Atlas Energy Resources 10-Q 2008 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2008

OR

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

For the transition period from _________ to __________

Commission file number:  1-33193

ATLAS ENERGY RESOURCES, LLC

(Exact name of registrant as specified in its charter)

Delaware	75-3218520
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Westpointe Corporate Center One
1550 Coraopolis Heights Road
Moon Township, PA	15108
(Address of principal executive offices)	(Zip code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes xNo ¨

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

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

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

Yes ¨ No x

ATLAS ENERGY RESOURCES, LLC

INDEX TO QUARTERLY REPORT ON FORM 10-Q

		Page
PART I	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Consolidated Balance Sheets – September 30, 2008 and December 31, 2007	3
	Consolidated Statements of Income for the Three Months and Nine Months Ended September 30, 2008 and 2007	4
	Consolidated Statement of Changes in Members’ Equity for the Nine Months Ended September 30, 2008	5
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2008 and 2007	6
	Notes to Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	49
Item 4.	Controls and Procedures	54
PART II	OTHER INFORMATION
Item 1.	Legal Proceedings	55
Item 1A	Risk Factors	55
Item 6.	Exhibits	56
SIGNATURES

2

ATLAS ENERGY RESOURCES, LLC

CONSOLIDATED BALANCE SHEETS

(in thousands)

	September 30,			December 31,
	2008			2007
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	19,300		$	25,258
Accounts receivable		70,797			57,311
Current portion of hedge asset		33,010			38,181
Prepaid expenses and other		17,450			8,265
Hedge receivable from Partnerships		851			213
Total current assets		141,408			129,228
Property, plant and equipment, net		1,860,858			1,693,467
Hedge receivable from Partnerships – long-term		14,038			13,542
Other assets, net		27,598			14,770
Intangible assets, net		4,143			5,061
Goodwill		35,166			35,166
	$	2,083,211		$	1,891,234
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	5		$	30
Accounts payable		73,747			55,051
Accrued liabilities		58,802			34,535
Liabilities associated with drilling contracts		32,626			132,517
Current portion of hedge liability		2,670			356
Total current liabilities		167,850			222,489
Long-term debt		868,838			740,000
Other long-term liabilities		8,127			2,372
Advances from affiliates		1,383			8,696
Long-term hedge liability		44,186			39,204
Asset retirement obligations		46,960			42,358
Commitments and contingencies (Note 10)
Members’ equity:
Class B common unit holders		943,980			835,447
Class A unit holder		6,506			5,770
Accumulated other comprehensive (loss)		(4,619	)		(5,102	)
Total members’ equity		945,867			836,115
	$	2,083,211		$	1,891,234

See accompanying notes to consolidated financial statements.

3

ATLAS ENERGY RESOURCES, LLC

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per unit data)

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
REVENUES
Well construction and completion	$	116,987		$	103,324		$	343,466		$	240,841
Gas and oil production		81,234			63,265			236,417			109,840
Administration and oversight		5,216			5,364			15,370			13,347
Well services		5,298			4,845			15,362			12,721
Gathering		4,886			3,471			15,151			10,509
Gain on mark-to-market derivatives		—			—			—			26,257
Total revenues		213,621			180,269			625,766			413,515
COSTS AND EXPENSES
Well construction and completion		101,727			89,847			298,666			209,427
Gas and oil production		16,315			11,960			44,601			20,307
Well services		2,753			2,515			7,815			6,705
Gathering		4,625			3,336			14,358			10,374
General and administrative		11,952			9,062			36,030			27,319
Depreciation, depletion and amortization		23,586			19,013			68,344			31,688
Total operating expenses		160,958			135,733			469,814			305,820
OPERATING INCOME		52,663			44,536			155,952			107,695
OTHER INCOME (EXPENSE)
Interest expense		(14,798	)		(13,032	)		(42,666	)		(14,972	)
Other-net		315			108			796			495
Total other expense		(14,483	)		(12,924	)		(41,870	)		(14,477	)
Net income	$	38,180		$	31,612		$	114,082		$	93,218
Allocation of net income attributable to members’ interests:
Class A units	$	2,417		$	1,416		$	6,836		$	2,648
Class B common units		35,763			30,196			107,246			90,570
Net income attributable to members’ interests	$	38,180		$	31,612		$	114,082		$	93,218
Net income per Class B common unit:
Basic	$	.56		$	0.50		$	1.73		$	2.02
Diluted	$	.56		$	0.49		$	1.71		$	1.99
Weighted average Class B common units outstanding:
Basic		63,381			60,710			62,083			44,933
Diluted		64,162			61,502			62,858			45,480

See accompanying notes to consolidated financial statements.

4

ATLAS ENERGY RESOURCES, LLC

CONSOLIDATED STATEMENT OF CHANGES IN MEMBERS’ EQUITY

NINE MONTHS ENDED SEPTEMBER 30, 2008

(in thousands, except unit data)

(Unaudited)

											Accumulated
											Other			Total
	Class A Units					Class B Common Units					Comprehensive			Members’
	Units		Amount			Units		Amount			Income (Loss)			Equity
Balance, January 1, 2008		1,238,986	$	5,770			60,710,374	$	835,447		$	(5,102	)	$	836,115
Units issued		54,500		—			2,670,375		107,714						107,714
Distributions paid on unissued units under incentive plan									(1,007	)					(1,007	)
Distributions to unit holders				(6,100	)				(109,441	)					(115,541	)
Stock-based compensation									4,021						4,021
Net income				6,836					107,246						114,082
Other comprehensive income												483			483
Balance, September 30, 2008		1,293,486	$	6,506			63,380,749	$	943,980		$	(4,619	)	$	945,867

See accompanying notes to consolidated financial statements.

5

ATLAS ENERGY RESOURCES, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Nine Months Ended
	September 30,
	2008			2007
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES:
Net income	$	114,082		$	93,218
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Amortization of deferred finance costs		2,182			858
Depreciation, depletion and amortization		68,344			31,688
Cash received from non-qualifying derivatives		10,508			6,503
Non-cash compensation on long-term incentive plans		4,021			3,382
Equity income of unconsolidated subsidiary		(171	)		—
Distributions paid to minority interest, net		(56	)		—
(Gain) loss on asset dispositions		(32	)		119
Non-cash gain on derivatives		—			(26,257	)
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable and prepaid expenses		(22,524	)		9,237
Increase in accounts payable and accrued expenses		34,282			2,960
Decrease in liabilities associated with drilling contracts		(99,891	)		(23,675	)
Changes in other operating assets and liabilities		11			286
Net cash provided by operating activities		110,756			98,322
CASH FLOWS USED IN INVESTING ACTIVITIES:
Net cash paid for acquisition		—			(1,267,977	)
Capital expenditures		(222,991	)		(125,428	)
Proceeds from sale of assets		63			1,071
Increase in other assets		(201	)		(104	)
Net cash used in investing activities		(223,129	)		(1,392,438	)
CASH FLOWS PROVIDED BY FINANCING ACTIVITIES:
Borrowings		326,000			882,936
Principal payments on borrowings		(604,025	)		(143,922	)
Net proceeds – senior unsecured notes		407,125			—
Net proceeds from Class B common units issued		107,714			597,500
Distributions to unit holders		(112,680	)		(34,898	)
Advances (to) from affiliates		(7,313	)		2,200
Increase in deferred financing costs and other		(10,406	)		(10,201	)
Net cash provided by financing activities		106,415			1,293,615
Decrease in cash and cash equivalents		(5,958	)		(501	)
Cash and cash equivalents at beginning of period		25,258			8,833
Cash and cash equivalents at end of period	$	19,300		$	8,332

See accompanying notes to consolidated financial statements.

6

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2008

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION

Atlas Energy Resources, LLC (“the Company”) is a publicly-traded Delaware limited liability company (NYSE: ATN). The Company is an independent developer and producer of natural gas and, to a lesser extent, oil in Northern Michigan's Antrim Shale and the Appalachian Basin. The Company is also a leading sponsor of and manages tax-advantaged direct investment partnerships, in which it coinvests to finance the exploitation and development of its acreage (“the Partnerships”). The Company's Northern Michigan operations were acquired on June 29, 2007 (See Note 3).

The Company was formed in June 2006 to own and operate substantially all of the natural gas and oil assets and the investment partnership management business of Atlas America, Inc. (“Atlas America”) (NASDAQ: ATLS). Atlas America has been involved in the energy industry since 1968, expanding its operations in 1998 when it acquired The Atlas Group, Inc. and in 1999 when it acquired Viking Resources Corporation, both engaged in the development and production of natural gas and oil and the sponsorship of investment partnerships. In December 2006, the Company completed an initial public offering of 7,273,750 units of its Class B common units, representing a 19.4% interest, at a price of $21.00 per common unit. The net proceeds of the offering of $139.9 million, after deducting underwriting discounts and costs, were distributed to Atlas America in the form of a non-taxable dividend and to repay debt. Concurrent with this transaction, Atlas America contributed all of the stock of its natural gas and oil development and production subsidiaries and its development and production assets in exchange for 29,352,996 common units and 748,456 Class A units. On June 29, 2007, the Company acquired DTE Gas and Oil Company from DTE Energy Company (“DTE”) for $1.273 billion in cash (See Note 3). On June 29, 2007, the Company also completed a private placement of 7,298,181 Class B common units and 16,702,828 Class D units to a group of institutional investors to fund the acquisition of DTE Gas and Oil Company. On November 10, 2007, the Class D units automatically converted to common units on a one-for-one basis. After the sale and private placement of 2,070,000 of 600,000 Class B common units, respectively, during the quarter ended June 30, 2008 (See Note 14), Atlas America owns 48.3% of the Company.

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Transactions between the Company and other Atlas America entities have been identified in the consolidated financial statements as transactions between affiliates (see Note 8).

In accordance with established practice in the oil and gas industry, the Company includes in its consolidated financial statements its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Partnerships in which it has an interest. 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 to its own economics as further explained under the heading “Oil and Gas Properties,” below. All material intercompany transactions have been eliminated.

The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2007 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 of America for interim reporting. They do not include all disclosures normally made in financial statements contained in a 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, 2007, which contains a summary of significant accounting policies followed by the Company in the preparation of its consolidated financial statements. These policies were also followed in preparing these financial

7

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— CONTINUED

September 30, 2008

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION – (Continued)

statements included herein. The results of operations for the three month and nine month period ended September 30, 2008 may not necessarily be indicative of the results of operations for the full year ending December 31, 2008.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and costs and expenses during the reporting period. Actual results could differ from these estimates.

Accounts Receivable and Allowance for Possible Losses

In evaluating its allowance for possible losses, the Company performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by the Company’s review of its customer’s credit information. The Company extends credit on an unsecured basis to many of its customers. At September 30, 2008 and December 31, 2007, the Company’s credit evaluation indicated that it had no need for an allowance for possible losses.

Reclassifications

Certain reclassifications have been made to the consolidated balance sheet as of December 31, 2007 and to the three months and nine months ended September 30, 2007 consolidated statements of income and cash flows to conform to the current period presentation.

Revenue Recognition

Because there are timing differences between the delivery of natural gas and oil and the Company’s receipt of a delivery statement, the Company has unbilled revenues. These revenues are accrued based upon volumetric data from the Company’s records and the Company’s estimates of the related transportation and compression fees which are, in turn, based upon applicable product prices. The Company had unbilled trade receivables at September 30, 2008 and December 31, 2007 of $56.8 million and $44.9 million, respectively, which are included in accounts receivable on its consolidated balance sheets.

Capitalized Interest

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

8

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

September 30, 2008

(Unaudited)

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – (Continued)

The weighted average interest rates used to capitalize interest and the amount of interest capitalized for the following periods is as follows (dollars shown in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Weighted average interest rate		4.1	%		7.3	%		4.5	%		6.6	%
Interest capitalized	$	831		$	722		$	2,012		$	1,554

Property, Plant and Equipment

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

The estimated service lives of property, plant and equipment are as follows:

Buildings and improvements	10-40 years
Furniture and equipment	3-7 years
Other	3-10 years

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

	September 30,			December 31,
	2008			2007
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,208,014		$	1,043,687
Wells and related equipment		816,130			752,184
		2,024,144			1,795,871
Unproved properties		17,625			16,380
Support equipment		9,021			6,936
		2,050,790			1,819,187
Land, buildings and improvements		6,437			5,881
Other		10,576			9,653
		2,067,803			1,834,721
Accumulated depreciation, depletion and amortization		(206,945	)		(141,254	)
	$	1,860,858		$	1,693,467

Oil and Gas Properties

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

9

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – (Continued)

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

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to income. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the statements of income. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Impairment of Long-Lived Assets

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

The review of the Company’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place at December 31, 2007, 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 partnership’s reserves. These assumptions include the Company’s actual capital contributions, an additional carried interest (generally 7% to 10%), a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

10

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – (Continued)

The Company’s lower operating and administrative costs result from the limited partners paying to the Company their proportionate share of these expenses plus a profit margin. These assumptions could result in the Company’s calculation of depletion and impairment being different than its proportionate share of the Partnership’s 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 must be at fair market value supported by an appraisal of an independent expert selected by the Company.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value.

