Atlas Energy Resources 10Q 2008 Q1 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 March 31, 2008

[ ]

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

For the transition period from _________ to __________

Commission file number: 1-33193

ATLAS ENERGY RESOURCES, LLC

(Exact name of registrant as specified in its charter)

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

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

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

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

Indicate by check mark whether the registrant 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 [ ] Accelerated filer [X] 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 - March 31, 2008 and December 31, 2007	3

	Consolidated Statements of Income for the Three Months Ended March 31, 2008 and 2007	4

	Consolidated Statement of Changes in Members’ Equity for the Three Months Ended March 31, 2008	5

	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2008 and 2007	6

	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	44

Item 4.	Controls and Procedures	48

PART II	OTHER INFORMATION

Item 6.	Exhibits	49

SIGNATURES		50

ATLAS ENERGY RESOURCES, LLC

CONSOLIDATED BALANCE SHEETS

(in thousands)

	March 31,			December 31,
	2008			2007
	(Unaudited)			(Audited)
ASSETS
Current assets:
Cash and cash equivalents	$	7,612		$	25,258
Accounts receivable		63,485			57,311
Hedge receivable from Partnerships		19,525			213
Current portion of hedge asset		179			38,181
Prepaid expenses and other		8,779			8,265
Total current assets		99,580			129,228

Property, plant and equipment, net		1,733,037			1,693,467
Other assets, net		36,864			28,312
Intangible assets, net		4,755			5,061
Goodwill		35,166			35,166
	$	1,909,402		$	1,891,234

LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	22		$	30
Accounts payable		59,171			55,051
Liabilities associated with drilling contracts		48,407			132,517
Current portion of hedge liability		64,361			356
Accrued liabilities		33,224			34,535
Total current liabilities		205,185			222,489

Long-term debt		829,000			740,000
Other long-term liabilities		3,535			2,372
Advances from affiliates		17,555			8,696
Long-term hedge liability		78,933			39,204
Asset retirement obligations		43,801			42,358

Commitments and contingencies (Note 10)

Members’ equity:
Class B common unit holders		837,268			835,447
Class A unit holder		6,053			5,770
Accumulated other comprehensive income (loss)		(111,928	)		(5,102	)
Total members’ equity	$	731,393		$	836,115
	$	1,909,402		$	1,891,234

See accompanying notes to consolidated financial statements

ATLAS ENERGY RESOURCES, LLC

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per unit data)

(Unaudited)

	Three Months Ended
	March 31,
	2008			2007
REVENUES
Well construction and completion	$	104,138		$	72,378
Gas and oil production		76,226			21,260
Administration and oversight		5,017			4,544
Well services		4,798			3,721
Gathering		4,410			3,288
Total revenues		194,589			105,191

COSTS AND EXPENSES
Well construction and completion		90,555			62,932
Gas and oil production		13,081			3,902
Well services		2,412			2,043
Gathering		96			—
Gathering fees-Atlas Pipeline		4,027			3,288
General and administrative		11,792			6,899
Depreciation, depletion and amortization		21,810			5,868
Total operating expenses		143,773			84,932

OPERATING INCOME		50,816			20,259

OTHER INCOME (EXPENSE)
Interest expense		(13,305	)		(410	)
Other-net		32			92
Total other income (expense)		(13,273	)		(318	)
Net income	$	37,543		$	19,941


Allocation of net income attributable to members’ interests:
Class A units	$	1,954		$	399
Class B common units		35,589			19,542
Net income attributable to members’ interests	$	37,543		$	19,941

Net income per Class B common unit:
Basic	$	.59		$	.53
Diluted	$	.58		$	.53
Weighted average Class B common units outstanding:
Basic		60,711			36,627
Diluted		61,234			36,967

See accompanying notes to consolidated financial statements

ATLAS ENERGY RESOURCES, LLC

CONSOLIDATED STATEMENT OF CHANGES IN MEMBERS’ EQUITY

THREE MONTHS ENDED MARCH 31, 2008

(in thousands, except unit data)

(Unaudited)

												Accumulated
												Other			Total
	Class A Units					Class B Common Units						Comprehensive			Members’
		Units		Amount			Units		Amount			(Loss)			Equity
Balance, January 1, 2008		1,238,986	$	5,770			60,710,374	$	835,447		$	(5,102	)	$	836,115
Units issued							375		—
Distributions paid on unissued units under incentive plan									(320	)					(320	)
Distributions to members				(1,671	)				(34,605	)					(36,276	)
Stock-based compensation									1,320						1,320
Other									(163	)					(163	)
Net income				1,954					35,589						37,543
Other comprehensive loss												(106,826	)		(106,826	)
Balance, March 31, 2008		1,238,986	$	6,053			60,710,749	$	837,268		$	(111,928	)	$	731,393

See accompanying notes to consolidated financial statements

ATLAS ENERGY RESOURCES, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Three Months Ended
	March 31,
	2008			2007
CASH FLOWS USED IN OPERATING ACTIVITIES:
Net income	$	37,543		$	19,941
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Amortization of deferred finance costs		770			13
Depreciation, depletion and amortization		21,810			5,868
Cash received from prior year ineffective derivatives		5,028			—
Non-cash compensation on long-term incentive plans		1,320			1,045
Equity in loss of unconsolidated subsidiary		73			—
Distributions paid to minority interest, net		(36	)		—
Gain on asset dispositions		(12	)		(28	)
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable and prepaid expenses		(6,674	)		9,740
Increase (decrease) in accounts payable and accrued expenses		6,310			(3,926	)
Decrease in liabilities associated with drilling contracts		(84,110	)		(67,084	)
Increase in other operating assets and liabilities		5			543
Net cash used in operating activities		(17,973	)		(33,888	)

CASH FLOWS USED IN INVESTING ACTIVITIES:
Capital expenditures		(55,617	)		(22,077	)
Proceeds from sale of assets		34			31
Decrease in other assets		(16	)		(7	)
Net cash used in investing activities		(55,599	)		(22,053	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings		98,000			56,500
Principal payments on borrowings		(259,008	)		(15	)
Net proceeds - senior unsecured notes		250,000			—
Distributions to unit holders		(35,631	)		(2,242	)
Advances (to) from affiliates		8,859			(232	)
Increase in deferred financing costs and other		(6,294	)		(136	)
Net cash provided by financing activities		55,926			53,875
Decrease in cash and cash equivalents		(17,646	)		(2,066	)
Cash and cash equivalents at beginning of period		25,258			8,833
Cash and cash equivalents at end of period	$	7,612		$	6,767

See accompanying notes to consolidated financial statements

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 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. (“AAI”) (NASDAQ: ATLS). AAI 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 AAI in the form of a non-taxable dividend and to repay debt. Concurrent with this transaction, AAI 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 completion of the offering and private placement, AAI owns 49.4% of the Company.

