates		26,079		5,689
Long-term derivative receivable from Partnerships		5,481		2,841
Other assets, net		19,193		20,906
	$	2,476,713	$	2,208,753
LIABILITIES AND OWNER’S EQUITY
Current liabilities:
Accounts payable		95,941		76,993
Accrued interest		11,223		29,245
Accrued liabilities		10,878		14,308
Liabilities associated with drilling contracts		95,189		122,532
Accrued well drilling and completion costs		65,373		89,261
Current portion of derivative payable to Partnerships		36,637		22,382
Current portion of derivative liability		2,069		4,652
Total current liabilities		317,310		359,373
Long-term debt, less current portion		678,193		786,390
Long-term derivative payable to Partnerships		43,055		22,380
Long-term derivative liability		25,378		14,315
Asset retirement obligations		54,200		51,813
Commitments and contingencies
Owner’s equity:
Owner’s equity		1,176,302		873,170
Accumulated other comprehensive income		182,130		101,143
		1,358,432		974,313
Non-controlling interests		145		169
Total owner’s equity		1,358,577		974,482
	$	2,476,713	$	2,208,753

See accompanying notes to consolidated financial statements

3

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Revenues:
Gas and oil production	$	67,503		$	65,986		$	200,600		$	207,908
Well construction and completion		60,748			81,496			176,685			257,231
Gathering		5,262			6,098			15,501			16,210
Administration and oversight		3,561			3,149			7,473			9,644
Well services		6,008			5,012			17,063			14,911
Other, net		75			201			1,146			280
Total revenues		143,157			161,942			418,468			506,184
Costs and expenses:
Gas and oil production		13,799			12,129			39,179			39,421
Well construction and completion		51,481			69,138			149,724			218,236
Gathering		7,522			7,973			22,398			18,951
Well services		2,796			2,378			8,071			6,922
General and administrative		15,533			20,573			42,595			47,390
Depreciation, depletion and amortization		30,257			24,563			87,232			79,866
Total costs and expenses		121,388			136,754			349,199			410,786
Operating income		21,769			25,188			69,269			95,398
Gain (loss) on asset sales		609			(1,444	)		286,308			(5,694	)
Interest expense		(17,387	)		(19,161	)		(52,406	)		(47,269	)
Net income		4,991			4,583			303,171			42,435
Income attributable to non-controlling interests		(10	)		(14	)		(39	)		(44	)
Net income attributable to owner’s/members’ interests	$	4,981		$	4,569		$	303,132		$	42,391
Allocation of net income attributable to owner’s/members’ interests:
Portion allocable to members’ interests (period prior to merger on September 29, 2009)	$	—		$	4,519		$	—		$	42,341
Portion allocable to owner’s interest (period subsequent to merger on September 29, 2009)		4,981			50			303,132			50
Net income attributable to owner’s/members’ interests	$	4,981		$	4,569		$	303,132		$	42,391
Allocation of net income attributable to members’ interests:
Class A member’s units	$	—		$	90		$	—		$	(7,109	)
Class B members’ units		—			4,429			—			49,450
Net income attributable to members’ interests	$	—		$	4,519		$	—		$	42,341
Net income attributable to Class B members per unit:
Basic	$	—		$	0.07		$	—		$	0.78
Diluted	$	—		$	0.07		$	—		$	0.78
Weighted average Class B members’ units outstanding:
Basic		—			63,381			—			63,381
Diluted		—			63,452			—			63,405

See accompanying notes to consolidated financial statements

4

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OWNER’S EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2010

(in thousands, except share data)

(Unaudited)

	Owner’s Equity		Accumulated Other Comprehensive Income		Non- Controlling Interests			Total Owner’s Equity
Balance at January 1, 2010	$	873,170	$	101,143	$	169		$	974,482
Distributions to non-controlling interests		—		—		(63	)		(63	)
Other comprehensive income		—		80,987		—			80,987
Net income		303,132		—		39			303,171
Balance at September 30, 2010	$	1,176,302	$	182,130	$	145		$	1,358,577

See accompanying notes to consolidated financial statements

5

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Nine Months Ended September 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	303,171		$	42,435
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		87,232			79,866
Amortization of deferred finance costs		3,607			2,897
Non-cash loss on derivative value, net		41,603			30,976
Non-cash compensation expense		—			3,387
(Gain) loss on asset sales		(286,308	)		5,694
Distributions paid to non-controlling interests		(63	)		(62	)
Equity income in unconsolidated companies		(1,240	)		(316	)
Changes in operating assets and liabilities:
Accounts receivable and other current assets		17,294			(3,264	)
Accounts payable and accrued liabilities		8,876			6,550
Liabilities associated with drilling contracts		(27,343	)		(80,293	)
Liabilities associated with well drilling and completion costs		(23,888	)		24,109
Net cash provided by operating activities		122,941			111,979
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(257,424	)		(130,785	)
Proceeds from asset sales		318,010			10,289
Other		771			(13	)
Net cash provided by (used in) investing activities		61,357			(120,509	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility		291,000			295,000
Repayments under credit facility		(399,000	)		(492,000	)
Net proceeds from issuance of debt		—			196,232
Distributions paid to members		—			(39,452	)
Contribution from owner		—			55,000
Other		(1,031	)		(9,458	)
Net cash provided by (used in) financing activities		(109,031	)		5,322
Net change in cash and cash equivalents		75,267			(3,208	)
Cash and cash equivalents, beginning of period		3,640			5,655
Cash and cash equivalents, end of period	$	78,907		$	2,447

See accompanying notes to consolidated financial statements

6

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2010

(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 oil, with operations in the Appalachian, Michigan and Illinois Basins.

On September 29, 2009, the Company completed its merger with Atlas America, Inc. (“Atlas America”) pursuant to the definitive merger agreement previously executed 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” or “ATLS”) (NASDAQ: ATLS). 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, the Class A units and management incentive interests owned by Atlas Energy Management, Inc. are combined with and shown as “owner’s equity” on the consolidated balance sheet. 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, 2009 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. 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, 2009. Certain amounts in the prior year’s consolidated financial statements have also been reclassified to conform to the current year presentation. The results of operations for the three and nine month periods ended September 30, 2010 may not necessarily be indicative of the results of operations for the full year ending December 31, 2010.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Non-Controlling Interest

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Transactions between the Company and ATLS and its affiliates have been identified in the consolidated financial statements as transactions between affiliates (see Note 10). The non-controlling ownership interest in the net income of the Company is reflected as non-controlling interest on the Company’s consolidated statements of operations, and the non-controlling interests in the assets and liabilities of the Company are reflected 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’s financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the energy partnerships in which the Company has an interest (“the Partnerships”). Such interests typically range from 15% to 35%. The Company’s financial statements do not include proportional consolidation of the depletion or impairment expenses of the Partnerships. Rather, the Company calculates these items specific to its own economics as further explained under the heading “Property, Plant and Equipment” below. All material intercompany transactions have been eliminated.

7

In April 2010, the Company entered into an undivided joint venture with Reliance Industries Limited (“Reliance”), whereby the Company sold a 40% undivided joint venture interest in approximately 300,000 net acres (approximately 120,000 net acres to Reliance) of its core undeveloped Marcellus Shale leasehold acreage to Reliance (see Note 3). The joint venture also calls for Reliance to provide the Company with a $1,357.5 million drilling carry, whereby Reliance will fund 75% of the Company’s respective portion of the drilling and completion costs of the wells developed on the joint venture leasehold acreage. As a result of this provision, the Company will effectively fund 15% of the capital costs required to drill each well, while Reliance will fund 85% until the $1,357.5 million is fully utilized. As a result of this transaction, the Company proportionally consolidated its 60% ownership interest in the operating results of the joint venture in its consolidated statements of operations. The Company also proportionally consolidated its ownership interest in the joint venture’s assets, to the extent contributed, and liabilities in its consolidated balance sheets.

Use of Estimates

The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Company’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Company’s consolidated financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, depreciation and amortization, asset impairments, 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 those estimates.

The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three and nine months ended September 30, 2010 and 2009 represent actual results in all material respects (see “- Revenue Recognition” accounting policy for further description).

Inventory

The Company values inventory at the lower of cost or market. The Company’s inventories, which consist of materials, pipes, supplies and other inventories, were principally determined using the average cost method.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired (see Note 4). Depreciation and amortization expense was based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.

The Company follows the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel equals 6 Mcf.

The Company’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include the Company’s costs of property interests in proportionately consolidated investment partnerships, joint venture wells, wells drilled solely by the Company for its interests, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the Company eliminates the cost from the property accounts, and the resultant gain or loss is reclassified to the Company’s consolidated statements of operations. Upon the sale of an individual well, the Company credits the proceeds to accumulated depreciation and depletion within its consolidated balance sheets. Upon the Company’s sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s consolidated 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.

8

Impairment of Long-Lived Assets

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of the Company’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, the Company’s reserve estimates for its investment in the Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ 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 in the Partnerships paying to the Company their proportionate share of these expenses plus a profit margin. These assumptions could result in the Company’s calculation of depletion and impairment being different than its proportionate share of the Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. 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 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 Partnership becomes uneconomic under the terms of the partnership agreement in order to recover these excess reserves and to acquire any additional residual interests in the wells held by other partnership investors. The acquisition of any well interest from the Partnership by the Company is governed under the partnership agreement and in general, must be at fair market value supported by an appraisal of an independent expert selected by the Company. There were no impairments of proved oil and gas properties recorded by the Company for the three and nine months ended September 30, 2010 and 2009.

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 unproved oil and gas properties recorded by the Company for the three and nine months ended September 30, 2010 and 2009.

During the three months ended December 31, 2009, the Company recognized a $156.4 million asset impairment related to oil and gas properties within property, plant and equipment on its consolidated balance sheet for its shallow natural gas wells in the Upper Devonian shale. This impairment related to the carrying amount of these oil and gas properties being in excess of its estimate of their fair value at December 31, 2009. The estimate of fair value of these oil and gas properties was impacted by, among other factors, the deterioration of natural gas prices.

9

Capitalized Interest

The Company capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds by the Company was 10.6% and 8.7% for the three months ended September 30, 2010 and 2009, respectively, and 10.3% and 7.4% for the nine months ended September 30, 2010 and 2009, respectively. The amount of interest capitalized by the Company was $4.3 million and $1.6 million for the three months ended September 30, 2010 and 2009, respectively, and $11.0 million and $5.3 million for the nine months ended September 30, 2010 and 2009, respectively.

