Atlas Energy Resources 10-Q 2007 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, 2007

OR

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

For the transition period from _________ to __________

Commission file number:  1-33193

ATLAS ENERGY RESOURCES, LLC

(Exact name of registrant as specified in its charter)

Delaware	75-3218520
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
311 Rouser Road
Moon Township, PA	15108
(Address of principal executive offices)	(Zip code)

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

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

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

Large accelerated filer o Accelerated filer   o Non-accelerated filer x

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

Yes o 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, 2007 and December 31, 2006	3
	Combined and Consolidated Statements of Income for the Three Months March 31, 2007 and 2006	4
	Consolidated Statement of Changes in Stockholders’ Equity for the Three Months Ended March 31, 2007	5
	Combined and Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2007 and 2006	6
	Notes to Combined and Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	28
Item 4.	Controls and Procedures	30
PART II	OTHER INFORMATION
Item 6.	Exhibits	31
SIGNATURES		32

PART I.  FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS ENERGY RESOURCES, LLC

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands)

	March 31,		December 31,
	2007		2006
ASSETS
Current assets:
Cash and cash equivalents	$	6,767	$	8,833
Accounts receivable		25,477		31,280
Unrealized hedge gain		7,239		27,618
Prepaid expenses		3,082		3,251
Total current assets		42,565		70,982
Property and equipment, net		293,574		277,814
Other assets, net		18,339		26,290
Intangible assets, net		5,007		5,211
Goodwill		35,166		35,166
	$	394,651	$	415,463
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	31	$	38
Accounts payable		34,005		37,931
Liabilities associated with drilling contracts		19,681		86,765
Advances from affiliate		12,269		12,502
Accrued liabilities		16,104		21,706
Total current liabilities		82,090		158,942
Long-term debt		56,522		30
Partnership hedge payable		6,577		13,248
Unrealized hedge loss		11,271		3,835
Asset retirement obligations		27,590		26,726
Commitments and contingencies (Note 11)
Members’ equity:
Class A unit holders		4,179		3,825
Class B common unit holders		206,130		187,769
Accumulated other comprehensive income		292		21,088
Total members’ equity		210,601		212,682
	$	394,651	$	415,463

See accompanying notes to combined and consolidated financial statements

3

ATLAS ENERGY RESOURCES, LLC

COMBINED AND CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per unit data)

(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
REVENUES
Well construction and completion	$	72,378		$	50,883
Gas and oil production		21,260			22,866
Administration and oversight		4,544			3,309
Well Services		3,721			2,766
Gathering		3,288			2,287
Total Revenues		105,191			82,111
COSTS AND EXPENSES
Well construction and completion		62,932			44,246
Gas and oil production		3,902			3,397
Well Services		2,043			1,766
Gathering fees-Atlas Pipeline		3,288			7,989
General and administrative		6,899			7,695
Depreciation, depletion and amortization		5,868			4,663
Total operating expenses		84,932			69,756
OPERATING INCOME		20,259			12,355
OTHER INCOME (EXPENSE)-NET		(318	)		114
Net income	$	19,941		$	12,469
Allocation of net income attributable to members’ interest/owners:
Portion applicable to owner’s interest (period prior to the initial public offering on December 18, 2006)	$	-		$	12,469
Portion applicable to members’ interests (period subsequent to the initial public offering on December 18, 2006)		19,941			-
	$	19,941		$	12,469
Allocation of net income attributable to members’ interests:
Class A Units	$	399
Class B common units		19,542
Net income attributable to members’ interests		19,941
Basic and diluted net income per Class B common unit	$	.53
Weighted average Class B common units outstanding:
Basic		36,627
Diluted		36,967

See accompanying notes to combined and consolidated financial statements

4

ATLAS ENERGY RESOURCES, LLC

CONSOLIDATED STATEMENT OF CHANGES IN MEMBERS’ EQUITY

THREE MONTHS ENDED MARCH 31, 2007

(in thousands, except unit data)

(Unaudited)

											Accumulated
											Other			Total
	Class A Units					Class B Common Units					Comprehensive			Members’
	Units		Amount			Units		Amount			Income (Loss)			Equity
Balance, January 1, 2007		748,456	$	3,825			36,626,746	$	187,769		$	21,088		$	212,682
Issuance of common units									4						4
Distribution to members				(45	)				(2,197	)					(2,242	)
Distribution paid on unissued units under incentive plan									(33	)					(33	)
Stock-based compensation									1,045						1,045
Net income				399					19,542						19,941
Other comprehensive loss												(20,796	)		(20,796	)
Balance, March 31, 2007		748,456	$	4,179			36,626,746	$	206,130		$	292		$	210,601

See accompanying notes to combined and consolidated financial statements

5

ATLAS ENERGY RESOURCES, LLC

COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	19,941		$	12,469
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of deferred finance costs		13			—
Depreciation, depletion and amortization		5,868			4,663
Non-cash compensation on long-term incentive plans		1,045			491
Gain on asset dispositions		(28	)		(25	)
Advances (to) from affiliate		(232	)		49,816
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable and prepaid expenses		9,740			(1,227	)
Decrease in accounts payable and accrued expenses		(3,926	)		(11,738	)
Decrease in liabilities associated with drilling contracts		(67,084	)		(45,672	)
Increase (decrease) in other operating assets and liabilities		543			(9,497	)
Net cash used in operating activities		(34,120	)		(720	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(22,077	)		(15,290	)
Proceeds from sale of assets		31			30
(Increase) decrease in other assets		(7	)		93
Net cash used in investing activities		(22,053	)		(15,167	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings		56,500			—
Principal payments on borrowings		(15	)		(21	)
Distribution to unit holders		(2,242	)		—
(Increase) in deferred financing costs and other		(136	)		—
Net cash provided by (used in) financing activities		54,107			(21	)
Decrease in cash and cash equivalents		(2,066	)		(15,908	)
Cash and cash equivalents at beginning of period		8,833			20,918
Cash and cash equivalents at end of period	$	6,767		$	5,010

See accompanying notes to combined and consolidated financial statements

6

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2007

(Unaudited)

NOTE 1 - BASIS OF PRESENTATION

Business Description

Atlas Energy Resources, LLC (“the Company”) is a limited liability company engaged primarily in the development and production of natural gas and, to a lesser extent, oil in the western New York, eastern Ohio, western Pennsylvania and Tennessee regions of the Appalachian Basin. The Company sponsors and manages tax-advantaged investment partnerships (the “Partnerships”), in which it coinvests to finance the exploitation and development of its acreage.