Principles of Consolidation

Transactions between the Company and other AAI 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 its pro rata share of assets, liabilities, revenues and costs and expenses of the Partnerships in which it has an interest. All significant intercompany balances and transactions within the Company 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. The results of operations for the three month period ended March 31, 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

Reference is hereby made to the Company’s Annual Report on Form 10-K for the fiscal 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 the quarterly report included herein.

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (CONTINUED)

March 31, 2008

(Unaudited)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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 March 31, 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 ended March 31, 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 March 31, 2008 and December 31, 2007 of $49.4 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.

The weighted average interest rate used to capitalize interest was 5.4% and 5.7% for the three months ended March 31, 2008 and 2007, respectively, which resulted in interest capitalized of $646,000 and $322,500 for the respective periods.

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

March 31, 2008

(Unaudited)

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

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):

	March 31,			December 31,
	2008			2007
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,064,705		$	1,043,687
Wells and related equipment		797,000			752,184
		1,861,705			1,795,871
Unproved properties		9,724			16,380
Support equipment		7,636			6,936
		1,879,065			1,819,187
Land, buildings and improvements		6,167			5,881
Other		9,995			9,653
		1,895,227			1,834,721
Accumulated depreciation, depletion and amortization		(162,190	)		(141,254	)
	$	1,733,037		$	1,693,467

Oil and Gas Properties

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

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.

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

March 31, 2008

(Unaudited)

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

Recently Issued Financial Accounting Standards

In March 2008, the Financial Accounting Standards Board, (“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.

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 SFAS 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. 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.

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

March 31, 2008

(Unaudited)

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

In September 2007, 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. 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.

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 FASB 159 did not impact the Company's consolidated financial statements for the quarter ended March 31, 2008.

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 Final FASB Staff Position, (“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. The deferral applies to nonfinancial assets and liabilities measured at fair value in a business combination; impaired properties; plant and equipment; intangible assets and goodwill; and 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.

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

March 31, 2008

(Unaudited)

NOTE 3 —ACQUISITION OF DTE GAS & OIL COMPANY

In 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 (“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, 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

The purchase price allocation for the acquisition is based on a third-party valuation. It is subject to minor adjustments as management finalizes the allocation. AGO’s operations are included within the Company’s consolidated financial statements beginning June 29, 2007.

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

March 31, 2008

(Unaudited)

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

The following data presents pro forma revenues, net income and basic and diluted net income per unit for the Company as if the AGO acquisition, Class B common unit and Class D unit 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):

	Three Months Ended
	March 31, 2007
	As Reported		Pro Forma Adjustments			Pro Forma

Revenues	$	105,191	$	(17,564	)	$	87,627
Net income	$	19,941	$	(54,699	)	$	(34,758	)
Net income per Class B common units outstanding - basic	$	0.53	$	(1.09	)	$	(0.56	)
Weighted average Class B common unit outstanding - basic		36,627		24,036			60,663
Net income per Class B common unit - diluted	$	0.53	$	(1.09	)	$	(0.56	)
Weighted average Class B common unit outstanding - diluted		36,967		24,036			61,003

Pro forma adjustments to revenues include losses on derivatives realized by AGO of $51.0 million. 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
	March 31,
	2008			2007
Net income	$	37,543		$	19,941
Other comprehensive loss:
Unrealized holding loss on hedging contracts		(100,194	)		(18,352	)
Less reclassification adjustment for gains realized in net income		(6,632	)		(2,444	)
Total other comprehensive loss		(106,826	)		(20,796	)
Comprehensive loss	$	(69,283	)	$	(855	)

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

	March 31, 2008			December 31, 2007
Unrealized loss on commodity derivatives	$	(109,801	)	$	(5,102	)
Unrealized loss on interest rate derivatives		(2,127	)		—
	$	(111,928	)	$	(5,102	)

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

March 31, 2008

(Unaudited)

NOTE 5 - NET INCOME PER COMMON UNIT

Basic earnings 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 AAI’s 2% interest and incentive distributions.

Diluted earnings 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
	March 31,
	2008		2007
Weighted average number of common unit holder units - basic		60,711		36,627
Add effect of dilutive unit incentive awards		523		340
Weighted average number of common unit holder units - diluted		61,234		36,967

NOTE 6 - OTHER ASSETS AND INTANGIBLE ASSETS

Other Assets

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

	March 31,		December 31,
	2008		2007
Long-term hedge receivable from Partnerships	$	21,709	$	13,542
Long-term derivative asset		1,963		6,882
Deferred finance costs, net of accumulated amortization of $3,478 and $2,708		13,012		7,650
Other		180		238
	$	36,864	$	28,312

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). Long-term hedge receivable from Partnerships represents the portion of the long-term unrealized hedge loss on contracts that has been allocated to them based on their share of total production volumes sold.

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 March 31, 2008 and 2007 was $306,000 and $204,000, respectively.

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

March 31, 2008

(Unaudited)

NOTE 6 - OTHER ASSETS AND INTANGIBLE ASSETS (Continued)

The aggregate estimated annual amortization expense of the above contracts for the next five years ending March 31 is as follows: 2009—$1.2 million ; 2010—$845,000; 2011—$703,000; 2012─$538,000 and 2013—$154,000.

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

	March 31,			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		(10,478	)		(10,172	)
	$	4,755		$	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 requires the Company to consider estimated salvage value in the calculation of depreciation, depletion and amortization.

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
	March 31,
	2008			2007
Asset retirement obligations, beginning of period	$	42,358		$	26,726
Liabilities incurred		782			520
Liabilities settled		(2	)		(21	)
Accretion expense		663			365
Asset retirement obligations, end of period	$	43,801		$	27,590

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

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

March 31, 2008

(Unaudited)

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 AAI. The employees supporting the Company’s operations are employees of AAI. AAI 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. These costs are reflected in general and administrative expense in the Company’s consolidated statements of income.

The Company participates in AAI’s cash management program. Any cash activity performed by AAI on behalf of the Company has been recorded 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’ revenue, and costs and expenses according to the respective Partnership agreements.

Relationship with Atlas Pipeline. The Company has a master gas gathering agreement with Atlas Pipeline which governs the transportation of substantially all of the natural gas the Company produces from the wells it operates. This agreement generally provides for the Company to pay Atlas Pipeline 16% of the sales price received for natural gas produced from wells located on Atlas Pipeline’s gathering systems. These fees are shown as Gathering fee—Atlas Pipeline on the Company’s consolidated statements of income. Atlas America agreed to assume the Company’s obligation to pay gathering fees to Atlas Pipeline after the Company’s initial public offering.