Intangible Assets

The Company has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through consummated acquisitions. The Company amortizes contracts acquired on a declining balance and straight-line method over their respective estimated useful lives. The following table reflects the components of intangible assets being amortized at September 30, 2010 and December 31, 2009 (in thousands):

	September 30, 2010			December 31, 2009			Estimated Useful Lives In Years
Partnership management and operating contracts:
Gross carrying amount	$	14,343		$	14,343			2 – 13
Accumulated amortization		(12,002	)		(11,470	)
Net carrying amount	$	2,341		$	2,873

Amortization expense on intangible assets was $0.2 million and $0.2 million for both the three months ended September 30, 2010 and 2009, and $0.5 million and $0.8 million for the nine months ended September 30, 2010 and 2009, respectively. Estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2010 - $0.7 million; 2011 - $0.7 million; 2012 - $0.2 million; 2013 - $0.2 million; and 2014 - $0.1 million.

Goodwill

At September 30, 2010 and December 31, 2009, the Company had $35.2 million of goodwill recorded in connection with consummated acquisitions. There were no changes in the carrying amount of goodwill for the three and nine months ended September 30, 2010 and 2009.

The Company tests its goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for its reporting units are not available, the Company’s management must apply judgment in determining the estimated fair value of these reporting units. The Company’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to the Company’s market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity 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’s management also considers the inclusion of a control premium within 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 compared to observable metrics on large mergers and acquisitions in the Company’s industry to determine whether those valuations appear reasonable in management’s judgment. The Company will continue to evaluate goodwill at least annually or when impairment indicators arise. There were no goodwill impairments recognized by the Company and its subsidiaries during the three and nine months ended September 30, 2010 and 2009.

10

Net Income Per Unit

As a result of the Merger on September 29, 2009, there are no Class B member common units outstanding. Net income attributable to Class B member units is only presented 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 Management’s Incentive Interests (“MII”), with a priority allocation of net income to the Class A member’s MIIs in accordance with the Company’s original 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 ATLS executed a definitive merger agreement. In anticipation of the Merger on September 29, 2009, the Company suspended distributions to the Class A and Class B members’ interests on 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 are no longer payable to ATLS.

The Company presents net income 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 EPS pursuant to the Two-Class Method. Prior to the Merger, the Company had a Long-Term Incentive Plan that contained previously awarded phantom units, which consisted of Class B units (see Note 12) and contained nonforfeitable rights to distribution equivalents of the Company. These participation rights 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 unit must be after the allocation of income to the phantom units on a pro-rata basis.

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 for the period indicated (in thousands):

	Period from July 1, 2009 to September 29, 2009			Period from January 1, 2009 to September 29, 2009
Net income attributable to members’ interests	$	4,519		$	42,341
Income allocable to Class A member’s actual cash incentive distributions reserved(1)		—			(8,024	)
Income allocable to Class A member’s 2% ownership interest		90			915
Net income allocable to Class A member’s ownership interest		90			(7,109	)
Net income allocable to Class B member’s ownership interest		4,429			49,450
Less: net income attributable to participating securities – phantom units(2)		(50	)		(558	)
Net income utilized in the calculation of net income attributable to Class B member per unit	$	4,379		$	48,892

⁽¹⁾ In connection with the Merger, the Company discontinued distributions in April 2009. Accordingly, the previously recorded amounts relating to the MII were reversed.

⁽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).

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Dilutive potential units of Class B members’ units consisted of the excess of shares issuable under the terms of the Company’s stock incentive plan over the number of such units that could have been reacquired (at the weighted average market price of units during the period) with the proceeds received from the exercise of the stock options (see Note 12). 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 for the period indicated (in thousands):

	Period from July 1, 2009 to September 29, 2009		Period from January 1, 2009 to September 29, 2009
Weighted average number of Class B members’ units – basic		63,381		63,381
Add: effect of dilutive unit options		71		24
Weighted average number of Class B members’ units – diluted		63,452		63,405

Revenue Recognition

Certain energy activities are conducted by the Company through, and a portion of its revenues are attributable to, sponsored investment partnerships. The Company contracts with the Partnerships to drill partnership wells. The contracts require that the Partnerships must 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 the Company’s consolidated balance sheets. The Company recognizes well services revenues at the time the services are performed. The Company is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned and includes them in administration and oversight revenues.

The Company generally sells natural gas and crude oil at prevailing market prices. Revenue is recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which the Company has an interest with other producers are recognized on the basis of the Company’s percentage ownership of working interest and/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.

The Company accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management estimates of the related commodity sales which are, in turn, based upon applicable product prices (see “–Use of Estimates” accounting policy for further description). The Company had unbilled revenues at September 30, 2010 and December 31, 2009 of $32.0 million and $29.6 million, respectively, which were included in accounts receivable within the Company’s consolidated balance sheets.

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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. The following table sets forth the calculation of the Company’s comprehensive income (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Net income	$	4,991		$	4,583		$	303,171		$	42,435
Income attributable to non-controlling interests		(10	)		(14	)		(39	)		(44	)
Net income attributable to owner’s/members’ interests		4,981			4,569			303,132			42,391
Other comprehensive income:
Changes in fair value of derivative instruments accounted for as cash flow hedges		60,266			5,017			147,697			68,298
Less: reclassification adjustment for realized gains in net income		(23,676	)		(34,051	)		(66,710	)		(79,101	)
Total other comprehensive income (loss)		36,590			(29,034	)		80,987			(10,803	)
Comprehensive income (loss) attributable to owner’s/members’ interests	$	41,571		$	(24,465	)	$	384,119		$	31,588

Recently Adopted Accounting Standards

In April 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-14, “Accounting for Extractive Industries – Oil & Gas: Amendments to Paragraph 932-10-S99-1” (“Update 2010-14”). Update 2010-14 provides amendments to add the SEC’s Regulation S-X Rule 4-10, “Financial Accounting and Reporting for Oil and Gas Producing Activities Pursuant to the Federal Securities Laws and the Energy Policy and Conservation Act of 1975” (“S-X Rule 4-10”) to Accounting Standards Codification (“ASC”) Topic 932 “Extractive Activities – Oil and Gas”. S-X Rule 4-10 was included in the SEC’s Final Rule, “Modernization of Oil and Gas Reporting, which became effective January 1, 2010. As Update 2010-14 only served to align the FASB’s ASC Topic 932 with the SEC’s S-X Rule 4-10, the Company’s adoption did not have a material impact on its financial position, results of operations or related disclosures.

In April 2010, the FASB issued Accounting Standards Update 2010-12, “Income Taxes (Topic 740): Accounting for Certain Tax Effects of the 2010 Health Care Reform Acts” (“Update 2010-12”). Update 2010-12 updates the FASB ASC for the SEC Staff Announcement, “Accounting for the Health Care and Education Reconciliation Act of 2010 and the Patient Protection and Affordable Care Act”. The announcement provides guidance on the accounting effect, if any, that arises from the different signing dates between the Health Care and Education Reconciliation Act of 2010, which is a reconciliation bill that amends the Patient Protection and Affordable Care Act (collectively, the “Acts”). Update 2010-12 clarifies the effect, if any, that the different signing dates might have on the accounting for these Acts. As Update 2010-12 serves only to clarify an accounting ambiguity between the Acts, the FASB did not provide a required adoption date.

In February 2010, the FASB issued Accounting Standards Update 2010-09, “Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements” (“Update 2010-09”). Update 2010-09 removes the requirement for an SEC filer to disclose a date through which subsequent events have been evaluated in both issued and revised financial statements. Revised financial statements include financial statements revised as a result of either correction of an error or retrospective application of U.S. generally accepted accounting standards. The requirements of Update 2010-09 were effective upon its issuance on February 24, 2010. The Company applied the requirements of Update 2010-09 upon its adoption, and it did not have an impact on its financial position, results of operations or related disclosures.

In January 2010, the FASB issued Accounting Standards Update 2010-06, “Fair Value Measurement and Disclosures (Topic (820) – Improving Disclosures about Fair Value Measurement” (“Update 2010-06”). Update 2010-06 clarifies and requires new disclosures about the transfer of amounts between Level 1 and Level 2, as well as significant transfers in and out of Level 3. In addition, for Level 2 and Level 3 measurements, Update 2010-06 requires additional disclosure about the valuation technique used or any changes in technique. Update 2010-06 also clarifies that entities must disclose fair value measurements by classes of assets and liabilities, based on the nature and risks of the assets and liabilities. The requirements of Update 2010-06 are effective at the start of a reporting entity’s first fiscal year beginning after December 15, 2009 (January 1, 2010 for the Company). The Company applied the requirements of Update 2010-06 upon its adoption on January 1, 2010, and it did not have a material impact on its financial position, results of operations or related disclosures.

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In January 2010, the FASB issued Accounting Standards Update 2010-02, “Consolidation (Topic (810) - Accounting and Reporting for Decreases in Ownership of a Subsidiary – A Scope Clarification” (“Update 2010-02”). Subtopic 810-10 previously applied to decrease-in-ownership provisions when an entity either deconsolidates or realizes a decrease in ownership in which the entity retains control. When an entity deconsolidates a subsidiary, it is required to record any remaining interest at fair value and recognize a gain or loss. Update 2010-02 amends Subtopic 810-10 “Consolidation – Overall” and provides clarification on the entities and activities required to follow more specific guidance already included in the ASC. Update 2010-02 includes in the scope of decrease-in-ownership provisions of ASC 810-10 a subsidiary or groups of assets that is a business or nonprofit activity, a subsidiary or group of assets transferred to an equity method investee or joint venture, or an exchange of a group of assets that constitutes a business or nonprofit activity for a non-controlling interest in an entity. Excluded from the scope of Subtopic 810-10 are sales of in-substance real estate and conveyances of oil and gas mineral rights. The requirements of Update 2010-02 are effective at the start of a reporting entity’s first fiscal year beginning after December 15, 2009 (January 1, 2010 for the Company). The Company applied the requirements of Update 2010-02 upon its adoption on January 1, 2010, and it did not have a material impact on its financial position, results of operations or related disclosures.

