Atlas Energy Resources 10-K 2006 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2006

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 or	(I.R.S. Employer
incorporation or organization)	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
Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common units representing Class B	New York Stock Exchange
limited liability company interests

Securities registered pursuant to Section 12(g) of the Act: None

Title of class

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes oNo x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes oNo x

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 oNo x

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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 (Check one):

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 Act). Yes o No x

The registrant completed its initial public offering in December 2006 and, therefore, there was no aggregate market value of common units as of June 30, 2006. The aggregate market value of common units held by non-affiliates of the registrant on March 1, 2007 was approximately $176.5 million.

DOCUMENTS INCORPORATED BY REFERENCE: None

[THIS PAGE INTENTIONALLY LEFT BLANK]

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ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K

			Page
PART I	Item 1:	Business	4
	Item 1A:	Risk Factors	19
	Item 1B:	Unresolved Staff Comments	33
	Item 2:	Properties	33
	Item 3:	Legal Proceedings	38
	Item 4:	Submission of Matters to a Vote of Security Holders	38
PART II	Item 5:	Market for Registrant's Common Equity and Related Shareholder Matters and Issuer Purchases of Equity Securities	39
	Item 6:	Selected Financial Data	40
	Item 7:	Management’s Discussion and Analysis of Financial Condition andResults of Operations	42
	Item 7A:	Quantitative and Qualitative Disclosures about Market Risk	62
	Item 8:	Financial Statements and Supplementary Data	64
	Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	93
	Item 9A:	Controls and Procedures	93
	Item 9B:	Other Information	93
PART III	Item 10:	Directors and Executive Officers of the Registrant	93
	Item 11:	Executive Compensation	97
	Item 12:	Security Ownership of Certain Beneficial Owners and Management	106
	Item 13:	Certain Relationships and Related Transactions	107
	Item 14:	Principal Accounting Fees and Services	108
PART IV	Item 15:	Exhibits and Financial Statement Schedules	109
SIGNATURES			111

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PART I

ITEM 1: BUSINESS

The matters discussed within this report include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates and projections. While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements.

Factors that could cause actual results to differ from those implied by the forward-looking statements in this report are more fully described under Item 1A, “Risk Factors” in this report. Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this report are made only as of the date hereof. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments.

We commenced operations in December 2006. References in this report to operations before that date are to our predecessor, Atlas America E&P Operations. In June 2006, Atlas America E&P Operations changed its fiscal year end from September 30 to December 31 and, therefore, information is included in this report for the years ended September 30, 2004 and 2005, the three month transition period ended December 31, 2005, and the year ended December 31, 2006.

General

We are a limited liability company focused on the development and production of natural gas and, to a lesser extent, oil in the Appalachian Basin region of the United States, principally in western New York, eastern Ohio, Western Pennsylvania and Tennessee. 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 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. (NASDAQ: ATLS). Atlas America has been involved in the energy industry since 1968, expanding its operations in 1998 when it acquired The Atlas Group, Inc. and in 1999 when it acquired Viking Resources Corporation, both engaged in the development and production of natural gas and oil and the sponsorship of investment partnerships. In December 2006, we completed our initial public offering of 7,273,750 common units 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 our parent, Atlas America in the form of a non-taxable dividend and to repay debt.

We are managed by Atlas Energy Management, Inc., a wholly-owned subsidiary of Atlas America. Through our manager, Atlas America personnel are responsible for managing our assets and capital raising.

As of December 31, 2006, our principal assets consisted of:

·   our investment partnership business, which includes equity interests in 92 investment partnerships and a registered broker-dealer which acts as the dealer-manager of our investment partnership offerings;

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·   either directly or through our investment partnerships, interests in 7,252 gross producing gas and oil wells, including overriding royalty interests in 634 gross producing gas and oil wells;

·   approximately 601,400 gross (547,700 net) acres, primarily in the Appalachian Basin, over half of which, or approximately 336,700 gross (323,300 net) acres, are undeveloped; and

·   an interest in a joint venture that gives us the right to drill up to 200 additional net wells before December 31, 2007 on approximately 212,000 acres in Tennessee.

At December 31, 2006, we had proved reserves of 180.9 billion cubic feet of natural gas equivalents, or Bcfe, including the reserves net to our equity interest in our investment partnerships and our direct interests in producing wells.

For the year ended December 31, 2006, we produced 27.0 million cubic feet of natural gas equivalents per day, or Mmcfe/d, which includes our proportionate share of production from our investment partnerships as well as our direct interests in producing wells. This resulted in an average reserve life of approximately 18 years based on our proved reserves at December 31, 2006.

As of December 31, 2006, 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.

We fund the drilling of natural gas and oil wells on our acreage by sponsoring and managing tax-advantaged investment partnerships. 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.

We derive substantially all of our revenues from our equity interest in the oil and gas produced by the investment partnerships as well as the fees paid by the partnerships to us for acting as the managing general partner as follows:

·   Gas and oil production. We receive an interest in each investment partnership proportionate to the value of our coinvestment in it and the value of the acreage we contribute to it, typically 27% to 33% of the overall capitalization of a particular partnership. We also receive an incremental interest in each partnership, typically 7%, for which we do not make any additional capital contribution. Consequently, our equity interest in the reserves and production of each partnership is typically between 34% and 40%.

·   Partnership management. As managing general partner of our investment partnerships, we receive the following fees:

·   Well construction and completion. For each well that is drilled by an investment partnership, we receive a 15% mark-up on those costs incurred to drill and complete the well.

·   Administration and oversight. Each partnership pays us a monthly per well administrative fee of $75 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well. In addition, for each well drilled by an investment partnership, we receive a fixed administration fee of approximately $15,000.

·   Well services. Each partnership pays us a monthly per well operating fee, currently $100 to $457, for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

·   Gathering. Each partnership pays us a gathering fee for gathering services. Historically, this fee was typically insufficient to cover all of the gathering fees due to Atlas Pipeline Partners, L.P., under Atlas America’s master natural gas gathering agreement with it. After the closing of our initial public offering, pursuant to the terms of our contribution agreement with Atlas America, our gathering revenues and costs within our partnership management segment net to $0. Please read “Other Agreements with Atlas America and its Affiliates—Contribution agreement.” 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.

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Recent Developments

During the fourth quarter of 2006 and first quarter of 2007, we and one of our investment partnerships drilled three wells to multiple pay zones, including the Marcellus Shale of Southwest Pennsylvania. The Marcellus Shale is a black, organic rich shale formation located at depths between 7,000 and 8,500 feet and ranges in thickness from 100 to 150 feet on our acreage in Fayette, Westmoreland and Greene Counties. We currently hold approximately 157,500 acres of prospective Marcellus acreage in these counties. Most of this acreage is held by production, meaning that it is covered by a continuing lease due to production from the property.

Appalachian Basin Overview

The Appalachian Basin includes the states of Kentucky, Maryland, New York, Ohio, Pennsylvania, Virginia, West Virginia and Tennessee. It is the most mature oil and gas producing region in the United States, having established the first oil production in 1860. Because the Appalachian Basin is located near the energy-consuming regions of the mid-Atlantic and northeastern United States, Appalachian producers have historically sold their natural gas at a premium to the benchmark price for natural gas on the NYMEX. For the twelve months ended December 31, 2006, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin was $0.36 per million British thermal unit, or MMBtu. In addition, most of our natural gas production has a high Btu content, resulting in an additional premium to NYMEX natural gas prices.

During the first several years of production, Appalachian Basin wells generally experience higher initial production rates and decline rates which are followed by an extended period of significantly lower production rates and decline rates.

Shallow reserves in the Appalachian Basin are typically in blanket formations and have a high degree of step-out development success; that is, as development progresses, reserves from newly completed wells are reclassified from the proved undeveloped to the proved developed category and additional adjacent locations are added to proved undeveloped reserves. As a result, the cumulative amount of total proved reserves tends to increase as development progresses. Wells in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. In addition, most wells produce dry natural gas, which does not require processing.

Gas and Oil Production

As of December 31, 2006, we owned interests in 7,252 gross wells, principally in the Appalachian Basin, of which we operated 6,155. In the year ended December 31, 2006, we drilled 715 gross wells, 99% of which were successful in producing natural gas in commercial quantities.

In September 2004, we expanded operations into Tennessee through a joint venture with Knox Energy, LLC that gave us an exclusive right to drill up to 300 net wells through June 30, 2007 on approximately 212,000 acres owned by Knox Energy. This agreement was amended and extended, giving us the right to drill an additional 200 net wells from January 1, 2007 to December 31, 2007, provided that we commenced the drilling of a minimum of 75 wells before September 30, 2007. As of December 31, 2006, we had drilled 141 net wells under this agreement and we have identified over 500 proved undeveloped drilling locations and approximately 2,600 additional potential drilling locations on our acreage and the Tennessee joint venture acreage.

For information concerning our natural gas and oil properties and production, see Item 2: “Properties.”

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 our investment partnerships invested $283.7 million in drilling and completing wells, of which we contributed $65.2 million.