The Company charges rates to wells connected to these gathering systems, substantially all of which are owned by the Partnerships, generally ranging from $.35 per Mcf to 13% of the sales price received for the natural gas transported. Under the terms of its contribution agreement with AAI, the Company remits this amount to AAI. 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 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. 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.

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

March 31, 2008

(Unaudited)

NOTE 9 - DERIVIATIVE AND FINANCIAL INSTRUMENTS (Continued)

At March 31, 2008, the Company had 675 natural gas and 120 oil futures contracts related to natural gas and oil sales covering 140 million MMbtus and 305 MBbls of natural gas and oil, respectively, maturing through March 31, 2013 at a combined average settlement price of $8.34 per MMBtu and $99.43 per Bbl, respectively.

The Company has a $109.8 million unrealized net loss shown in accumulated other comprehensive income (loss) at March 31, 2008. If the fair values of the instruments remain at current market values, the Company will reclassify $47.7 million of losses to its consolidated statements of income over the next twelve-month period as these contracts settle and $62.1 million of losses will be reclassified in later periods.

The Company recognized gains on settled contracts covering natural gas production of $6.5 million and $2.4 million for the three months ended March 31, 2008 and 2007, respectively. There were no oil settlements for the three months ended March 31, 2008 or 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 ended March 31, 2008 and 2007 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges

On May 18, 2007, the Company signed a definitive agreement to acquire AGO (see Note 3). In connection with the financing of this transaction, the Company agreed as a condition precedent to closing that it would hedge 80% of its projected natural gas volumes for no less than three years from the closing date of the transaction. During May 2007, the Company entered into derivative instruments to hedge 80% of the projected production of the assets to be acquired as required under the financing agreement. The production volume of the assets to be acquired was not considered to be “probable forecasted production” under SFAS 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 combined and 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.

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

March 31, 2008

(Unaudited)

NOTE 9 - DERIVATIVE AND FINANCIAL INSTRUMENTS (Continued)

As of March 31, 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		(Liability)
	(MMbtu)		(per MMbtu)		(in thousands)⁽¹⁾
2008		29,670,000	$	8.72	$	(44,667	)
2009		37,760,000	$	8.54		(41,732	)
2010		26,360,000	$	8.11		(22,838	)
2011		18,680,000	$	7.90		(15,482	)
2012		13,800,000	$	8.20		(7,813	)
2013		1,500,000	$	8.73		(132	)
					$	(132,664	)

Natural Gas Costless Collars

Production
Period Ending					Average		Fair Value
December 31,	Option Type		Volumes		Floor and Cap		(Liability)
			(MMbtu)		(per MMbtu)		(in thousands) ⁽¹⁾
2008		Puts purchased		1,170,000	$	7.50	$	—
2008		Calls sold		1,170,000	$	9.40		(1,423	)
2010		Puts purchased		2,880,000	$	7.75		—
2010		Calls sold		2,880,000	$	8.75		(2,055	)
2011		Puts purchased		7,200,000	$	7.50		—
2011		Calls sold		7,200,000	$	8.45		(4,968	)
2012		Puts purchased		720,000	$	7.00		—
2012		Calls sold		720,000	$	8.37		(633	)
							$	(9,079	)

Crude Oil Fixed Price Swaps

Production
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset
	(Bbl)		(per Bbl)		(in thousands)⁽²⁾
2008		33,000	$	103.25	$	125
2009		36,000	$	99.03		117
2010		31,000	$	96.52		76
2011		25,000	$	95.79		52
2012		21,500	$	95.35		36
2013		6,000	$	95.35		9
					$	415

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

March 31, 2008

(Unaudited)

NOTE 9 - DERIVATIVE AND FINANCIAL INSTRUMENTS (Continued)

Crude Oil Costless Collars

Production
Period Ending					Average		Fair Value
December 31,	Option Type		Volumes		Floor and Cap		Asset
			(Bbl)		(per Bbl)		(in thousands) ⁽²⁾
2008		Puts purchased		30,500	$	85.00	$	15
2008		Calls sold		30,500	$	127.13		—
2009		Puts purchased		36,500	$	85.00		50
2009		Calls sold		36,500	$	118.63		—
2010		Puts purchased		31,000	$	85.00		44
2010		Calls sold		31,000	$	112.92		—
2011		Puts purchased		27,000	$	85.00		35
2011		Calls sold		27,000	$	110.81		—
2012		Puts purchased		21,500	$	85.00		25
2012		Calls sold		21,500	$	110.06		—
2013		Puts purchased		6,000	$	85.00		7
2013		Calls sold		6,000	$	110.09		—
							$	176
					Total net liability		$	(141,152	)

_____________

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

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

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

	March 31,			December 31,
	2008			2007
Current portion of hedge asset	$	179		$	38,181
Long-term hedge asset		1,963			6,882
Current portion of hedge liability		(64,361	)		(356	)
Long-term hedge liability		(78,933	)		(39,204	)
	$	(141,152	)	$	5,503

In addition, $40.3 million of unrealized losses and $3.4 million of unrealized hedge gains have been allocated to the Partnerships at March 31, 2008 and December 31, 2007, respectively, based on the Partnerships’ share of estimated future gas production related to the hedges not yet settled and is included in the consolidated balance sheets as follows (in thousands):

	March 31,			December 31,
	2008			2007
Unrealized hedge loss - short-term	$	19,525		$	213
Other assets - long-term		21,709			13,542
Accrued liabilities - short-term		(101	)		(9,013	)
Unrealized hedge gain - long-term		(811	)		(1,348	)
	$	40,322		$	3,394

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

March 31, 2008

(Unaudited)

NOTE 9 - DERIVATIVE AND FINANCIAL INSTRUMENTS (Continued)

Interest Rate Risk Hedging Program

At March 31, 2008, the Company had debt outstanding of $579.0 million under its revolving credit facility. During the quarter ended March 31, 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”) on $150.0 million of the outstanding debt through January 2011. The LIBOR interest rate swaps are at 4.36%, which includes an initial margin of 1.25% over the three-year fixed swap price of 3.11%. 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 loss of approximately $2.1 million at March 31, 2008. The Company recognized gains on settled swaps of $91,000 for the three months ended March 31, 2008. The Company did not enter into any interest rate swaps in the three months ended March 31, 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.

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.

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

March 31, 2008

(Unaudited)

NOTE 9 - DERIVATIVE AND FINANCIAL INSTRUMENTS (Continued)

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 March 31, 2008 (in thousands):

	Level 2			Total

Commodity-based derivatives	$	(141,152	)	$	(141,152	)
Interest rate swap-based derivatives		(2,127	)		(2,127	)
	$	(143,279	)	$	(143,279	)

NOTE 10 - COMMITMENTS AND CONTINGENCIES

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.