Recently Issued Financial Accounting Standards

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

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

11

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – (Continued)

In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162, “The Hierarchy of Generally Accepted Accounting Policies” (“SFAS 162”), which reorganizes the sources of accounting principles into a GAAP hierarchy in order of authority. The purpose of the new standard is to improve financial reporting by providing a consistent framework for determining what accounting principles should be used when preparing United States generally accepted accounting principles (“U.S. GAAP”) financial statements. The standard is effective 60 days after the SEC’s approval of the PCAOB’s amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” The adoption of SFAS 162 will not have an impact on the Company’s financial position or results of operations.

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

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

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

12

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – (Continued)

In January 2008, the FASB issued Statement 133 Implementation Issue No. E23, “Hedging – General Issues Involving the Application of the Shortcut Method under Paragraph 68” (“Implementation Issue E23”). Implementation Issue E23 is effective for hedging relationships designated on or after January 1, 2008, and amends SFAS 133 to explicitly permit use of the “shortcut” method for those hedging relationships in which: the interest rate swap has a nonzero fair value at the inception of the hedging relationship attributable solely to differing prices within the bid-ask spread; or the hedged item has a trade date that differs from its settlement date because of generally established conventions in the marketplace in which the transaction to acquire or issue the hedging item is executed. The Company uses the “long-haul” method by applying the change in variable cash flow method (See Note 9) to measure ineffectiveness on its interest rate swaps under SFAS 133 and therefore Implementation Issue E23 did not have a significant impact on its financial position or results of operations.

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

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

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. By electing the fair value option in conjunction with a derivative, an entity can achieve an accounting result similar to a fair value hedge without having to comply with complex hedge accounting rules. The statement was effective for the Company as of January 1, 2008. The Company adopted SFAS 159 at January 1, 2008, and has elected not to apply the fair value option to any of its financial instruments not already carried at fair value in accordance with other accounting standards, and therefore the adoption of SFAS 159 did not impact the Company’s consolidated financial statements for the nine months ended September 30, 2008.

13

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – (Continued)

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurement” (“SFAS 157”). SFAS 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements. In February 2008, the FASB issued FSP FAS 157-2, “Effective Date of FASB Statement No. 157”, (“FSP FAS 157-2”). FSP FAS 157-2, which was effective upon issuance, delays the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value at least once a year, to fiscal years beginning after November 15, 2008. On January 1, 2009, the Company will adopt SFAS 157 for nonfinancial assets and liabilities that are not measured at fair value on a recurring basis. For the Company, the nonfinancial assets and liabilities will be limited to the initial recognition of asset retirement obligations. FSP FAS 157-2 also covers interim periods within the fiscal years for items within its scope. The delay is intended to allow the FASB and its constituents the time to consider the various implementation issues associated with SFAS 157. The Company adopted SFAS 157 as of January 1, 2008 with respect to its commodity and interest rate swap derivative instruments which are measured at fair value within its consolidated financial statements. See Note 9 for disclosures pertaining to the provisions of SFAS 157 with regard to the Company’s fair value measurements.

NOTE 3 —ACQUISITION OF DTE GAS & OIL COMPANY

On June 29, 2007, the Company acquired all of the outstanding equity interests of DTE Gas & Oil Company (“DGO”) from DTE Energy Company (NYSE:DTE) and MCN Energy Enterprises for $1.273 billion, including adjustments for working capital of $15.0 million and current year capital expenditures of $19.0 million. Assets acquired included interests in approximately 2,150 natural gas wells with estimated proved reserves of approximately 610.6 billion cubic feet of natural gas equivalents located in the northern lower peninsula of Michigan, 228,000 developed acres, and 66,000 undeveloped acres. With this acquisition, the Company increased its natural gas and oil production as well as entered into a new region that offers additional opportunities to expand its operations. Subsequent to the acquisition of DGO, the Company changed DGO’s name to Atlas Gas & Oil Company, LLC (“AGO”).

To fund the acquisition, the Company borrowed $713.9 million on its new credit facility (See Note 11) and received net proceeds of $597.5 million from a private placement of its Class B common and new Class D units (See Note 14). Proceeds of $52.5 million were used to pay the outstanding balance of the Company’s then existing credit facility. The acquisition was accounted for using the purchase method of accounting under SFAS 141. The following table presents the purchase price allocation, which is based on a third-party evaluation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed based on their estimated fair market value at the date of acquisition (in thousands):

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

14

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 3 —ACQUISITION OF DTE GAS & OIL COMPANY - (Continued)

The following data presents pro forma revenues, net income (loss) and basic and diluted net income (loss) per unit for the Company as if the AGO acquisition, Class B common unit and Class D unit private placement (See Note 14) and new revolving credit facility (See Note 11) had occurred on January 1, 2007. The Company has prepared these unaudited pro forma financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the Company had completed the acquisition at January 1, 2007 or the results that will be attained in the future (in thousands, except per unit amounts):

	Nine Months Ended
	September 30, 2007
	As		Pro Forma			Pro
	Reported		Adjustments			Forma
Revenues	$	413,515	$	15,888		$	429,403
Net income (loss)	$	93,218	$	(57,877	)	$	35,341
Net income (loss) per Class B common units outstanding – basic	$	2.02	$	(1.46	)	$	0.56
Weighted average Class B common units outstanding – basic		44,933		15,777			60,710
Net income (loss) per Class B common unit – diluted	$	1.99	$	(1.44	)	$	0.55
Weighted average Class B common unit outstanding – diluted		45,480		16,022			61,502

Pro forma adjustments to revenues include losses on derivatives realized by AGO of $54.1 million for the nine months ended September 30, 2007. All existing derivatives were canceled upon the acquisition of AGO by the Company and the Company entered into new derivative contracts covering future AGO production. Pro forma adjustments include financial hedges between AGO and its affiliate. In addition, pro forma adjustments include depreciation, depletion and amortization related to assets acquired and interest expense associated with debt entered into to acquire such assets.

NOTE 4 - COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources. These changes, other than net income, are referred to as “other comprehensive income (loss)” and, for the Company, include changes in the fair value of unrealized hedging contracts related to commodity and interest rate derivatives. A reconciliation of the Company’s comprehensive income (loss) for the periods indicated is as follows (in thousands):

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2008		2007			2008			2007
Net income	$	38,180	$	31,612		$	114,082		$	93,218
Other comprehensive income (loss):
Unrealized holding gain (loss) on hedging contracts		282,906		32,537			(25,821	)		13,429
Reclassification adjustment for (gains) losses realized in net income		27,925		(4,844	)		26,304			(9,598	)
Total other comprehensive income		310,831		27,693			483			3,831
Comprehensive income	$	349,011	$	59,305		$	114,565		$	97,049

15

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 4 - COMPREHENSIVE INCOME (LOSS) – (Continued)

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

	September 30, 2008			December 31, 2007
Unrealized loss on commodity derivatives	$	(5,580	)	$	(5,102	)
Unrealized gain on interest rate derivatives		961			—
	$	(4,619	)	$	(5,102	)

NOTE 5 – NET INCOME PER COMMON UNIT

Basic net income per unit for Class B common units is computed by dividing net income, after the deduction of net income allocable to the Class A units and unit incentive awards, attributable to unit holders by the weighted average number of units outstanding during each period. The Class A unit holder’s allocable share of net income is calculated on a quarterly basis based upon Atlas America’s 2% interest and incentive distributions.

Diluted net income per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of the Company’s restricted unit and unit option awards, as calculated by the treasury stock method. Restricted units and unit options consist of common units issuable under the terms of the Company’s Long-Term Incentive Plan (See Note 13).

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
Weighted average number of common unit holder units – basic		63,381		60,710		62,083		44,933
Add effect of dilutive unit incentive awards		781		792		775		547
Weighted average number of common unit holder units – diluted		64,162		61,502		62,858		45,480

NOTE 6 - OTHER ASSETS AND INTANGIBLE ASSETS

Other Assets

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

	September 30,		December 31,
	2008		2007
Long-term hedge asset	$	10,502	$	6,882
Deferred finance costs, net of accumulated amortization of $4,890 and $2,708		15,588		7,650
Interest swap receivable		899		—
Other		609		238
	$	27,598	$	14,770

16

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 6 - OTHER ASSETS AND INTANGIBLE ASSETS – (Continued)

Deferred finance costs related to the Company’s credit facility and senior notes (see Note 11) are recorded at cost and amortized over their respective lives (5 to 10 years).

Intangible Assets

Included in intangible assets are partnership management, operating contracts and a non-compete agreement acquired through acquisitions which were recorded at fair value on their acquisition dates. The Company amortizes these contracts on the declining balance and straight-line methods, over their respective estimated lives, ranging from two to thirteen years. Amortization expense for these contracts for the three months ended September 30, 2008 and 2007 was $306,000 and $205,000, respectively, and for the nine months ended September 30, 2008 and 2007 was $918,000 and $613,000, respectively.

The aggregate estimated annual amortization expense of the above contracts for the next five years ending September 30 is as follows: 2009—$1.2 million ; 2010—$607,000; 2011—$689,000; 2012─$287,000 and 2013—$144,000.

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

	September 30,			December 31,
	2008			2007
Management and operating contracts	$	14,343		$	14,343
Non-compete agreement		890			890
Total costs		15,233			15,233
Accumulated amortization		(11,090	)		(10,172	)
	$	4,143		$	5,061

NOTE 7 - ASSET RETIREMENT OBLIGATIONS

The Company accounts for asset retirement obligations under SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”) and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), which require that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, with the associated asset retirement costs being capitalized as a part of the carrying amount of the long-lived asset. The Company has asset retirement obligations related to the plugging and abandonment of its oil and gas wells. SFAS 143 also requires the Company to consider estimated salvage value in the calculation of depreciation, depletion and amortization.

17

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 7 - ASSET RETIREMENT OBLIGATIONS – (Continued)

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						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Asset retirement obligations, beginning of period	$	45,334		$	41,792		$	42,358		$	26,726
Liabilities acquired (See Note 3)		—			505			—			13,920
Liabilities incurred		975			997			2,615			2,024
Liabilities settled		(36	)		(9	)		(38	)		(30	)
Accretion expense		687			673			2,025			1,318
Asset retirement obligations, end of period	$	46,960		$	43,958		$	46,960		$	43,958

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

NOTE 8 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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

Relationship with Atlas America. The employees supporting the Company’s operations are employees of Atlas America. Atlas America provides centralized corporate functions on behalf of the Company, including legal, finance, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. 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. These costs are reflected in general and administrative expense in the Company’s consolidated statements of income.

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

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

18

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 8 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS – (Continued)

Relationship with Atlas Pipeline. The Company has a master gas gathering agreement with Atlas Pipeline which governs the transportation of substantially all of the natural gas the Company produces from the wells it operates in the Northern Appalachian Basin. This agreement generally provides for the Company to pay Atlas Pipeline 16% of the sales price received for natural gas produced from wells located on Atlas Pipeline’s gathering systems. These fees are shown as a component of gathering expense on the Company’s consolidated statements of income which amounted to $4.5 million and $3.3 million for the three months ended September 30, 2008 and 2007, respectively. Gathering expense was $14.0 million and $10.4 million for the nine months ended September 30, 2008 and 2007, respectively. Atlas America agreed to assume the Company’s obligation to pay gathering fees to Atlas Pipeline after the Company’s initial public offering.

The Company charges rates to wells connected to these gathering systems, substantially all of which are owned by the Partnerships, generally ranging from $0.35 per Mcf to 13% of the sales price received for the natural gas transported. Under the terms of its contribution agreement with Atlas America, the Company remits this amount to Atlas America. Therefore, after the closing of its initial public offering, the gathering revenues and costs within the Company’s Appalachian area of operations net to $0.