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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 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. We have not subordinated our share of revenues from any of our investment partnerships since March 2005, and do not believe any amounts which may be subordinated in the future will be material to our operations.

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.

Natural Gas Sales

We have a natural gas supply agreement with Hess Corporation which is valid through March 31, 2009. Subject to certain exceptions, Hess has a last right of refusal to buy all of the natural gas produced and delivered by us and our affiliates, including our investment partnerships, at certain delivery points within the facilities of:

·   East Ohio Gas Company, National Fuel Gas Distribution, Columbia of Ohio, and Peoples Natural Gas Company, which are local distribution companies; and

·   National Fuel Gas Supply, Columbia Gas Transmission Corporation, Tennessee Gas Pipeline Company, and Texas Eastern Transmission Company, which are interstate pipelines.

Our agreement with Hess has the following exclusions:

·   natural gas we sell to Warren Consolidated, an industrial end-user and direct delivery customer;

·   natural gas that at the time of the agreement was already dedicated for the life of the well to another buyer;

·   natural gas that is produced by a company which was not an affiliate of ours at the time of the agreement;

·   natural gas sold through interconnects established subsequent to the agreement;

·   natural gas that is delivered to interstate pipelines or local distribution companies other than those described above; and

·   natural gas that is produced from wells operated by a third-party or subject to an agreement under which a third-party was to arrange for the gathering and sale of the natural gas.

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Based on the most recent monthly production data available to us as of December 31, 2006, we anticipate that we and our affiliates, including our investment partnerships, will sell approximately 30% of our natural gas production during the twelve months ending December 31, 2007 under the Hess agreement. The agreement also permits us to implement physical hedge transactions through Hess, as described below under “Business—Natural Gas Hedging.” The Hess agreement established an indexed price formula for each of the delivery points during an initial period of one to two years, and requires the parties to negotiate a new pricing arrangement at each delivery point for subsequent periods. If, at the end of any applicable period, the parties cannot agree to a new price for any delivery point, then we may solicit offers from third-parties to buy the natural gas for that delivery point. If Hess does not match this price, then we may sell the natural gas to the third-party. This process is repeated at the end of each contract period, which is usually one year. We market the remainder of our natural gas, which is principally located in the Fayette County, PA area, primarily to Colonial Energy, Inc., UGI Energy Services, and others.

We expect that natural gas produced from wells drilled in areas of the Appalachian Basin other than described above will be primarily tied to the spot market price and supplied to:

·   gas marketers;

·   local distribution companies;

·   industrial or other end-users; and/or

·   companies generating electricity.

Crude Oil Sales

Crude oil produced from our wells flows directly into storage tanks where it is picked up by oil companies, a common carrier, or pipeline companies acting for the oil companies which are purchasing the crude oil. We anticipate selling any oil produced by our wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil in spot sales.

Natural Gas Hedging

Pricing for natural gas and oil production has been volatile and unpredictable for many years. To limit our exposure to changing natural gas prices, we use financial and physical hedges for a portion of our natural gas production. Through our hedges, we seek to provide a measure of stability in the volatile environment of natural gas prices. The financial hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to 36 months in the future. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, our manager has a management committee to assure that all financial trading is done in compliance with our hedging policies and procedures. We do not intend to contract for positions that we cannot offset with actual production. As of December 31, 2006, we had financial hedges and physical hedges in place for approximately 79% of our expected production for the twelve months ending December 31, 2007.

Hess and other third-party marketers to which we sell gas, such as Colonial Energy and UGI Energy Services, also use NYMEX-based financial instruments to hedge their pricing exposure and make price hedging opportunities available to us. We enter into physical hedge transactions which are not deemed hedges for accounting purposes because they require firm delivery of natural gas and are considered normal sales of natural gas. We generally limit these arrangements to much smaller quantities than those projected to be available at any delivery point. The price paid by Hess, Colonial Energy, UGI Energy Services, and any other third-party marketers for certain volumes of natural gas sold under these sales agreements may be significantly different from the underlying monthly spot market value. Fixed prices are defined as the price we have established with the related purchaser and are not subject to change in the future. For a description of our financial hedges, please read Item 7A: “Quantitative and Qualitative Disclosures About Market Risk” in this report.

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Natural Gas Gathering

We conduct our natural gas transportation and processing operations through Atlas America’s affiliate, Atlas Pipeline Partners, L.P. (NYSE: APL). Atlas Pipeline owns approximately 1,600 miles of gathering systems located in eastern Ohio, western New York and western Pennsylvania serving approximately 5,865 wells.

In connection with the completion of our initial public offering, and the contribution by Atlas America of its natural gas and oil development and production assets to us, we entered into the following agreements with Atlas Pipeline.

Omnibus Agreement

Under the omnibus agreement, Atlas America and its affiliates agreed to add wells to Atlas Pipeline's gathering systems and provide consulting services when Atlas Pipeline constructs new gathering systems or extend existing systems. We joined the omnibus agreement as an obligor (except for the provisions of the omnibus agreement imposing conditions upon the disposition of the general partner interest of Atlas Pipeline's general partner), and Atlas America became secondarily liable as a guarantor of our performance. The omnibus agreement is a continuing obligation, having no specified term or provisions regarding termination except for a provision terminating the agreement if Atlas Pipeline's general partner is removed without cause.

Well connections. We are required to construct, at our sole cost and expense, up to 2,500 feet of small diameter (two inches or less) sales or flow lines from the wellhead of any well we drill and operate to a point of connection to Atlas Pipeline’s gathering systems. Where we have extended sales and flow lines to within 1,000 feet of one of Atlas Pipeline’s gathering systems, we may require Atlas Pipeline to extend its system to connect to that well. With respect to other wells that are more than 2,500 feet from Atlas Pipeline’s gathering systems, Atlas Pipeline has the right, at its cost and expense, to extend its gathering system to within 2,500 feet of the well and to require us, at our cost and expense, to construct up to 2,500 feet of flow line to connect to the gathering system extension. If Atlas Pipeline elects not to exercise its right to extend its gathering systems, we may connect a well to a natural gas gathering system owned by a third party or to any other delivery point; however, Atlas Pipeline will have the right to assume the cost of construction of the necessary flow lines, which then become its property and part of its gathering systems.

Consulting services. The omnibus agreement requires us to assist Atlas Pipeline in identifying existing gathering systems for possible acquisition and to provide consulting services to Atlas Pipeline in evaluating and making a bid for these systems. We must give Atlas Pipeline notice of identification by us or any of our affiliates of any gathering system as a potential acquisition candidate, and must provide Atlas Pipeline with information about the gathering system, its seller and the proposed sales price, as well as any other information or analyses we compile with respect to the gathering system. Atlas Pipeline must determine, within a time period specified by our notice to it, which must be a reasonable time under the circumstances, whether it wants to acquire the identified system and advise us of its intent. If Atlas Pipeline advises us that it does not intend to make the acquisition, does not complete the acquisition within a reasonable time period, or advises us that it does not intend to acquire the system, then we may do so.

Gathering system construction. We will provide Atlas Pipeline with construction management services if Atlas Pipeline determines to expand one or more of its gathering systems. We are entitled to reimbursement for our costs, including an allocable portion of employee salaries, in connection with our construction management services.

Natural Gas Gathering Agreements

Under our master natural gas gathering agreement with Atlas Pipeline we pay gathering fees as follows:

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·   for natural gas from our well interests, other than those of our investment partnerships, that were connected to Atlas Pipeline’s gathering systems at February 2, 2000, the greater of $0.40 per thousand cubic feet, or Mcf, 16% of the gross sales price of the natural gas transported;

·   for (i) natural gas from well interests allocable to our investment partnerships that drilled or drill wells on or after December 1, 1999 that are connected to the gathering systems (ii) natural gas from our well interests, other than those of our investment partnerships, that are connected to the gathering systems after February 2, 2000, and (iii) well interests allocable to third parties in wells connected to the gathering systems at February 2, 2000, the greater of $0.35 per Mcf or 16% of the gross sales price of the natural gas transported; and

·   for natural gas from well interests we operate and drilled after December 1, 1999 that are connected to a gathering system that is not owned by Atlas Pipeline and for which Atlas Pipeline assumes the cost of constructing the connection to that gathering system, an amount equal to the greater of $0.35 per Mcf or 16% of the gross sales price of the natural gas transported, less the gathering fee charged by the other gathering system.

We receive gathering fees from contracts or other arrangements with the owners of well interests connected to Atlas Pipeline’s gathering systems. Pursuant to the contribution agreement described below under "—Other Agreements with Atlas America and its Affiliates—Contribution Agreement", Atlas America agreed to assume our obligation to pay gathering fees to Atlas Pipeline. We, in turn, assigned to Atlas America the gathering fees we receive from our investment partnerships and gathering fees attributable to our production interest. The gathering fees payable to Atlas Pipeline generally exceed the amount we receive from our investment partnerships for gathering services. See Item 1A: Risk Factors. If Atlas America fails to pay gathering fees to Atlas Pipeline as required by its assumption agreement with us, we will have to pay to Atlas Pipeline the difference between the gathering fee payable and the amount we receive from our investment partnerships for gathering services out of our own resources.