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). In December 2006, the Company completed an initial public offering of 7,273,750 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 the Company’s parent, AAI, in the form of a non-taxable dividend and to repay debt. Atlas Energy Management, Inc., a wholly-owned subsidiary of AAI, is the managing member of the Company and owns 748,456 Class A units, or a 2% interest, through which it manages and effectively controls the Company. AAI also owns 29,352,996 units or 80.1%  of the Class B common units.

The combined and consolidated financial statements of the Company before the date of its initial public offering have been prepared from the separate records maintained by AAI and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Company had been operated as an unaffiliated entity. Transactions between the Company and other AAI entities have been identified in the combined and consolidated financial statements as transactions between affiliates (see Note 7). 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 combined and consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2006 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim combined and 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, 2006. The results of operations for the three month period ended March 31, 2007 may not necessarily be indicative of the results of operations for the full year ending December 31, 2007.

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, 2006, which contains a summary of significant accounting policies followed by the Company in the preparation of its combined and consolidated financial statements.  These policies were also followed in preparing the quarterly report included herein.  

Use of Estimates

Preparation of the combined and 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.

Receivables

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, 2007 and December 31, 2006, the Company’s credit evaluation indicated that it had no need for an allowance for possible losses.

7

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

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

Reclassifications

Certain reclassifications have been made to the prior period combined and consolidated financial statements 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, 2007 and December 31, 2006 of $19.2 million and $19.4 million, respectively, which are included in Accounts receivable on its Consolidated Balance Sheets.

Recently Issued Financial Accounting Standards

In February 2007, the Financial Accounting Standards Board (“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. The statement will be effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. The statement offers various options in electing to apply its provisions and at this time the Company has not made any decision as to its application and is evaluating the impact of the adoption of SFAS 159 on the Company’s financial position and results of operations.

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. SFAS 157 is effective for the Company beginning January 1, 2008. The Company is currently evaluating the impact of the adoption of SFAS 157 on its financial position and results of operations.

NOTE 3 - COMPREHENSIVE INCOME

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

	Three Months Ended
	March 31,
	2007			2006
Net income	$	19,941		$	12,469
Other comprehensive income (loss):
Unrealized holding gain (loss) on hedging contracts		(18,352	)		4,387
Less reclassification adjustment for gains realized in net income		(2,444	)		(1,420	)
Total other comprehensive income (loss)		(20,796	)		2,967
Comprehensive income (loss)	$	(855	)	$	15,436

8

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 4 - NET INCOME PER COMMON UNIT

The Company’s basic net income attributable to common unit holders per unit is computed by dividing the Company’s net income attributable to Class B common unit holders, which is determined after the deduction of the net income allocable to the Class A units, by the Company’s weighted average number of Class B common unit holder units outstanding during the period. The Company’s diluted net income attributable to Class B common unit holders per unit is calculated by dividing the Company’s net income attributable to Class B common unit holders by the sum of the weighted average number of the Company’s Class B common units outstanding and the dilutive effect 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 Class B common units as of March 31, 2007 used to compute basic net income attributable to Class B common unit holders per unit with those used to compute diluted net income attributable to Class B common unit holders per unit (in thousands):

Weighted average number of Class B common units - basic	36,627
Add effect of dilutive unit incentive awards	340
Weighted average number of Class B common units - diluted	36,967

NOTE 5 - OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL

Other Assets

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

	March 31,		December 31,
	2007		2006
Long-term hedge receivable from Partnerships	$	6,476	$	2,131
Unrealized hedge gain – long term		11,445		23,843
Other		418		316
	$	18,339	$	26,290

Long-term hedge receivable from Partnerships represents the portion of the long-term unrealized hedge loss on contracts that has been reallocated to the Partnerships.

Intangible Assets

Included in intangible assets are partnership management and operating contracts acquired through previous acquisitions which were recorded at fair value on their acquisition dates. The Company amortizes contracts acquired on the declining balance and straight-line methods over their respective estimated lives, ranging from five to thirteen years. Amortization expense for these contracts for the three months ended March 31, 2007 and 2006 was $204,000 and $220,000, respectively.

The aggregate estimated annual amortization expense of partnership management and operating contracts for the next five years ending March 31 is as follows: 2008—$808,000; 2009—$769,000; 2010—$734,000; 2011—$703,000 and 2012—$538,000.

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

	March 31,			December 31,
	2007			2006
Cost	$	14,343		$	14,343
Accumulated amortization		(9,336	)		(9,132	)
	$	5,007		$	5,211

9

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

Goodwill

The Company applies the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets,” (“SFAS 142”), which requires that goodwill no longer be amortized, but instead evaluated for impairment at least annually. The evaluation of impairment under SFAS 142 requires the use of projections, estimates and assumptions as to the future performance of the Company’s operations, including anticipated future revenues, expected future operating costs and the discount factor used. Actual results could differ from projections, resulting in revisions to the Company’s assumptions and, if required, recognition of an impairment loss. The Company’s evaluation of goodwill at December 31, 2006 indicated there was no impairment loss and no impairment indicators arose during the three months ended March 31, 2007. The Company will continue to evaluate its goodwill at least annually or when impairment indicators arise, and will reflect the impairment of goodwill, if any, within the Statements of Income in the period in which the impairment is indicated.

NOTE 6 - PROPERTY AND EQUIPMENT

Property and equipment is stated at cost. Depreciation, depletion and amortization are based on cost less estimated salvage value primarily using the unit-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.