NOTE 9—DERIVATIVE AND FINANCIAL INSTRUMENTS

Commodity Risk Hedging Program

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

At September 30, 2008, the Company had 693 natural gas and 165 crude oil futures contracts related to natural gas and oil sales covering 145 million MMbtus and 346,000 Bbls of natural gas and crude oil, respectively, maturing through June 30, 2013 at a combined average settlement price of $8.29 per MMBtu and $97.61 per Bbl, respectively.

The Company has a $5.6 million unrealized net liability related to financial hedges on its gas and oil production shown as a component of accumulated other comprehensive loss at September 30, 2008. If the fair values of the instruments remain at current market values, the Company will reclassify $16.5 million of unrealized gains to its consolidated statements of income over the next twelve-month period as these contracts settle and $22.1 million of unrealized losses will be reclassified in later periods.

The Company recognized gains (losses) on settled contracts covering natural gas production of $(27.2) million and $4.9 million for the three months ended September 30, 2008 and 2007 respectively, and $(25.6) million and $9.6 million for the nine months ended September 30, 2008 and 2007, respectively. The Company recognized losses of $380,000 and $412,000 on settled oil production for the three months and nine months ended September 30, 2008, respectively. There were no gains (losses) on oil settlements for the nine months ended September 30, 2007. As the underlying prices and terms in the Company’s hedge contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three months and nine months ended September 30, 2008 and 2007 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

19

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

September, 2008

(Unaudited)

NOTE 9—DERIVATIVE AND FINANCIAL INSTRUMENTS - (Continued)

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

As of September 30, 2008, the Company had the following natural gas and oil volumes hedged:

Natural Gas Fixed Price Swaps

Production
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset/(Liability)
	(MMbtu)		(per MMbtu)		(in thousands) (1)
2008		9,890,000	$	8.87	$	13,683
2009		45,060,000	$	8.56		16,077
2010		33,660,000	$	8.14		(11,620	)
2011		25,980,000	$	7.91		(11,840	)
2012		17,440,000	$	8.13		(4,196	)
2013		1,500,000	$	8.73		443
					$	2,547

Natural Gas Costless Collars

Production
Period Ending					Average		Fair Value
December 31,	Option Type		Volumes		Floor and Cap		Asset/(Liability)
			(MMbtu)		(per MMbtu)		(in thousands) (1)
2008		Puts purchased		390,000	$	7.50	$	80
2008		Calls sold		390,000	$	9.40		—
2009		Puts purchased		240,000	$	11.00		714
2009		Calls sold		240,000	$	15.35		—
2010		Puts purchased		3,120,000	$	7.92		—
2010		Calls sold		3,120,000	$	9.10		(604	)
2011		Puts purchased		7,200,000	$	7.50		—
2011		Calls sold		7,200,000	$	8.45		(3,804	)
2012		Puts purchased		720,000	$	7.00		—
2012		Calls sold		720,000	$	8.37		(468	)
							$	(4,082	)

20

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 9—DERIVATIVE AND FINANCIAL INSTRUMENTS - (Continued)

Crude Oil Fixed Price Swaps

Production
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset/(Liability)
	(Bbl)		(per Bbl)		(in thousands) (2)
2008		22,400	$	103.67	$	47
2009		58,900	$	99.92		(148	)
2010		48,900	$	97.31		(344	)
2011		40,400	$	96.43		(327	)
2012		33,500	$	96.00		(280	)
2013		9,000	$	95.95		(75	)
					$	(1,127	)

Crude Oil Costless Collars

Production
Period Ending					Average		Fair Value
December 31,	Option Type		Volumes		Floor and Cap		Asset/(Liability)
			(Bbl)		(per Bbl)		(in thousands) (2)
2008		Puts purchased		10,500	$	85.00	$	2
2008		Calls sold		10,500	$	126.44		—
2009		Puts purchased		36,500	$	85.00		—
2009		Calls sold		36,500	$	118.63		(86	)
2010		Puts purchased		31,000	$	85.00		—
2010		Calls sold		31,000	$	112.92		(190	)
2011		Puts purchased		27,000	$	85.00		—
2011		Calls sold		27,000	$	110.81		(196	)
2012		Puts purchased		21,500	$	85.00		—
2012		Calls sold		21,500	$	110.06		(165	)
2013		Puts purchased		6,000	$	85.00		—
2013		Calls sold		6,000	$	110.09		(47	)
							$	(682	)
Total net liability							$	(3,344	)

_____________

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

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

21

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 9—DERIVATIVE AND FINANCIAL INSTRUMENTS - (Continued)

The fair value of the derivatives is included in the consolidated balance sheets as follows (in thousands):

	September 30,			December 31,
	2008			2007
Current portion of hedge asset	$	33,010		$	38,181
Long-term hedge asset		10,502			6,882
Current portion of hedge liability		(2,670	)		(356	)
Long-term hedge liability		(44,186	)		(39,204	)
	$	(3,344	)	$	5,503

In addition, $1.2 million and $3.4 million of unrealized hedge liabilities have been allocated to the limited partners in the Partnerships at September 30, 2008 and December 31, 2007, respectively, based on the Partnerships’ share of estimated future gas and oil production related to the hedges not yet settled and is included in the consolidated balance sheets as follows (in thousands):

	September 30,			December 31,
	2008			2007
Unrealized hedge loss – short-term	$	851		$	213
Other assets – long-term		14,038			13,542
Accrued liabilities – short-term		(10,346	)		(9,013	)
Unrealized hedge gain – long-term		(3,289	)		(1,348	)
	$	1,254		$	3,394

Interest Rate Risk Hedging Program

At September 30, 2008, the Company had debt outstanding of $462.0 million under its revolving credit facility. During the nine months ended September 30, 2008, the Company entered into hedging arrangements in the form of interest rate swaps to reduce the impact of volatility of changes in the London interbank offered rate (“LIBOR”).  The Company has LIBOR interest rate swaps at a three-year fixed swap rate of 3.11% on $150.0 million of outstanding debt through January 2011. The swaps have been designated as cash flow hedges to minimize the risk associated with changes in the designated benchmark interest rate (in this case, LIBOR) related to forecasted payments associated with interest on the credit facility. The Company has accounted for the interest rate swaps under the “long-haul” method to measure ineffectiveness under SFAS 133. Using the change in variable cash flow method, no hedge ineffectiveness was identified. The value of the Company’s cash flow hedges included in accumulated other comprehensive income was a net unrecognized gain of approximately $961,000 at September 30, 2008. The Company recognized losses on settled swaps of $312,000 and $335,000 for the three months and nine months ended September 30, 2008, respectively. The Company did not enter into any interest rate swaps in the three months or nine months ended September 30, 2007.

Fair Value of Financial Instruments

The Company adopted the provisions of SFAS 157 at January 1, 2008. SFAS 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS 157’s hierarchy defines three levels of inputs that may be used to measure fair value:

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

22

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 9—DERIVATIVE AND FINANCIAL INSTRUMENTS - (Continued)

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

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

The Company uses the fair value methodology outlined in SFAS 157 to value the assets and liabilities for its outstanding derivative contracts. All of the Company’s derivative contracts are defined as Level 2. The Company’s natural gas and crude oil derivative contracts are valued based on prices quoted on the NYMEX or WTI and adjusted by the respective counterparty using various assumptions including quoted forward prices, time value, volatility factors, and contractual prices for the underlying instruments. The Company’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model.  In accordance with SFAS 157, the following table represents the Company’s fair value hierarchy for its financial instruments at September 30, 2008 (in thousands):

	Level 2			Total
Commodity-based derivatives.	$	(3,344	)	$	(3,344	)
Interest rate swap-based derivatives		961			961
	$	(2,383	)	$	(2,383	)

NOTE 10—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 Company believes that any liability incurred would not be material.

The Company may be required to subordinate a part of its net partnership revenues from the Partnerships to the receipt by investor partners of cash distributions from the investment partnerships equal to at least 10% of their subscriptions determined on a cumulative basis, in accordance with the terms of the partnership agreements.

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

Legal Proceedings

On June 20, 2008, the Company’s wholly-owned subsidiary, Atlas America, LLC, was named as a co-defendant in the matter 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 the Company and another defendant, Wind City Oil & Gas, LLC, interfered with the closing of this assignment on June 6, 2008. The Company purchased the Leases from Miller for approximately $19.1 million. The Company acted in good faith and believes that the outcome of the litigation will be resolved in its favor.

23

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 10—COMMITMENTS AND CONTINGENCIES – (Continued)

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

NOTE 11 — LONG-TERM DEBT

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

	September 30,			December 31,
	2008			2007
Revolving credit facility	$	462,000		$	740,000
Senior unsecured notes		400,000			—
Unamortized notes premium		6,838			—
Other debt		5			30
		868,843			740,030
Less current maturities		(5	)		(30	)
	$	868,838		$	740,000

Revolving Credit Facility. Upon the closing of its acquisition of DTE Gas & Oil (See Note 3), the Company replaced its credit facility with a new 5-year credit facility with an initial borrowing base of $850.0 million with J.P. Morgan Chase Bank, N.A. (“J.P. Morgan”) as administrative agent, Wachovia Bank, N. A. as syndication agent, and other lenders. The borrowing base is redetermined semiannually on April 1 and October 1 subject to changes in the Company’s oil and gas reserves. The borrowing base is also reduced by 25% of the amount of any senior unsecured notes issued by the Company. The borrowing base at September 30, 2008 was $697.5 million. Up to $50 million of the facility may be in the form of standby letters of credit. The facility is secured by substantially all of the Company’s assets and is guaranteed by each of the Company’s subsidiaries (other than Anthem Securities, Inc.) and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at the Company’s option. At September 30, 2008, the weighted average interest rate on outstanding borrowings was 4.9%.

The base rate for any day equals the higher of the federal funds rate plus 0.50% or the J.P. Morgan prime rate. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for Eurocurrency liabilities. The applicable margin ranges from 0.0% to 0.75% for base rate loans and 1.00% to 1.75% for LIBOR loans.

The credit facility requires the Company to maintain specified financial ratios of current assets to current liabilities and debt to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”) as disclosed in the credit agreement. In addition, the credit agreement limits sales, leases or transfers of assets and the incurrence of additional indebtedness. The credit agreement limits the distributions payable by the Company if an event of default has occurred and is continuing or would occur as a result of such distribution. The Company is in compliance with these covenants as of September 30, 2008. The facility terminates in June 2012, when all outstanding borrowings must be repaid. At September 30, 2008 and December 31, 2007, $462.0 million and $740.0 million, respectively, were outstanding under this facility. In addition, letters of credit of $1.2 million and $1.1 million were outstanding at each date, which are not reflected as borrowings on the Company’s consolidated balance sheets.

24

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 11— LONG-TERM DEBT - (Continued)

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

Annual principal debt payments over the next five years ending September 30 are as follows (in thousands):

2009	$	5
2010		—
2011		—
2012		462,000
2013 and thereafter		406,838
	$	868,843

NOTE 12—OPERATING SEGMENT INFORMATION

The Company’s operations include three reportable operating segments. These operating segments reflect the way the Company manages its operations and makes business decisions.

The Company organizes its oil and gas production segments by geographic location. The Appalachia segment represents the Company’s well interests in the states of Pennsylvania, Ohio, New York, West Virginia and Tennessee. The Michigan segment represents the Company’s well interests in the Antrim Shale, located in Michigan’s northern, Lower Peninsula, and its undeveloped acreage in the New Albany Shale in Indiana.

25

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 12—OPERATING SEGMENT INFORMATION-(Continued)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
	(in thousands)				(in thousands)
Gas and oil production
Appalachia:
Revenues	$	34,297	$	26,623	$	97,193	$	72,366
Costs and expenses		7,541		4,719		18,422		12,907
Segment profit	$	26,756	$	21,904	$	78,771	$	59,459
Michigan:
Revenues(1)	$	46,937	$	36,642	$	139,224	$	63,731
Costs and expenses		8,774		7,241		26,179		7,400
Segment profit	$	38,163	$	29,401	$	113,045	$	56,331
Partnership management
Revenues	$	131,496	$	116,383	$	386,796	$	276,797
Costs and expenses		108,982		95,698		320,523		226,506
Segment profit	$	22,514	$	20,685	$	66,273	$	50,291

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(in thousands)						(in thousands)
Reconciliation of segment profit to net income
Segment profit
Gas and oil production-Appalachia	$	26,756		$	21,904		$	78,771		$	59,459
Gas and oil production-Michigan		38,163			29,401			113,045			56,331
Partnership management		22,514			20,685			66,273			50,291
Total segment profit		87,433			71,990			258,089			166,081
General and administrative		(11,952	)		(9,062	)		(36,030	)		(27,319	)
Depreciation, depletion and amortization		(23,586	)		(19,013	)		(68,344	)		(31,688	)
Interest expense		(14,798	)		(13,032	)		(42,666	)		(14,972	)
Other − net(2)		1,083			729			3,033			1,116
Net income	$	38,180		$	31,612		$	114,082		$	93,218

_____________

⁽¹⁾ Revenues for the nine months ended September 30, 2007 include non-cash gains of $26.3 million related to non-qualifying hedges associated with the acquisition of AGO, see Note 9.