The master natural gas gathering agreement is a continuing obligation and, accordingly, has no specified term or provisions regarding termination. However, if Atlas Pipeline’s general partner is removed as the general partner of Atlas Pipeline without cause, then no gathering fees will be due under the agreement with respect to new wells drilled by us.

In addition to the master natural gas gathering agreement, we are party to three other gas gathering agreements with Atlas Pipeline:

·   Under two agreements, relating to wells located in southeastern Ohio which were originally acquired from Kingston Oil Corporation and wells located Fayette County, Pennsylvania which were originally acquired from American Refining and Exploration Company, we pay Atlas Pipeline gathering fees of $0.80 per Mcf. These wells are owned directly by our subsidiaries, and Atlas America has not assumed any part of our obligation to pay the gathering fees to Atlas Pipeline under these agreements.

·   Under another agreement, which covers wells owned by third parties unrelated to us and our investment partnerships, we pay Atlas Pipeline gathering fees that range between $0.20 and $0.29 per Mcf or between 10% to 16% of the weighted average sales price. The gathering fees payable under this agreement are a direct pass-through of the gathering fees we receive from the third party wells. Accordingly, Atlas America has not assumed any part of our obligation to pay the gathering fees to Atlas Pipeline under this agreement, and has been removed as an obligor under it.

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Other Agreements with Atlas America and Its Affiliates

Contribution Agreement

Contribution of assets by Atlas America. The substantial majority of the assets we own were held, directly or indirectly, by subsidiaries of Atlas America. In connection with our initial public offering, Atlas America entered into a contribution agreement pursuant to which it contributed to us all of the stock of its natural gas and oil development and production subsidiaries as well as the development and production assets owned by it. As consideration for this contribution, we distributed to Atlas America the net proceeds we received from that offering, as well as 29,352,996 of our common units, the Class A units and the management incentive interests. As part of the contribution agreement, Atlas America has agreed to indemnify us until December 2007 against certain potential environmental liabilities associated with the operation of the assets and occurring before the closing date of the offering and against claims for covered environmental liabilities made before the fourth anniversary of the closing of the offering. The obligation of the indemnitors will not exceed $25.0 million, and they will not have any indemnification obligation until our losses exceed $500,000 in the aggregate, and then only to the extent such aggregate losses exceed $500,000. Additionally, Atlas America has agreed to indemnify us for losses attributable to title defects to our oil and gas property interests for three years after the closing of the offering, and indefinitely for losses attributable to retained liabilities and income taxes attributable to pre-closing operations and formation transactions. Furthermore, we have agreed to indemnify Atlas America for all losses attributable to the post-closing operations of the assets contributed to us, to the extent not subject to its indemnification obligations.

Atlas America’s assumption of obligations under the master natural gas gathering agreement with Atlas Pipeline. Upon completion of our initial public offering, we became a party to an existing master natural gas gathering agreement between Atlas America and Atlas Pipeline pursuant to which Atlas Pipeline gathers substantially all of the natural gas from wells operated by us. Pursuant to the contribution agreement, Atlas America has agreed to assume our obligation to pay gathering fees to Atlas Pipeline under the master natural gas gathering agreement; we have agreed to pay Atlas America the gathering fees we receive from our investment partnerships and fees associated with production to our interest.

Management Agreement

Upon completion of our initial public offering, we entered into a management agreement with Atlas Energy Management, a subsidiary of Atlas America, pursuant to which Atlas Energy Management will manage our business affairs under the supervision of our board of directors. Atlas Energy Management will provide us with all services necessary or appropriate for the conduct of our business. In exercising its powers and discharging its duties under the management agreement, Atlas Energy Management must act in good faith.

Before making any distribution on our common units, we will reimburse Atlas Energy Management for all expenses that it incurs on our behalf pursuant to the management agreement. These expenses will include costs for providing corporate staff and support services to us. Atlas Energy Management will charge on a fully-allocated cost basis for services provided to us. This fully-allocated cost basis is based on the percentage of time spent by personnel of Atlas Energy Management and its affiliates on our matters and includes the compensation paid by Atlas Energy Management and its affiliates to such persons and their allocated overhead. The allocation of compensation expense for such persons will be determined based on a good faith estimate of the value of each such person’s services performed on our business and affairs, subject to the periodic review and approval of our audit or conflicts committee.

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Atlas Energy Management, its stockholders, directors, officers, employees and affiliates will not be liable to us, our directors or unitholders for acts or omissions performed in good faith and in accordance with and pursuant to the management agreement, except by reason of acts constituting gross negligence, bad faith, willful misconduct, fraud or a knowing violation of criminal law. We will indemnify Atlas Energy Management, its stockholders, directors, officers, employees and affiliates with respect to all expenses, losses, damages, liabilities, demands, charges and claims arising from acts of Atlas Energy Management, its stockholders, directors, officers, employees and affiliates not constituting gross negligence, bad faith, willful misconduct, fraud or a knowing violation of criminal law performed in good faith in accordance with and pursuant to the management agreement. Atlas Energy Management and its affiliates will indemnify us and our directors and officers with respect to all expenses, losses, damages, liabilities, demands, charges and claims arising from acts of Atlas Energy Management or its affiliates constituting gross negligence, bad faith, willful misconduct, fraud or a knowing violation of criminal law or any claims by employees of Atlas Energy Management or its affiliates relating to the terms and conditions of their employment. Atlas Energy Management and/or Atlas America will carry errors and omissions and other customary insurance.

The management agreement may not be amended without the prior approval of our conflicts committee if the proposed amendment will, in the reasonable discretion of our board, adversely affect our common unitholders.

The management agreement does not have a specific term; however, Atlas Energy Management may not terminate the agreement before December 18, 2016. We may terminate the management agreement only upon the affirmative vote of holders of at least two-thirds of our outstanding common units, including units held by Atlas America. In the event we terminate the management agreement, Atlas Energy Management will have the option to require the successor manager, if any, to purchase its membership interests and management incentive interests for their fair market value as determined by agreement between the departing manager and the successor manager.

Operating Segment Information

For financial information concerning our operating segments, including revenues from external customers, profit (loss) and total assets, see Note 9 to our Combined and Consolidated Financial Statements.

Availability of Oil Field Services

We contract for drilling rigs and purchase goods and services necessary for the drilling and completion of wells from a number of drillers and suppliers, none of which supplies a significant portion of our annual needs. During the year ended December 31, 2006, we faced no shortage of these goods and services. We cannot predict the duration of the current supply and demand situation for drilling rigs and other goods and services with any certainty due to numerous factors affecting the energy industry and the demand for natural gas and oil.

Major Customers

Our natural gas is sold under contract to various purchasers. During the year ended December 31, 2006, we did not have any customers that accounted for 10% or more of our revenues.

Competition

The energy industry is intensely competitive in all of its aspects. We operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital through our investment partnerships, contracting for drilling equipment and securing trained personnel. We also compete with the exploration and production divisions of public utility companies for natural gas and oil property acquisitions. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. Our competitors may be able to pay more for natural gas and oil properties and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Furthermore, competition arises not only from numerous domestic and foreign sources of natural gas and oil but also from other industries that supply alternative sources of energy. Product availability and price are the principal means of competition in selling oil and natural gas.

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Many of our competitors possess greater financial and other resources than ours which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than we do.

Moreover, we also compete with a number of other companies that offer interests in investment partnerships. As a result, competition for investment capital to fund investment partnerships is intense.

Markets

The availability of a ready market for natural gas and oil and the price obtained, depends upon numerous factors beyond our control, as described in Item 1A: “Risk Factors”. During the year ended December 31, 2006 we did not experience problems in selling our natural gas and oil, although prices have varied significantly during and after those periods.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas of the Appalachian region. These seasonal anomalies may pose challenges for meeting our well construction objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay our operations. In the past, we have drilled a greater number of wells during the winter months due to the fact that we have typically received the majority of funds from our investment partnerships during the fourth calendar quarter. Generally the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

Environmental Matters and Regulation

General

Our operations are subject to comprehensive and stringent federal, state and local laws and regulations governing, among other things, where and how we install wells, how we handle wastes from our operations and the discharge of materials into the environment. Our operations will be subject to the same environmental laws and regulations as other companies in the natural gas and oil industry. Among other requirements and restrictions, these laws and regulations:

·   require the acquisition of various permits before drilling commences;

·   require the installation of expensive pollution control equipment;

·   restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

·   limit or prohibit drilling activities on lands lying within or, in some cases, adjoining wilderness, wetlands and other protected areas;

·   require remedial measures to reduce, mitigate or respond to releases of pollutants or hazardous substances from former operations, such as pit closure and plugging of abandoned wells;

·   impose substantial liabilities for pollution resulting from our operations; and

·   with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

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These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently enact new, and revise existing, environmental laws and regulations, and any new laws or changes to existing laws that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs. We believe that our operations on the whole substantially comply with all currently applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict how environmental laws and regulations that may take effect in the future may impact our properties or operations. For the year ended December 31, 2006, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. As of the date of this report, we are not aware of any environmental issues or claims that will require material capital expenditures during 2007 or that will otherwise have a material impact on our financial position or results of operations.