Property and equipment consists of the following at the dates indicated (in thousands):

	March 31,			December 31,
	2007			2006
Mineral interests:
Proved properties	$	4,765		$	1,290
Unproved properties		1,002			1,002
Wells and related equipment		365,675			348,742
Land, building and improvements		4,316			4,169
Support equipment		5,958			5,541
Other		4,803			4,698
		386,519			365,442
Accumulated depreciation, depletion and amortization:
Oil and gas properties		(88,399	)		(83,216	)
Other		(4,546	)		(4,412	)
		(92,945	)		(87,628	)
	$	293,574		$	277,814

NOTE 7 - 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, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. The Company and Atlas Pipeline Partners, L.P. (“Atlas Pipeline”) comprise substantially all of Atlas America’s operations, and therefore the Company and Atlas Pipeline bear substantially all of those costs which are reflected in general and administrative expense in the Company’s Combined and 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.

10

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 7 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS - (Continued)

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. AAI has agreed to assume the Company’s obligation to pay gathering fees to Atlas Pipeline and the Company has remitted to AAI the gathering fees it receives. These fees are shown as Gathering fees—Atlas Pipeline on the Company’s Combined and Consolidated Statements of Income. The Company charges rates to wells connected to these gathering systems, substantially all of which are owned by the Partnerships, generally ranging from $.29 to $.35 per Mcf or a percentage of the sales price received for the natural gas transported and pays this amount to AAI.

NOTE 8 -DEBT

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

	March 31,		December 31,
	2007		2006
Revolving credit facility	$	56,500	$	−
Other debt		53		68
		56,553		68
Less current maturities		31		38
	$	56,522	$	30

In December 2006, the Company entered into a new $250.0 million credit facility, which is led by Wachovia Bank, N.A. (“Wachovia”). The revolving credit facility has a current borrowing base of $175.0 million which may be redetermined subject to changes in the Company’s oil and gas reserves. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by the Company’s assets and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at the Company’s option. The base rate for any day equals the higher of the federal funds rate plus 0.50% or the Wachovia 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 Euro currency funding. The applicable margin ranges from 0.0% to 0.75% for base rate loans and 1.00% to 1.75% for LIBOR loans.

The revolving credit facility requires the Company to maintain specified ratios of current assets to current liabilities, interest coverage (as defined), and debt to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”). In addition, the facility limits sales, leases or transfers of assets and the incurrence of additional indebtedness. The facility limits the dividends 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, 2007. The facility terminates in December 2011, when all outstanding borrowings must be repaid. At March 31, 2007, $56.5 million was outstanding under this facility. In addition, $495,000 was outstanding under letters of credit which are not reflected as borrowings on the Company’s Consolidated Balance Sheets.

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

2008	$	31
2009		22
2010		−
2011		−
2012		56,500
	$	56,553

11

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 9 - ASSET RETIREMENT OBLIGATIONS

The Company accounts for asset retirement obligations under FAS No. 143, “Accounting for Retirement Asset 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,
	2007			2006
Asset retirement obligations, beginning of period	$	26,726		$	18,499
Liabilities incurred		520			676
Liabilities settled		(21	)		-
Accretion expense		365			124
Asset retirement obligations, end of period	$	27,590		$	19,299

The above accretion expense is included in depreciation, depletion and amortization in the Company’s Combined and Consolidated Statements of Income.

NOTE 10 - DERIVATIVE INSTRUMENTS

From time to time, the Company enters into natural gas futures, option, and collar contracts to hedge its exposure to changes in natural gas 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.

The Company formally documents 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 futures and options contracts to the forecasted transactions. The Company assesses, 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 the hedged items. Historically these contracts have qualified and been designated as cash flow hedges and 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. Such gains and losses are charged or credited to Accumulated other comprehensive income (loss) and recognized as a component of gas revenues in the month the hedged gas 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 gas reference prices under a hedging instrument and actual gas prices, the Company 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, 2007, the Company had 293 open natural gas futures contracts related to natural gas sales covering 60.8 million MMBtus of natural gas, maturing through March 31, 2012 at a combined average settlement price of $8.31 per MMBtu. The Company recognized a gain of $2.4 million and $1.4 million on settled contracts covering natural gas production for the three months ended March 31, 2007 and 2006, respectively. There were no gains or losses recognized during the three months ended March 31, 2007 or 2006 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges.

12

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 10 - DERIVATIVE INSTRUMENTS - (continued)

Of the $292,000 net gain in Accumulated other comprehensive income at March 31, 2007, the Company will reclassify $218,000 of gains to its Combined and Consolidated Statements of Income over the next twelve month period as these contracts expire, and $74,000 of gains will be reclassified in later periods if the fair values of the instruments remain at current market values.

As of March 31, 2007, the Company had the following natural gas volumes hedged:

Fixed Price Swaps

Twelve Month			Average		Fair Value
Period Ending	Volumes		Fixed Price		Asset
March 31	(MMBtu)		(per MMBtu)		(in thousands) (1)
2008		16,380,000	$	8.676	$	1,342
2009		16,080,000		8.599		611
2010		14,040,000		8.195		1,133
2011		7,950,000		7.572		(1,440	)
2012		3,600,000		7.365		(46	)
					$	1,600

Costless Collars

Twelve Month					Average		Fair Value
Period Ending			Volumes		Floor and Cap		Asset (Liability)
March 31	Option Type		(MMBtu)		(per MMBtu)		(in thousands)(1)
2008		Puts purchased		1,200,000	$	7.500	$	-
2008		Calls sold		1,200,000		8.600		(364	)
2008		Puts purchased		390,000		7.500		-
2008		Calls sold		390,000		9.400		(465	)
2009		Puts purchased		1,170,000		7.500		-
2009		Calls sold		1,170,000		9.400		(84	)
							$	(913	)
Total net asset							$	687

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

13

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 10 - DERIVATIVE INSTRUMENTS - (continued)

The following table sets forth the book and estimated fair values of derivative instruments (in thousands):