⁽²⁾ Revenues net of expenses for AGO well services and transportation of $768,000 and $621,000 for the three months ended September 30, 2008 and 2007, respectively, and $2.2 million and $621,000 for the nine months ended September 30, 2008 and 2007, respectively, do not meet the quantitative threshold for reporting segment information. These amounts have been included in “Other – net” above.

26

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 12—OPERATING SEGMENT INFORMATION – (Continued)

The following table reconciles revenues shown for each operating segment to total revenues shown on the consolidated statements of income for the three months and nine months ended September 30, 2008 and 2007, respectively.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
	(in thousands)				(in thousands)
Revenues:
Gas & oil production – Appalachia	$	34,297	$	26,623	$	97,193	$	72,366
Gas & oil production – Michigan		46,937		36,642		139,224		63,731
Partnership management		131,496		116,383		386,796		276,797
Other		891		621		2,553		621
	$	213,621	$	180,269	$	625,766	$	413,515

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
	(in thousands)				(in thousands)
Capital expenditures
Gas and oil production:
Appalachia	$	69,665	$	42,743	$	165,991	$	96,024
Michigan		19,769		26,025		53,962		26,025
Partnership management		1,047		1,134		2,247		2,384
Corporate		135		445		791		995
	$	90,616	$	70,347	$	222,991	$	125,428

	September 30,		December 31,
	2008		2007
	(in thousands)
Balance sheets
Goodwill:
Gas and oil production – Appalachia	$	21,527	$	21,527
Partnership management		13,639		13,639
	$	35,166	$	35,166
Total assets
Gas and oil production:
Appalachia	$	685,807	$	491,199
Michigan		1,316,461		1,330,432
Partnership management		38,250		30,359
Corporate		42,693		39,244
	$	2,083,211	$	1,891,234

27

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 13—BENEFIT PLANS

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

Restricted Stock and Phantom Units. Under the ATN LTIP, 35,793 units of restricted stock and phantom units were awarded in the nine months ended September 30, 2008. The fair value of the grants is based on the closing unit price on the grant date, and is being charged to operations over the requisite service periods using a straight-line attribution method.

The following table summarizes the activity of restricted stock and phantom units for the nine months ended September 30, 2008:

				Weighted
				Average
				Grant Date
	Units			Fair Value
Non-vested shares outstanding at December 31, 2007		624,665		$	24.42
Granted		35,793			31.62
Vested		(12,279	)		21.06
Forfeited		(100	)		35.00
Non-vested shares outstanding at September 30, 2008		648,079		$	24.88

Stock Options. During the nine months ended September 30, 2008, 14,000 unit options were awarded under the ATN LTIP. Option awards expire 10 years from the date of grant and are generally granted with an exercise price equal to the market price of the Company’s common units at the date of grant. The Company uses the Black-Scholes option pricing model to estimate the weighted average fair value per option granted with the following assumptions:

	Date Granted
	January 2, 2008			June 16, 2008
Options granted		6,500			7,500
Expected life (years)		6.25			6.25
Expected volatility		27	%		34	%
Risk-free interest rate		2.8	%		4.0	%
Expected dividend yield		7.0	%		6.2	%
Weighted average fair value of stock options granted	$	3.41		$	7.66

28

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 13 - BENEFIT PLANS - (Continued)

The following table sets forth option activity for the nine months ended September 30, 2008:

						Weighted
						Average
				Weighted		Remaining		Aggregate
				Average		Contractual		Intrinsic
				Exercise		Term		Value
	Shares			Price		(in years)		(in thousands)
Outstanding at December 31, 2007		1,895,052		$	24.09		8.9
Granted		14,000		$	35.36
Exercised		—		$	—
Forfeited or expired		(4,850	)	$	26.75
Outstanding at September 30, 2008		1,904,202		$	24.17		8.2	$	3,102
Exercisable at September 30, 2008		93,438		$	21.00		7.5
Available for grant at September 30, 2008		1,165,536

The Company recognized $1.4 million and $1.3 million in compensation expense related to restricted stock units, phantom units and stock options for the three months ended September 30, 2008 and 2007, respectively. The Company recognized $4.0 million and $3.4 million in related compensation expense for the nine months ended September 30, 2008 and 2007, respectively. The Company paid $354,000 and $220,000 with respect to its LTIP DERs for the three months ended September 30, 2008 and 2007, respectively. The Company paid $1.0 million and $472,000 with respect to its LTIP DER’s for the nine months ended September 30, 2008 and 2007, respectively. These amounts were recorded as a reduction of members’ equity on the Company’s consolidated balance sheets. At September 30, 2008, the Company had approximately $13.0 million of unrecognized compensation expense related to the unvested portion of the restricted stock units, phantom units and options.

NOTE 14 – COMMON UNIT OFFERINGS

Public Common Unit Purchase

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

Atlas America Common Unit Purchase

On May 5, 2008, the Company sold 600,000 of its Class B common units to Atlas America in a private placement at $42.00 per common unit, increasing Atlas America’s ownership of ATN’s common units to 29,952,996 common units. The proceeds of $25.2 million were used to repay a portion of the Company’s outstanding balance under its revolving credit facility.

29

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

September 30, 2008

(Unaudited)

NOTE 14 - COMMON UNIT OFFERINGS - (Continued)

Private Placement of Class B and Class D Units

To partially fund the acquisition of AGO on June 29, 2007, the Company completed a private placement of 7,298,181 Class B common units and 16,702,828 Class D units to a group of institutional investors at a weighted average price of $25.00 per unit for net proceeds of $597.5 million. The private placement of the Class B common and Class D units was exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. The Class D units were a new class of equity security, which automatically converted to common units on a one-to-one basis upon the receipt of the consent of the Company’s unit holders, which the Company obtained in November 2007. The Company entered into a registration rights agreement in connection with the sale of the units. The agreement required the Company to prepare and file a registration statement covering the resale of such units by January 31, 2008 and have such registration statement declared effective by May 30, 2008. The Company filed this registration statement, which was declared effective on February 20, 2008.

NOTE 15 – CASH DISTRIBUTIONS

The Company generally distributes within 45 days after the end of each quarter, all of its available cash (as defined in its limited liability agreement) for that quarter. Distributions declared by the Company from inception are as follows:

			Cash
			Distribution			Cash				Manager
Date Cash			Per			Distribution		Cash		Incentive
Distribution			Common			to Common		Distribution		Distribution
Paid or Payable	For Quarter Ended		Unit			Unit holders (2)		to the Manager		Payable
						(in thousands)		(in thousands)		(in thousands)
February 14, 2007		December 31, 2006	$	0.06(1	)	$	2,231	$	45	$	—
May 15, 2007		March 31, 2007	$	0.43		$	15,989	$	322	$	—
August 14, 2007		June 30, 2007	$	0.43		$	15,989	$	322	$	—
November 14, 2007		September 30, 2007	$	0.55		$	33,697	$	681	$	784
February 14 , 2008		December 31, 2007	$	0.57		$	34,925	$	706	$	965
May 15, 2008		March 31, 2008	$	0.59		$	36,507	$	738	$	1,214
August 14, 2008		June 30, 2008	$	0.61		$	39,016	$	789	$	1,687
November 14, 2008		September 30, 2008	$	0.61(3	)	$	39,022	$	789	$	1,687

____________

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

⁽²⁾ Includes distributions paid on unissued units under the Company’s employee incentive plan.

⁽³⁾ On October 29, 2008, the Company declared a quarterly cash distribution for the quarter ended September 30, 2008 of $0.61 per common unit. The distribution is payable November 14, 2008 to holders of record as of November 10, 2008.

30

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

When used in this Form 10-Q, the words “believes” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements.  Such statements are subject to certain risks and uncertainties more particularly described in Item 1A, under the caption “Risk Factors”, in our annual report on Form 10-K for fiscal 2007.  These risks and uncertainties could cause actual results to differ materially.  Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof.  We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

GENERAL

We are a limited liability company focused on the development and production of natural gas and, to a lesser extent, oil principally in northern Michigan and the Appalachian Basin. In northern Michigan, we drill wells for our own account. In the Appalachian Basin, we sponsor and manage tax-advantaged investment partnerships, or the Partnerships, in which we coinvest, to finance the exploitation and development of our acreage.

We were formed in June 2006 to own and operate substantially all of the natural gas and oil assets and the investment partnership management business of Atlas America. Atlas America has been involved in the energy industry since 1968, expanding its operations in 1998 when it acquired The Atlas Group, Inc. and in 1999 when it acquired Viking Resources Corporation, both engaged in the development and production of natural gas and oil and the sponsorship of investment partnerships. We are managed by Atlas Energy Management, a wholly-owned subsidiary of Atlas America.

We operate three business segments:

· Two gas and oil production segments, in Appalachia and Michigan – Indiana area, which consist of our interests in gas and oil properties.

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

As of and for the three months and nine months ended September 30, 2008, we had the following key assets and highlights:

In our Appalachia gas and oil operations:

· we own direct and indirect working interests in approximately 9,057 gross producing gas and oil wells, of which we operate approximately 85%;

· we own overriding royalty interests in approximately 627 gross producing gas and oil wells;

· net daily production was 35.7 Mmcfe per day and 34.4 Mmcfe per day for the three months and nine months ended September 30, 2008, respectively;

· we lease approximately 931,000 gross (885,000 net) acres, of which approximately 623,000 gross (616,000 net) acres are undeveloped;

· included in our gross undeveloped acreage, we control approximately 555,000 Marcellus acres in Pennsylvania, New York and West Virginia, of which approximately 271,000 of these acres are located in our core Marcellus Shale position in southwestern Pennsylvania;

· we have identified 3,739 geologically favorable shallow drilling locations in the Appalachian Basin;

31

· our partnership management business in Appalachia includes our equity interests in 93 investment partnerships and a registered broker-dealer which acts as the dealer-manager of our investment partnership offerings;

· we drilled 81.5 net vertical and one horizontal Marcellus Shale wells during the nine months ended September 30, 2008; and,

· we drilled and participated in 2 successful horizontal wells in the Chattanooga Shale of eastern Tennessee.

In our Michigan-Indiana gas and oil operations:

· we own direct and indirect working interests in approximately 2,416 gross producing gas and oil wells, of which we operate approximately 76%;

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

· net daily production was 60.5 Mmcfe per day and 59.8 Mmcfe per day for the three months and nine months ended September 30, 2008, respectively;

In Michigan:

· we lease approximately 346,600 gross (272,200 net) acres, of which approximately 44,200 gross (33,600 net) acres, are undeveloped; and

· we drilled 135 gross wells (111 net wells) during the nine months ended September 30, 2008.

In Indiana:

· we lease approximately 114,000 net acres, all of which are undeveloped.

How We Evaluate our Operations

Non-GAAP Financial Measures

We use a variety of financial and operations measures to assess our performance, including non-GAAP financial measures, EBITDA, Adjusted EBITDA and distributable cash flow. These measures are not calculated or presented in accordance with generally accepted accounting principles, or GAAP.

Adjusted EBITDA is a significant performance metric used by our management to indicate (prior to the establishment of any cash reserves) the cash distributions we expect to pay to our unit holders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDA is also used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts and others to assess:

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

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

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

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

The following table presents a reconciliation of net income, our most directly comparable GAAP performance measure, to EBITDA, Adjusted EBITDA and distributable cash flow for each of the periods presented (in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Reconciliation of net income to non-GAAP measures:
Net income	$	38,180		$	31,612		$	114,082		$	93,218
Depreciation and amortization		23,586			19,013			68,344			31,688
Interest expense		14,798			13,032			42,666			14,972
EBITDA		76,564			63,657			225,092			139,878
Adjustment to reflect cash impact of derivatives(1)		2,560			6,503			10,508			6,503
Gain on mark-to-market derivatives(2)		—			—			—			(26,257	)
Non-recurring derivative fees		—			—			—			3,873
Non-cash compensation expense		1,362			1,294			4,021			3,382
Adjusted EBITDA	$	80,486		$	71,454		$	239,621		$	127,379
Interest expense		(14,798	)		(13,032	)		(42,666	)		(14,972	)
Amortization of deferred financing costs (included within interest expense)		670			360			2,182			858
Maintenance capital expenditures		(12,975	)		(12,975	)		(38,925	)		(30,475	)
Distributable cash flow	$	53,383		$	45,807		$	160,212		$	82,790

_______________

⁽¹⁾Represents cash proceeds received from the settlement of ineffective derivative gains recognized in fiscal 2007 associated with the acquisition of AGO from natural gas produced during the quarter and year-to-date but not reflected in the three months and nine months ended September 30, 2008 and 2007 consolidated statements of income.