National Environmental Policy Act.Natural gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will typically require an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that will be made available for public review and comment. All of our proposed exploration and production activities on federal lands require governmental permits, many of which are subject to the requirements of NEPA. This process has the potential to delay the development of natural gas and oil projects.

Waste Handling.The Solid Waste Disposal Act, including the Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency, or EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil and natural gas constitute “solid wastes”, which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation.

We believe that our operations are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes to be significant, any more stringent regulation of natural gas and oil exploitation and production wastes could increase our costs to manage and dispose of such wastes.

Comprehensive Environmental Response, Compensation and Liability Act.The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on persons who are considered under the statute to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

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Our operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. Although we believe Atlas America utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges.The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The Clean Water Act also requires specified facilities to maintain and implement spill prevention, control and countermeasure plans and to take measures to minimize the risks of petroleum spills. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for failure to obtain or non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe our operations on the whole are in substantial compliance with the requirements of the Clean Water Act.

Air Emissions.The Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through permits and other requirements. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic and other air pollutants at specified sources. Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new emission limitations. These regulations may increase the costs of compliance for some facilities, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance. These laws and regulations also apply to entities that use natural gas as fuel, and may increase the costs of compliance of our customers to the point where demand for natural gas is affected. We believe that our operations are in substantial compliance with the requirements of the Clean Air Act.

OSHA and Other Regulations.We are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Other Laws and Regulation.The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases, which are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has resisted recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The natural gas and oil industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations are not adversely impacted by current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

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Other Regulation of the Natural Gas and Oil Industry

The natural gas and oil industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the natural gas and oil industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

·   the location of wells;

·   the method of drilling and casing wells;

·   the surface use and restoration of properties upon which wells are drilled;

·   the plugging and abandoning of wells; and

·   notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Natural Gas Regulation. The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The Federal Energy Regulatory Commission’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

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State Regulation. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Tennessee currently imposes a 3% severance tax on natural gas and oil production and Ohio imposes a severance tax of $0.025 per Mcf of natural gas and $0.10 per barrel, or Bbl of oil. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon the unitholders.

Credit Facility

Simultaneously with the closing of our initial public offering, we entered into a $250 million senior secured credit facility with Wachovia Bank, National Association, as administrative agent, Wachovia Capital Markets LLC, 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 initial borrowing base is $155 million. The borrowing base will be subject to redetermination on March 15, 2007 and on a semi-annual basis thereafter. The credit facility will mature on December 18, 2011.

Our obligations under the credit facility are secured by mortgages on our natural gas and oil properties as well as a pledge of all of our ownership interests in our operating subsidiaries, other than Anthem Securities, Inc. We are required to maintain mortgages on properties representing at least 80% of our natural gas and oil properties. Additionally, the obligations under the credit facility are guaranteed by all of our existing operating subsidiaries and by any future subsidiaries, other than Anthem Securities.

Borrowings under the new credit facility are available for development, exploitation and acquisition of natural gas and oil properties, working capital and general corporate purposes.

At our election, interest will be determined by reference to:

·   the London interbank offered rate, or LIBOR, plus an applicable margin between 1.00% and 1.75% per annum, depending on our usage of the facility; or

·   the higher of (i) the federal funds rate plus 0.50% or (ii) the Wachovia prime rate, plus, in each case, an applicable margin between 0.00% and 0.75% per annum, depending on our usage of the facility.

Interest is generally payable quarterly for domestic bank rate loans and at the end of each applicable interest period for LIBOR loans.

The credit facility contains covenants that, among other things, limit our ability to:

·   incur indebtedness;

·   grant certain liens;

·   enter into certain leases;

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·   make certain loans, acquisitions, capital expenditures and investments;

·   enter into hedging arrangements that exceed 85% of our proved reserves;

·   make any change to the character of our business or the business of the investment partnerships;

·   merge or consolidate; or

·   engage in certain asset dispositions, including a sale of all or substantially all of our assets.

The credit facility requires us to maintain a current ratio (defined as the ratio of current assets to current liabilities excluding assets and liabilities under hedging agreements, deferred profit on advance payments received for the drilling and completion of oil and gas wells, and current maturity of any amount due under the credit facility, plus any unused amount under the borrowing base) of not less than 1.0 to 1.0; a funded debt to EBITDA ratio of not more than 3.5 to 1.0; and a minimum interest coverage ratio (defined as our EBITDA divided by our interest expense) of not less than 2.5 to 1.0. The credit facility defines EBITDA for any period of four quarters as the sum of consolidated net income for the period plus interest, income taxes, depreciation, depletion and amortization.

We have the ability to pay distributions to unitholders as long as there has not been an event of default and an event of default would not result from the distribution.

If an event of default exists under the credit facility, the lenders will be able to accelerate the maturity of the credit facility and exercise other customary rights and remedies. Each of the following is an event of default:

·   failure to pay any principal when due or any interest, fees or other amounts in the credit facility;

·   failure to pay any principal or interest on any of our other debt aggregating $2.5 million or more;

·   a representation, warranty or certification made under the loan documents or in any certificate furnished thereunder is false or misleading as of the time made or furnished in any material respect;

·   failure to perform under any obligation set forth in the credit facility, subject to a grace period;

·   an event having a material adverse effect on us, any of the guarantors or the collateral used to secure indebtedness;

·   admission in writing the inability to, or being generally unable to, pay debts as they become due;

·   bankruptcy or insolvency events;

·   commencement of a proceeding or case in any court of competent jurisdiction, without application or consent, involving:

·   liquidation, reorganization, dissolution or winding-up; or

·   the appointment of a trustee, receiver, custodian, liquidator or the like;

·   the entry of, and failure to pay, one or more judgments in excess of $2.5 million;

·   the loan documents cease to be in full force and effect or cease to create a valid, binding and enforceable lien;

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·   a change of control, generally defined as (i) a group or person acquiring 35% or more of our outstanding voting units (other than Atlas America and its affiliates), (ii) our failure to own 85% or more of the outstanding shares of voting capital stock of any of our subsidiaries that is a guarantor under the credit facility, (iii) our failure to own 100% of Atlas Energy Operating Company or (iv) the failure of Atlas America or any of its wholly-owned subsidiaries to own at least 51% of the equity of our manager; and

·   concealment of property with the intent to hinder, delay or defraud any lender with respect to their rights to such property.

Employees

We do not have any employees. To carry out our operations, our manager and its affiliates employed approximately 370 persons as of December 31, 2006.

ITEM 1A: RISK FACTORS

Statements made by us in written or oral form to various persons, including statements made in filings with the SEC that are not strictly historical facts, are “forward-looking” statements that are based on current expectations about our business and assumptions made by management. These statements are subject to risks and uncertainties that exist in our operations and business environment that could result in actual outcomes and results that are materially different than predicted. The following includes some, but not all, of those factors or uncertainties:

We may not have sufficient cash flow from operations to pay the initial quarterly distribution, or IQD, following the establishment of cash reserves and payment of fees and expenses, including payments to our manager. We may not have sufficient cash flow from operations each quarter to pay the IQD. Under the terms of our limited liability company agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of any cash reserve amounts that our board of directors establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders and the holders of the management incentive interests. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

·   the amount of natural gas and oil we produce;

·   the price at which we sell our natural gas and oil;

·   the level of our operating costs;

·   our ability to acquire, locate and produce new reserves;

·   results of our hedging activities;

·   the level of our interest expense, which depends on the amount of our indebtedness and the interest payable on it; and

·   the level of our capital expenditures.

The actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

·   our ability to make working capital borrowings to pay distributions;

·   the cost of acquisitions, if any;

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·   fluctuations in our working capital needs;

·   timing and collectibility of receivables;

·   restrictions on distributions imposed by lenders;

·   payments to our manager;

·   the amount of our estimated maintenance capital expenditures;

·   prevailing economic conditions; and

·   the amount of cash reserves established by our board of directors for the proper conduct of our business.

As a result of these factors, the amount of cash we distribute in any quarter to our unitholders may fluctuate significantly from quarter to quarter and may be significantly less than the IQD amount that we expect to distribute.

If commodity prices decline significantly, our cash flow from operations will decline and we may have to lower our distribution or may not be able to pay distributions at all. Our revenue, profitability and cash flow substantially depend upon the prices and demand for natural gas and oil. The natural gas and oil markets are very volatile and a drop in prices can significantly affect our financial results and impede our growth. Changes in natural gas and oil prices will have a significant impact on the value of our reserves and on our cash flow. Prices for natural gas and oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas or oil, market uncertainty and a variety of additional factors that are beyond our control, such as:

·   the level of the domestic and foreign supply and demand;

·   the price and level of foreign imports;

·   the level of consumer product demand;

·   weather conditions and fluctuating and seasonal demand;

·   overall domestic and global economic conditions;

·   political and economic conditions in natural gas and oil producing countries, including those in the Middle East and South America;

·   the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

·   the impact of the U.S. dollar exchange rates on natural gas and oil prices;

·   technological advances affecting energy consumption;

·   domestic and foreign governmental relations, regulations and taxation;

·   the impact of energy conservation efforts;

·   the cost, proximity and capacity of natural gas pipelines and other transportation facilities; and

·   the price and availability of alternative fuels.