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 (January 1, 2010 for the Company), 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. The Company adopted the requirements of Update 2009-15 on January 1, 2010, and it did not have a material impact on its financial position, 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 820-10-25-20 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. The requirements of ASC 820-10-25-20 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 adopted the requirements of ASC 810-10-25-20 on January 1, 2010, and it did not have a material impact on its financial position, results of operations or related disclosures.

Recently Issued Accounting Standards

In July 2010, the FASB issued Accounting Standards Update 2010-20, “Receivables – Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses” (“Update 2010-20”). Update 2010-20 provides enhanced disclosure requirements for allowance for credit losses and the credit quality of financing receivables to assist financial statement users in assessing credit risk exposures and evaluating the adequacy of the allowance for credit losses. This amendment requires disclosures on a disaggregated basis that will further facilitate the evaluation of the nature of credit risk inherent in an entity’s financing receivables, how the risks are analyzed and assessed in arriving at the allowance for credit losses, and the changes and reasons for such changes in the allowance for credit losses. This amendment also requires disclosure of credit quality indicators, past due information, a roll-forward schedule of the allowance for credit losses, and any modifications to financing receivables. The requirements of Update 2010-20 are effective at the end of a reporting entity’s first annual or quarterly reporting period ending after December 15, 2010 (December 31, 2010 for the Company). The Company will apply the requirements of Update 2010-20 upon its adoption on December 31, 2010 and does not expect it to have a material impact on its financial position, results of operations or related disclosures.

In March 2010, the FASB issued Accounting Standards Update 2010-11, “Derivatives and Hedging (Topic 815): Scope Exception Related to Embedded Credit Derivatives” (“Update 2010-11”). Update 2010-11 provides clarification with regard to the type of embedded credit derivative that is exempt from embedded derivative bifurcation requirements. Specifically, only one form of embedded credit derivative qualifies for the exemption – one that is related only to the subordination of one financial instrument to another. As a result, entities that have contracts containing an embedded credit derivative feature in a form other than such subordination may need to separately account for the embedded credit derivative feature. The requirements of Update 2010-11 are effective at the start of a reporting entity’s first fiscal year beginning after June 15, 2010 (January 1, 2011 for the Company). The Company will apply the requirements of Update 2010-11 upon its adoption on January 1, 2011 and does not expect it to have a material impact on its financial position, results of operations or related disclosures.

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NOTE 3 – MARCELLUS SHALE JOINT VENTURE

On April 20, 2010, the Company consummated a joint venture transaction with Reliance Industries Limited, whereby Reliance paid approximately $340.0 million in cash for a 40% undivided interest in approximately 300,000 net acres (120,000 net to Reliance) of core undeveloped Marcellus Shale leasehold acreage. The Company recognized a gain of $289.2 million, net of related transaction costs, within its consolidated statements of operations for the nine months ended September 30, 2010 for the sale of the 40% undivided ownership interest in the leasehold acreage. In addition to the cash paid at closing, the Company will receive an additional $1,357.5 million in the form of a drilling carry. During the carry period, Reliance will fund 75% of the Company’s respective portion of drilling and completion costs of the wells developed on the joint venture leasehold acreage. As a result of this provision, the Company will effectively fund 15% of the capital costs required to drill each well, while Reliance will fund 85%, until the $1,357.5 million is fully utilized. The Company has five and one-half years to utilize the drilling carry, with a two-year extension possible if certain conditions are met. The Company serves as the development operator for the joint venture and acts as the sole leasing agent for the joint venture in the area of mutual interest (“AMI”). Reliance will have the option after one year to operate in certain project areas within the AMI, but outside of the Company’s core operating counties in southwestern Pennsylvania. The Company proportionally consolidated its 60% ownership interest in the operating results of the joint venture in its consolidated statements of operations. The Company also proportionally consolidated its ownership interest in the joint venture’s assets, to the extent contributed, and liabilities in its consolidated balance sheets.

Acquisition of additional Marcellus Shale Acreage. In April 2010, the Company and Reliance agreed, through two separate transactions, to purchase an additional approximate 27,500 undeveloped core Marcellus Shale leasehold acres, which are contained within the joint venture’s AMI, for an average purchase price of approximately $4,900 per acre. One of the transactions was for approximately 16,500 leasehold acres for a total purchase price of $81.5 million, which closed in October 2010. The Company was reimbursed $32.6 million by Reliance for its 40% ownership interest in the acreage purchased in this transaction. The other transaction was for approximately 11,000 leasehold acres, for which the Company agreed to pay a total purchase price of $53.0 million at closing, which is expected to occur prior to December 31, 2010. Pursuant to the joint venture agreement, Reliance is obligated for its 40% portion of the cost of this transaction.

NOTE 4 – PROPERTY, PLANT AND EQUIPMENT

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

	September 30, 2010			December 31, 2009			Estimated Useful  Lives in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,319,250		$	1,243,932
Pre-development costs		7,619			6,270
Wells and related equipment		1,120,135			1,017,370
Total proved properties		2,447,004			2,267,572
Unproved properties		68,879			41,816
Support equipment		11,372			8,930
Total natural gas and oil properties		2,527,255			2,318,318
Pipelines, processing and compression facilities		34,388			27,928			15 – 40
Rights of way		183			57			20 – 40
Land, buildings and improvements		8,934			8,768			10 – 40
Other		9,721			7,542			3 – 10
		2,580,481			2,362,613
Less – accumulated depreciation, depletion and amortization		(576,044	)		(491,195	)
	$	2,004,437		$	1,871,418

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NOTE 5 – OTHER ASSETS

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

	September 30, 2010		December 31, 2009
Deferred finance and organization costs, net of accumulated amortization of $13,325 and $9,718 at September 30, 2010 and December 31, 2009, respectively	$	16,910	$	19,743
Other investments		2,142		900
Security deposits		141		263
	$	19,193	$	20,906

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 7).

NOTE 6 – 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 the Company’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. 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,
	2010			2009			2010			2009
Asset retirement obligations, beginning of period	$	53,455		$	50,142		$	51,813		$	48,136
Liabilities incurred		179			125			340			721
Liabilities settled		(222	)		(113	)		(313	)		(198	)
Accretion expense		788			753			2,360			2,248
Asset retirement obligations, end of period	$	54,200		$	50,907		$	54,200		$	50,907

The above accretion expense was included in depreciation, depletion and amortization in the Company’s consolidated statements of operations and the asset retirement obligation liabilities were included within other long-term liabilities in the Company’s consolidated balance sheets.

NOTE 7 – DEBT

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

	September 30, 2010		December 31, 2009
Revolving credit facility	$	76,000	$	184,000
10.75 % senior notes – due 2018		405,372		405,922
12.125 % senior notes – due 2017		196,821		196,468
Total debt		678,193		786,390
Less current maturities		—		—
Total long-term debt	$	678,193	$	786,390

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Revolving Credit Facility

At September 30, 2010, the Company had a credit facility with a syndicate of banks with a borrowing base of $550.0 million that matures in June 2012. The borrowing base is redetermined semiannually on April 1 and October 1 subject to changes in oil and gas reserves and is automatically reduced by 25% of the stated principal of any senior unsecured 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 $1.6 million was outstanding at September 30, 2010, which was not reflected as borrowings on the Company’s consolidated balance sheets. The facility is secured by substantially all of the Company’s assets and is guaranteed by each of its subsidiaries. At September 30, 2010 and December 31, 2009, the weighted average interest rate on outstanding borrowings was 3.0% and 2.9%, respectively. The base rate for any day equals the higher of the federal funds rate plus 0.50%, the J.P. Morgan prime rate or the adjusted LIBOR for a month interest period plus 1.0%. Adjusted LIBOR is LIBOR divided by 1.00 less the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for Eurocurrency liabilities. The facility allows the Company to distribute to ATLS (a) amounts equal to ATLS’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, it may carry over up to $20.0 million for use in the next year.

The events which constitute an event of default for the Company’s credit facility are 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, 2010. The credit facility also requires the Company to maintain a ratio 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 less than or equal to 3.5 to 1.0. Based on the definitions contained in the Company’s credit facility, its ratio of current assets to current liabilities was 2.5 to 1.0 and its ratio of total debt to EBITDA was 2.5 to 1.0 at September 30, 2010.

Senior Notes

At September 30, 2010, 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”). 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, which are shown inclusive of unamortized premium of $5.4 million, are redeemable at any time on or after February 1, 2013, and the 12.125% Senior Notes, which are shown net of unamortized discount of $3.2 million, are redeemable at any time 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 a price equal to 101% of the principal amount of the 10.75% Senior Notes and 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 was in compliance with these covenants as of September 30, 2010.

Cash payments for interest related to debt made by the Company were $75.1 million and $55.7 million for the nine months ended September 30, 2010 and 2009, respectively.

NOTE 8 – DERIVATIVE INSTRUMENTS

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

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The Company formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity and interest derivative contracts to the forecasted transactions. The Company assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Company will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the Company through the utilization of market data, will be recognized immediately within other income in the Company’s consolidated statements of operations. For derivatives qualifying as hedges, the Company recognizes the effective portion of changes in fair value in owner’s equity as accumulated other comprehensive income and reclassifies the portion relating to commodity derivatives to gas and oil production revenues for the Company’s derivatives and the portion relating to interest rate derivatives to interest expense within the Company’s consolidated statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Company recognizes changes in fair value within other income in its consolidated statements of operations as they occur.

Derivatives are recorded on the Company’s consolidated balance sheet as assets or liabilities at fair value. The Company reflected net derivative assets on its consolidated balance sheets of $184.9 million and $113.0 million at September 30, 2010 and December 31, 2009, respectively. Of the $182.1 million of net gain in accumulated other comprehensive income within owner’s equity on the Company’s consolidated balance sheet related to commodity and interest rate derivatives at September 30, 2010, if the fair values of the instruments remain at current market values, the Company will reclassify $76.6 million of gains to the Company’s consolidated statements of operations over the next twelve month period as these contracts expire, consisting of $77.9 million of gains to gas and oil production revenues and $1.3 million of losses to interest expense. Aggregate gains of $105.5 million will be reclassified to the Company’s consolidated statements of operations in later periods as these remaining contracts expire, consisting of gains to gas and oil production revenues. Actual amounts that will be reclassified will vary as a result of future price changes.