⁽²⁾Representsineffective non-cash gains related to the change in value of derivative contracts associated with the acquisition of AGO on June 29, 2007.

RECENT DEVELOPMENTS

Acquisition of Indiana Assets

 Beginning July 1, 2008 through October 31, 2008, we began establishing a position in the New Albany Shale in southwestern Indiana totaling approximately $15.0 million. We acquired 114,000 net undeveloped acres and entered into a farm-out agreement that will give us rights to an additional 78,000 net undeveloped acres. These leases are located in Sullivan, Knox, Greene, Owen, Clay and Lawrence counties, Indiana. In addition, we acquired a 50% undivided interest in a gas gathering system with related compression and fluid disposal facilities in Sullivan County.

Agreement with Miller Petroleum, Inc.

On June 19, 2008, we entered into a $19.6 million agreement with Miller Petroleum, Inc. (“Miller”) whereby Miller assigned (i) 100% of the working interest in its oil and gas leases comprising 27,620 acres in the Koppers North and Koppers South section of Campbell County, Tennessee, (ii) 100% of the working interest in 8 existing wells, and (iii) 100% of the working interest in its oil and gas leases comprising 1,952 acres adjacent to the Koppers acreage. The agreement also provides Miller with an option to participate up to 25% in up to 10 wells to be drilled on the assigned acreage. In addition, we entered into two agreements with Miller whereby (i) Miller will provide drilling services to us for a two-year term and (ii) we or our affiliates will transport and process natural gas for Miller from its existing wells.

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Public Equity Offering

On May 16, 2008, we sold 2,070,000 of our Class B common units at $41.50 per common unit in a public offering with UBS Investment Bank and Wachovia Securities acting as joint book-running managers and underwriters. The net proceeds of approximately $82.5 million (after underwriting expenses of $3.4 million) were used to repay a portion of our outstanding balance under our revolving credit facility. The increased borrowing capacity will be used to fund additional acreage acquisitions and accelerated development of the Marcellus Shale as well as further development of our other drilling programs and lease acquisition activities.

Senior Unsecured Notes

 In January 2008, we completed a private placement of $250.0 million of Senior Notes to institutional buyers pursuant to Rule 144A under the Securities Act of 1933. On May 5, 2008, we issued an additional $150.0 million of 10.75% senior unsecured notes (“Senior Notes”) due 2018 at 104.75% of par to yield 9.85% to the par call on February 1, 2016. We intend to treat both the May 2008 and the January 2008 issuances as a single class of debt securities. We used the net proceeds of $402.7 million (including accrued interest paid of $4.7 million and net underwriting fees of $9.2 million) to reduce the balance outstanding on our revolving credit facility. 

 Interest on the Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year. The Senior Notes are redeemable at any time at specified redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, before February 1, 2011, we may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The Senior Notes are also subject to repurchase by us at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if we do not reinvest the net proceeds within 360 days.

The Senior Notes are junior in right of payment to our secured debt, including our obligations under our credit facility. The indenture governing the Senior Notes contains covenants, including limitations of our ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of our assets.

Private Equity Offering

On May 7,2008, we sold 600,000 Class B common units to Atlas America in a private placement at $42.00 per common unit, increasing Atlas America’s ownership of our Class B common units to 29,952,996 common units or 46.3%. The proceeds of $25.2 million were used to repay a portion of our outstanding balance under our revolving credit facility.

Interest Rate Swap

In January 2008, we entered into an interest rate swap contract for $150.0 million, swapping the floating rate incurred on a portion of our existing senior secured credit facility for a three-year fixed rate of 3.11%. The interest rate swap contract will mature in January 2011.

Partnership Management

We generally fund our drilling activities, other than those of our Michigan business unit, through sponsorship of tax-advantaged investment partnerships. Accordingly, the amount of development activities we undertake depends in part upon our ability to obtain investor subscriptions to the investment partnerships. We have budgeted to raise between $450.0 and $500.0 million in fiscal 2008 and have raised $238.4 million in the nine months ended September 30, 2008. During the nine months ended September 30, 2008, our investment partnerships invested $414.5 million in drilling and completing wells, of which we contributed $110.6 million.

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Acquisition of DTE Antrim assets

On June 29, 2007, we acquired DTE Gas & Oil Company, now known as Atlas Gas & Oil Company, or AGO, from DTE Energy Company (“DTE” -NYSE:DTE) for approximately $1.3 billion in cash. The assets acquired, which consisted principally of interests in natural gas wells in the Antrim Shale, are the basis for the formation of our Michigan gas and oil operations. We funded the purchase price from $713.9 million borrowed under our credit facility and the issuance of 24,001,009 Class B common units at $25.00 per unit for proceeds of $597.5 million. We intend to continue to expand our business through strategic acquisitions and internal growth projects that increase distributable cash flow.

Credit Facility

 Upon the closing of the DTE Gas & Oil acquisition, we replaced our credit facility with a new 5-year, $850.0 million credit facility. As of September 30, 2008, the credit facility has a current borrowing base of $697.5 million, which will be redetermined semi-annually based on changes in our oil and gas reserves. The facility is secured by our assets and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR rate plus the applicable margin, elected at our option. The base rate for any day equals the higher of the federal funds rate plus 0.50% or the JPMorgan prime rate. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for Eurocurrency liabilities. The applicable margin ranges from 0.0% to 0.75% for base rate loans and 1.00% to 1.75% for LIBOR loans. At September 30, 2008, the weighted average interest rate on outstanding borrowings under our credit facility was 4.9%.

GENERAL TRENDS AND OUTLOOK

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

 Currently, there is an unprecedented uncertainty in the financial markets. This uncertainty presents additional potential risks to us. These risks include the availability and costs associated with our borrowing capabilities and raising additional capital, and an increase in the volatility of the market price of our common unit. While we have no plans to access debt or equity in the capital markets, should we decide to do so in the near future, the terms, size, and cost of new debt or equity could be less favorable than in previous transactions.

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Historically, natural gas and oil prices have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital.

Commodity Prices

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

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

Natural Gas Supply and Outlook

We believe that current natural gas prices will continue to cause relatively high levels of natural gas-related drilling in the United States as producers seek to increase their level of natural gas production. Although the number of natural gas wells drilled in the United States has increased overall in recent years, a corresponding increase in production has not been realized, primarily as a result of smaller discoveries and the decline in production from existing wells. We believe that an increase in United States drilling activity, additional sources of supply such as liquefied natural gas, and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for, and to compensate for the slowing production of, natural gas in the United States. The areas in which we operate are experiencing significant drilling activity as a result of recent high natural gas prices, new increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques.

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

Reserve Outlook

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

Impact of Inflation

Inflation in the United States did not have a material impact on our results of operations for the three-year period ended December 31, 2007. If inflation occurs in the future, to the extent permitted by competition and our existing agreements, we have and will continue to pass along increased costs to our investors and customers in the form of higher fees. For further discussion, see —“CHANGES IN PRICES AND INFLATION”.

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RESULTS OF OPERATIONS

GAS AND OIL PRODUCTION

The following table sets forth information relating to our production segments during the periods indicated:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Production revenues (in thousands):
Gas (1)	$	77,253		$	60,302		$	224,345		$	102,439
Oil	$	3,956		$	2,938		$	12,014		$	7,357
Production volume:(2)
Appalachia
Gas (Mcf/day) (1)		33,228			29,324			31,929			26,220
Oil (Bbls/day)		413			443			410			422
Michigan
Gas (Mcf/day)		60,436			59,304			59,755			59,325
Oil (Bbls/day)		11			3			11			3
Total (Mcfe/day)		96,209			91,304			94,210			88,095
Average sales prices:
Gas (per Mcf) (3) (6)	$	9.26		$	8.19		$	9.35		$	8.55
Oil (per Bbl)(5)	$	101.34		$	71.63		$	104.15		$	63.75
Production costs:(7)
Lease operating expenses
As a percent of production revenues		9	%		10	%		9	%		10	%
Per Mcfe	$	.85		$	.74		$	.82		$	.78
Taxes – Per Mcfe	$	.41		$	.25		$	.39		$	.17
Total production costs per Mcfe	$	1.26		$	.99		$	1.21		$	.95
Depletion per Mcfe	$	2.57		$	2.19		$	2.55		$	2.24

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⁽¹⁾ Excludes sales of residual gas and sales to landowners.

⁽²⁾ 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.

⁽³⁾ Our average sales price for gas before the effects of financial hedging was $10.49 and $6.55 per Mcf for the three months ended September 30, 2008 and 2007, respectively and $10.03 and $7.12 per Mcf for the nine months ended September 30, 2008 and 2007, respectively.

⁽⁴⁾ We acquired AGO on June 29, 2007, and production volume from these assets has only been included from that date.

⁽⁵⁾ Our average sales price for oil before the effects of financial hedging were $106.94 and $108.09 per Bbl for the three months and nine months ended September 30, 2008. There were no oil financial hedges for the three months and nine months ended September 30, 2007.

⁽⁶⁾ Includes $2.6 million and $6.5 million in derivative proceeds, which were not included as gas revenue in the three months ended September 30, 2008 and 2007, respectively and $10.5 million and $6.5 million for the nine months ended September 30, 2008 and 2007, respectively.

⁽⁷⁾ Production costs consist of labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, insurance, production overhead, and production taxes.

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Three Months Ended September 30, 2008 Compared to the Three Months Ended September 30, 2007

Our natural gas revenues were $77.3 million in the three months ended September 30, 2008, an increase of $17.0 million (28%) from $60.3 million in the three months ended September 30, 2007. The $17.0 million increase in natural gas revenues consisted of $4.2 million attributable to increases in natural gas sales production volumes, and $12.8 million attributable to increases in natural gas sales prices (after the effect of financial hedges).

The increase in our gas production volumes of 463,000 Mcfs was attributable to an increase of 104,000 Mcfs (22%) produced in Michigan from our acquisition of AGO which we acquired on June 29, 2007, and an increase of 359,000 Mcfs (78%) in our Appalachian natural gas production volumes due to production associated with wells we drilled for our investment partnerships in the twelve months ended September 30, 2008. We believe that gas volumes will continue to be favorably impacted in the remainder of 2008 with the contribution of our Michigan business unit and as ongoing projects to extend and enhance the gathering systems of Atlas Pipeline are completed and wells drilled are connected in these areas of expansion.

Our oil revenues were $3.9 million in the three months ended September 30, 2008, an increase of $1.0 million (35%) from $2.9 million during the three months ended September 30, 2007. The increase resulted from a 41% increase in the average sales price of oil, partially offset by a 5% decrease in production volumes. The $1.0 million increase consisted of $1.2 million attributable to increases in sales prices (after the effect of financial hedges), and $202,000 attributable to volume decreases, as we primarily drill for natural gas, rather than oil.

Our Appalachian production costs were $7.5 million in the three months ended September 30, 2008, an increase of $2.8 million (60%) from $4.7 million in the three months ended September 30, 2007. The increase includes a $819,000 increase attributable to labor, water hauling and maintenance costs associated with an increase in the number of wells we own from the prior year period and a $1.9 million increase in transportation fees charged to our wells connected to Atlas Pipeline’s gathering system due to an increase in volumes produced and prices received as compared to the prior year period.

Our Michigan production costs were $8.8 million in the three months ended September 30, 2008, an increase of $1.6 million (21%) from $7.2 million in the three months ended September 30, 2007. These costs represent labor, compressor, transportation, severance tax and maintenance costs. The increase of $1.6 million is primarily attributable to a $1.5 million increase in severance taxes due to increased production volumes and prices received compared to the prior year period.

Nine Months Ended September 30, 2008 Compared to the Nine Months Ended September 30, 2007

Our natural gas revenues were $224.3 million in the nine months ended September 30, 2008, an increase of $121.9 million (119%) from $102.4 million in the nine months ended September 30, 2007. The $121.9 million increase in natural gas revenues consisted of $110.6 million attributable to increases in natural gas production volumes and $11.3 million attributable to increases in natural gas sales prices (after the effect of financial hedges).