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In the past, the prices of natural gas and oil have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2006, the NYMEX Henry Hub natural gas index price ranged from a high of $11.43 per MMBtu to a low of $4.20 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $75.92 per Bbl to a low of $56.93 per Bbl.

At December 31, 2006, we owned interests in 7,252 gross wells. Producers with higher rates of production than ours are less sensitive to declining commodity prices due to the relatively fixed nature of well operating costs. Lower natural gas and oil prices may not only decrease our revenues, but also reduce the amount of natural gas and oil that we can produce economically, which would also decrease our revenues and cause us to shut in, and eventually plug and abandon, uneconomic wells.

Unless we replace our reserves, our reserves and production will decline, which would reduce our cash flow from operations and impair our ability to make distributions to our unitholders. Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Based on our December 31, 2006 reserve report, our average annual decline rate for proved developed producing reserves is approximately 12% during the first five years, approximately 7% in the next five years and less than 6% thereafter. Because total estimated proved reserves include proved undeveloped reserves at December 31, 2006, production will decline at this rate even if those proved undeveloped reserves are developed and the wells produce as expected. This rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances. Thus, our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. Our ability to find and acquire additional recoverable reserves to replace current and future production at acceptable costs depends on our generating sufficient cash flow from operations and other sources of capital, principally our sponsored investment partnerships, all of which are subject to the risks discussed elsewhere in this section.

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. Underground accumulations of natural gas and oil cannot be measured in an exact way. Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Our independent petroleum engineers prepare estimates of our proved reserves. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we make certain assumptions regarding future natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas and oil we ultimately recover being different from our reserve estimates.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from our natural gas properties also will be affected by factors such as:

·   actual prices we receive for natural gas;

·   the amount and timing of actual production;

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·   the amount and timing of our capital expenditures;

·   supply of and demand for natural gas; and

·   changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. Additionally, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

Any significant variance in our assumptions could materially affect the quantity and value of reserves, the amount of PV-10 described in this report, and our financial condition and results of operations. Additionally, our reserves or PV-10 may be revised downward or upward based upon production history, results of future exploitation and development activities, prevailing natural gas and oil prices and other factors. A material decline in prices paid for our production can reduce the estimated volumes of our reserves because the economic life of our wells could end sooner. Similarly, a decline in market prices for natural gas or oil may reduce our PV-10. Any of these negative effects on our reserves or PV-10 may decrease the value of our common units.

Our operations require substantial capital expenditures, which will reduce our cash available for distribution. Additionally, each quarter we are required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available to unitholders than if actual maintenance capital expenditures were deducted. We will need to make substantial capital expenditures to maintain our capital asset base over the long term. For the year ending December 31, 2007, we estimate these expenditures to be approximately $35.0 million. These maintenance capital expenditures may include the drilling and completion of additional wells to offset the production decline from our producing properties or additions to our inventory of unproved or proved reserves. These expenditures could increase as a result of:

·   changes in our reserves;

·   changes in natural gas prices;

·   changes in labor and drilling costs;

·   our ability to acquire, locate and produce reserves;

·   changes in leasehold acquisition costs; and

·   government regulations relating to safety and the environment.

Our significant maintenance capital expenditures will reduce the amount of cash we have available for distribution to our unitholders. Additionally, our actual maintenance capital expenditures will vary from quarter to quarter. Our limited liability company agreement requires us to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and approval by our board of directors, including a majority of our conflicts committee, at least once a year. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders will be lower than if we deducted actual maintenance capital expenditures from operating surplus. If we underestimate the appropriate level of estimated maintenance capital expenditures, we may have less cash available for distribution in future periods when actual capital expenditures begin to exceed our previous estimates. Over time, if we do not set aside sufficient cash reserves or have available sufficient sources of financing and make sufficient expenditures to maintain our capital asset base, we will be unable to pay distributions at the anticipated level and may have to reduce our distributions.

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We are required to make substantial capital expenditures to increase our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to make cash distributions may be diminished. The natural gas and oil industry is capital intensive. We intend to finance our future capital expenditures with capital raised through our sponsored investment partnerships, cash flow from operations and bank borrowings. In particular, our forecast of cash available for distribution for the year ending December 31, 2007 assumes that we will raise $270.0 million from third parties through our investment partnerships. This amount of capital is significantly more than the $218.5 million we raised during the year ended December 31, 2006 and significantly more than the average annual amount of $152.0 million we raised for the three years ended September 30, 2006. If we are unable to obtain sufficient capital funds on satisfactory terms, we may be unable to increase or maintain our inventory of properties and reserve base, or be forced to curtail drilling or other activities. This would result in a decline in our revenues and our ability to increase cash distributions may be diminished. If we do not make sufficient or effective expansion capital expenditures, including with funds from third-party sources, we will be unable to expand our business operations and will be unable to raise the level of our future cash distributions.

Changes in tax laws may impair our ability to obtain capital funds through investment partnerships. Under current federal tax laws, there are tax benefits to investing in investment partnerships such as those we sponsor, including deductions for intangible drilling costs and depletion deductions. Changes to federal tax law that reduce or eliminate these benefits may make investment in our investment partnerships less attractive and, thus, reduce our ability to obtain funding from this significant source of capital funds. A recent change to federal tax law that may affect us is the Jobs and Growth Tax Relief Reconciliation Act of 2003, which reduced the maximum federal income tax rate on long-term capital gains and qualifying dividends to 15% through 2008. These changes may make investment in our investment partnerships relatively less attractive than investments in assets likely to yield capital gains or qualifying dividends.

Our credit facility has substantial restrictions and financial covenants. A default under these provisions could cause all of our debt to be immediately due and restrict our payment of distributions to our unitholders. Our revolving credit facility restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We are also required to comply with specified financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the credit facility could result in a default, which could cause our existing indebtedness to be immediately due and restrict our payment of distributions to our unitholders.

Our future debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities. We have the ability to borrow $155 million under our credit facility, subject to borrowing base limitations in the credit agreement. Our future indebtedness could have important consequences to us, including:

·   our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

·   covenants contained in our credit arrangements require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

·   we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and

·   our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

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Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms or at all.

We may not be able to continue to raise funds through our investment partnerships at the levels we have recently experienced, which may in turn restrict our ability to maintain our drilling activity at the levels recently experienced. We have sponsored limited and general partnerships to raise funds from investors to finance our development drilling activities. Accordingly, the amount of development activities we undertake depends in large part upon our ability to obtain investor subscriptions to invest in these partnerships. During the past three years we have raised successively larger amounts of funds through these investment partnerships, raising $107.7 million in fiscal 2004, $148.7 million in fiscal 2005, and $52.2 million in the three months ended December 31, 2005 and $218.5 million in calendar 2006. Additionally, our forecast of cash available for distribution for the twelve month period ending December 31, 2007 assumes that we will raise $270.0 million from third parties through our investment partnerships. In the future, we may not be successful in raising funds through these investment partnerships at the same levels we have recently experienced, and we also may not be successful in increasing the amount of funds we raise as we have done in recent years. Our ability to raise funds through our investment partnerships depends in large part upon the perception of investors of their potential return on their investment and their tax benefits from investing in them, which perception is influenced significantly by our historical track record of generating returns and tax benefits to the investors in our existing partnerships.

In the event that our investment partnerships do not achieve satisfactory returns on investment or the anticipated tax benefits, we may have difficulty in continuing to increase the amount of funds we raise through these partnerships or in maintaining the level of funds we have recently raised through these partnerships. In this event, we may need to obtain financing for our drilling activities on a less attractive basis than the financing we realize through these partnerships or we may determine to reduce our drilling activity.

Our fee-based revenues may decline if we are unsuccessful in continuing to sponsor investment partnerships, and our fee-based revenue may not increase at the same rate as recently experienced if we are unable to raise funds at the same or higher levels as we have recently experienced. Our fee-based revenues are based on the number of investment partnerships we sponsor and the number of partnerships and wells we manage or operate. If we are unsuccessful in sponsoring future investment partnerships, our fee-based revenues may decline. Additionally, our fee-based revenue may not increase at the same rate as recently experienced if we are unable to raise funds at the same or higher levels as we have recently experienced.

Competition in the natural gas and oil industry is intense, which may hinder our ability to acquire gas and oil properties and companies and to obtain capital, contract for drilling equipment and secure trained personnel. We operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital through our investment partnerships, contracting for drilling equipment and securing trained personnel. We will also compete with the exploration and production divisions of public utility companies for natural gas and oil property acquisitions. Our competitors may be able to pay more for natural gas and oil properties and drilling equipment and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Moreover, our competitors for investment capital may have better track records in their programs, lower costs or better connections in the securities industry segment that markets oil and gas investment programs than we do. All of these challenges could make it more difficult for us to execute our growth strategy. We may not be able to compete successfully in the future in acquiring leasehold acreage or prospective reserves or in raising additional capital.