AAI 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.

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

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

March 31, 2008

(Unaudited)

NOTE 11 - LONG-TERM DEBT

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

	March 31,			December 31,
	2008			2007
Revolving credit facility	$	579,000		$	740,000
Senior unsecured notes		250,000			—
Other debt		22			30
		829,022			740,030
Less current maturities		(22	)		(30	)
	$	829,000		$	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 will be redetermined semiannually on April 1 and October 1 subject to changes in the Company’s oil and gas reserves. The initial borrowing base was reduced to $672.5 million in January 2008, upon the issuance by the Company of $250.0 million in senior unsecured notes and subsequently redetermined on April 30, 2008 to a borrowing base of $735.0 million. Up to $50.0 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 an 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 March 31, 2008, the weighted average interest rate on outstanding borrowings was 4.3%.

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 March 31, 2008. The facility terminates in June 2012, when all outstanding borrowings must be repaid. At March 31, 2008 and December 31, 2007, $579.0 million and $740.0 million, respectively, were outstanding under this facility. In addition, letters of credit of $1.1 million were outstanding at each date, which are not reflected as borrowings on the Company’s consolidated balance sheets.

Senior Unsecured Notes. In January 2008, the Company issued $250.0 million of 10-year, 10.75% senior unsecured notes due 2018. The Company used the proceeds of the note offering to reduce the balance outstanding on its senior secured 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. In connection with a Senior Notes registration rights agreement entered into by the Company, it filed an exchange offer registration statement with the Securities and Exchange Commission on March 28, 2008.

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

March 31, 2008

(Unaudited)

NOTE 11 - LONG-TERM DEBT (Continued)

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

2009	$	22
2010		―
2011		―
2012		―
2013 and thereafter		829,000
	$	829,022

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.

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

March 31, 2008

(Unaudited)

NOTE 12 - OPERATING SEGMENT INFORMATION (Continued)

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.

	Three Months Ended
	March 31,
	2008		2007
Gas and oil production
Appalachia:
Revenues	$	28,908	$	21,260
Costs and expenses		5,019		3,902
Segment profit	$	23,889	$	17,358

Michigan:
Revenues	$	47,318	$	—
Costs and expenses		8,062		—
Segment profit	$	39,256	$	—

Partnership management⁽¹⁾
Revenues	$	117,416	$	83,931
Costs and expenses		96,989		68,263
Segment profit	$	20,427	$	15,668

	Three Months Ended
	March 31,
	2008			2007
Reconciliation of segment profit to net income
Segment profit
Gas and oil production-Appalachia	$	23,889		$	17,358
Gas and oil production-Michigan		39,256			—
Partnership management		20,427			15,668
Total segment profit		83,572			33,026
General and administrative		(11,792	)		(6,899	)
Depreciation, depletion and amortization		(21,810	)		(5,868	)
Interest expense		(13,305	)		(410	)
Other − net		878			92
Net income	$	37,543		$	19,941

_____________

⁽¹⁾	Does not include revenues and expenses for AGO well services and transportation of $846,000 that do not meet the quantitative threshold for reporting segment information for the three months ended March 31, 2008. This amount has been included in “Other - net” above.

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

March 31, 2008

(Unaudited)

NOTE 12—OPERATING SEGMENT INFORMATION (Continued)


	Three Months Ended
	March 31,
	2008		2007
Capital expenditures
Gas and oil production:
Appalachia	$	39,211	$	21,494
Michigan		15,263		—
Partnership management		810		477
Corporate		333		106
	$	55,617	$	22,077

		March 31,		December 31,
		2008		2007
Balance sheets
Goodwill:
Gas and oil production - Appalachia	$	21,527	$	21,527
Partnership management		13,639		13,639
	$	35,166	$	35,166

Total assets
Gas and oil production:
Appalachia	$	534,613	$	491,199
Michigan		1,314,763		1,330,432
Partnership management		33,070		30,359
Corporate		26,956		39,244
	$	1,909,402	$	1,891,234

NOTE 13 - BENEFIT PLANS

Stock 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 AAI’s compensation committee, which may grant awards of either restricted stock units, phantom units or unit options for an aggregate of 3,742,000 common units. Awards granted in the three months ended March 31, 2008 and 2007 vest 25% after three years and 100% upon the four year anniversary of grant, except for awards of 1,500 units in each period 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 the Company’s compensation committee, cash equivalent to the then fair market value of a common unit of the Company. In tandem with phantom unit grants, the Company’s compensation committee may grant a distribution equivalent right (“DER”), which is the right to receive cash per 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.

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

March 31, 2008

(Unaudited)

NOTE 13 - BENEFIT PLANS (Continued)

Restricted Stock and Phantom Units. Under the ATN LTIP, 12,375 and 511,000 units of restricted stock and phantom units were awarded in the three months ended March 31, 2008 and 2007, respectively. The fair value of the grants is based on the closing stock price on the grant date, and is being charged to operations over the requisite service periods using a straight-line attribution method.

The following table summarizes the activity of restricted stock and phantom units for the three months ended March 31, 2008:

				Weighted
				Average
				Grant Date
	Units			Fair Value
Non-vested shares outstanding at December 31, 2007		624,665		$	24.42
Granted		12,375			28.17
Vested		(375	)		23.06
Forfeited		(100	)		35.00
Non-vested shares outstanding at March 31, 2008		636,565		$	24.49

Stock Options. In the three months ended March 31, 2008 and 2007, 6,500 and 1,297,600 unit options, respectively, 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:

	Three Months Ended
	March 31,
	2008			2007
Expected life (years)		6.25			6.25
Expected volatility		27	%		25	%
Risk-free interest rate		2.8	%		4.7	%
Expected dividend yield		7.0	%		8.0	%
Weighted average fair value of stock options granted	$	3.41		$	2.41

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

March 31, 2008

(Unaudited)

NOTE 13 - BENEFIT PLANS (Continued)

The following table sets forth option activity for the three months ended March 31, 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		6,500		$	30.24
Exercised		—			—
Forfeited or expired		(1,200	)	$	26.05
Outstanding at March 31, 2008		1,900,352		$	24.11		8.7	$	13,085
Options exercisable at March 31, 2008		93,438		$	21.00		8.7
Available for grant at March 31, 2008		1,192,804

The Company recognized $1.3 million and $1.0 million in compensation expense related to restricted stock units, phantom units and stock options for the three months ended March 31, 2008 and 2007, respectively. The Company paid $320,000 and $34,000 with respect to its LTIP DERs for the three months ended March 31, 2008 and 2007, respectively. These amounts were recorded as a reduction of members’ equity on the Company’s consolidated balance sheets. At March 31, 2008, the Company had approximately $14.8 million of unrecognized compensation expense related to the unvested portion of the restricted stock units, phantom units and options.