The increase in our gas production volumes of 12.4 Mmcf’s was attributable to 10.8 Mmcf (87%) produced in Michigan from our acquisition of AGO which we acquired on June 29, 2007, and an increase of 1.6 Mmcf (13%) in our Appalachian natural gas production volumes due to production associated with wells we drilled for our investment partnerships in the nine months ended September 30, 2008.

Our oil revenues were $12.0 million in the nine months ended September 30, 2008, an increase of $4.6 million (64%) from $7.4 million during the nine months ended September 30, 2007. The increase resulted from a 63% increase in the average sales price of oil (after the effect of financial hedges), as production volumes remained relatively the same.

Our Appalachian production costs were $18.4 million in the nine months ended September 30, 2008, an increase of $5.5 million (43%) from $12.9 million in the nine months ended September 30, 2007. The increase includes $1.9 million attributable to increases in labor, water hauling, compressor, and maintenance costs and a $3.0 million increase in transportation fees charged to our wells connected to Atlas Pipeline’s gathering system due to an increase in volumes produced and prices received as compared to the prior year period.

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Our Michigan production costs were $26.2 million in the nine months ended September 30, 2008, an increase of $18.8 million (254%) from $7.4 million in the nine months ended September 30, 2007. The increase is primarily attributable to increases of $7.7 million in severance taxes and $9.2 million in labor, repair, compressor and transportation expenses for a nine-month period in 2008. These costs were included for a three-month period in 2007 due to our acquisition of AGO on June 29, 2007.

PARTNERSHIP MANAGEMENT

Well Construction and Completion

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Average construction and completion revenue per well	$	483		$	361		$	511		$	322
Average construction and completion cost per well		420			314			444			280
Average construction and completion gross profit per well	$	63		$	47		$	67		$	42
Gross profit margin	$	15,259		$	13,477		$	44,800		$	31,414
Gross profit percent		13	%		13	%		13	%		13	%
Net wells drilled:
Marcellus		26			5			68			8
Other		216			281			604			739
Total net wells drilled		242			286			672			748

Three Months Ended September 30, 2008 Compared to the Three Months Ended September 30, 2007

Our well construction and completion segment margin was $15.3 million in the three months ended September 30, 2008, an increase of $1.8 million (13%) from $13.5 million in the three months ended September 30, 2007. During the three months ended September 30, 2008, the increase of $1.8 million in segment margin was attributable to an increase in the gross profit per well ($4.5 million) partially offset by a decrease in the number of wells drilled ($2.7 million). Since our drilling contracts are on a “cost-plus” basis (typically cost-plus 15%), an increase in our average costs per well also results in a proportionate increase in our average revenue per well which directly affects the number of wells we drill. Our average costs and revenues per well has increased due to an increase in the number of Marcellus Shale wells drilled during the three months ended September 30, 2008.

It should be noted that “Liabilities associated with drilling contracts” on our balance sheet includes $12.9 million of funds raised in the first nine months of fiscal 2008 that have not been applied to the completion of wells as of September 30, 2008 due to the timing of drilling operations, and thus had not been recognized as well construction and completion revenue.  We expect to recognize this amount as revenue in the fourth quarter of fiscal 2008. During fiscal 2007 we raised $363.3 million and have budgeted to raise between $450.0 and $500.0 million in fiscal 2008 (approximately $210.0 million to $260.0 million to be raised in the quarter ended December 31, 2008). During the nine months ended September 30, 2008, we raised $238.4 million. We anticipate favorable income tax laws related to oil and gas investments and higher gas prices will continue to favorably impact our fundraising and therefore our drilling revenues in the remainder of fiscal 2008.

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Nine Months Ended September 30, 2008 Compared to the Nine Months Ended September 30, 2007

Our well construction and completion segment margin was $44.8 million in the nine months ended September 30, 2008, an increase of $13.4 million (43%) from $31.4 million in the nine months ended September 30, 2007.  During the nine months ended September 30, 2008, the increase of $13.4 million in segment margin was attributable to an increase in the gross profit per well ($18.4 million) partially offset by a decrease in the number of wells drilled ($5.0 million).

Administration and Oversight

Administration and oversight represents supervision and administrative fees earned for the drilling and subsequent management of wells for our investment partnerships. We charge the partnerships a well drilling management fee of $60,000 per net Marcellus shale well ($45,000 per net well prior to March 31, 2008) and $15,000 per net well for all other partnership wells. In addition, we charge a $75 per well per month administration fee to each partnership well.

Our administrative and oversight fees were $5.2 million in the three months ended September 30, 2008, a decrease of $149,000 (3%) from $5.4 million in the three months ended September 30, 2007. This decrease reflects a decrease of $251,000 in well drilling management fees due to fewer wells drilled and an increase of $102,000 in partnership administration fees.

Our administration and oversight fees were $15.4 million in the nine months ended September 30, 2008, an increase of $2.1 million (15%) from $13.3 million in the nine months ended September 30, 2007. This increase resulted from an increase of $1.7 million in well drilling management fees and an increase of $313,000 in partnership administrative fees, as the number of wells increased that we drill and manage for our investment partnerships in the twelve months ended September 30, 2008, compared to the prior year twelve-month period.

Well Services

Our well services revenues were $5.3 million in the three months ended September 30, 2008, an increase of $454,000 (9%) from $4.8 million in the three months ended September 30, 2007. This increase resulted from an increase in the number of wells operated for our investment partnerships due to additional wells drilled in the twelve months ended September 30, 2008.

Our well services expenses were $2.8 million in the three months ended September 30, 2008, an increase of $238,000 (9%) from $2.5 million in the three months ended September 30, 2007. The increase was attributable to an increase in wages, benefits, and field office expenses associated with an increase in employees due to the increase in the number of wells we operate for our investment partnerships.

Our well services revenues were $15.4 million in the nine months ended September 30, 2008, an increase of $2.7 million (21%) from $12.7 million in the nine months ended September 30, 2007. This increase resulted from an increase in the number of wells operated for our investment partnerships due to additional wells drilled in the twelve months ended September 30, 2008.

Our well services expenses were $7.8 million in the nine months ended September 30, 2008, an increase of $1.1 million (16%) from $6.7 million in the nine months ended September 30, 2007. This increase was attributable to an increase in wages, benefits, and field office expenses associated with an increase in employees due to the increase in the number of wells we operate for our investment partnerships.

Gathering

We charge transportation fees to our investment partnership wells that are connected to Atlas Pipeline’s Appalachian gathering systems. Prior to our initial public offering, we paid these fees, plus an additional amount to bring the total transportation charge up to, generally, 16% of the gas sales price, to Atlas Pipeline in accordance with our gathering agreements with Atlas Pipeline. In connection with the completion of our initial public offering in December 2006, Atlas America assumed our obligation to pay gathering fees to Atlas Pipeline. We are obligated to pay the gathering fees we receive from our investment partnerships to Atlas America, with the result that our gathering revenues and expenses within our partnership management segment net to $0. We also pay our proportionate share of gathering fees based on our percentage interest in the well, which are included in gas and oil production expense. The remaining gathering income we receive is attributable to income received from a small pipeline system in which we own an interest in Michigan.

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Our gathering fee payable to Atlas Pipeline was $4.5 million for the three months ended September 30, 2008, an increase of $1.2 million (35%) from $3.3 million in the three months ended September 30, 2007. The increase in the three months ended September 30, 2008 is primarily a result of an increase in throughput of natural gas transported due to higher production volumes in Appalachia.

Our gathering fee payable to Atlas Pipeline was $14.0 million for the nine months ended September 30, 2008, an increase of $3.6 million (35%) from $10.4 million in the nine months ended September 30, 2007. The increase in the nine months ended September 30, 2008 is primarily a result of an increase in throughput of natural gas transported due to higher production volumes in Appalachia.

OTHER INCOME, COSTS AND EXPENSES

General and Administrative

Three Months Ended September 30, 2008 Compared to the Three Months Ended September 30, 2007

Our general and administrative expenses were $11.9 million in the three months ended September 30, 2008, an increase of $2.8 million (32%) from $9.1 million in the three months ended September 30, 2007. These expenses include, among other things, salaries and benefits not allocated to a specific segment, costs of running our corporate office, partnership syndication activities and outside services. The increase of $2.8 million in the three months ended September 30, 2008 compared to the three months ended September 30, 2007 is principally attributable to the following:

· salaries and wages increased $653,000 due to an increase in salaries, long-term incentive plan costs, and an increase in the number of employees as a result of the growth of our business;

· outside services, professional fees, insurance and office operations increased $899,000 as we continue to expand our syndication activities and our drilling funds we raise in our investment partnerships; and

· land and leasing costs in Appalachia increased $1.3 million due to an increase in activities of our land department as we acquire additional acreage and well sites.

Nine Months Ended September 30, 2008 Compared to the Nine Months Ended September 30, 2007

Our general and administrative expenses were $36.0 million in the nine months ended September 30, 2008, an increase of $8.7 million (32%) from $27.3 million in the nine months ended September 30, 2007. These expenses include, among other things, salaries and benefits not allocated to a specific segment, costs of running our corporate office, partnership syndication activities and outside services. The increase of $8.7 million in the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007 is principally attributed to the following:

· costs associated with AGO acquired on June 29, 2007 increased $4.8 million for the nine months ended September 30, 2008;

· we paid $3.9 million in fees related to hedging natural gas volumes associated with the acquisition of AGO on June 29, 2007; there were no such fees in the nine months ended September 30, 2008;

· salaries and wages increased $4.2 million due to an increase in wage rates and an increase in the number of employees as a result of the growth of our business; 

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· net syndication costs, outside services, professional fees, insurance, and office operations increased $1.4 million as we continue to expand our syndication activities and our drilling activities; and

· land and leasing costs in Appalachia increased $2.2 million due to an increase in activities of our land department as we acquire additional acreage and well sites.

Depletion

Our depletion (including accretion of our asset retirement obligations) of oil and gas properties as a percentage of oil and gas revenues was 28% in the three months ended September 30, 2008, compared to 29% in the three months ended September 30, 2007. Depletion expense per Mcfe was $2.57 in the three months ended September 30, 2008, an increase of $0.38 (17%) per Mcfe from $2.19 in the three months ended September 30, 2007. Increases in our depletable basis and production volumes from the acquisition of AGO on June 29, 2007 and our investments in our partnerships caused depletion expense to increase $4.3 million (23%) to $22.7 million in the three months ended September 30, 2008 compared to $18.4 million in the three months ended September 30, 2007. Depletion expense associated with AGO’s asset base was $13.4 million and for our Appalachia asset base was $9.3 million for the three months ended September 30, 2008. The variances from period to period are directly attributable to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties.

Our depletion (including accretion of our asset retirement obligations) of oil and gas properties as a percentage of oil and gas revenues was 28% in the nine months ended September 30, 2008, compared to 27% in the nine months ended September 30, 2007. Depletion expense per Mcfe was $2.55 in the nine months ended September 30, 2008, an increase of $0.31 (14%) per Mcfe from $2.24 in the nine months ended September 30, 2007. Increases in our depletable basis and production volumes from the acquisition of AGO on June 29, 2007 and our investments in our partnerships caused depletion expense to increase $35.8 million to $65.8 million in the nine months ended September 30, 2008 compared to $30.0 million in the nine months ended September 30, 2007. Depletion expense associated with AGO’s asset base was $39.9 million and for our Appalachian asset base was $25.9 million for the nine months ended September 30, 2008. The variances from period to period are directly attributable to 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.

Interest Expense

Our interest expense was $14.8 million in the three months ended September 30, 2008, an increase of $1.8 million (14%) from $13.0 million in the three months ended September 30, 2007. This increase consists of an increase of $10.8 million associated with the issuance of our Senior Notes in January and May 2008, offset by a decrease of $9.0 million in interest expense on our revolving credit facility. The borrowings on our revolving credit facility were used to fund the acquisition of AGO in June 2007 and to fund our acreage and drilling capital expenditures. The issuance of our Senior Notes was used to pay down borrowings on our revolving credit facility.

Our interest expense was $42.7 million in the nine months ended September 30, 2008, an increase of $27.7 million (185%) from $15.0 million in the nine months ended September 30, 2007. This increase consists of an increase of $25.3 million associated with the issuance of our Senior Notes in January and May 2008 and an increase of $2.4 million of interest expense on our revolving credit facility. The borrowings on our revolving credit facility were used to fund the acquisition of AGO in June 2007 and to fund our acreage and drilling capital expenditures. The issuance of our Senior Notes was used to pay down borrowings on our revolving credit facility.