The following table summarizes the fair value of the Company’s derivative instruments as of September 30, 2010 and December 31, 2009, as well as the gain or loss recognized in the consolidated statements of operations for effective derivative instruments for the three and nine months ended September 30, 2010 and 2009:

Fair Value of Derivative Instruments:

	Asset Derivatives					Liability Derivatives
Derivatives in Cash Flow Hedging Relationships	Balance Sheet Location	Fair Value					Fair Value
		September  30, 2010		December  31, 2009		Balance Sheet Location	September  30, 2010			December  31, 2009
		(in thousands)					(in thousands)
Commodity contracts:	Current assets	$	103,598	$	73,066	Current liabilities	$	(690	)	$	(901	)
	Long-term assets		108,766		58,930	Long-term liabilities		(25,378	)		(14,091	)
			212,364		131,996			(26,068	)		(14,992	)
Interest rate contracts:	Current assets		—		—	Current liabilities		(1,379	)		(3,751	)
	Long-term assets		—		—	Long-term liabilities		—			(224	)
			—		—			(1,379	)		(3,975	)
Total derivatives		$	212,364	$	131,996		$	(27,447	)	$	(18,967	)

Effects of Derivative Instruments on Consolidated Statements of Operations:
Derivatives in Cash Flow Hedging Relationships	Gain/(Loss) Recognized in  OCI on Derivative (Effective Portion) for the Three Months Ended September 30,						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,
	2010			2009					2010			2009
	(in thousands)								(in thousands)
Commodity contracts	$	60,277		$	5,983			Gas and oil production	$	24,749		$	35,134
Interest rate contracts		(12	)		(966	)		Interest expense		(1,073	)		(1,083	)
	$	60,265		$	5,017				$	23,676		$	34,051
Derivatives in Cash Flow Hedging Relationships	Gain/(Loss) Recognized in  OCI on Derivative (Effective Portion) for the Nine Months Ended September 30,						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,
	2010			2009					2010			2009
	(in thousands)								(in thousands)
Commodity contracts	$	148,248		$	70,269			Gas and oil production	$	69,948		$	82,216
Interest rate contracts		(550	)		(1,971	)		Interest expense		(3,238	)		(3,115	)
	$	147,698		$	68,298				$	66,710		$	79,101

18

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 January 2010, the Company received approximately $20.1 million in net proceeds from the early settlement of natural gas derivative positions for production periods from 2011 through 2013. In August 2010, the Company received approximately $21.5 million in net proceeds from the early settlement of natural gas derivative positions for production periods from 2013 to 2014. In May 2009, the Company received approximately $28.5 million in net proceeds from the early termination of natural gas and oil derivative positions for production periods from 2011 through 2013. In conjunction with the early terminations of these derivatives, the Company entered into new derivative positions at prevailing prices at the time of the transactions. The net proceeds from the early terminations of these derivatives were used to reduce indebtedness under the Company’s revolving credit facility (see Note 7). The gain realized upon the early terminations of these derivative positions will continue to be reported in accumulated other comprehensive income and will be reclassified to 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 recognized gains of $24.7 million and $35.1 million for the three months ended September 30, 2010 and 2009, respectively, and $69.9 million and $82.2 million for the nine months ended September 30, 2010 and 2009, respectively, on settled contracts covering natural gas and oil production. These gains are included within gas and oil production revenue in the Company’s consolidated statements of operations. As the underlying prices and terms in the Company’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three and nine months ended September 30, 2010 and 2009 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

At September 30, 2010, the Company had interest rate derivative contracts with an aggregate notional principal amount of $150.0 million through January 2011. Under the terms of the contracts, the Company will pay a three-year fixed swap interest rate of 3.1%, 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. In April 2010, the Company repaid a portion of its outstanding balance under the revolving credit facility, which had a balance of $76.0 million at September 30, 2010. Prior to the repayment of a portion of the outstanding balance under the revolving credit facility, the interest rate derivative contracts were designated as cash flow hedges. As a result of this reduction in the outstanding balance under the credit facility to an amount below the notional amount of the interest rate derivative contract and the uncertainty of whether the forecasted transaction will occur, the Company discontinued hedge accounting for these derivatives. In accordance with prevailing accounting literature, the portion of any gain or loss in other comprehensive income related to forecasted hedge transactions that are no longer expected to occur are to be removed from other comprehensive income and recognized within the Company’s statements of operations. As a result, the Company recognized a loss of $0.2 million within other income on its consolidated statements of operations for the three months ended September 30, 2010 and a loss of $0.1 million for the nine months ended September 30, 2010 for the change in fair value following the discontinuation of hedge accounting.

19

At September 30, 2010, the Company had the following interest rate and commodity 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 3.1% - Receive LIBOR		2010	$	(1,012	)
						2011		(367	)
							$	(1,379	)
Natural Gas Fixed Price Swaps
Production Period Ending December 31,			Volumes		Average Fixed Price		Fair Value Asset
			(mmbtu)(1)		(per mmbtu)(1)		(in thousands)(2)
2010				10,070,000	$	7.387	$	34,670
2011				26,480,000	$	6.591		56,805
2012				20,852,300	$	6.797		35,663
2013				13,211,500	$	5.915		8,047
2014				6,960,000	$	5.714		1,953
							$	137,138
Natural Gas Costless Collars
Production Period Ending December 31,	Option Type		Volumes		Average Floor and Cap		Fair Value Asset/ (Liability)
			(mmbtu)(1)		(per mmbtu)(1)		(in thousands)(2)
2010		Puts purchased		1,290,000	$	6.605	$	3,480
2010		Calls sold		1,290,000	$	7.805		(1	)
2011		Puts purchased		13,380,000	$	6.147		24,551
2011		Calls sold		13,380,000	$	7.236		(658	)
2012		Puts purchased		12,240,000	$	6.052		18,731
2012		Calls sold		12,240,000	$	7.160		(4,063	)
2013		Puts purchased		14,880,000	$	5.311		18,005
2013		Calls sold		14,880,000	$	6.522		(11,943	)
2014		Puts purchased		6,840,000	$	5.337		9,268
2014		Calls sold		6,840,000	$	6.461		(7,409	)
							$	49,961
Crude Oil Fixed Price Swaps
Production Period Ending December 31,			Volumes		Average Fixed Price		Fair Value Asset/ (Liability)
			(Bbl) (1)		(per Bbl)(1)		(in thousands)(3)
2010				12,600	$	97.060	$	230
2011				42,600	$	77.460		(299	)
2012				33,500	$	76.855		(343	)
2013				10,000	$	77.360		(104	)
							$	(516	)

20

Crude Oil Costless Collars

Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap		Fair Value Asset/(Liability)
		(Bbl)(1)		(per Bbl)(1)		(in thousands)(3)
2010	Puts purchased		8,000	$	85.000	$	54
2010	Calls sold		8,000	$	112.219		—
2011	Puts purchased		27,000	$	67.223		82
2011	Calls sold		27,000	$	89.436		(221	)
2012	Puts purchased		21,500	$	65.506		102
2012	Calls sold		21,500	$	91.448		(258	)
2013	Puts purchased		6,000	$	65.358		37
2013	Calls sold		6,000	$	93.442		(83	)
						$	(287	)
					Total Company net asset	$	184,917

⁽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, 2010 and December 31, 2009, net unrealized derivative assets of $74.2 million and $41.7 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, 2010			December 31, 2009
Current portion of derivative receivable from Partnerships	$	56		$	270
Long-term derivative receivable from Partnerships		5,481			2,841
Current portion of derivative payable to Partnerships		(36,637	)		(22,382	)
Long-term portion of derivative payable to Partnerships		(43,055	)		(22,380	)
	$	(74,155	)	$	(41,651	)

NOTE 9 – 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 – Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Company uses a fair value methodology to value the assets and liabilities for its derivative contracts (see Note 8). The Company’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. The Company’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model and are therefore defined as Level 2 fair value measurements. Information for assets and liabilities measured at fair value on a recurring basis at September 30, 2010 and December 31, 2009 was as follows (in thousands):

	Level 1		Level 2			Level 3		Total
September 30, 2010
Commodity-based derivatives		—		186,296			—		186,296
Interest rate derivatives		—		(1,379	)		—		(1,379	)
Total	$	—	$	184,917		$	—	$	184,917
December 31, 2009
Commodity-based derivatives		—		117,003			—		117,003
Interest rate derivatives		—		(3,974	)		—		(3,974	)
Total	$	—	$	113,029		$	—	$	113,029

21

Other Financial Instruments

The estimated fair value of the Company’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Company could realize upon the sale or refinancing of such financial instruments.

The Company’s other current assets and liabilities on its consolidated balance sheets are financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature. The estimated fair values of the Company’s debt at September 30, 2010 and December 31, 2009, which consists principally of its Senior Notes and borrowings under its credit facility, were $751.5 million and $853.0 million, respectively, compared with the carrying amounts of $678.2 million and $786.4 million, respectively. The Senior Notes were valued based upon recent trading activity. The carrying value of outstanding borrowings under the credit facility, which bear interest at a variable interest rate, approximates their estimated fair value.

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

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 6). Information for assets that are measured at fair value on a nonrecurring basis for the three and nine months ended September 30, 2010 and 2009 was as follows (in thousands):

	Three Months Ended September 30,
	2010				2009
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	179	$	179	$	125	$	125
Total	$	179	$	179	$	125	$	125
	Nine Months Ended September 30,
	2010				2009
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	340	$	340	$	721	$	721
Total	$	340	$	340	$	721	$	721

NOTE 10 – 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 ATLS. ATLS 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 ATLS. 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 ATLS’s cash management program. Any transaction performed by ATLS 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.

22

Relationship with the Company’s Sponsored Investment Partnerships. The Company conducts certain activities through, and a portion of its revenues are attributable to, the Partnerships. The Company serves as general partner and operator of the Partnerships and assumes customary rights and obligations for the Partnerships. As the general partner, the Company is liable for the Partnerships’ liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Partnerships. The 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. On May 31, 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) (“APL”), and The Williams Companies, Inc. (NYSE: WMB). (“Williams”). Upon contribution of its Appalachia Basin natural gas gathering system to Laurel Mountain, APL 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. APL is a subsidiary of the Company’s parent company, ATLS. Laurel Mountain owns and operates all of APL’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 $6.5 million during the year ended December 31, 2009. The Company used the net proceeds from the sale to repay outstanding borrowings under its revolving credit facility.