	March 31, 2007
	Book Value			Fair Value
Assets
Derivative instruments	$	18,684		$	18,684
	$	18,684		$	18,684
Liabilities
Derivative instruments	$	(17,997	)	$	(17,997	)
	$	(17,997	)	$	(17,997	)
	$	687		$	687

The fair value of the derivatives is included in the Company’s Consolidated Balance Sheets as of the dates indicated as follows (in thousands):

	March 31,			December 31,
	2007			2006
Unrealized hedge gain - short-term	$	7,239		$	27,618
Other assets - long-term		11,445			23,843
Accrued liabilities - short-term		(6,726	)		(172	)
Unrealized hedge loss - long-term		(11,271	)		(3,835	)
	$	687		$	47,454

Of the $687,000 and $47.5 million net unrealized hedge gains at March 31, 2007 and December 31, 2006, respectively, the Company’s retained portion of $292,000 and $21.1 million is included in Accumulated other comprehensive income and $395,000 and $26.4 million has been allocated to the Partnerships and included in the Consolidated Balance Sheets as of the dates indicated are as follows (in thousands):

	March 31,			December 31,
	2007			2006
Unrealized hedge gain - short-term	$	3,864		$	96
Other assets - long-term		6,476			2,131
Accrued liabilities - short-term		(4,158	)		(15,345	)
Unrealized hedge loss - long-term		(6,577	)		(13,248	)
	$	(395	)	$	(26,366	)

14

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 11 - COMMITMENTS AND CONTINGENCIES

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

One of the Company’s subsidiaries, Resource Energy, LLC, together with Resource America, Inc. (the former parent of AAI) was a defendant in a class action originally filed in February 2000 in the New York Supreme Court, Chautauqua County, by individuals, putatively on their own behalf and on behalf of similarly situated individuals, who leased property to the Company. The complaint alleged that the Company was not paying landowners the proper amount of royalty revenues with respect to natural gas produced from the leased properties. The complaint was seeking damages in an unspecified amount for the alleged difference between the amount of royalties actually paid and the amount of royalties that allegedly should have been paid. In April 2007, a settlement of this lawsuit was approved by the court. Pursuant to the tentative settlement terms, the Company has agreed to pay $300,000, upgrade certain gathering systems and cap certain transportation expenses chargeable to the land owners. The Company is indemnified by AAI for this matter.

NOTE 12 - OPERATING SEGMENT INFORMATION

The Company’s operations include two reportable operating segments. These operating segments reflect the way the Company manages its operations and makes business decisions. Operating segment data for the periods indicated are as follows (in thousands):

	Three Months Ended
	March 31,
	2007		2006
Gas and oil production
Revenues	$	21,260	$	22,866
Costs and expenses		3,902		3,397
Segment profit	$	17,358	$	19,469
Partnership management
Revenues	$	83,931	$	59,245
Costs and expenses		68,263		54,001
Segment profit	$	15,668	$	5,244

15

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 12 - OPERATING SEGMENT INFORMATION - (continued)

	Three Months Ended
	March 31,
	2007			2006
Reconciliation of segment profit to net income
Segment profit
Gas and oil production	$	17,358		$	19,469
Partnership management		15,668			5,244
Total segment profit		33,026			24,713
General and administrative		(6,899	)		(7,695	)
Depreciation, depletion and amortization		(5,868	)		(4,663	)
Other income - net		(318	)		114
Net income	$	19,941		$	12,469
Capital expenditures
Gas and oil production	$	21,494		$	14,881
Partnership management		477			204
Corporate		106			205
	$	22,077		$	15,290
		March 31,			December 31,
		2007			2006
Balance sheets
Goodwill
Gas and oil production	$	21,527		$	21,527
Partnership management		13,639			13,639
	$	35,166		$	35,166
Total assets
Gas and oil production	$	358,959		$	377,807
Partnership management		26,969			26,474
Corporate		8,723			11,182
	$	394,651		$	415,463

For the three months ended March 31, 2007 and 2006, there were no operating segments that had revenues from a single customer which exceeded 10% of total revenues.

16

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 13 - BENEFIT PLANS

Incentive Plan. In December 2006, the Company adopted 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 the AAI compensation committee, which may grant awards of either restricted units or unit options for an aggregate of 3,742,000 common units.

Restricted and Phantom Units. A restricted unit is a common unit that is subject to forfeiture prior to vesting. A phantom unit represents the right to receive one unit of the Company’s common units upon vesting. Units will vest over a four year service period. The fair value of the grants is based on the closing price of the common units or cash equivalent to the then fair market value of a common unit on the grant date, and is being charged to operations over the requisite service periods. Upon termination of service by a grantee, all non-vested units are forfeited. The Company recognized $799,000 in compensation expense related to restricted and phantom units for the three months ended March 31, 2007. At March 31, 2007, the Company had approximately $11.8 million of unrecognized compensation expense related to the non-vested portion of these units.

The following table summarizes the activity of restricted and phantom units for the three months ended March 31, 2007.

			Weighted
			Average
			Grant Date
	Units		Fair Value
Non-vested units outstanding, December 31, 2006		47,619	$	21.00
Granted		511,000		23.06
Vested		–		–
Forfeited		–		–
Non-vested units outstanding, March 31, 2007		558,619	$	22.88

Options. Option awards expire 10 years from the date of grant, and will vest over a four year service period. In December 2006, the Black-Scholes option pricing model was used to estimate the weighted average fair value of $2.14 per option granted with the following assumptions (a) expected dividend yield of 8.0%, (b) risk-free interest rate of 4.4%, (c) expected volatility of 25.0%, and (d) an expected life of 6.25 years. In January 2007, additional units were granted, and the Black-Scholes option pricing model was used to estimate the weighted average fair value of $2.41 per unit option with the following assumptions (a) expected dividend yield of 8%, (b) risk-free interest rate of 4.7%, (c) expected volatility of 25.0%, and (d) an expected life of 6.25 years. The Company recognized $246,000 in compensation expense related to options granted for the three months ended March 31, 2007. At March 31, 2007, the Company had approximately $3.5 million of unrecognized compensation expense related to the non-vested portion of the options .