LIQUIDITY AND CAPITAL RESOURCES

General

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

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	Nine Months Ended
	September 30,
	2008			2007
Provided by operating activities	$	110,756		$	98,322
Used in investing activities		(223,129	)		(1,392,438	)
Provided by financing activities		106,415			1,293,615
Decrease in cash and cash equivalents	$	(5,958	)	$	(501	)

We had $19.3 million in cash and cash equivalents at September 30, 2008, as compared to $25.3 million at December 31, 2007. We had a working capital deficit of $26.4 million at September 30, 2008, a decrease of $66.9 million from a working capital deficit of $93.3 million at December 31, 2007.  The decrease in our working capital deficit is primarily due to a net decrease of $99.9 million in liabilities associated with drilling contracts and a net decrease of $2.2 million in unrealized hedge liabilities, partially offset by an increase of $43.0 million and $9.2 million in accounts payable and accrued liabilities, and prepaid expenses, respectively. Our level of liabilities associated with drilling contracts is dependent upon the remaining amount of our drilling obligations at any balance sheet date, which is dependent upon the timing and level of funds raised through our investment partnerships. At September 30, 2008, we have $234.3 million available under our credit facility to fund working capital obligations.

CASH FLOWS

Cash flows provided by operating activities.Cash provided by operations is an important source of short-term liquidity for us.  It is directly affected by changes in the price of natural gas and oil, interest rates and our ability to raise funds from our drilling investment partnerships.  Netcash provided by operating activities increased $12.5 million in the nine months ended September 30, 2008 to $110.8 million from $98.3 million in the nine months ended September 30, 2007, substantially as a result of the following:

· an increase in net income before depreciation, depletion and amortization of $58.8 million in the nine months ended September 30, 2008 as compared to the prior year period, principally due to the acquisition of AGO acquired on June 29, 2007 and increases in net income from our partnership management operations and our Appalachian production segment;

· an increase of $26.3 million of non-cash gains related to ineffective derivatives recognized in the nine months ended September 30, 2007 plus an increase of $4.0 million in cash received in the current year period on the settlement of these derivatives; and

· changes in operating assets and liabilities decreased operating cash flows by $76.9 million in the nine months ended September 30, 2008, compared to the nine months ended September 30, 2007.

The change in operating assets and liabilities is primarily a result of changes in the following current assets and liabilities:

· a decrease of $31.8 million in accounts receivable and prepaid expenses;

· an increase of $31.3 million in accounts payable and accrued expenses; and

· a decrease of $76.2 million in liabilities associated with our drilling contracts. Our level of liabilities associated with drilling contracts is dependent upon the remaining amount of our drilling obligations at any balance sheet date, which is dependent upon the timing and level of funds raised through our investment partnerships.

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Cash flows used in investing activities.Cash used in our investing activities decreased $1.169 billion in the nine months ended September 30, 2008 to $223.1 million from $1.392 billion in the nine months ended September 30, 2007 primarily from our $1.268 billion acquisition of AGO, which occurred on June 29, 2007. We also increased our capital expenditures $97.6 million which is related to the purchase of undeveloped lease acreage and higher drilling costs for the wells we drilled in fiscal 2008.

Cash flows provided by financing activities. Cash provided by our financing activities decreased $1.187 billion in the nine months ended September 30, 2008 to $106.4 million from $1.294 billion in the nine months ended September 30, 2007, primarily as a result of the following: 

· we received proceeds of $407.1 million from the issuance of our Senior Notes including a premium of $7.1 million in the nine months ended September 30, 2008;

· net borrowing decreased $1.017 billion in the nine months ended September 30, 2008, due to the funding of our AGO acquisition on June 29, 2007 during the prior nine-month similar period;

· we received proceeds of $107.7 million from the sale of our Class B common units in the nine months ended September 30, 2008 compared to proceeds of $597.5 million received in the nine months ended September 30, 2007;

· net monies borrowed from Atlas America decreased $9.5 million in the nine months ended September 30, 2008, compared to the nine months ended September 30, 2007;

· deferred financing costs increased $205,000 in the nine months ended September 30, 2008 due to the issuance of our Senior Notes; and

· we paid $112.7 million in distributions to our unit holders in the nine months ended September 30, 2008, an increase of $77.8 million from $34.9 million in the nine months ended September 30, 2007.

Capital Requirements

Capital expenditures. During the nine months ended September 30, 2008, our capital expenditures consisted of maintenance capital expenditures and expansion capital expenditures, as defined below:

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

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

During the nine months ended September 30, 2008, our capital expenditures related primarily to investments in our investment partnerships and the acquisition of leasehold acreage, in which we invested $110.6 million and $58.1 million, respectively. During the nine months ended September 30, 2007, we invested $72.5 million and $10.4 million in our investment partnerships and lease acreage acquisitions, respectively, for an overall increase of $85.8 million in the nine months ended September 30, 2008. We funded and expect to continue to fund these capital expenditures through cash on hand, from operations and from amounts available under our credit facility.

The level of capital expenditures we devote to our leasing and production operations depends upon any acquisitions made and the level of funds raised through our investment partnerships. We have budgeted to raise between $450.0 million and $500.0 million in fiscal 2008 and have raised $238.4 million in the nine months ended September 30, 2008. We believe cash flows from operations and amounts available under our credit facility will be adequate to fund our capital expenditures.  However, the amount of funds we raise and the level of our capital expenditures will vary in the future depending on market conditions for natural gas and other factors.

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We expect to fund our maintenance and expansion capital expenditures with cash flow from operations and the temporary use of funds raised in our investment partnerships in the period before we invest these funds, as well as funding our investment capital expenditures and any expansion capital expenditures that we might incur with borrowings under our credit facility. We estimate that we will have sufficient cash flow from operations after funding our maintenance capital expenditures to enable us to make our quarterly cash distributions in the amount of at least our initial quarterly distribution to unit holders through December 31, 2008.

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

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
Maintenance capital expenditures	$	12,975	$	12,975	$	38,925	$	30,475
Expansion capital expenditures		77,641		59,555		184,066		1,364,792
Total	$	90,616	$	72,530	$	222,991	$	1,395,267

Credit Facility

Simultaneously with the closing of our acquisition of DTE Gas & Oil, we entered into a senior secured credit facility with an initial borrowing base of $850.0 million ($462.0 million outstanding at September 30, 2008) with JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities, Inc., as lead arranger, and other lenders. The credit facility allows us to borrow up to the determined amount of the borrowing base, which is based upon the loan collateral value assigned to our various natural gas and oil properties. The credit facility borrowing base is redetermined each April 1 and October 1 based on changes in our oil and gas reserves. The credit facility will mature in June 2012 and has a current borrowing base of $697.5 million at September 30, 2008 (which was reaffirmed at the October 1, 2008 redetermination date).

Shelf Registration Statement

The Company has an effective shelf registration statement with the Securities and Exchange Commission that permits it to periodically issue equity and debt securities. However, the amount, type and timing of any offerings will depend upon, among other things, the Company’s funding requirements, prevailing market conditions and compliance with its credit facility and unsecured senior note covenants.

CHANGES IN PRICES AND INFLATION

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

Although certain of our costs and expenses are affected by general inflation, inflation has not normally had a significant effect on us. However, as the price of oil and natural gas has risen throughout 2008, there has been an increase in the demand for leasehold acreage, drilling locations and for energy equipment and services, thereby increasing the costs of acquiring or obtaining such equipment and services. We have also experienced higher costs in the products we use containing steel as well as rising fuel costs. Recent drilling success in the Marcellus Shale formation in Appalachia has dramatically increased competition and the price paid for leasehold acreage. Since our drilling activities are on a “cost-plus” basis, we have been able to pass on these higher costs to our investment partnerships by charging higher fees. Our focus has been to increase our oil and gas reserves and production while controlling costs at a level that is appropriate for long-term growth and operations.

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ENVIRONMENTAL REGULATION

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

CASH DISTRIBUTIONS

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

· all cash on hand at the end of the quarter;

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

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

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

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

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

Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to unit holders. We seek to maintain a coverage ratio for our distributions of at least 1.2x on a rolling 4-quarter basis. Our coverage ratio for the quarter ended September 30, 2008 was 1.4x. We calculate our coverage ratio as the amount of all of our cash receipts less disbursements, including interest expense and estimated maintenance capital expenditures, divided by the amount of distributions to our unit holders.

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

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

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On October 29, 2008, we declared our quarterly cash distribution for the third quarter of 2008 of $0.61 per common unit. The $39.5 million distribution will be paid on November 14, 2008 to unit holders of record as of November 10, 2008.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The following table summarizes our contractual obligations at September 30, 2008:

			Payments due by period
			(in thousands)
			Less than		2 – 3		4 - 5		After 5
Contractual cash obligations:	Total		1 Year		Years		Years		Years
Revolving credit facility and other debt(1)	$	462,005	$	5	$	—	$	462,000	$	—
Senior unsecured notes(1)		406,838		—		—		—		406,838
Operating lease obligations		8,067		1,542		2,451		1,882		2,192
Capital lease obligations		—		—		—		—		—
Unconditional purchase obligations		—		—		—		—		—
Other long-term obligation		—		—		—		—		—
Total contractual cash obligations	$	876,910	$	1,547	$	2,451	$	463,882	$	409,030

⁽¹⁾Not included in the table above are estimated interest payments calculated at the rates in effect at September 30, 2008 of: 2009 - $64.7 million; 2010 - $64.7 million; 2011 - $64.7 million; 2012 - $59.3 million and 2013 - $43.0 million.

			Payments due by period
			(in thousands)
			Less than		1 – 3		4 – 5		After 5
Other commercial commitments:	Total		1 Year		Years		Years		Years
Standby letters of credit	$	1,159	$	1,159	$	—	$	—	$	—
Guarantees		3,585		243		1,442		1,425		475
Standby replacement commitments		—		—		—		—		—
Other commercial commitments		—		—		—		—		—
Total commercial commitments	$	4,744	$	1,402	$	1,442	$	1,425	$	475

OFF BALANCE SHEET ARRANGEMENTS

As of September 30, 2008, our off-balance sheet arrangements are limited to an unconditional guarantee for the repayment of one-half of a bank loan for the purchase of drilling equipment in relation to our 50% ownership in Crown Drilling of Pennsylvania, LLC. The estimated amount of the guarantee is $3.6 million as of September 30, 2008 and is in effect until the loan is repaid in full, including accrued interest.

CRITICAL ACCOUNTING POLICIES

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of our assets, liabilities, revenues and cost and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates, including those related to the provision for possible losses, goodwill and identifiable intangible assets, and certain accrued liabilities. We base our estimates on historical experience and on various other assumptions that we believe reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

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 We utilize the successful efforts method of accounting for our natural gas and oil properties. Unproved properties are assessed periodically within specific geographic areas and impairments are charged to expense. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Developmental drilling costs are capitalized. Exploratory drilling costs are capitalized but charged to expense if the well is determined to be unsuccessful.

RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS

The Financial Accounting Standards Board, or FASB, recently issued the following standards which were reviewed by us to determine the potential impact on our financial statements upon adoption.

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

In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162, “The Hierarchy of Generally Accepted Accounting Policies”, or SFAS 162, which reorganizes the sources of accounting principles into a GAAP hierarchy in order of authority. The purpose of the new standard is to improve financial reporting by providing a consistent framework for determining what accounting principles should be used when preparing United States generally accepted accounting principles (“U.S. GAAP”) financial statements. The standard is effective 60 days after the SEC’s approval of the PCAOB’s amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” The adoption of SFAS 162 will not have an impact on our financial position or results of operations.