Upon completion of APL’s formation of the Laurel Mountain joint venture, 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 APL. Pursuant to these gas gathering agreements with Laurel Mountain, the Company generally pays a gathering fee equal to 16% of the realized natural gas sales price (adjusted for the settlement of natural gas derivative instruments). However, in most of the Company’s direct investment partnerships, it collects a gathering fee of 13% of the realized natural gas sales price per the respective partnership agreement. As a result, the Company’s Appalachian gathering expenses within its partnership management segment will generally exceed the revenues collected from the investment partnerships by approximately 3%. 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. Unlike the terminated agreements, ATLS will not assume or guarantee the Company’s obligation to pay gathering fees to Laurel Mountain.

Relationship with Crown Drilling of Pennsylvania, LLC. The Company has an equity interest in Crown Drilling of Pennsylvania, LLC (“Crown”), a company that performs the drilling activities for certain of the Company’s investment partnerships. In addition to its equity ownership, the Company guarantees 50% of the outstanding balances of Crown’s credit agreement. As of September 30, 2010, the Company’s guarantee was limited to $9.5 million.

NOTE 11 – 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 months ended September 30, 2010 and 2009, $3.7 million and $1.3 million, respectively, of the Company’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the investment partnerships. For the nine months ended September 30, 2010 and 2009, $8.9 million and $2.2 million, respectively, of net revenues were subordinated.

The Company is party to employment agreements with certain executives that provide compensation and certain other benefits. The agreements also provide for severance payments under certain circumstances.

As of September 30, 2010, the Company is committed to expend approximately $86.6 million on drilling and completion expenditures.

23

Legal Proceedings

Following the announcement of the Merger on April 27, 2009, five purported class actions were filed in Delaware Chancery Court and were later consolidated into a single complaint, In re Atlas Energy Resources, LLC Unitholder Litigation, C.A. No. 4589-VCN (the “Consolidated Action”) filed on July 1, 2009 (the “Consolidated Complaint”). The Consolidated Complaint named ATLS and various officers and directors of the Company as defendants (the “Defendants”), alleged violations of fiduciary duties in connection with the Merger, and requested injunctive relief and damages.

In October 2009, the Company filed a motion to dismiss the Consolidated Complaint. Subsequently, in December 2009, plaintiffs filed an Amended Complaint (the “Amended Complaint”). The Amended Complaint alleges that Defendants breached their purported fiduciary duties to ATN’s public unitholders in connection with their negotiation of the Merger. In particular, plaintiffs allege that the Merger was not entirely fair to ATN’s public unitholders, and that Defendants conducted the Merger process in bad faith. Pursuant to the Delaware Chancery Court’s (the “Court”) January 2010 Scheduling Stipulation and Order, Defendants filed their opening brief in support of their motion to dismiss on February 18, 2010 and plaintiffs filed their brief in opposition on May 3, 2010. Defendants filed a reply brief on June 11, 2010 and oral argument was held on the motion on July 20, 2010. The Court dismissed the claims against all of the directors and officers named as defendants. The Court held that there was no showing that any individual defendant acted in bad faith. However, the Court ruled that the plaintiffs could proceed with their claim against the Company.

In June 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 the decision. On May 18, 2010, the appeal was argued before the Tennessee Court of Appeals. The parties are awaiting the court’s decision.

The Company is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Company’s financial condition or results of operations.

NOTE 12 – BENEFIT PLANS

Prior to the Merger on September 29, 2009, the Company had a Long-Term Incentive Plan (“LTIP”), which provided equity incentive awards to officers, employees and directors and employees of its affiliates, consultants and joint-venture partners. Subsequent to the Merger, ATLS assumed the Company’s LTIP and renamed the LTIP as 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 ATLS at a ratio of 1.0 Company common unit to 1.16 ATLS common shares. No new grant awards will be issued under the Assumed LTIP.

Other than the conversion of the LTIP awards to ATLS options, restricted shares or phantom shares, the terms of the grants that had been awarded under the LTIP remain unchanged under the Assumed LTIP. Awards granted to all participants other than non-employee directors vest 25% upon the third anniversary of the grant date and 75% upon the fourth anniversary of the grant date. Awards to non-employee directors vest 25% per year over four years. Generally, upon termination of service by a grantee, all unvested awards will be forfeited. Upon vesting of a phantom stock award, a grantee is entitled to receive an equivalent number of common shares of ATLS. Non-employee directors have the right, upon the vesting of their phantom stock awards to receive an equivalent number of common shares or, the cash equivalent to the then fair market value of ATLS common shares.

24

Restricted Unit and Phantom Units. The fair value of the grants under the Assumed LTIP was based on the closing unit price on the grant date, and was charged to operations over the requisite service periods using the straight-line method. The following table summarizes the pre-Merger unconverted restricted unit and phantom unit activity for the period beginning January 1, 2009 through September 29, 2009:

	Number of Units(1)			Weighted Average Grant Date Fair Value(1)
Non-vested units outstanding at January 1, 2009		768,829		$	23.86
Granted		28,523		$	16.48
Vested(2)		(13,073	)	$	21.70
Forfeited		(46,000	)	$	31.12
Non-vested outstanding at September 29, 2009		738,279		$	23.16
Converted non-vested Atlas Energy stock phantom and restricted stock units outstanding at September 29, 2009		856,404		$	19.97
Non-cash compensation expense recognized (in thousands)	$	2,766

⁽¹⁾ The shares and fair values for the period beginning January 1, 2009 through September 29, 2009 (pre-Merger shares) have not been adjusted to reflect the post-Merger conversion of 1.0 Company common unit to 1.16 ATLS common shares.

⁽²⁾ The intrinsic value for vested shares for the period beginning January 1, 2009 through September 29, 2009 was $0.2 million. No shares vested during the period beginning July 1, 2009 through September 29, 2009.

Unit Options. Option awards under the Assumed LTIP expire 10 years from the date of grant and were granted with an exercise price equal to the market price of the Company’s stock at the date of grant. For the period beginning January 1, 2009 through September 29, 2009, the following table summarizes the unconverted number of the Company’s Class B member units prior to the Merger on September 29, 2009 and weighted average exercise price. There were no proceeds from the exercise of options during the period beginning January 1, 2009 through September 29, 2009. The following table sets forth the LTIP option activity for the period indicated:

	Number of Units(1)			Weighted Average Exercise Price(1)
Outstanding at January 1, 2009		1,902,902		$	24.17
Granted		5,000		$	25.78
Exercised		—		$	—
Forfeited or expired		(123,600	)	$	31.96
Outstanding at September 29, 2009		1,784,302		$	23.64
Converted non-vested Atlas Energy stock options outstanding at September 29, 2009		2,069,790		$	20.38
Non-cash compensation expense recognized (in thousands)	$	640

(1) The shares and fair values for the period beginning January 1, 2009 through September 29, 2009 (pre-Merger shares) have not been adjusted to reflect the post-Merger conversion of 1.0 Company common unit to 1.16 ATLS common shares.

The Company recognized $0.4 million and $3.4 million in compensation expense related to the restricted stock units, phantom units and unit options for the three months and nine months ended September 30, 2009, respectively. The Company paid $0.4 million with respect to distribution equivalent rights (“DER”) for the nine months ended September 30, 2009. No payment was made with respect to its LTIP DERs for the three months ended September 30, 2009. This amount was recorded as a reduction of members’ equity on the Company’s consolidated balance sheet during the respective period. At September 30, 2010, the Company had no unrecognized compensation expense related to the unvested portion of the restricted shares, phantom shares and stock options.

25

NOTE 13 – 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. Operating segment data for the periods indicated are as follows (in thousands):

	Three Months Ended September 30,						Nine Months  Ended September 30,
	2010			2009			2010			2009
Gas and oil production
Revenues	$	67,503		$	65,986		$	200,600		$	207,908
Costs and expenses		(13,799	)		(12,129	)		(39,179	)		(39,421	)
Depreciation, depletion and amortization expense		(28,813	)		(23,486	)		(83,240	)		(76,612	)
Segment income	$	24,891		$	30,371		$	78,181		$	91,875
Well construction and completion
Revenues	$	60,748		$	81,496		$	176,685		$	257,231
Costs and expenses		(51,481	)		(69,138	)		(149,724	)		(218,236	)
Segment income	$	9,267		$	12,358		$	26,961		$	38,995
Other partnership management (1)
Revenues	$	14,906		$	14,460		$	41,183		$	41,045
Costs and expenses		(10,318	)		(10,351	)		(30,469	)		(25,873	)
Depreciation, depletion and amortization expense		(1,444	)		(1,077	)		(3,992	)		(3,254	)
Segment income	$	3,144		$	3,032		$	6,722		$	11,918
Reconciliation of segment income to net income
Segment income
Gas and oil production	$	24,891		$	30,371		$	78,181		$	91,875
Well construction and completion		9,267			12,358			26,961			38,995
Other partnership management		3,144			3,032			6,722			11,918
Total segment income		37,302			45,761			111,864			142,788
General and administrative expenses(2)		(15,533	)		(20,573	)		(42,595	)		(47,390	)
Gain (loss) on asset sales(2)		609			(1,444	)		286,308			(5,694	)
Interest expense(2)		(17,387	)		(19,161	)		(52,406	)		(47,269	)
Net income	$	4,991		$	4,583		$	303,171		$	42,435
Capital expenditures
Gas and oil production	$	93,890		$	24,938		$	246,817		$	105,324
Well construction and completion		—			—			—			—
Other partnership management		2,773			8,886			9,514			24,493
Corporate		500			548			1,093			968
Total capital expenditures	$	97,163		$	34,372		$	257,424		$	130,785

	September 30, 2010		December 31, 2009
Balance sheet
Goodwill:
Gas and oil production	$	21,527	$	21,527
Well construction and completion		6,389		6,389
Other partnership management		7,250		7,250
	$	35,166	$	35,166
Total assets:
Gas and oil production	$	2,282,159	$	2,115,867
Well construction and completion		12,304		12,054
Other partnership management		50,528		44,311
Corporate		131,722		36,521
	$	2,476,713	$	2,208,753

⁽¹⁾ Includes revenues and expenses from well services, transportation and administration and oversight that do not meet the quantitative threshold for reporting segment information.

⁽²⁾ The Company notes that interest expense, general and administrative expenses, and gain (loss) on asset sales have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.