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Furthermore, competition arises not only from numerous domestic and foreign sources of natural gas and oil but also from other industries that supply alternative sources of energy. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. Product availability and price are the principal means of competition in selling oil and natural gas. Many of our competitors possess greater financial and other resources than ours which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than we do.

Our business depends on the gathering and transportation facilities of Atlas Pipeline. Any limitation in the availability of those facilities would interfere with our ability to market the natural gas we produce and could reduce our revenues and cash available for distribution. Atlas Pipeline gathers more than 90% of our current production. The marketability of our natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by Atlas Pipeline and other third parties. The amount of natural gas that can be produced and sold is subject to curtailment in circumstances such as pipeline interruptions due to scheduled and unscheduled maintenance or excessive pressure or physical damage to the gathering or transportation system. The curtailments arising from these and similar circumstances may last from a few days to several months.

If Atlas America fails to pay gathering fees to Atlas Pipeline as required by its assumption agreement with us, we will have to pay to Atlas Pipeline the difference between the gathering fee payable and the amount we receive from our investment partnerships for gathering services out of our own resources. We are a party to a master gas gathering agreement with Atlas Pipeline which requires, among other things, paying Atlas Pipeline gathering fees for gathering our gas. The gathering agreement is a continuing obligation and not terminable by us, except that if Atlas Pipeline’s general partner is removed without cause, then no gathering fees will be due under the agreement with respect to new wells drilled by us. Atlas America assumed our obligation to pay these gathering fees pursuant to the contribution agreement, and we agreed to pay Atlas America the gathering fees we receive from our investment partnerships and fees associated with production to our interest. The gathering fees payable to Atlas Pipeline generally exceed the amount we receive from our investment partnerships for gathering services. For the year ended December 31, 2006, this excess amount was approximately $30.3 million. If Atlas America defaulted on its obligation to us under the assumption agreement to pay gathering fees to Atlas Pipeline, we would be liable to Atlas Pipeline for the payment of the fees, which would reduce our income and cash available for distributions to unitholders.

Shortages of drilling rigs, equipment and crews could delay our operations and reduce our cash available for distribution. Higher natural gas and oil prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Over the past three years, we and other oil and natural gas companies have experienced higher drilling and operating costs. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash available for distribution.

Because we handle natural gas and oil, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment. The operations of our wells and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:

·   the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;

·   the federal Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

·   the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling and disposal of waste from our facilities; and

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·   the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business and the substances we handle. For example, an accidental release from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies may be enacted or adopted and could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover remediation costs under our insurance policies. Please read “Business — Environmental Matters and Regulation.”

Many of our leases are in areas that have been partially depleted or drained by offset wells. Our key project areas are located in active drilling areas in the Appalachian Basin. As a result, many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of natural gas in these areas.

Our identified drilling location inventories are susceptible to uncertainties that could materially alter the occurrence or timing of our drilling activities, which may result in lower cash from operations and, therefore, may impact our ability to pay distributions. Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of December 31, 2006, we had identified approximately 500 proved undeveloped drilling locations and approximately 2,600 additional potential drilling locations. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, natural gas prices, costs and drilling results. In addition, Wright and Company, Inc. has not assigned any proved reserves to the over 2,600 unproved potential drilling locations we have identified and therefore there may exist greater uncertainty with respect to the success of drilling wells at these drilling locations. Our final determination on whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or if we will be able to produce natural gas and oil from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from our anticipated drilling activities. Our forecast of estimated cash available for distribution to our unitholders is based on an assumption that we will drill 888 gross wells on behalf of investment partnerships during the year ending December 31, 2007, which number of wells exceeds the total number of currently identified proved undeveloped well locations. In the event that we are unable to continue to identify drilling locations that we believe will provide us attractive development opportunities in sufficient quantities to support our growth plans, we may be required to reduce the amount of funds raised through our investment partnerships, which in turn would result in a reduction in the fee-based revenue that we would otherwise realize and therefore would negatively impact our ability to make cash distributions to our unitholders at the initial quarterly distribution rate.

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Some of our undeveloped leasehold acreage is subject to leases that may expire in the near future. Leases covering approximately 9,000 of our 547,700 net acres, or 2%, are scheduled to expire on or before December 31, 2007. If we are unable to renew these leases, or any leases scheduled for expiration beyond December 31, 2007, on favorable terms, we will lose the right to develop the acreage that is covered by an expired lease and our production would decline, which would reduce our cash flows from operations and could impair our ability to make distributions.

Drilling for and producing natural gas are high risk activities with many uncertainties. Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. Additionally, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

·   the high cost, shortages or delivery delays of equipment and services;

·   unexpected operational events and drilling conditions;

·   adverse weather conditions;

·   facility or equipment malfunctions;

·   title problems;

·   pipeline ruptures or spills;

·   compliance with environmental and other governmental requirements;

·   unusual or unexpected geological formations;

·   formations with abnormal pressures;

·   injury or loss of life;

·   environmental accidents such as gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment or oil leaks, including groundwater contamination;

·   fires, blowouts, craterings and explosions; and

·   uncontrollable flows of natural gas or well fluids.

Any one or more of the factors discussed above could reduce or delay our receipt of drilling and production revenues, thereby reducing our earnings, and could reduce revenues in one or more of our investment partnerships, which may make it more difficult to finance our drilling operations through sponsorship of future partnerships. In addition, any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.

Although we maintain insurance against various losses and liabilities arising from our operations, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could reduce our results of operations and impair our ability to make distributions to our unitholders.

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Properties that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities. One of our growth strategies is to capitalize on opportunistic acquisitions of natural gas reserves. However, our reviews of acquired properties are inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well we acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we inspect a well. Any unidentified problems could result in material liabilities and costs that negatively impact our financial condition and results of operations.

Even if we are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems. Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable and may be limited by floors and caps on such indemnity.

Hedging transactions may limit our potential gains or cause us to lose money. Pricing for natural gas has been volatile and unpredictable for many years. To limit exposure to changing natural gas prices, we use financial and physical hedges for our natural gas production. Physical hedges are not deemed hedges for accounting purposes because they require firm delivery of natural gas and are considered normal sales of natural gas. We generally limit these arrangements to smaller quantities than those projected to be available at any delivery point. Additionally, we may enter into financial hedges, which may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to 36 months in the future.

By removing the price volatility from a significant portion of our natural gas production, we have reduced, but not eliminated, the potential effects of changing natural gas prices on our cash flow from operations for those periods. Furthermore, while intended to help reduce the effects of volatile natural gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if natural gas prices were to rise substantially over the price established by the hedge. Under circumstances in which, among other things, production is substantially less than expected, the counterparties to our futures contracts fail to perform under the contracts or a sudden, unexpected event materially impacts natural gas prices, we may be exposed to the risk of financial loss.

We may be exposed to financial and other liabilities as the managing general partner in investment partnerships. We serve as the managing general partner of 92 investment partnerships and will be the managing general partner of new investment partnerships that we sponsor. As a general partner, we are contingently liable for the obligations of these partnerships to the extent that partnership assets or insurance proceeds are insufficient. We have agreed to indemnify each investor partner in our investment partnerships from any liability that exceeds such partner’s share of the investment partnership’s assets. Furthermore, investor partners in some of our investment partnerships have the right to present their interests for purchase by us, as managing general partner, up to 5% to 10% of the total limited partner interests in any calendar year.

Our revenues may decrease if investors in our investment partnerships do not receive a minimum return. We have agreed to subordinate up to 50% of our share of production revenues to specified returns to the investor partners in our investment partnerships, typically 10% per year for the first five years of distributions. Thus, our revenues from a particular partnership will decrease if it does not achieve the specified minimum return and our ability to make distributions to unitholders may be impaired. We have not subordinated our share of revenues from any of our investment partnerships since March 2005, but did subordinate $91,000 in 2005 and $335,000 in 2004.

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If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

We are subject to comprehensive federal, state, local and other laws and regulations that could increase the cost and alter the manner or feasibility of our doing business. Our operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon natural gas and oil wells. Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Part of the regulatory environment in which we operate includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. Additionally, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could inhibit our ability to develop our properties. Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, reduce our profitability. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry that can spread these additional costs over a greater number of wells and larger operating staff. Please read “Business—Environmental Matters and Regulation” and “Business—Other Regulation of the Natural Gas and Oil Industry” for a description of the laws and regulations that affect us.

Atlas America and its affiliates own a controlling interest in us. Atlas America and its affiliates own approximately 80.0% of our common units and all of our Class A units. Accordingly, Atlas America possesses a controlling vote on all matters submitted to a vote of our unitholders, including election of our board of directors. As long as Atlas America owns a controlling interest in us, it will be able to approve or disapprove matters submitted to members for a vote irrespective of the vote of persons buying common units in this offering. Atlas America will be able to cause a change of control of our company. This concentration of ownership may have the effect of preventing or discouraging transactions involving an actual or a potential change of control of our company, regardless of whether a premium is offered over then-current market prices. Moreover, even if subsequent issuances result in Atlas America holding less than a majority of the common units, it will be able to determine matters requiring class voting so long as it controls the Class A units.