The following table summarizes the activity of options for the three months ended March 31, 2007.

					Weighted
					Average		Aggregate
			Weighted		Remaining		Intrinsic
			Average		Contractual		Value
	Units		Exercise Price		Term (in years)		(in thousands)
Outstanding, December 31, 2006		373,752	$	21.00		9.25
Granted		1,297,600		23.06		9.75
Exercised		–		–		–
Forfeited or expired		–		–		–
Outstanding, March 31, 2007		1,671,352	$	22.60		9.58	$	6,769
Options exercisable, March 31, 2007		0
Available for grant		1,512,029

17

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 14 - 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:

Date Cash Distribution Paid	For Quarter Ended		Cash Distribution per Common Unit			Total Cash Distribution to Common Unitholders		Total Cash Distribution to the Manager
						(in thousands)		(in thousands)
February 14, 2007		December 31, 2006	$	0.06	(1)	$	2,197	$	45

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

On April 26, 2007, the Company declared a cash distribution of $0.43 per unit on its outstanding common units, representing the cash distribution for the quarter ended March 31, 2007. The $16.1 million distribution, including $322,000 to Atlas Energy Management, Inc., the manager will be paid on May 15, 2007 to unitholders of record at the close of business on May 8, 2007.

18

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

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 2006.  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 the Appalachian Basin. We sponsor and manage tax-advantaged investment partnerships, in which we coinvest, to finance the exploitation and development of our acreage.

We were formed in 2006 to own and operate substantially all of the natural gas and oil assets and the investment partnership management business of Atlas America, Inc. (NASDAQ: ATLS). We are managed by Atlas Energy Management, Inc., or AEM, a wholly-owned subsidiary of Atlas America. Through our manager, Atlas America personnel are responsible for managing our assets and raising capital.

During the three months ended March 31, 2007, we continued to grow our operations, increasing our revenues, number of wells drilled and number of wells operated.

Our gross revenues depend, to a significant extent, on the price of natural gas and oil, which can fluctuate significantly.  We seek to balance this volatility with the more stable net income from our well drilling and well servicing operations which are principally fee-based.  Our business strategy for increasing our reserve base includes acquisitions of undeveloped properties or companies with significant amounts of undeveloped property.  At March 31, 2007, we had $118.0 million available under our credit facility, which could be employed to finance such acquisitions.

BUSINESS SEGMENTS

We operate two business segments:

·   Our gas and oil production segment, which consists 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.

Gas and Oil Production

As of March 31, 2007, we owned interests in 7,523 gross wells, principally in the Appalachian Basin, of which we operated 6,384. In the three months ended March 31, 2007, we drilled 242 net wells, 98% of which were successful in producing natural gas in commercial quantities. In September 2004, we expanded our operations into Tennessee through a joint venture with Knox Energy, LLC that gives us an exclusive right to drill up to 158 additional net wells before December 31, 2007 on approximately 212,000 acres owned by Knox Energy. As of March 31, 2007, we had drilled 185 net wells under this agreement. We had identified over 500 proved undeveloped drilling locations and approximately 2,600 additional potential drilling locations on our acreage and our Tennessee joint venture acreage as of March 31, 2007.

Our results of operations for our gas and oil production segment are impacted by increases and decreases in the volume of natural gas that we produce, which we refer to as production volumes. Production volumes and pipeline capacity utilization rates generally are driven by wellhead production and the number of new wells drilled and connected in our areas of operation and more broadly, by demand for natural gas. Our results of operations for our gas and oil production segment are also impacted by the prices we receive and the margins we generate. Because of the volatility of the prices for natural gas, as of March 31, 2007 we had financial hedges in place for approximately 77% of our expected production for the twelve months ending March 31, 2008.

19

Partnership Management

We generally fund our drilling activities 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 $218.5 million in the year ended December 31, 2006 and plan to raise up to $270.0 million in the year ending December 31, 2007.

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 general or managing 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 generally agree to subordinate up to 50% of our share of production revenues to specified returns to the investor partners, typically 10% per year for the first five years of distributions.

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, 90% of the subscription proceeds received by each partnership are 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.

Our results of operations for our partnership management segment are impacted by increases and decreases in the number of wells that we drill and the number of wells we operate. Well construction activity is generally driven by commodity prices and demand for natural gas and oil. Additionally, the level of funds we raise through investment partnerships affects the number of wells we drill. Investor funds raised will also be dependent on commodity prices and tax laws associated with natural gas and oil.

20

GENERAL TRENDS 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.

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, results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital.

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.

Results of Operations for the Three Months Ended March 31, 2007 Compared to the Three Months Ended March 31, 2006

Gas and Oil Production

The following table sets forth information relating to our production revenues, production volumes, sales prices, production costs and depletion for the periods indicated:

	Three Months Ended
	March 31,
	2007			2006
Production revenues (in thousands):
Gas (1)	$	19,427		$	20,492
Oil	$	1,826		$	2,365
Production volume (2):
Gas (mcf/day) (1)		23,681			20,866
Oil (bbls/day)		359			423
Total (mcfe/day) (3)		25,835			23,404
Average sales prices:
Gas (per mcf) (3)	$	9.12		$	10.91
Oil (per bbl) (3)	$	56.52		$	62.13
Production costs (4):
As a percent of production revenues		10	%		8	%
Per mcfe	$	.87		$	.90
Depletion per mcfe	$	2.31		$	1.98

(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 was $7.85 and $9.37 per mcf for the three months ended March 31 2007 and 2006, 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.

21

Our natural gas revenues were $19.4 million in the three months ended March 31, 2007, a decrease of $1.1 million (5%) from $20.5 million in the three months ended March 31, 2006. The decrease was attributable to a 16% decrease in the average sales price of natural gas partially offset by a 13% increase in production volumes. The $1.1 million decrease in natural gas revenues consisted of $3.4 million attributable to decreases in natural gas sales prices and $2.3 million attributable to increased production volumes.