NOTE 14 – SUBSEQUENT EVENTS

Merger Agreement.    On November 9, 2010, ATLS announced that it entered into a definitive merger agreement (the “Merger Agreement”) with Chevron Corporation (“Chevron”), pursuant to which Chevron agreed to acquire ATLS through a merger of a newly formed wholly owned subsidiary of Chevron with and into ATLS (the “Merger”). In the Merger, each share of ATLS common stock will receive $38.25 in cash, and each share of outstanding ATLS common stock will also receive a pro rata share of the distribution of approximately 41 million common units of Atlas Pipeline Holdings, L.P. (“AHD”) held by ATLS.

Concurrently with entering into the Merger Agreement, ATLS and the Company entered into a transaction agreement (the “Transaction Agreement”) with AHD, pursuant to which the Company agreed to sell to AHD approximately 175 Bcfe of natural gas reserves, certain other energy assets and fee revenues from the investment management business owned by ATLS, for $250 million, comprised of approximately 23.38 million AHD units (which had a value of approximately $220 million as of November 8, 2010) and $30 million in cash (“AHD Sale”). Following the issuance of these AHD units to ATLS, ATLS will own approximately 41 million units of AHD, or approximately 81% of the outstanding units of AHD, all of which will be distributed to ATLS’s shareholders immediately prior to the Merger. AHD will also acquire the general partner interest in AHD so that, following the AHD distribution, AHD will cease to be controlled by ATLS.

Concurrently with entering into the Merger Agreement and the Transaction Agreement, the Company and Atlas Pipeline Partners, L.P. ( “APL”) have agreed that, prior to the Merger, the Company will acquire APL’s 49% interest in Laurel Mountain Midstream, LLC for $403 million in cash payable to APL (the “LMM Sale”).

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

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

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, “Risk Factors”, in our annual report on Form 10-K for the year ended December 31, 2009. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. 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.

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 appearing elsewhere in this report. Since we meet the requirements within General Instruction H(1)(a) and (b) of Form 10-Q, Item 2 has been presented in a reduced disclosure format pursuant to the guidelines within General Instruction H.

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. We have also 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 Shale. 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.

The following table presents the number of wells we drilled, both gross and for our interest, and the number of gross wells we turned in line during the three and nine months ended September 30, 2010 and 2009:

	Three Months Ended September 30				Nine Months Ended September 30
	2010		2009		2010		2009
Gross wells drilled:
Appalachia:
Partnerships		15		27		25		125
Marcellus Shale joint venture		17		—		28		—
Our direct interest		—		3		—		5
		32		30		53		130
Michigan/Indiana:
Partnerships		30		11		57		47
Our direct interest		3		—		3		3
		33		11		60		50
Gross wells drilled		65		41		113		180
Our share of gross wells drilled(1):
Appalachia:
Partnerships		5		7		7		29
Marcellus Shale joint venture		8		—		15		—
Our direct interest		—		2		—		3
		13		9		22		32
Michigan/Indiana:
Partnerships		7		3		14		11
Our direct interest		1		—		1		1
		8		3		15		12
Our share of gross wells drilled		21		12		37		44
Gross wells turned in line:
Appalachia:
Partnerships		11		57		78		270
Marcellus Shale joint venture		4		—		4		—
Our direct interest		1		1		11		3
		16		58		93		273
Michigan/Indiana:
Partnerships		34		12		65		41
Our direct interest		—		2		3		15
		34		14		68		56
Gross wells turned in line		50		72		161		329

⁽¹⁾ Includes (i) our percentage interest in the wells in which we have a direct ownership interest and (ii) our percentage interest in the wells based on our percentage interest in our investment partnerships.

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Production Volumes. The following table presents our total net gas and oil production volumes and production per day during the three and nine months ended September 30, 2010 and 2009:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2010			2009		2010			2009
Production:(1)(2)
Appalachia:(3)
Natural gas (MMcf)		5,295			3,549		13,419			10,851
Oil (000’s Bbls)		89	(4)		42		246	(4)		121
Total (MMcfe)		5,827			3,803		14,892			11,575
Michigan/Indiana:
Natural gas (MMcf)		5,039			5,384		14,933			15,910
Oil (000’s Bbls)		3	(4)		1		8	(4)		2
Total (MMcfe)		5,055			5,389		14,983			15,924
Total:
Natural gas (MMcf)		10,334			8,933		28,352			26,761
Oil (000’s Bbls)		91	(4)		43		254	(4)		123
Total (MMcfe)		10,882			9,192		29,875			27,499
Production per day: (1)(2)
Appalachia:(3)
Natural gas (Mcfd)		57,554			38,579		49,155			39,748
Oil (Bpd)		964	(4)		460		899	(4)		442
Total (Mcfed)		63,339			41,339		54,551			42,400
Michigan/Indiana:
Natural gas (Mcfd)		54,777			58,519		54,700			58,277
Oil (Bpd)		28	(4)		9		30	(4)		9
Total (Mcfed)		54,944			58,573		54,882			58,331
Total:
Natural gas (Mcfd)		112,331			97,099		103,855			98,024
Oil (bpd)		992	(4)		469		930	(4)		451
Total (Mcfed)		118,283			99,913		109,433			100,730

⁽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.

⁽⁴⁾ Includes NGL production volume for the three and nine months ended September 30, 2010.

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Production Revenues, Prices and Costs. Our production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised 99% of our proved reserves on an energy equivalent basis at December 31, 2009. The following table presents our production revenues and average sales prices for our natural gas and oil production for the three and nine months ended September 30, 2010 and 2009, 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,
	2010			2009		2010			2009
Production revenues (in thousands):
Appalachia:(1)
Natural gas revenue	$	24,988		$	22,802	$	73,589		$	79,873
Oil revenue		4,318	(6)		3,185		13,228	(6)		8,264
Total revenues	$	29,306		$	25,987	$	86,817		$	88,137
Michigan/Indiana:
Natural gas revenue	$	38,130		$	39,946	$	113,533		$	119,646
Oil revenue		67	(6)		53		250	(6)		125
Total revenues	$	38,197		$	39,999	$	113,783		$	119,771
Total:
Natural gas revenue	$	63,118		$	62,748	$	187,122		$	199,519
Oil revenue		4,385	(6)		3,238		13,478	(6)		8,389
Total revenues	$	67,503		$	65,986	$	200,600		$	207,908
Average sales price:(2)
Natural gas (per Mcf):
Total realized price, after hedge(3) (4)	$	6.62		$	7.29	$	7.08		$	7.67
Total realized price, before hedge(3) (4)	$	4.35		$	3.19	$	4.74		$	4.01
Oil (per Bbl):
Total realized price, after hedge	$	73.73		$	75.03	$	74.67		$	68.13
Total realized price, before hedge	$	65.82		$	62.81	$	68.44		$	52.30
Production costs (per Mcfe):(2)
Appalachia:(1)
Lease operating expenses(5)	$	0.76		$	0.98	$	0.88		$	1.04
Production taxes		0.02			0.03		0.03			0.03
Transportation and compression		0.78			0.75		0.72			0.78
	$	1.56		$	1.76	$	1.62		$	1.85
Michigan/Indiana:
Lease operating expenses	$	0.80		$	0.69	$	0.80		$	0.70
Production taxes		0.28			0.22		0.29			0.25
Transportation and compression		0.22			0.23		0.23			0.24
	$	1.30		$	1.14	$	1.32		$	1.20
Total:
Lease operating expenses(5)	$	0.78		$	0.81	$	0.84		$	0.84
Production taxes		0.14			0.14		0.16			0.16
Transportation and compression		0.52			0.45		0.47			0.47
	$	1.44		$	1.40	$	1.47		$	1.47

⁽¹⁾ Appalachia includes our operations located in Pennsylvania, Ohio, New York, West Virginia and Tennessee.

⁽²⁾ “Mcf” represents thousand cubic feet; “Mcfe” represents thousand cubic feet equivalents; and “Bbl” represents barrels.

⁽³⁾ Excludes the impact of certain allocations of production revenue to investor partners within our investment partnerships for the three and nine months ended September 30, 2010 and 2009. Including the effect of these allocations, the average realized gas sales price were $6.08 per Mcf ($3.81 per Mcf before the effects of financial hedging) and $7.06 per Mcf ($2.97 per Mcf before the effects of financial hedging) for the three months ended September 30, 2010 and 2009, respectively, and $6.60 per Mcf ($4.26 per Mcf before the effects of financial hedging) and $7.55 per Mcf ($3.89 per mcf before the effects of financial hedging) for the nine months ended September 30, 2010 and 2009, respectively.

⁽⁴⁾ Includes adjustments of $(0.2) million and $0.4 million for the three months ended September 30, 2010 and 2009, respectively, and $(0.1) million and $2.4 million for the nine months ended September 30, 2010 and 2009, respectively, related to cash proceeds received and payments made in June 2007 from the settlement of ineffective derivatives associated with the acquisition of our Michigan operations.

⁽⁵⁾ 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, Appalachia lease operating expenses per Mcfe were $0.44 per Mcfe ($1.24 per Mcfe for total production costs) and $0.80 per Mcfe ($1.58 per Mcfe for total production costs) for the three months ended September 30, 2010 and 2009, respectively, and $0.56 per Mcfe ($1.31 per Mcfe for total production costs) and $0.94 per Mcfe ($1.75 per Mcfe for total production costs) for the nine months ended September 30, 2010 and 2009, respectively. Including the effects of these costs, total lease operating expenses per Mcfe were $0.61 per Mcfe ($1.27 per Mcfe for total production costs) and $0.73 per Mcfe ($1.32 per Mcfe for total production costs) for the three months ended September 30, 2010 and 2009, respectively, and $0.68 per Mcfe ($1.31 per Mcfe for total production costs) and $0.80 per Mcfe ($1.43 per Mcfe for total production costs) for the nine months ended September 30, 2010 and 2009, respectively.

⁽⁶⁾ Includes NGL production revenue for the three and nine months ended September 30, 2010.