NOTE 14 - PRIVATE PLACEMENT OF CLASS B COMMON AND CLASS D UNITS

To partially fund the acquisition of AGO, 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.

ATLAS ENERGY RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

March 31, 2008

(Unaudited)

NOTE 15 - CASH DISTRIBUTIONS

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

			Cash
			Distribution			Total Cash		Total		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⁽³⁾		March 31, 2008	$	0.59		$	36,153	$	731	$	1,203

____________

⁽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 April 22, 2008 the Company declared a quarterly cash distribution for the quarter ended March 31, 2008 of $0.59 per common unit. The distribution is payable May 15, 2008 to holders of record as of May 7, 2008.

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, which consist of our interests in oil and gas 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 ended March 31, 2008, we had the following key assets:

In our Appalachia gas and oil operations:

direct and indirect working interests in approximately 7,948 gross producing gas and oil wells;

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

net daily production of 32.7 Mmcfe per day;

approximately 873,100 gross (827,400 net) acres, of which approximately 578,300 gross (571,200 net) acres, are undeveloped; and

In our Michigan gas and oil operations:

direct and indirect working interests in approximately 2,347 gross producing gas and oil wells;

overriding royalty interests in approximately 78 gross producing gas and oil wells;

net daily production of 59.1 Mmcfe per day; and

approximately 347,600 gross (275,300 net) acres, of which approximately 52,900 gross (43,300 net) acres, are undeveloped.

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

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.

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. Drilling costs are capitalized, but charged to expense if the well is determined to be unsuccessful. Generally, if a well does not find proved reserves within one year following completion of drilling, the costs of drilling the well are charged to expense.

Higher natural gas and oil prices have led to higher demand for drilling rigs, operating personnel and field supplies and services and have caused increases in the costs of those goods and services. To date, the higher sales prices have more than offset the higher drilling and operating costs.

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. Our future growth will depend in part on our ability to continue to add reserves in excess of production.

How We Evaluate our Operations

Non-GAAP Financial Measures

We use a variety of financial and operations measures to assess our performance, including a 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.

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:

	Three Months Ended
	March 31,
	2008			2007
Reconciliation of net income to non-GAAP measures:
Net income	$	37,543		$	19,941
Depreciation and amortization		21,810			5,868
Interest expense		13,305			410
EBITDA		72,658			26,219
Adjustment to reflect cash impact of derivatives		5,028	⁽¹⁾		−
Non-cash compensation expense		1,320			1,045
Adjusted EBITDA	$	79,006		$	27,264
Interest expense		(13,305	)		(410	)
Amortization of deferred financing costs (included within interest expense)		770			13
Maintenance capital expenditures		(12,975	)		(8,750	)
Distributable cash flow	$	53,496		$	18,117

^{_________________}

⁽¹⁾	Represents cash proceeds received during the quarter from the settlement of ineffective derivative gains recognized in fiscal 2007 associated with natural gas produced during the quarter but not reflected in the three months ended March 31, 2008 Consolidated Statements of Income.

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 borrowings under a new credit facility with a current borrowing base of $735.0 million that matures in June 2012. We intend to continue to expand our business through strategic acquisitions and internal growth projects that increase distributable cash flow.

Private Equity Offering

We financed a portion of the purchase price for the DTE Gas & Oil acquisition with the proceeds of a private offering, completed on June 29, 2007. We raised net proceeds of $597.5 million through the sale of 7,298,181 Class B common units and 16,702,828 Class D units at a weighted average price of $25.00. On November 10, 2007, the Class D units automatically converted to common units on a one-for-one basis. On February 20, 2008, a registration statement with the Securities and Exchange Commission covering the resale of these units became effective.

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 April 30, 2008, the credit facility has a current borrowing base of $735.0 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% of 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 March 31, 2008, the weighted average interest rate on outstanding borrowings under our credit facility was 4.3%.

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 Partnerships. We raised $363.3 million in the year ended December 31, 2007 and plan to raise $400.0 million in the year ended December 31, 2008. During the three months ended March 31, 2008, our investment partnerships invested $119.8 million in drilling and completing wells, of which we contributed $25.7 million.

We generally structure our investment partnerships so that, upon formation of a partnership, we coinvest in and contribute leasehold acreage to it, enter into drilling and well operating agreements with it and become its managing general partner. In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues which are not directly dependent on natural gas and oil prices. We receive an interest in our investment partnerships proportionate to the amount of capital and the value of the leasehold acreage we contribute, typically 27% to 30% of the overall capitalization in a particular partnership. We also receive an additional interest in each partnership, typically 7%, for which we do not make any additional capital contribution.

Our investment partnerships provide tax advantages to their investors because an investor’s share of the partnership’s intangible drilling cost deduction may be used to offset ordinary income. Intangible drilling costs include items that do not have salvage value, such as labor, fuel, repairs, supplies and hauling. Historically, under our partnership agreements, approximately 90% of the subscription proceeds received by each partnership have been used to pay 100% of the partnership’s intangible drilling costs. For example, an investment of $10,000 has generally permitted the investor to deduct approximately $9,000 in the year in which the investor invests.

RECENT DEVELOPMENTS

Senior Unsecured Notes

In January 2008, we issued $250.0 million of 10-year, 10.75% senior unsecured notes due 2018. We used the proceeds of the note offering to reduce the balance outstanding on our senior secured 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 certain 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. In connection with a Senior Notes registration rights agreement entered into by us, we filed an exchange offer registration statement with the Securities and Exchange Commission on March 28, 2008.

Interest Rate Swap

GENERAL TRENDS AND OUTLOOK

We expect our business to be affected by the following 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.

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.

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. In order to sustain and grow our level of distributions, we will need to make acquisitions that are accretive to distributable cash flow per unit. We intend to pursue acquisitions of producing oil and gas properties from third parties. 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. It may in the future, however, increase the cost to acquire or replace property, plant and equipment, and may increase the costs of labor and supplies. 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.