The increase in our gas production volumes of 2,815 Mcf/d resulted from production associated with new wells drilled for our investment partnerships. We believe that gas volumes will continue to be favorably impacted in the remainder of 2007 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 $1.8 million in the three months ended March 31, 2007, a decrease of $539,000 (23%) from $2.4 million during the three months ended March 31, 2006. The decrease resulted from a 9% decrease in the average sales price of oil, and a 15% decrease in production volumes. The $539,000 decrease consisted of $214,000 attributable to decreases in sales prices, and $325,000 attributable to volume decreases, as we drill primarily for natural gas rather than oil.

Our production costs were $3.9 million in the three months ended March 31, 2007, an increase of $505,000 (15%) from $3.4 million in the three months ended March 31, 2006. This increase includes an increase in transportation charges, labor and maintenance costs associated with an increase in the number of wells we own from the prior year period. The transportation fees charged to our wells connected to Atlas Pipeline’s gathering system were generally increased as a percent of gas revenues beginning in January 2007.

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,
	2007		2006
Average construction and completion revenue per well	$	299	$	291
Average construction and completion cost per well		260		253
Average construction and completion gross profit per well	$	39	$	38
Gross profit margin	$	9,446	$	6,637
Net wells drilled		242		175

Our well construction and completion segment margin was $9.4 million in the three months ended March 31, 2007, an increase of $2.8 million (42%) from $6.6 million in the three months ended March 31, 2006.  During the three months ended March 31, 2007, the increase of $2.8 million in segment margin was attributable to an increase in the number of wells drilled ($2.5 million) and an increase in the gross profit per well ($268,000). The increase in the number of wells drilled is the result of an increase in our fundraising in fiscal 2006. It should be noted that “Liabilities associated with drilling contracts” on our balance sheet includes $6.9 million of funds raised in calendar 2006 that have not been applied to the completion of wells as of March 31, 2007 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 2007. During fiscal 2006 we raised $218.5 million and plan to raise approximately $270.0 million fiscal 2007. We anticipate favorable oil and gas prices will continue to favorably impact our fundraising and therefore our drilling revenues in the remainder of fiscal 2007.

22

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 $4.5 million in the three months ended March 31, 2007, an increase of $1.2 million (37%) from $3.3 million in the three months ended March 31, 2006. This increase resulted from an increase in the number of wells drilled and managed for our investment partnerships in the three months ended March 31, 2007 as compared to the three months ended March 31, 2006.

Well Services

Our well services revenues were $3.7 million in the three months ended March 31, 2007, an increase of $955,000 (35%) from $2.8 million in the three months ended March 31, 2006. 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, 2007.

Our well services expenses were $2.0 million in the three months ended March 31, 2007, an increase of $277,000 (16%) from $1.8 million in the three months ended March 31, 2006. 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. Our gathering fee to Atlas Pipeline was $3.3 million for the three months ended March 31, 2007, a decrease of $4.7 million (59%) from $8.0 million in the three months ended March 31, 2006. The decrease in the three months ended March 31, 2007 is primarily a result of the assumption by Atlas America of our obligation to pay Atlas Pipeline under our gas gathering agreement with it. In connection with the completion of our initial public offering, 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.

General and Administrative

Our general and administrative expenses were $6.9 million in the three months ended March 31, 2007, a decrease of $796,000 (10%) from $7.7 million in the three months ended March 31, 2006. 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 decrease of $796,000 in the three months ended March 31, 2007 is principally attributed to our sharing of expenses with our parent, Atlas America, Inc.

Depletion

Our depletion of oil and gas properties as a percentage of oil and gas revenues was 25% in the three months ended March 31, 2007, compared to 18% in the three months ended March 31, 2006. Depletion expense per Mcfe was $2.31 in the three months ended March 31, 2007, an increase of $0.33 (17%) per Mcfe from $1.98 in the three months ended March 31, 2006. Increases in our depletable basis and production volumes caused depletion expense to increase $1.2 million to $5.4 million in the three months ended March 31, 2007 compared to $4.2 million in the three months ended Months 31, 2006. 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.

Other income (expense)-net

Our other income (expense)-net was ($318,000) in the three months ended March 31, 2007, a decrease of $432,000, from $114,000 in the three months ended March 31, 2006. This decrease is primarily related to an increase of $408,000 in interest expense due to the $56.5 million borrowed under our credit facility at March 31, 2007. There were no borrowings during the three months ended March 31, 2006.

23

Liquidity and Capital Resources

General.  We fund our exploration and production operations with a combination of cash generated by operations, capital raised through investment partnerships and, if required, use of our credit facility. 

Credit Facility. In December 2006, we entered into a new $250.0 million credit facility, which is led by Wachovia Bank, N.A., or Wachovia. The revolving credit facility borrowing base was increased to $175.0 million in March 2007, which may be redetermined subject to changes in our oil and gas reserves. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by our assets and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at our option.

The Wachovia credit facility requires us to maintain specified ratios of current assets to current liabilities, interest coverage (as defined), and debt to earnings before interest, taxes, depreciation, depletion and amortization, or EBITDA. In addition, the facility limits sales, leases or transfers of assets and the incurrence of additional indebtedness. The facility limits the dividends payable by us if an event of default has occurred and is continuing or would occur as a result of such distribution. We are in compliance with these covenants as of March 31, 2007. The facility terminates in December 2011, when all outstanding borrowings must be repaid. At March 31, 2007 and December 31, 2006, $57.0 million and $495,000, respectively, were outstanding under this facility including letters of credit of $495,000 at each date which are not reflected as borrowings on our Consolidated Balance Sheets. At March 31, 2007, our weighted average interest rate on outstanding borrowings was 8.5%.

Our long-term debt (including current maturities) was 27% and 0% of our total equity at March 31, 2007 and December 31, 2006, respectively.  Since December 31, 2006, total debt has increased by $56.5 million. The increase in long-term debt relates to borrowings under our credit facility to fund our drilling operations.