Our limited liability company agreement limits and modifies our directors’ and officers’ fiduciary duties. Our limited liability company agreement contains provisions that modify and limit our directors’ and officers’ fiduciary duties to us and our unitholders. For example, our limited liability company agreement provides that:

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·   our directors and officers will not have any liability to us or our unitholders for decisions made in good faith, which is defined so as to require that they believed the decision was in our best interests; and

·   our directors and officers will not be liable for monetary damages to us or our unitholders for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the directors or officers acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that such conduct was unlawful.

Members of our board of directors and Atlas America and its affiliates, including our manager, may have conflicts of interest with us. Conflicts of interest may arise between us and our unitholders and members of our board of directors and Atlas America and its affiliates, including our manager. These potential conflicts may relate to the divergent interests of these parties. Situations in which the interests of members of our board of directors and Atlas America and its affiliates, may differ from interests of owners of common units include, among others, the following situations:

·   Our limited liability company agreement gives our board of directors broad discretion in establishing cash reserves for the proper conduct of our business, which will affect the amount of cash available for distribution. For example, our board of directors will use its reasonable discretion to establish and maintain cash reserves sufficient to maintain our asset base.

·   Our manager will recommend to our board of directors the timing and extent of our drilling program and related capital expenditures, asset purchases and sales, and financing alternatives and reserve adjustments, all of which will affect the amount of cash that we distribute to our unitholders.

·   In some instances our board of directors may cause us to borrow funds in order to permit us to pay cash distributions to our unitholders, even if the purpose or effect of the borrowing is to make management incentive distributions.

·   Except as provided in our omnibus agreement with Atlas America, members of our board of directors and Atlas America and its affiliates, including our manager, are not prohibited from investing or engaging in other businesses or activities that compete with us.

·   We do not have any employees and rely solely on employees of our manager and its affiliates. Our officers and the officers of our manager who provide services to us are not required to work full time on our affairs. These officers may devote significant time to the affairs of our manager’s affiliates. There may be significant conflicts between us and our affiliates regarding the availability of these officers to manage us.

We are a “controlled company” within the meaning of NYSE rules and, as a result, qualify for, and intend to rely on, exemptions from some of the NYSE listing requirements with respect to independent directors. Because Atlas America controls a majority of our outstanding common units, we are a controlled company within the meaning of NYSE rules which exempt controlled companies from the following corporate governance requirements:

·   the requirement that a majority of the board of directors consist of independent directors;

·   the requirement to have a nominating/corporate governance committee of the board of directors, composed entirely of members who are independent as defined by NYSE rules, that is responsible for identifying individuals qualified to become board members, consistent with criteria approved by the board, selection of board nominees for the next annual meeting of shareholders, development of corporate governance guidelines and oversight of the evaluation of the board and management;

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·   the requirement to have a compensation committee of the board of directors, composed entirely of independent directors, that is responsible for reviewing and approving corporate goals and objectives relevant to chief executive officer compensation, evaluation of the chief executive officer’s performance in light of the goals and objectives, determination and approval of the chief executive officer’s compensation, and making recommendations to the board with respect to compensation of other executive officers and incentive compensation and equity-based plans that are subject to board approval; and

·   the requirement for an annual performance evaluation of the nominating/corporate governance and compensation committees.

For so long as we remain a controlled company, we do not intend to have a majority of independent directors or nominating/corporate governance or compensation committees. Accordingly, you will not have the same protections afforded to shareholders of companies that are subject to all of the NYSE corporate governance requirements.

We may issue additional units without unitholder approval, which would dilute existing ownership interests. We may issue an unlimited number of units of any type, including common units, without the approval of our unitholders. The issuance of additional units or other equity securities may have the following effects:

·   a unitholder’s proportionate ownership interest in us may decrease;

·   the amount of cash distributed on each common unit may decrease;

·   the relative voting strength of each previously outstanding unit may be diminished; and

·   the market price of the common units may decline.

Our limited liability company agreement provides for a limited call right that may require unitholders to sell their common units at an undesirable time or price. If, at any time, any person owns more than 87.5% of the common units then outstanding, such person has the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units then outstanding at a price not less than the then-current market price of the common units. As a result, our unitholders may be required to sell their common units at an undesirable time or price and therefore may receive a lower or no return on their investment. Unitholders may also incur tax liability upon a sale of their units.

Our manager may transfer its interests in us to a third party without common unitholder consent. Our manager may transfer its Class A units and management incentive interests to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our common unitholders. Furthermore, Atlas America is not restricted from transferring its equity interest in our manager.

Atlas America may sell common units in the future, which could reduce the market price of our outstanding units. Atlas America owns 29,352,996 common units. In addition, our manager has the right to convert its Class A units and management incentive interests into common units if we terminate the management agreement, and its Class A units will automatically convert into common units, and it will have the option of converting its management incentive interests, if the common unitholders vote to eliminate the special voting rights of our Class A units. We have agreed to register for sale common units held by Atlas America and its affiliates. These registration rights allow Atlas America, our manager and their affiliates to request registration of their common units and to include any of those units in a registration of other securities by us. If Atlas America and its affiliates were to sell a substantial portion of their units, it could reduce the market price of our outstanding common units.

We depend on our manager and Atlas America, and may not find suitable replacements if the management agreement terminates. We have no employees. Our support personnel are employees of Atlas America. We have no separate facilities and completely rely on our manager and, because our manager has no direct employees, Atlas America. If our management agreement terminates, we may be unable to find a suitable replacement for them.

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Our management agreement was not negotiated at arm’s-length and, as a result, may not be as favorable to us as if it had been negotiated with a third party. Our officers and four of our directors, Edward E. Cohen, Jonathan Z. Cohen, Richard D. Weber and Matthew A. Jones, are officers or directors of our manager, and Messrs. Cohen are directors of Atlas America. As a consequence, our management agreement was not the result of arm’s-length negotiations and its terms may not be as favorable to us as if it had been negotiated with an unaffiliated third party.

Expense reimbursements due to our manager under our management agreement will reduce cash available for distribution to our unitholders. Before making any distribution on our common units, we will reimburse our manager for all expenses that it incurs on our behalf pursuant to the management agreement. These expenses will include all costs incurred on our behalf, including costs for providing corporate staff and support services to us. Our manager will charge on a fully allocated cost basis for services provided to us. This fully allocated cost basis is based on the percentage of time spent by personnel of our manager and its affiliates on our matters and includes the compensation paid by our manager and its affiliates to such persons and their allocated overhead. The allocation of compensation expense for such persons will be determined based on a good faith estimate of the value of each such person’s services performed on our business and affairs, subject to the periodic review and approval of our audit or conflicts committee.

Termination of the management agreement by us is difficult. Termination of our management agreement is difficult: we may terminate the management agreement only upon the affirmative vote of at least two-thirds of our outstanding common units, including units owned by Atlas America and its affiliates. Upon any termination, our manager will have the right to convert its Class A units into common units on a one-for-one basis and convert its management incentive interests into common units based on their fair market value if the successor manager does not purchase them. Atlas America will be able to prevent the removal of our manager so long as it owns at least two-thirds of our common units.

Our manager’s liability is limited under the management agreement, and we have agreed to indemnify our manager against certain liabilities. Our manager will not assume any responsibility under the management agreement other than to render the services called for under it, and will not be responsible for any action of our board of directors in following or declining to follow its advice or recommendations. Our manager, its directors, officers, employees and affiliates will not be liable to us, any subsidiary of ours, our directors or our unitholders for acts performed in good faith and in accordance with the management agreement, except by reason of acts constituting bad faith, willful misconduct, fraud or criminal conduct. We have agreed to indemnify the parties for all damages and claims arising from acts not constituting bad faith, willful misconduct, fraud or criminal conduct and performed in good faith in accordance with and pursuant to the management agreement.

Our limited liability company agreement restricts the voting rights of unitholders owning 20% or more of our common units. Our limited liability company agreement restricts the voting rights of common unitholders by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than Atlas America, our manager, their affiliates or transferees and persons who acquire such units with the prior approval of our board of directors, cannot vote on any matter. Our limited liability company agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting common unitholders’ ability to influence the manner or direction of management.

If the holders of our common units vote to eliminate the special voting rights of the holders of our Class A units, the Class A units will automatically convert into common units on a one-for-one basis and our manager will have the option of converting the management incentive interests into common units at their fair market value, which may be dilutive to you. The holders of our Class A units have the right to vote as a separate class on extraordinary transactions submitted to a unitholder vote such as a merger or sale of all or substantially all of our assets. This right can be eliminated upon a vote of the holders of not less than two-thirds of our outstanding common units. If such elimination is so approved, the Class A units will automatically convert into common units on a one-for-one basis and our manager will have the right to convert its management incentive interests into common units based on their then fair market value, which may be dilutive to you.