RESULTS OF OPERATIONS

GAS AND OIL PRODUCTION

The following table sets forth information relating to our production segments during the periods indicated (dollars shown in thousands):

	Three Months Ended
	March 31,
	2008			2007
Production revenues (in thousands):
Gas ⁽¹⁾	$	72,874		$	19,427
Oil		3,351			1,826
Production volume:⁽²⁾
Appalachia
Gas (Mcf/day) ⁽¹⁾		30,286			23,681
Oil (Bbls/day)		399			359
Michigan
Gas (Mcf/day)		59,056			—
Oil (Bbls/day)		6			—
Total (Mcfe/day)		91,772			25,835
Average sales prices:
Gas (per Mcf)^{(3) (5)}	$	9.58		$	9.12
Oil (per Bbl)		91.03			56.52
Production costs:⁽⁴⁾
As a percent of production revenues		12	%		10	%
Per Mcfe - Appalachia	$	.91		$	.87
Per Mcfe - Michigan	$	1.22		$	—
Total per Mcfe	$	1.11		$	.87
Transportation costs:
Per Mcfe - Appalachia		.78			.80
Per Mcfe - Michigan		.28			—
Depletion per Mcfe	$	2.52		$	2.31

____________

⁽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 before the effects of financial hedging were $8.32 and $7.85 for the three months ended March 31, 2008 and 2007, respectively.

⁽⁴⁾	Production costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes, insurance and production overhead.

⁽⁵⁾	Includes $5.0 million in derivative proceeds, which were not included as gas revenue in the three months ended March 31, 2008.

Our natural gas revenues were $72.9 million in the three months ended March 31, 2008, an increase of $53.5 million (275%) from $19.4 million in the three months ended March 31, 2007. The increase was attributable to volumes associated with AGO which we acquired in June 2007 and a 28% increase in our Appalachian production volumes due to production associated with wells we drilled for our investment partnerships in the twelve months ended March 31, 2008. The $53.5 million increase in natural gas revenues consisted of $53.8 million attributable to increases in natural gas production volumes, partially offset by $323,000 attributable to decreases in natural gas sales prices (after the effect of financial hedges).

We believe that gas volumes will continue to be favorably impacted in the remainder of 2008 with the acquisition of AGO in June 2007 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 $3.4 million in the three months ended March 31, 2008, an increase of $1.6 million (84%) from $1.8 million during the three months ended March 31, 2007. The increase resulted from a 61% increase in the average sales price of oil, and a 14% increase in production volumes. The $1.6 million increase consisted of $1.2 million attributable to increases in sales prices, and $410,000 attributable to volume increases, from the production of new wells we drilled in the twelve months ended March 31, 2008.

Our Appalachia production costs were $5.0 million in the three months ended March 31, 2008, an increase of $1.1 million (29%) from $3.9 million in the three months ended March 31, 2007. This increase includes $667,000 attributable to increases in labor, compressor, and maintenance costs and a $450,000 increase in transportation costs associated with an increase in the number of wells we own from the prior year period.

Our Michigan production costs were $8.1 million in the three months ended March 31, 2008, representing labor, compressor, transportation and maintenance costs.

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
	March 31,
	2008		2007
Average construction and completion revenue per well	$	478	$	299
Average construction and completion cost per well		416		260
Average construction and completion gross profit per well	$	62	$	39

Gross profit margin	$	13,583	$	9,446

Net wells drilled		218		242

Our well construction and completion segment margin was $13.6 million in the three months ended March 31, 2008, an increase of $4.2 million (44%) from $9.4 million in the three months ended March 31, 2007. During the three months ended March 31, 2008, the increase of $4.2 million in segment margin was attributable to an increase in the gross profit per well ($5.6 million) offset by a decrease in the number of wells drilled ($1.4 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 effects the number of wells we drill. Our average costs and revenues per well have increased due to an increase in the number of Marcellus Shale wells drilled during the quarter ended March 31, 2008.

It should be noted that “Liabilities associated with drilling contracts” on our balance sheet includes $31.5 million of funds raised that have not been applied to the completion of wells as of March 31, 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 second quarter of fiscal 2008. During fiscal 2007 we raised $363.3 million and plan to raise approximately $400.0 million in fiscal 2008.

Administration and Oversight

Administration and oversight represents supervision and administrative fees earned for the drilling and subsequent management of wells for our investment partnerships. Our administration and oversight fees were $5.0 million in the three months ended March 31, 2008, an increase of $474,000 (10%) from $4.5 million in the three months ended March 31, 2007. This increase resulted from an increase in the number of wells drilled and managed for our investment partnerships in the twelve months ended March 31, 2008.

Well Services

Our well services revenues were $4.8 million in the three months ended March 31, 2008, an increase of $1.1 million (29%) from $3.7 million in the three months ended March 31, 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 March 31, 2008.

Our well services expenses were $2.4 million in the three months ended March 31, 2008, an increase of $369,000 (18%) from $2.0 million in the three months ended March 31, 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 it. 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.

Our gathering fee payable to Atlas Pipeline was $4.0 million for the three months ended March 31, 2008, an increase of $738,000 (22%) from $3.3 million in the three months ended March 31, 2007. The increase in the three months ended March 31, 2008 is primarily a result of an increase in throughput of natural gas transported due to higher production volumes in Appalachia.

ALL OTHER INCOME, COSTS AND EXPENSES

General and Administrative

Our general and administrative expenses were $11.8 million in the three months ended March 31, 2008, an increase of $4.9 million (71%) from $6.9 million in the three months ended March 31, 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 $4.9 million in the three months ended March 31, 2008 is principally attributed to the following:

costs associated with AGO acquired on June 29, 2007 were $1.9 million for the quarter ended March 31, 2008;

salaries and wages increased $839,000 due to an increase in salaries and an increase in the number of employees as a result of the growth of our business;

costs associated with our long-term incentive plans increased $275,000 in the three months ended March 31, 2008 as compared to the three months ended March 31, 2007 due to additional units granted in fiscal year 2007;

net syndication costs increased $843,000 as we continue to expand our syndication activities and the drilling funds we raise in our investment partnerships;

accounting and professional fees increased $299,000 due to the growth of our business, higher audit fees and the processing fees associated with the year-end tax reporting to our unit holders; and

exploration costs in Appalachia increased $419,000 due to an increase in activities of our land department as we acquire additional acreage and well sites.

Depletion

Our depletion of oil and gas properties as a percentage of oil and gas revenues was 28% in the three months ended March 31, 2008, compared to 25% in the three months ended March 31, 2007. Depletion expense per Mcfe was $2.52 in the three months ended March 31, 2008, an increase of $0.21 (9%) per Mcfe from $2.31 in the three months ended March 31, 2007. Increases in our depletable basis and production volumes caused depletion expense to increase $15.7 million to $21.0 million in the three months ended March 31, 2008 compared to $5.4 million in the three months ended Months 31, 2007. Depletion expense associated with AGO’s asset base was $13.2 million for the three months ended March 31, 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 $13.3 million in the three months ended March 31, 2008, an increase of $12.9 million from $410,000 in the three months ended March 31, 2007. This increase consists of $7.7 million of interest expense on our credit facility and $5.2 million associated with the issuance of our senior notes in January 2008. These borrowings were used to fund the acquisition of AGO in June 2007 and to fund our drilling capital expenditures.