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Three Months Ended September 30, 2010 Compared with the Three Months Ended September 30, 2009. Total natural gas revenues were $63.1 million for the three months ended September 30, 2010, an increase of $0.4 million from $62.7 million for the three months ended September 30, 2009. This increase consisted of a $9.3 million increase attributable to higher natural gas production volumes, partially offset by a $5.3 million decrease attributable to lower realized natural gas prices and a $3.6 million increase in gas revenues allocated to the investor partners within our investment partnerships for the three months ended September 30, 2010 compared with the prior year period. Total oil revenues were $4.4 million for the three months ended September 30, 2010, an increase of $1.2 million from $3.2 million for the comparable prior year period. This increase resulted primarily from a $1.7 million increase from the sale of natural gas liquids, partially offset by a $0.5 million decrease associated with lower oil production volumes and lower average realized prices.

Appalachia production costs were $7.2 million for the three months ended September 30, 2010, an increase of $1.2 million from $6.0 million for the three months ended September 30, 2009. This increase was principally due to a $1.7 million increase in transportation costs associated with the Laurel Mountain joint venture and a $0.7 million increase associated with labor, maintenance expenses and other costs associated with the growth of our operations. This amount was partially offset by a $1.2 million increase associated with our proportionate share of lease operating expenses associated with our revenue that was allocated to the investor partners within our investment partnerships. Michigan/Indiana production costs were $6.6 million for the three months ended September 30, 2010, an increase of $0.5 million from $6.1 million for the comparable prior year period. This increase was primarily attributable to a $0.2 million increase for production-related taxes, a $0.2 million increase in parts and materials expenses due to timing of purchases and a $0.1 million increase in compression station expenses.

Nine Months Ended September 30, 2010 Compared with the Nine Months Ended September 30, 2009. Total natural gas revenues were $187.1 million for the nine months ended September 30, 2010, a decrease of $12.4 million from $199.5 million for the nine months ended September 30, 2009. This decrease consisted of a $13.4 million decrease attributable to lower realized natural gas prices and a $10.3 million increase in gas revenues allocated to the investor partners within our investment partnerships for the nine months ended September 30, 2010 compared with the prior year period, partially offset by a $11.3 million increase attributable to higher natural gas production volumes. Total oil revenues were $13.5 million for the nine months ended September 30, 2010, an increase of $5.1 million from $8.4 million for the comparable prior year period. This increase resulted primarily from a $5.1 million increase from the sale of natural gas liquids and a $0.7 million increase associated with higher average realized oil prices, partially offset by a $0.7 million decrease associated with lower oil production volumes.

Appalachia production costs were $19.5 million for the nine months ended September 30, 2010, a decrease of $0.8 million from $20.3 million for the nine months ended September 30, 2009. This decrease was principally due to a $3.6 million increase associated with our proportional share of lease operating expenses associated with our revenue that was allocated to the investor partners within our investment partnerships, partially offset by a $1.6 million increase in transportation costs due to increased production volume and a $1.2 million increase in other production related expenses. Michigan/Indiana production costs were $19.7 million for the nine months ended September 30, 2010, an increase of $0.6 million from $19.1 million for the comparable prior year period. This increase was primarily attributable to a $0.5 million increase in parts and materials expenses due to timing of purchases and a $0.4 million increase for production-related taxes, partially offset by a decrease of $0.3 million associated with transportation expenses.

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PARTNERSHIP MANAGEMENT

Well Construction and Completion

Drilling Program Results. The number of wells we drill will vary within the partnership management segment 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 amounts of drilling partnership investor capital raised and deployed (in thousands), as well as the number of gross and net development wells we drilled for our investment partnerships during the three and nine months ended September 30, 2010 and 2009. We drilled one exploratory well during the three and nine months ended September 30, 2010. There were no exploratory wells drilled during the three and nine months ended September 30, 2009:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Drilling partnership investor capital:
Raised	$	119,919	$	9,177	$	149,336	$	131,177
Deployed	$	60,748	$	81,496	$	176,685	$	257,231
Gross partnership wells drilled:
Appalachia		15		27		25		125
Michigan/Indiana		30		11		57		47
Total		45		38		82		172
Net partnership wells drilled:
Appalachia		15		26		25		111
Michigan/Indiana		26		10		49		43
Total		41		36		74		154

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 during the periods indicated (dollars in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Average construction and completion:
Revenue per well	$	1,321	$	2,328	$	1,749	$	1,513
Cost per well		1,119		1,975		1,482		1,284
Gross profit per well	$	202	$	353	$	267	$	229
Gross profit margin	$	9,267	$	12,358	$	26,961	$	38,995
Partnership net wells associated with revenue recognized(1):
Marcellus Shale - horizontal		3		1		8		4
Marcellus Shale - vertical		1		20		23		59
Tennessee - horizontal		—		3		8		9
Tennessee - vertical		3		—		3		—
Michigan/Indiana - horizontal		29		7		48		18
Michigan/Indiana - vertical		5		4		6		22
Other - shallow		5		—		5		58
		46		35		101		170

⁽¹⁾ Consists of Partnership net wells for which well construction and completion revenue was recognized on a percentage of completion basis.

Three Months Ended September 30, 2010 Compared with the Three Months Ended September 30, 2009. Well construction and completion segment margin was $9.3 million for the three months ended September 30, 2010, a decrease of $3.1 million from $12.4 million for the three months ended September 30, 2009. This decrease was due to a $5.3 million decrease associated with lower gross profit per well, partially offset by a $2.2 million related to an increase in the number of wells recognized for revenue within the investment partnerships. Since our drilling contracts with the investment partnerships are on a “cost-plus” basis (typically cost-plus 18%), an increase or decrease in our average cost per well also results in a proportionate increase or decrease in our average revenue per well, which directly affects the number of wells we drill. Average cost and revenue per well have decreased due to a shift to drilling Michigan/Indiana wells within the investor partnerships subsequent to the formation of our Marcellus Shale joint venture in the second quarter 2010. Typically, Michigan/Indiana wells have a lower cost per well as compared to Marcellus Shale wells.

31

Our consolidated balance sheet at September 30, 2010 includes $95.2 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 2010.

Nine Months Ended September 30, 2010 Compared with the Nine Months Ended September 30, 2009. Well construction and completion segment margin was $27.0 million for the nine months ended September 30, 2010, a decrease of $12.0 million from $39.0 million for the nine months ended September 30, 2009. This decrease was due to a $18.4 million decrease associated with a decline in the number of wells recognized for revenue within the investment partnerships, partially offset by a $6.4 million increase due to increased gross profit per well. Average cost and revenue per well have increased due to a shift, principally during the first quarter 2010, from drilling less expensive shallow partnership wells to more expensive deep or horizontal shale partnership wells in both Appalachia and Michigan/Indiana during the nine months ended September 30, 2010 in comparison to the comparable prior year period.

Administration and Oversight

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

Three Months Ended September 30, 2010 Compared with the Three Months Ended September 30, 2009. Administration and oversight fee revenues were $3.6 million for the three months ended September 30, 2010, an increase of $0.5 million from $3.1 million for the three months ended September 30, 2009. This increase was primarily due to an increase in the number of wells drilled during the current year period in comparison to the prior year period.

Nine Months Ended September 30, 2010 Compared with the Nine Months Ended September 30, 2009. Administration and oversight fee revenues were $7.5 million for the nine months ended September 30, 2010, a decrease of $2.1 million from $9.6 million for the nine months ended September 30, 2009. This decrease was primarily due to fewer wells drilled during the current year period in comparison to the prior year comparable period, partially offset by an increase in the number of Marcellus Shale horizontal wells drilled, for which we earn higher fees for our partnership management activities in comparison to conventional wells.

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.

Three Months Ended September 30, 2010 Compared with the Three Months Ended September 30, 2009. Well services revenues were $6.0 million for the three months ended September 30, 2010, an increase of $1.0 million from $5.0 million for the three months ended September 30, 2009. Well services expenses were $2.8 million for three months ended September 30, 2010, an increase of $0.4 million from $2.4 million for the three months ended September 30, 2009. These increases were primarily attributable to an increase in the number of producing wells.

Nine Months Ended September 30, 2010 Compared with the Nine Months Ended September 30, 2009. Well services revenues were $17.1 million for the nine months ended September 30, 2010, an increase of $2.2 million from $14.9 million for the nine months ended September 30, 2009. Well services expenses were $8.1 million for nine months ended September 30, 2010, an increase of $1.2 million from $6.9 million for the nine months ended September 30, 2009. These increases were primarily attributable to an increase in the number of producing wells.

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. (“APL”), our affiliate, contributed its Appalachian gathering systems to Laurel Mountain, a joint venture in which APL 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 investment partnerships. During the period from January 1, 2009 to June 1, 2009, we were required to remit these gathering fees to ATLS, who in turn remitted them to APL.

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Pursuant to these gas gathering agreements with Laurel Mountain, we generally pay a gathering fee equal to 16% of the realized natural gas sales price (adjusted for the settlement of natural gas derivative instruments). However, in most of our direct investment partnerships, we collect a gathering fee of 13% of the realized natural gas sales price per the respective partnership agreement. As a result, our Appalachian gathering expenses within our partnership management segment will generally exceed the revenues collected from the investment partnerships by approximately 3%.

For the three months ended September 30, 2010 and 2009, we received $5.3 million and $6.1 million, respectively, in gathering fees collected from our investment partnerships and were obligated to remit $7.5 million and $8.0 million, respectively, in gathering expense. For the nine months ended September 30, 2010 and 2009, we received $15.5 million and $16.2 million, respectively, in gathering fees collected from our investment partnerships and were obligated to remit $22.4 million and $19.0 million, respectively, in gathering expense. The increase in net gathering expense between periods was principally due to lower investment partnership volumes, a decrease in natural gas prices and an increase in our equity natural gas volumes due to an increase in the number of wells drilled for our own account.

OTHER COSTS AND EXPENSES

General and Administrative

Total general and administrative expenses, including amounts reimbursed to affiliates, decreased to $15.5 million for the three months ended September 30, 2010 compared with $20.6 million for the three months ended September 30, 2009 due principally to a decrease in restructuring costs related to our merger with ATLS in September 2009, partially offset by an increase in wages and other corporate activities related to the increase in drilling activities in our Marcellus Shale acreage.

Total general and administrative expenses, including amounts reimbursed to affiliates, decreased to $42.6 million for the nine months ended September 30, 2010 compared with $47.4 million for the nine months ended September 30, 2009 due principally to a decrease in restructuring costs related to our merger with ATLS in September 2009, partially offset by an increase in wages and other corporate activities related to the increase in drilling activities in our Marcellus Shale acreage.