Cash flows. The following table sets forth our sources and uses of cash (in thousands):

	Three Months Ended
	March 31,
	2007			2006
Used in operations	$	(34,120	)	$	(720	)
Used in investing activities		(22,053	)		(15,167	)
Provided by (used in) financing activities		54,107			(21	)
Decrease in cash and cash equivalents	$	(2,066	)	$	(15,908	)

We had $6.8 million in cash and cash equivalents at March 31, 2007, as compared to $8.8 million at December 31, 2006.   We had a working capital deficit of $39.5 million at March 31, 2007, an increase in working capital of $48.5 million from a working capital deficit of $88.0 million at December 31, 2006.  The increase in our working capital is due to a decrease of $67.1 million in liabilities associated with our drilling contracts which we funded through $56.5 million of borrowings on our credit facility, partially offset by a decrease in our current portion of hedge receivable of $22.0 million. At March 31, 2007, we have $118.0 million available under our credit facility to fund working capital obligations.

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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.  Netcash used in operating activities increased $33.4 million in the three months ended March 31, 2007 to $34.1 million from $720,000 in the three months ended March 31, 2006, substantially as a result of the following:

· an increase in net income before depreciation and amortization of $8.7 million in the three months ended March 31, 2007 as compared to the prior year period, principally as a result of income from well construction and completion profits and administration and oversight and well services margins;

· an increase in the adjustment to add back non-cash items of $554,000 related to our compensation expense resulting from grants under long-term incentive plans;

· we received $49.8 million in advances from AAI during the three months ended March 31, 2006 as compared to $232,000 we remitted to AAI during the three months ended March 31, 2007, which decreased operating cash flows by $50.0 million; and

· changes in operating assets and liabilities increased operating cash flow by $7.4 million in the three months ended March 31, 2007, compared to the three months ended March 31, 2006.

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

· A decrease of $7.8 million in accounts payable and accrued liabilities;

· An increase of $11.0 million in accounts receivable and prepaid expenses;

· An increase of $10.0 million in other operating assets and liabilities; partially offset by,

· An increase of $21.4 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 of funds raised through our investment partnerships.

Cash flows from investing activities.Cash used in our investing activities increased $6.9 million in the three months ended March 31, 2007 to $22.1 million from $15.2 million in the three months ended March 31, 2006 primarily from a $6.8 million increase in capital expenditures related to the increase in the number of wells we drilled.

Cash flows from financing activities. Cash provided by our financing activities increased $54.1 million in the three months ended March 31, 2007 to $54.1 million from cash used of $21,000 in the three months ended March 31, 2006, as a result of the following: 

· net borrowings on debt increased by $56.5 million in the three months ended March 31, 2007 as compared to March 31, 2006 principally as a result of funds used in our drilling operations; and

· we paid $2.2 million in distributions to our unitholders in the three months ended March 31, 2007.

Capital Requirements: During the three months ended March 31, 2007, 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 our investments in our drilling partnerships.

The level of capital expenditures we devote to our exploration and production operations depends upon the level of funds raised through our investment partnerships.  We have budgeted to raise up to $270 million in fiscal 2007.  We estimate our total capital expenditures to be approximately $78.4 million during the year ended December 31, 2007. We believe cash flows from operations and amounts available under our credit facility will be adequate to fund our contributions to these partnerships.  However, the amount of funds we raise and the level of our capital expenditures will vary in the future depending on market conditions for natural gas and other factors.  

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We 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,
	2007		2006
Maintenance capital expenditures	$	8,750
Expansion capital expenditures		13,327
Total	$	22,077	$	15,290(1	)

(1) We did not characterize capital expenditures as maintenance or expansion and did not plan capital expenditures in a manner intended to maintain or expand our asset base or production before our initial public offering on December 18, 2006.   Cash distributions. Our limited liability company agreement requires that we distribute 100% of available cash to the Class A unitholder, AEM, and our Class B common unitholders within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of our cash receipts, less cash disbursements and net additions to reserves, plus cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.   All cash we distribute to unitholders will be characterized as either operating surplus or capital surplus, as defined in our limited liability company agreement and is subject to different distribution rules. We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We do not anticipate distributing any cash from capital surplus.   Available cash is initially distributed 98% to our Class B common unitholders and 2% to AEM. These distribution percentages are modified to provide for incentive distributions (any distribution paid to AEM in excess of 2% of the aggregate amount of cash being distributed) to be paid to AEM if quarterly distributions to the Class B common unitholders exceed specified targets as defined in our limited liability company agreement. We anticipate that incentive distributions will begin after four full, consecutive quarters, or beginning with the quarter ended March 31, 2008.

Contractual Obligations and Commercial Commitments

The following table summarizes our contractual obligations at March 31, 2007.

			Payments Due By Period
			(in thousands)
			Less than		2 - 3		4 - 5		After 5
Contractual cash obligations:	Total		1 Year		Years		Years		Years
Long-term debt(1)	$	56,553	$	31	$	22	$	56,500	$	-
Secured revolving credit facilities		-		-		-		-		-
Operating lease obligations		1,626		648		772		205		1
Capital lease obligations		-		-		-		-		-
Unconditional purchase obligations		-		-		-		-		-
Other long-term obligation		-		-		-		-		-
Total contractual cash obligations	$	58,179	$	679	$	794	$	56,705	$	1

(1) Not included in the table above are estimated interest payments calculated at the rates in effect at March 31, 2007 of: 2007 - $4.8 million; 2008 - $4.8 million; 2009 - $4.8 million; 2010 - $4.8 million and 2011 - $3.5 million.

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			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	$	495	$	495	$	-	$	-	$	-
Guarantees		-		-		-		-		-
Standby replacement commitments		-		-		-		-		-
Other commercial commitments		-		-		-		-		-
Total commercial commitments	$	495	$	495	$	-	$	-	$	-

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America.  The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of our assets, liabilities, revenues, costs 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, deferred tax assets and liabilities, 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.

For a detailed discussion on the application of policies critical to our business operations and other accounting policies, see our Annual Report on Form 10-K for the year ended December 31, 2006, Note 2 of the "Notes to Combined and Consolidated Financial Statements" and Note 2 to the “Notes to Combined and Consolidated Financial Statements” included in this report.