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

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

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

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

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

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

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In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” or SFAS 159. SFAS 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. By electing the fair value option in conjunction with a derivative, an entity can achieve an accounting result similar to a fair value hedge without having to comply with complex hedge accounting rules. The Statement was effective for us as of January 1, 2008. We adopted SFAS 159 at January 1, 2008, and have elected not to apply the fair value option to any of our financial instruments not already carried at fair value in accordance with other accounting standards, and therefore the adoption of FASB 159 did not impact our consolidated financial statements for the quarter ended September 30, 2008.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurement,” or SFAS 157. SFAS 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements. In February 2008, the FASB issued FSP FAS 157-2, “Effective Date of FASB Statement No. 157”, or FSP FAS 157-2. FSP FAS 157-2, which was effective upon issuance, delays the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value at least once a year, to fiscal years beginning after November 15, 2008. On January 1, 2009, we will adopt SFAS 157 for nonfinancial assets and liabilities that are not measured on a recurring basis. For us, the nonfinancial assets and liabilities will be limited to the initial recognition of asset retirement obligations. FSP FAS 157-2 also covers interim periods within the fiscal years for items within its scope. The delay is intended to allow the FASB and its constituents the time to consider the various implementation issues associated with SFAS 157. We adopted SFAS 157 as of January 1, 2008 with respect to our commodity and interest rate swap derivative instruments which are measured at fair value within our consolidated financial statements. See Note 9 to our consolidated financial statements for disclosures pertaining to the provisions of SFAS 157 with regard to our fair value measurements.

ITEM 3: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

General

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

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

The following analysis presents the effect on our earnings, cash flows and financial position as if hypothetical changes in market risk factors occurred on September 30, 2008. Only the potential impacts of hypothetical assumptions are analyzed. The analysis does not consider other possible effects that could impact our business.

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Interest Rate Risk

At September 30, 2008, we had an outstanding balance of $462.0 million on our revolving credit facility with a current borrowing base at September 30, 2008 of $697.5 million. The interest rate in effect at September 30, 2008 is based on LIBOR plus an applicable margin of 1.25%. The margin ranges from between 1.0% and 1.75% based on borrowing base utilization. The weighted average interest rate for borrowings under this credit facility was 4.6% for the nine months ended September 30, 2008 and 4.9% at September 30, 2008. At September 30, 2008, the carrying value and fair value of our total debt is $868.8 million and $822.0 million, respectively.

A hypothetical change in the fair value of our revolving and senior note debt arising from a 10% potential change in the quoted interest rate would be approximately $16.4 million. With our current debt structure, a hypothetical 10% change in the weighted average interest rate would change our net income by $1.5 million.

Interest Rate Swap

We enter into hedging arrangements to reduce the impact of volatility of changes in the LIBOR interest rate on our interest payments for our debt. In January 2008, we entered into an interest rate swap contract for $150.0 million, swapping the floating rate incurred on a portion of our existing senior secured credit facility for a fixed rate of 3.11%. The interest rate swap contract will mature in January 2011. The fair value of our cash flow hedges included in accumulated other comprehensive income was a net unrecognized gain of approximately $961,000 at September 30, 2008. We recognized losses on settled swaps of $312,000 and $335,000 for the three months and nine months ended September 30, 2008 respectively. We did not enter into any interest rate swaps in the nine months ended September 30, 2007. Combining the 3.11% interest rate on the swap and the 10.75% interest rate on our senior notes, we have fixed $550.0 million of our outstanding debt at a weighted average interest rate of approximately 8.7%. In addition, at September 30, 2008 the weighted average interest rate of borrowings for both our credit facility and our senior notes was 7.5%.

Commodity Price Risk

Our major market risk exposure in commodities is fluctuations in the pricing of our gas and oil production. Realized pricing is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production. Pricing for gas and oil production has been volatile and unpredictable for many years. To limit our exposure to changing natural gas and oil prices, we enter into natural gas and oil costless collar, and option contracts. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified, approved counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Oil contracts are based on a West Texas Intermediate, or WTI index.

Our risk management objective is to lock in a range of pricing for expected production volumes. Considering those volumes for which we have entered into financial hedge agreements for the twelve-month period ending September 30, 2009, and current indices, a theoretical 10% upward or downward change in the price of natural gas and crude oil would result in a change in net income of approximately $3.8 million.

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

At September 30, 2008, we had 693 open natural gas and 165 oil futures contracts related to sales covering 145 million MMBtus of natural gas and 346,000 Bbls of oil, maturing through September 30, 2013 at an average settlement price of $8.29 per MMBtu and $97.61 per Bbl, respectively.

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We recognized gains (losses) on settled contracts covering natural gas production of $(27.2) million and $4.9 million for the three months ended September 30, 2008 and 2007, respectively  and $(25.6) million and $9.6 million for the nine months ended September 30, 2008 and 2007, respectively. We recognized losses of $380,000 and $412,000 on settled oil production for the three months and nine months ended September 30, 2008, respectively. There were no gains (losses) on oil settlements for the three months and nine months ended September 30, 2007. As the underlying prices and terms in our hedge contracts were consistent with the indices used to sell our natural gas and oil, there were no gains or losses recognized during the three months and nine months ended September 30, 2008 and 2007 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

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

We have a $5.6 million net unrealized liability related to financial hedges in accumulated other comprehensive loss associated with commodity derivatives at September 30, 2008 compared to a net unrealized liability of $5.1 million at December 31, 2007.  If the fair values of the instruments remain at current market values, we will reclassify $16.5 million of unrealized gains to our consolidated statements of income over the next twelve-month period as these contracts settle and $22.1 million of unrealized losses will be reclassified in later periods.

The fair value of the derivatives at September 30, 2008 is a net unrealized hedge liability of $3.3 million, of which our portion is $2.1 million and $1.2 million of unrealized hedge losses have been reallocated to our investment partnerships. At October 31, 2008, commodity prices for natural gas and crude oil have declined further. We estimate that our unrealized net liability has decreased by approximately $79.8 million, to an estimated unrealized net asset of $76.5 million at October 31, 2008, from a $3.3 million liability at September 30, 2008.

As of September 30, 2008, we had the following natural gas and oil volumes hedged:

Natural Gas Fixed Price Swaps

Production
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset/(Liability)
	(MMbtu)		(per MMbtu)		(in thousands) (1)
2008		9,890,000	$	8.87	$	13,683
2009		45,060,000	$	8.56		16,077
2010		33,660,000	$	8.14		(11,620	)
2011		25,980,000	$	7.91		(11,840	)
2012		17,440,000	$	8.13		(4,196	)
2013		1,500,000	$	8.73		443
					$	2,547

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Natural Gas Costless Collars

Production
Period Ending					Average		Fair Value
December 31,	Option Type		Volumes		Floor and Cap		Asset/(Liability)
			(MMbtu)		(per MMbtu)		(in thousands) (1)
2008		Puts purchased		390,000	$	7.50	$	80
2008		Calls sold		390,000	$	9.40		—
2009		Puts purchased		240,000	$	11.00		714
2009		Calls sold		240,000	$	15.35		—
2010		Puts purchased		3,120,000	$	7.92		—
2010		Calls sold		3,120,000	$	9.10		(604	)
2011		Puts purchased		7,200,000	$	7.50		—
2011		Calls sold		7,200,000	$	8.45		(3,804	)
2012		Puts purchased		720,000	$	7.00		—
2012		Calls sold		720,000	$	8.37		(468	)
							$	(4,082	)

Crude Oil Fixed Price Swaps

Production
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset/(Liability)
	(Bbl)		(per Bbl)		(in thousands) (2)
2008		22,400	$	103.67	$	47
2009		58,900	$	99.92		(148	)
2010		48,900	$	97.31		(344	)
2011		40,400	$	96.43		(327	)
2012		33,500	$	96.00		(280	)
2013		9,000	$	95.95		(75	)
					$	(1,127	)

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Crude Oil Costless Collars

Production
Period Ending					Average		Fair Value
December 31,	Option Type		Volumes		Floor and Cap		Asset/(Liability)
			(Bbl)		(per Bbl)		(in thousands) (2)
2008		Puts purchased		10,500	$	85.00	$	2
2008		Calls sold		10,500	$	126.44		—
2009		Puts purchased		36,500	$	85.00		—
2009		Calls sold		36,500	$	118.63		(86	)
2010		Puts purchased		31,000	$	85.00		—
2010		Calls sold		31,000	$	112.92		(190	)
2011		Puts purchased		27,000	$	85.00		—
2011		Calls sold		27,000	$	110.81		(196	)
2012		Puts purchased		21,500	$	85.00		—
2012		Calls sold		21,500	$	110.06		(165	)
2013		Puts purchased		6,000	$	85.00		—
2013		Calls sold		6,000	$	110.09		(47	)
							$	(682	)
Total net liability							$	(3,344	)

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

Fair Value of Financial Instruments

We adopted the provisions of SFAS 157 at January 1, 2008.  SFAS 157 establishes a fair value hierarchy which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS 157’s hierarchy defines three levels of inputs that may be used to measure fair value:

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

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

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

We use the fair value methodology outlined in SFAS 157 to value the assets and liabilities for our outstanding derivative contracts. All of our derivative contracts are defined as Level 2. Our natural gas and crude oil derivative contracts are valued based on prices quoted on the NYMEX or WTI and adjusted by the respective counterparty using various assumptions including quoted forward prices, time value, volatility factors, and contractual prices for the underlying instruments.  Our interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model. In accordance with SFAS 157, the following table represents our fair value hierarchy for our financial instruments at September 30, 2008 (in thousands):

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	Level 2			Total
Commodity-based derivatives.	$	(3,344	)	$	(3,344	)
Interest rate swap-based derivatives		961			961
	$	(2,383	)	$	(2,383	)

ITEM 4.CONTROLS AND PROCEDURES

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

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

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

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PART II.OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

We are currently involved in various disputes incidental to our normal business operations. In addition, we have been named as a party to a certain legal action brought by CNX Gas Company, LLC which is discussed in Note 10 of the notes to the consolidated financial statements included in Part I, Item 1 of this Form 10-Q, which is incorporated herein by reference. Management is of the opinion that the final resolution of any currently pending or threatened litigation is not likely to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

ITEM 1A.RISK FACTORS

The registrant’s current report on Form 8-K filed April 17, 2008 is incorporated by reference herein.

Due to the accounting treatment of our derivative contracts, increases in prices for natural gas and crude oil could result in non-cash balance sheet reductions.

With the objective of enhancing the predictability of future revenues, from time to time we enter into natural gas and crude oil derivative contracts. We elected to designate these derivative contracts as cash flow hedges under the provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Due to the mark-to-market accounting treatment for these contracts, we could recognize incremental hedge liabilities between reporting periods resulting from increases in reference prices for natural gas and crude oil, which could result in our recognizing a non-cash low in our accumulated other comprehensive income (loss) and a consequent non-cash decrease in our members’ equity between reporting periods. Any such decrease could be substantial.

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ITEM 6.EXHIBITS

Exhibit No.		Description
3.1		Amended and Restated Limited Liability Company Agreement of Atlas Energy Resources, LLC(1)
3.2		Amendment No. 1 to Amended and Restated Operating Agreement of Atlas Energy Resources, LLC(2)
3.3		Certificate of Formation of Atlas Energy Resources, LLC(3)
4.1		Form of common unit certificate (included as Exhibit A to the Amended and Restated Limited Liability Company Agreement of Atlas Energy Resources, LLC)(1)
10.1		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	(a)	First Amendment to Credit Agreement, dated as of October 25, 2007(4)
10.2		Indenture dated January 23, 2008(5)
10.3		Registration Rights Agreement dated January 23, 2008(5)
10.4		Purchase Agreement dated January 17, 2008(6)
10.5		Purchase Agreement dated May 5, 2008(7)
10.6		Purchase Agreement dated May 6, 2008(6)
10.7		Registration Rights Agreement dated May 9, 2008(6)
10.8		Contribution, Conveyance and Assumption Agreement, dated as of December 18, 2006, among Atlas America, Inc., Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC)(1)
10.8		Omnibus Agreement, dated as of December 18, 2006, between Atlas America, Inc. and Atlas Energy Resources, LLC(1)
10.9		Management Agreement, dated as of December 18, 2006, among Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC and Atlas Energy Management, Inc(1)
10.10		Amendment and Joinder to Gas Gathering Agreements, dated as of December 18, 2006, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, LLC, Viking Resources, LLC, Atlas Noble, LLC, Atlas Resources, LLC, Atlas America, LLC, Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC(1)
10.11		Amendment and Joinder to Omnibus Agreement, dated as of December 18, 2006 among Atlas Pipeline, Atlas America, Resource Energy, LLC, Viking Resources, LLC, Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC(1)
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 January 24, 2008.
(6)	Previously filed as an exhibit to our Form 8-K filed May 9, 2008.
(7)	Previously filed as an exhibit to our Form 8-K filed May 5, 2008.

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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
	(Registrant)
Date: November 6,, 2008	By:	/s/ Matthew A. Jones
		Matthew A. Jones
		Chief Financial Officer
Date: November 6, 2008	By:	/s/Nancy J. McGurk
		Nancy J. McGurk Senior Vice President and Chief Accounting Officer

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