Depreciation, Depletion and Amortization

Total depreciation, depletion and amortization increased to $30.3 million for the three months ended September 30, 2010 compared with $24.6 million for the comparable prior year period, due primarily to a $5.3 million increase in our depletion expense. Total depreciation, depletion and amortization increased to $87.2 million for the nine months ended September 30, 2010 compared with $79.9 million for the comparable prior year period, due primarily to a $6.6 million increase in our depletion expense.

The following table presents our depletion expense, excluding amounts attributable to APL and AHD, per Mcfe for our Appalachia and Michigan/Indiana regions for the respective periods:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Depletion expense (in thousands):
Appalachia	$	13,836		$	9,383		$	38,665		$	34,645
Michigan/Indiana		14,977			14,103			44,575			41,967
Total	$	28,813		$	23,486		$	83,240		$	76,612
Depletion expense as a percentage of gas and oil production revenue		43	%		36	%		41	%		37	%
Depletion per Mcfe:
Appalachia	$	2.37		$	2.47		$	2.60		$	2.99
Michigan/Indiana	$	2.96		$	2.62		$	2.98		$	2.64
Total	$	2.65		$	2.56		$	2.79		$	2.79

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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. For the three months ended September 30, 2010, depletion expense increased $5.3 million to $28.8 million compared with $23.5 million for the three months ended September 30, 2009. Our depletion expense of oil and gas properties as a percentage of oil and gas revenues was 43% for the three months ended September 30, 2010, compared with 36% for the three months ended September 30, 2009. Depletion expense per Mcfe was $2.65 for the three months ended September 30, 2010, an increase of $0.09 per Mcfe from $2.56 for the three months ended September 30, 2009. Depletion expense increased between periods principally due to an overall increase in production volumes, partially offset by a $156.4 million write-down of our Upper Devonian field during the three months ended December 31, 2009.

For the nine months ended September 30, 2010, depletion expense increased $6.6 million to $83.2 million compared with $76.6 million for the nine months ended September 30, 2009. Our depletion expense of oil and gas properties as a percentage of oil and gas revenues was 41% for the nine months ended September 30, 2010, compared with 37% for the nine months ended September 30, 2009. Depletion expense per Mcfe was $2.79 for both the nine months ended September 30, 2010 and 2009. Depletion expense increased between periods principally due to an overall increase in production volumes, partially offset by a $156.4 million write-down of our Upper Devonian field during the three months ended December 31, 2009.

Gain (loss) on Asset Sales

Gain on asset sales, net of related transaction costs, of $0.6 million and $286.3 million for the three and nine months ended September 30, 2010, respectively, principally relates to the gain recognized on the sale of acreage to Reliance Industries Limited in connection with the formation of our undivided Marcellus Shale joint venture in the second quarter 2010. Loss on asset sales of $1.4 million and $5.7 million for the three and nine months ended September 30, 2009 represents the loss associated with the contribution of certain natural gas gathering and processing assets to the Laurel Mountain joint venture.

Interest Expense

Total interest expense decreased to $17.4 million for the three months ended September 30, 2010 as compared with $19.2 million for the three months ended September 30, 2009. This $1.8 million decrease was principally attributable to lower average borrowings under our credit facility, primarily due to the repayment of amounts outstanding subsequent to the formation of our Marcellus Shale joint venture.

Total interest expense increased to $52.4 million for the nine months ended September 30, 2010 as compared with $47.3 million for the nine months ended September 30, 2009. This $5.1 million increase was principally attributable to a $13.7 million increase associated with our issuance of $200.0 million of 12.125% senior unsecured notes in July 2009, partially offset by a $5.7 million decrease in credit facility interest associated with lower average borrowings under our credit facility and a $2.9 million favorable increase in capitalized interest. The $5.7 million decrease associated with our credit facility was primarily due to the repayment of amounts outstanding subsequent to the formation of our Marcellus Shale joint venture.

LIQUIDITY AND CAPITAL RESOURCES

General

Our primary sources of liquidity are cash generated from operations, funding provided by the drilling carry associated with our Marcellus joint venture for a portion of our capital expenditures, capital raised through investment partnerships and borrowings under our credit facility. Our primary cash requirements, in addition to normal operating expenses, are for debt service and capital expenditures. In general, we expect to fund:

• capital expenditures and working capital deficits through cash generated from operations, cash provided by our joint venture drilling carry, additional borrowings and capital raised through investment partnerships; and

• debt principal payments through additional borrowings as they become due.

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Recent instability in the financial markets, as a result of recession or otherwise, has increased the cost of capital while the availability of funds 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 cash flow from operations, our joint venture drilling carry 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 us to the extent required and on acceptable terms. We believe that we will have sufficient liquid assets, cash from operations, our joint venture drilling carry and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve month period. However, we are subject to business, operational and other risks that could adversely affect our cash flow. We may supplement our cash generation with proceeds from financing activities, including borrowings under our credit facility and other borrowings, the sale of assets and other transactions.

Revolving Credit Facility

At September 30, 2010, we had a credit facility with a syndicate of banks with a borrowing base of $550.0 million that matures in June 2012. The borrowing base is redetermined semiannually on April 1 and October 1 subject to changes in oil and gas reserves and 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 $1.6 million was outstanding at September 30, 2010. The facility is secured by substantially all of our assets and is guaranteed by each of our subsidiaries. The facility allows us to distribute to ATLS (a) amounts equal to ATLS’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 use in the next year.

The events which constitute an event of default for our credit facility are 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 are in compliance with these covenants as of September 30, 2010. The credit facility also requires us to maintain a ratio 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 less than or equal to 3.5 to 1.0. Based on the definitions contained in our credit facility, our ratio of current assets to current liabilities was 2.5 to 1.0 and our ratio of total debt to EBITDA was 2.5 to 1.0 at September 30, 2010.

ITEM 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities 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 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 and with the participation of our management, including 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, as of September 30, 2010, our disclosure controls and procedures were effective at the reasonable assurance level.

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 affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Following the announcement of the Merger on April 27, 2009, five purported class actions were filed in Delaware Chancery Court and were later consolidated into a single complaint, In re Atlas Energy Resources, LLC Unitholder Litigation, C.A. No. 4589-VCN (the “Consolidated Action”) filed on July 1, 2009 (the “Consolidated Complaint”). The Consolidated Complaint named ATLS and various officers and directors of ours as defendants (the “Defendants”), alleged violations of fiduciary duties in connection with the Merger, and requested injunctive relief and damages.

In October 2009, we filed a motion to dismiss the Consolidated Complaint. Subsequently, in December 2009, plaintiffs filed an Amended Complaint (the “Amended Complaint”). The Amended Complaint alleges that Defendants breached their purported fiduciary duties to our public unitholders in connection with their negotiation of the Merger. In particular, plaintiffs allege that the Merger was not entirely fair to our public unitholders, and that Defendants conducted the Merger process in bad faith. Pursuant to the Delaware Chancery Court’s (the “Court”) January 2010 Scheduling Stipulation and Order, Defendants filed their opening brief in support of their motion to dismiss on February 18, 2010 and plaintiffs filed their brief in opposition on May 3, 2010. Defendants filed a reply brief on June 11, 2010 and oral argument was held on the motion on July 20, 2010. The Court dismissed the claims against all of the directors and officers named as defendants. The Court held that there was no showing that any individual defendant acted in bad faith. However, the Court ruled that the plaintiffs could proceed with their claim against us.

Predicting the outcome of this lawsuit is difficult. An adverse judgment for monetary damages could have a material adverse effect on our operations. Based on the facts known to date, we believe that the claims asserted against it in this lawsuit are without merit, and will continue to defend itself vigorously against the claims.

In June 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 alleges 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 the decision. On May 18, 2010, the appeal was argued before the Tennessee Court of Appeals. The parties are awaiting the court’s decision.

We are also party to various routine legal proceedings arising in the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations.

ITEM 6. EXHIBITS

Exhibit No.	Description
2.1	Purchase and Sale Agreement, dated April 9, 2010, by and between Atlas Energy Resources, LLC and Reliance Marcellus, LLC. (15) Schedules and exhibits to the Agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company agrees to furnish a copy of any omitted schedule or similar attachment to the SEC upon request
2.2	Participation and Development Agreement, dated April 20, 2010, by and between Atlas Energy Resources, LLC, Atlas America, LLC, Viking Resources, LLC, Atlas Resources, LLC and Reliance Marcellus, LLC. (16) Schedules and exhibits to the Agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company agrees to furnish a copy of any omitted schedule or similar attachment to the SEC upon request
2.3	Standstill, AMI and Transfer Restriction Agreement, dated April 20, 2010, by and among Atlas Energy, Inc., Atlas Energy Resources, LLC, Reliance Industries Limited and Reliance Marcellus, LLC(16)
2.4	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) Schedules and exhibits to the Agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company agrees to furnish a copy of any omitted schedule or similar attachment to the SEC upon request
3.1	Second Amended and Restated Limited Liability Company 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 Limited Liability 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 Notes due 2018 (included as an exhibit to the Indenture filed as Exhibit 4.2 hereto)

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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 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)
10.1(d)	Third Amendment to Credit Agreement, dated as of July 10, 2009(11)
10.2	Management Agreement, dated as of December 18, 2006, among Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, and Atlas Energy Management, Inc. (1)
10.3	Agreement for Services among Atlas America, Inc., and Richard Weber, dated April 5, 2006(3)
10.4	Atlas Energy, Inc. Assumed Long-Term Incentive Plan(13)
10.5	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)
10.6	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.
10.7	Gas Gathering Agreement for Natural Gas on the Expansion 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.
12.1	Computation of 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⁾ [Intentionally omitted]

⁽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.

⁽¹⁵⁾ Previously filed as an exhibit to our Form 8-K filed April 13, 2010.

⁽¹⁶⁾ Previously filed as an exhibit to our Form 8-K filed April 21, 2010.

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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
Date: November 9, 2010	By:	/S/ EDWARD E. COHEN
		Edward E. Cohen
		Chairman and Chief Executive Officer
Date: November 9, 2010	By:	/S/ MATTHEW A. JONES
		Matthew A. Jones
		Chief Financial Officer
Date: November 9, 2010	By:	/S/ SEAN P. MCGRATH
		Sean P. McGrath
		Chief Accounting Officer

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