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):

	Three Months Ended
	March 31,
	2008			2007

Used in operations	$	(17,973	)	$	(33,888	)
Used in investing activities		(55,599	)		(22,053	)
Provided by financing activities		55,926			53,875
Decrease in cash and cash equivalents	$	(17,646	)	$	(2,066	)

We had $7.6 million in cash and cash equivalents at March 31, 2008, as compared to $25.3 million at December 31, 2007. We had a working capital deficit of $105.6 million at March 31, 2008, an increase of $12.3 million from a working capital deficit of $93.3 million at December 31, 2007. The increase in our working capital deficit is due to a decrease of $25.5 million in current hedge receivable and an increase of $64.0 million in current hedge payable, partially offset by a decrease of $84.1 million in liabilities associated with 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. At March 31, 2008, we have $92.4 million available under our credit facility to fund working capital obligations.

CASH FLOWS

Cash flows from operating activities. Cash provided by operations is an important source of short-term liquidity for us. It is directly affected by changes in the price of natural gas and oil, interest rates and our ability to raise funds from our drilling investment partnerships. Net cash used in operating activities decreased $15.9 million in the three months ended March 31, 2008 to $18.0 million from cash used of $33.9 million in the three months ended March 31, 2007, substantially as a result of the following:

an increase in net income before depreciation, depletion and amortization of $34.3 million in the three months ended March 31, 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 $5.0 million related to cash received from prior year ineffective derivative gains; and

changes in operating assets and liabilities decreased operating cash flows by $23.7 million in the three months ended March 31, 2008, compared to the three months ended March 31, 2007.

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

an increase of $16.4 million in accounts receivable and prepaid expenses;

an increase of $10.2 million in accounts payable and accrued expenses; and

a decrease of $17.0 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.

Cash flows used in investing activities. Cash used in our investing activities increased $33.5 million in the three months ended March 31, 2008 to $55.6 million from $22.1 million in the three months ended March 31, 2007 primarily from our $33.5 million increase in capital expenditures related to the increase in the number of wells we drilled in fiscal 2008.

Cash flows from financing activities. Cash provided by our financing activities increased $2.0 million in the three months ended March 31, 2008 to $55.9 million from cash provided of $53.9 million in the three months ended March 31, 2007, primarily as a result of the following:

we issued $250.0 million in senior unsecured notes;

we made repayments on our credit facility from the proceeds of our issuance $250.0 senior secured notes, net of borrowings of $217.5 million;

net monies borrowed from Atlas America increased $9.1 million in the three months ended March 31, 2008, compared to the three months ended March 31, 2007;

deferred financing costs increased $6.0 million in the three months ended March 31, 2008 due to the issuance of our senior unsecured notes; and

we paid $35.6 million in distributions to our unit holders in the three months ended March 31, 2008, an increase of $33.4 million from the three months ended March 31, 2007.

Capital Requirements

Capital expenditures. During the three months ended March 31, 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 three months ended March 31, 2008, our capital expenditures related primarily to investments in our investment partnerships, in which we invested $25.7 million, compared to $17.5 million in the three months ended March 31, 2007. 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 exploration and production operations depends upon any acquisitions made and the level of funds raised through our investment partnerships. We have budgeted to raise up to $400.0 million in fiscal 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.

We expect to fund our maintenance capital expenditures with cash flow from operations and the temporary use of funds raised in our investment partnerships in the period before we invest these funds, as well as funding our investment capital expenditures and any expansion capital expenditures that we might incur with borrowings under our credit facility and with the temporary use of funds raised in our investment partnerships in the period before we invest the funds. We 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
	March 31,
	2008		2007

Maintenance capital expenditures	$	12,975	$	8,750
Expansion capital expenditures		42,642		13,327
Total	$	55,617	$	22,077

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 ($579.0 million outstanding at March 31, 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 will be redetermined based on changes in our oil and gas reserves. The credit facility will mature in June 2012. In January 2008, the borrowing base for Atlas Energy Operating Company was reduced from $850.0 million to $672.5 million upon our issuance of $250.0 million in senior notes and subsequently redetermined on April 30, 2008 to a borrowing base of $735.0 million

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, inflationary trends may occur if the price of natural gas were to increase since such an increase may increase the demand for acreage and for energy equipment and services, thereby increasing the costs of acquiring or obtaining such equipment and services.

ENVIRONMENTAL REGULATION

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

CASH DISTRIBUTIONS

We do not have a contractual obligation to make distributions to our 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; or

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

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

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 March 31, 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.

On April 22, 2008, we declared our quarterly cash distribution for the first quarter of 2008 of $0.59 per common unit. The $36.9 million distribution will be paid on May 15, 2008 to unit holders of record as of May 7, 2008.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The following table summarizes our contractual obligations at March 31, 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⁾	$	579,022	$	22	$	—	$	579,000	$	—
Senior unsecured notes ⁽¹⁾		250,000		—		—		—		250,000
Operating lease obligations		6,978		1,363		2,011		1,227		2,377
Capital lease obligations		—		—		—		—		—
Unconditional purchase obligations		—		—		—		—		—
Other long-term obligation		—		—		—		—		—
Total contractual cash obligations	$	836,000	$	1,385		2,011	$	580,227	$	252,377

⁽¹⁾	Not included in the table above are estimated interest payments calculated at the rates in effect at March 31, 2008 of: 2009 - $52.6 million; 2010 - $52.6 million; 2011 - $52.6 million; 2012 - $52.6 million and 2013 - $33.4 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	$	1,109	$	1,109	$	—	$	—	$	—
Guarantees		32,686		5,362		11,052		11,217		5,055
Standby replacement commitments		—		—		—		—		—
Other commercial commitments		—		—		—		—		—
Total commercial commitments	$	33,795	$	6,471	$	11,052	$	11,217	$	5,055

CRITICAL ACCOUNTING POLICIES

The discussion and analysis of our financial condition and results of operations are based upon our combined 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.

RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS

In March 2008, the Financial Accounting Standards Board, or 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 SFAS 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 SFAS 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.

In September 2007, 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. 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 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.

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 March 31, 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 Final FASB Staff Position, 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. The deferral applies to nonfinancial assets and liabilities measured at fair value in a business combination; impaired properties; plant and equipment; intangible assets and goodwill; and 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.

The following analysis presents the effect on our earnings, cash flows and financial position as if hypothetical changes in market risk factors occurred on March 31, 2008. Only the potential impacts of hypothetical assumptions are analyzed. The analysis does not consider other possible effects that could impact our business.