Recently Issued Financial Accounting Standards

In February 2007, the Financial Accounting Standards Board, or FASB issued Statement of Financial Accounting Standards No. 159, “TheFair 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. The statement will be effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. The statement offers various options in electing to apply its provisions, and at this time we have not made any decisions on its application and are evaluating the impact of the adoption of SFAS 159 on our financial position and results of operations.

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. SFAS 157 is effective for us beginning January 1, 2008. We are currently evaluating the impact of the adoption of SFAS 157 on our financial position and results of operations.

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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 following discussion is not meant to be a precise indicator of expected future losses, but rather an indicator 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 interest rate cap 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, 2007. 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, 2007, we have a $250 million revolving credit facility of which $57.0 million was outstanding (including $495,000 in letters of credit). The weighted average interest rate for borrowings under this credit facility was 8.5% at March 31, 2007. Holding all other variables constant, a hypothetical 10% change in the weighted average interest rate would decrease our net income by approximately $480,300.

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 use physical hedges. These transactions are similar to NYMEX-based futures contracts, swaps and options, but also require firm delivery of the hedged quantity. Thus, we limit these arrangements to much smaller quantities than those projected to be available at any delivery point.

We also negotiate with certain purchasers for delivery of a portion of natural gas we will produce for the upcoming year. The prices under most of our gas sales contracts are negotiated on an annual basis and are index-based. 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 physical or financial hedge agreements for the twelve months ending March 31, 2008, and current indices, a theoretical 10% upward or downward change in the price of natural gas would result in a change in net income of approximately $2.4 million.

We also enter into natural gas futures 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. A portion of the future sales is periodically hedged through the use of swaps and collar contracts.

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 futures and options contracts to the forecasted transactions. We assess, both at the inception of the hedge and on an ongoing basis, whether the derivatives are highly effective in offsetting changes in the fair value of hedged items. Historically these contracts have qualified and been designated as cash flow hedges and 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. Changes in fair value are recognized in combined equity and recognized within the combined 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.

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As of March 31, 2007, we had financial and physical hedges in place for approximately 77% of our expected production volumes for the twelve months ending March 31, 2008. At March 31, 2007, we had 293 open natural gas futures contracts related to natural gas sales covering 60.8 million MMBtus of natural gas, maturing through March 31, 2012 at an average settlement price of $8.31 per MMBtu. We recognized gains of $2.4 million and $1.4 million on settled contracts covering natural gas production for the three months ended March 31, 2007 and 2006, respectively. There were no gains or losses recognized during the three months ended March 31, 2007 or 2006 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges. Of the $687,000 net unrealized hedge gain, our portion is $292,000 and $395,000 and has been allocated to our investment partnerships.

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Of the $292,000 net gain in accumulated other comprehensive income at March 31, 2007, we will reclassify $218,000 of gains to our consolidated statements of income over the next twelve month period as these contracts expire and $74,000 of gains will be reclassified in later periods if the fair values of the instruments remain at current market values.

As of March 31, 2007, we had the following natural gas volumes hedged:

Fixed Price Swaps

Twelve Month
Period Ending			Average		Fair Value
March 31	Volumes		Fixed Price		Asset
	(MMBtu)		(per MMBtu)		(in thousands) (1)
2008		16,380,000	$	8.676	$	1,342
2009		16,080,000		8.599		611
2010		14,040,000		8.195		1,133
2011		7,950,000		7.572		(1,440	)
2012		3,600,000		7.365		(46	)
					$	1,600

Costless Collars

Twelve Month					Average		Fair Value
Period Ending			Volumes		Floor and Cap		Asset (Liability)
March 31	Option Type		(MMBtu)		(per MMBtu)		(in thousands)(1)
2008		Puts purchased		1,200,000	$	7.500	$	-
2008		Calls sold		1,200,000		8.600		(364	)
2008		Puts purchased		390,000		7.500		-
2008		Calls sold		390,000		9.400		(465	)
2009		Puts purchased		1,170,000		7.500		-
2009		Calls sold		1,170,000		9.400		(84	)
							$	(913	)
Total Net asset							$	687

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

ITEM 4.CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) designed to provide reasonable assurance that the information required to be reported in the Exchange Act filings is recorded, processed, summarized and reported within the time periods specified and pursuant to the regulations of the Securities and Exchange Commission, including controls and procedures designed to ensure that this information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding the required disclosure.

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the 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 have concluded that our disclosure controls and procedures were effective at a reasonable level of assurance as of March 31, 2007.

This quarterly report on Form 10Q does not include a report of management’s assessment regarding internal control over financial reporting or attestation report of our registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.

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PART II.  OTHER INFORMATION

ITEM 6.EXHIBITS

Exhibit No.	Description
3.1	Amended and Restated Limited Liability Company Agreement of Atlas Energy Resources, LLC (1)
3.2	Certificate of Formation of Atlas Energy Resources, LLC(2)
3.3	Amendments to Bylaws(2)
10.1	Revolving Credit Agreement dated December 18, 2006, among Atlas Energy Operating Company LLC, its subsidiaries, Wachovia National Bank, as administrative agent, and other lenders signatory thereto(1)
31.1	Rule 13(a)-14(a)/15d-14(a) Certification.
31.2	Rule 13(a)-14(a)/15d-14(a) Certification.
32.1	Section 1350 Certification.
32.2	Section 1350 Certification.

(1)	Previously filed as an exhibit to our Form 8-K filed December 22, 2006.
(2)	Previously filed as an exhibit to our registration statement on Form S-1 (Reg. No. 333-136094).

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SIGNATURES

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

		ATLAS ENERGY RESOURCES, LLC
		(Registrant)
Date: May 9, 2007	By:	/s/ Matthew A. Jones
		Matthew A. Jones
		Chief Financial Officer
Date: May 9, 2007	By:	/s/Nancy J. McGurk
		Nancy J. McGurk Senior Vice President and Chief Accounting Officer

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