Interest Rate Risk

At March 31, 2008, we had an outstanding balance of $579.0 million on our revolving credit facility with a current borrowing base at April 30, 2008 of $735.0 million. The interest rate in effect at March 31, 2008 is based on LIBOR plus an applicable margin of 1.5%. 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 4.3% at March 31, 2008.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. Currently, we have outstanding interest rate swaps that fix the LIBOR rate at 4.61% (including the applicable margin of 1.5%) on $150.0 million of our outstanding debt through January 2011. At March 31, 2008, the carrying value and fair value of our debt is $829.0 million and $831.2 million, respectively.

A hypothetical change in the fair value of our total debt arising from a 10% potential change in the quoted interest rate would be approximately $6.2 million.

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 fixed rate of approximately 4.36%, which includes an initial margin of 1.25% over the three year fixed swap rate of 3.11%. The interest rate swap contract will mature in January 2011. Combining the 3.11% interest rate on the new swap and the 10.75% interest rate on the new senior notes, we have fixed $400 million of our outstanding debt at a weighted average interest rate of approximately 7.89%. In addition, at March 31, 2008 the weighted average interest rate of borrowings for both our credit facility and our senior notes was 6.3%. With our current debt structure, a hypothetical 10% change in the weighted average interest rate would change our net income by approximately $1.9 million.

Commodity Price Risk

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

Our risk management objective 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 year ending December 31, 2008, and current indices, a theoretical 10% upward or downward change in the price of natural gas or crude oil would result in a change in net income of approximately $7.3 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 March 31, 2008, we had 675 open natural gas and 120 oil futures contracts related to sales covering 140 million MMBtus of natural gas and 305 MBls of oil, maturing through March 31, 2013 at an average settlement price of $8.34 per MMBtu and $99.43 per Bbl, respectively.

We recognized gains on settled contracts covering natural gas production of $6.5 million and $2.4 million for the three months ended March 31, 2008 and 2007, respectively. There were no oil settlements for the three months ended March 31, 2008 and 2007. As the underlying prices and terms in our hedge contracts were consistent with the indices used to sell our natural gas, there were no gains or losses recognized during the three months ended March 31, 2008 and 2007, respectively for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges.

On May 18, 2007, we signed a definitive agreement to acquire AGO (see Note 3 to our consolidated financial statements). 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 were 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 to June 28, 2007. Upon closing of the acquisition on June 29, 2007, the production volumes of the assets acquired were 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 $109.8 million net loss in accumulated other comprehensive loss related to commodity derivatives at March 31, 2008. If the fair values of the instruments remain at current market values, we will reclassify $47.7 million of losses to our consolidated statements of income over the next twelve-month period as these contracts settle and $62.1 million of losses will be reclassified in later periods.

Of the $141.2 million net unrealized hedge liability at March 31, 2008, our portion is $100.9 million and $40.3 million of unrealized hedge losses have been reallocated to our investment partnerships.

As of March 31, 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		(Liability)
	(MMbtu)		(per MMbtu)		(in thousands)⁽¹⁾
2008		29,670,000	$	8.72	$	(44,667	)
2009		37,760,000	$	8.54		(41,732	)
2010		26,360,000	$	8.11		(22,838	)
2011		18,680,000	$	7.90		(15,482	)
2012		13,800,000	$	8.20		(7,813	)
2013		1,500,000	$	8.73		(132	)
					$	(132,664	)

Natural Gas Costless Collars

Production
Period Ending					Average		Fair Value
December 31,	Option Type		Volumes		Floor and Cap		(Liability)
			(MMbtu)		(per MMbtu)		(in thousands)⁽¹⁾
2008		Puts purchased		1,170,000	$	7.50	$	—
2008		Calls sold		1,170,000	$	9.40		(1,423	)
2010		Puts purchased		2,880,000	$	7.75		—
2010		Calls sold		2,880,000	$	8.75		(2,055	)
2011		Puts purchased		7,200,000	$	7.50		—
2011		Calls sold		7,200,000	$	8.45		(4,968	)
2012		Puts purchased		720,000	$	7.00		—
2012		Calls sold		720,000	$	8.37		(633	)
							$	(9,079	)

Crude Oil Fixed Price Swaps

Production
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset
	(Bbl)		(per Bbl)		(in thousands) ⁽²⁾
2008		33,000	$	103.25	$	125
2009		36,000	$	99.03		117
2010		31,000	$	96.52		76
2011		25,000	$	95.79		52
2012		21,500	$	95.35		36
2013		6,000	$	95.35		9
					$	415

Crude Oil Costless Collars

Production
Period Ending					Average		Fair Value
December 31,	Option Type		Volumes		Floor and Cap		Asset
			(Bbl)		(per Bbl)		(in thousands) ⁽²⁾
2008		Puts purchased		30,500	$	85.00	$	15
2008		Calls sold		30,500	$	127.13		—
2009		Puts purchased		36,500	$	85.00		50
2009		Calls sold		36,500	$	118.63		—
2010		Puts purchased		31,000	$	85.00		44
2010		Calls sold		31,000	$	112.92		—
2011		Puts purchased		27,000	$	85.00		35
2011		Calls sold		27,000	$	110.81		—
2012		Puts purchased		21,500	$	85.00		25
2012		Calls sold		21,500	$	110.06		—
2013		Puts purchased		6,000	$	85.00		7
2013		Calls sold		6,000	$	110.09		—
							$	176
Total net liability					Total net liability		$	(141,152	)

_____________

⁽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.

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 March 31, 2008 (in thousands):

	Level 2			Total

Commodity-based derivatives	$	(141,152	)	$	(141,152	)
Interest rate swap-based derivatives		(2,127	)		(2,127	)
	$	(143,279	)	$	(143,279	)

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 significant 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.

PART II. OTHER INFORMATION

Item 1A: Risk Factors

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

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 ⁽¹⁾
3.3	Certificate of Formation of Atlas Energy Resources, LLC ⁽²⁾
10.1	Indenture dated January 23, 2008⁽³⁾
10.2	Registration Rights Agreement dated January 23, 2008⁽³⁾
10.3	Purchase Agreement dated January 17, 2008
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 June 29, 2007.
⁽²⁾	Previously filed as an exhibit to our registration statement on Form S-1 (Reg. No. 333-136094).
⁽³⁾	Previously filed as an exhibit to our Form 8-K filed January 24, 2008.

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: May 5, 2008	By:	/s/ Matthew A. Jones
		Matthew A. Jones Chief Financial Officer


Date: May 5, 2008	By:	/s/ Nancy J. McGurk
		Nancy J. McGurk Senior Vice President and Chief Accounting Officer

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Atlas Energy Resources Inactive 10-Q2008 Q1 Quarterly report

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