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Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution. The anticipated after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed as corporate distributions, and no income, gain, loss, deduction or credit would flow through to you. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, our treatment as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and therefore result in a substantial reduction in the value of our common units.

Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced. Our limited liability company agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the IQD amount and the incentive distribution amounts will be adjusted to reflect the impact of that law on us.

We will be considered to have terminated for tax purposes due to a sale or exchange of 50% or more of our interests within a twelve-month period. We will be considered to have terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A constructive termination results in the closing of our taxable year for all unitholders and in the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, may result in more than 12 months of our taxable income or loss being includable in taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns, and unitholders receiving two Schedule K-1s, for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders.

ITEM 1B: UNRESOLVED STAFF COMMENTS

None

ITEM 2: PROPERTIES

Office Properties

We own a 24,000 square foot office building in Moon Township, Pennsylvania, a 17,000 square foot field office and warehouse facility in Jackson Center, Pennsylvania and an office in Deerfield, Ohio. We lease a 1,400 square foot field office in Ohio under a lease expiring in 2009 and one 4,600 square foot field office in Pennsylvania under a lease expiring in 2009. We also rent 14,100 square feet of office space in Uniontown, Ohio under a lease expiring in August 30, 2008. We also lease other field offices in Ohio and New York on a month-to-month basis.

Productive Wells

The following table sets forth information as of December 31, 2006 regarding productive natural gas and oil wells in which we have a working interest:

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	Number of productive wells
	Gross		(1)	Net		(1)
Oil wells		504			341
Gas wells		6,114			2,927
Total		6,618			3,268

(1)   Includes our interest in wells owned by 92 investment partnerships for which we serve as general partner and various joint ventures. Does not include our royalty or overriding interests in 634 wells.

Production

The following table sets forth the quantities of our natural gas and oil production, average sales prices and average production costs per equivalent unit of production for the periods indicated.

									Average
									production
	Production				Average sales price				cost per
Period	Oil (bbls)		Gas (mcf)		per bbl		per mcf (1)		mcfe (2)
Year ended December 31, 2006		150,628		8,946,376	$	62.30	$	8.83	$	1.41
Three months ended December 31, 2005		39,678		1,975,099	$	56.13	$	11.06	$	1.10
Year ended September 30, 2005		157,904		7,625,695	$	50.91	$	7.26	$	.95
Year ended September 30, 2004		181,021		7,285,281	$	32.85	$	5.84	$	.87

(1)   Average sales price before the effects of financial hedging was $7.90 for the year ended December 31, 2006; we did not have any financial hedging transactions in any of the other periods presented.

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

Developed and Undeveloped Acreage

The following table sets forth information about our developed and undeveloped natural gas and oil acreage as of December 31, 2006. The information in this table includes our interest in acreage owned by our investment partnerships sponsored by us. The table does not include the approximately 212,000 acres in Tennessee covered by our joint venture with Knox Energy because we do not own this acreage.

	Developed acreage				Undeveloped acreage
	Gross		Net		Gross		Net
Arkansas		2,560		403		-		-
Kansas		160		20		-		-
Kentucky		924		462		9,060		4,530
Louisiana		1,819		206		-		-
Mississippi		40		3		-		-
Montana		-		-		2,650		2,650
New York		20,517		15,053		38,172		38,172
North Dakota		639		96		-		-
Ohio		114,226		95,054		37,811		34,287
Oklahoma		4,323		468		-		-
Pennsylvania		107,495		107,495		233,538		233,538
Tennessee		6,400		4,265		4,627		4,627
Texas		4,520		329		-		-
West Virginia		1,078		539		10,806		5,403
Wyoming		-		-		80		80
		264,701		224,393		336,744		323,287

(1)   Developed acres are acres spaced or assigned to productive wells.

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(2)   Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves.

(3)   A gross acre is an acre in which we own an interest. The number of gross acres is the total number of acres in which we own an interest.

(4)   Net acres is the sum of the fractional interests owned in gross acres. For example, a 50% interest in an acre is one gross acre but is 0.50 net acre.

Natural Gas and Oil Leases

The typical natural gas and oil lease agreement provides for the payment of royalties to the mineral owner for all natural gas and oil produced from any well(s) drilled on the leased premises. In the Appalachian Basin this amount is typically 1/8^th (12.5%) resulting in an 87.5% net revenue interest to us for most leases directly acquired by us. In certain instances, this royalty amount may increase to 1/6 ^th (16.66%) when leases are taken from larger landowners or mineral owners such as coal and timber companies.

Because the acquisition of natural gas and oil leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are often held by other natural gas and oil operators. In order to gain the right to drill these leases we may elect to farm-in leases and/or purchase leases from other natural gas and oil operators. Typically the assignor of such leases will reserve an overriding royalty interest, ranging from 1/32 ^nd to 1/16 ^th (3.125% to 6.25%), which further reduces the net revenue interest available to us to between 84.375% and 81.25%.

Sometimes these third party owners of natural gas and oil leases retain the option to participate in the drilling of wells on leases farmed out or assigned to us. Normally the retained interest is a 25% working interest. In this event, our working interest ownership will be reduced by the amount retained by the third party operator. In all other instances we anticipate owning a 100% working interest in newly drilled wells.

In almost all of the areas we operate in the Appalachian Basin, the surface owner is normally the natural gas and oil owner allowing us to deal with a single owner. This simplifies the research process required to identify the proper owners of the natural gas and oil rights and reduces the per acre lease acquisition cost and the time required to successfully acquire the desired leases.

The leases for our developed acreage generally have terms that extend for the life of the wells, while the leases on our undeveloped acreage have terms that vary from less than one year to five years. We paid rentals of approximately $885,000 in the year ended December 31, 2006 to maintain our leases.

We believe that we hold good and indefeasible title to our producing properties, in accordance with standards generally accepted in the natural gas industry, subject to exceptions stated in the opinions of counsel employed by us in the various areas in which we conduct our activities. We do not believe that these exceptions detract substantially from our use of any property. As is customary in the natural gas industry, we conduct only a perfunctory title examination at the time we acquire a property. Before we commence drilling operations, we conduct an extensive title examination and we perform curative work on defects that we deem significant. We have obtained title examinations for substantially all of our managed producing properties. No single property represents a material portion of our holdings.

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Our properties are subject to burdens such as liens incident to operating agreements, taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. We do not believe that any of these burdens will materially interfere with our use of our properties.

Drilling Activity

The following table sets forth information with respect to the number of wells in which we have completed drilling during the periods indicated, regardless of when drilling was initiated.

	Development wells								Exploratory wells
	Productive				Dry				Productive				Dry
	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)
Year ended December 31, 2006		711.0		235.3		4.0		1.4		—		—		—		—
Three months ended December 31, 2005		192.0		64.1		—		—		—		—		—		—
Year ended September 30, 2005		644.0		210.0		18.0		6.3		—		—		—		—
Year ended September 30, 2004		493.0		160.5		11.0		3.8		—		—		1.0		1.0

(1)   Includes the number of physical wells in which we hold any working interest, regardless of our percentage interest.

(2)   Includes (i) our percentage interest in wells in which we have a direct ownership interest and (ii) with respect to wells in which we have an indirect ownership interest through our investment partnerships, our percentage interest in the wells based on our percentage interest in our investment partnerships and not those of the other partners in our investment partnerships.

Natural Gas and Oil Reserves

The following tables summarize information regarding our estimated proved natural gas and oil reserves at September 30, 2004 and 2005, and at December 31, 2005 and December 31, 2006. Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The estimated reserves include reserves attributable to our direct ownership interests in oil and gas properties as well as the reserves attributable to our percentage interests in the oil and gas properties owned by investment partnerships in which we own partnership interests. All of the reserves are located in the United States. We base these estimated proved natural gas and oil reserves and future net revenues of natural gas and oil reserves upon reports prepared by Wright & Company, Inc., energy consultants. In accordance with SEC guidelines, we make the standardized measure and PV-10 estimates of future net cash flows from proved reserves using natural gas and oil sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. We based our estimates of proved reserves upon the following weighted average prices as of the dates indicated:

	At December 31,		At December 31,		At September 30,
	2006		2005		2005		2004
Natural gas (per Mcf)	$	6.33	$	10.84	$	14.75	$	6.91
Oil (per Bbl)	$	57.26	$	57.54	$	63.29	$	46.00

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Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserve reports of other engineers might differ from the reports of our consultants, Wright & Company. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of this estimate. Future prices received from the sale of natural gas and oil may be different from those estimated by Wright & Company in preparing its reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced and the proved undeveloped reserves may not be developed within the periods anticipated. Please read Item 1A: “Risk factors.” You should not construe the estimated PV-10 and standardized measure values as representative of the current or future fair market value of our proved natural gas and oil properties. PV-10 and standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas and oil prices or for the escalation of expenses and capital costs. The meaningfulness of these estimates depends upon the accuracy of the assumptions upon which they were based.

We evaluate natural gas reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas reserves. We deduct operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows. We base the estimates on operating methods and conditions prevailing as of the dates indicated. We cannot assure you that these estimates are accurate predictions of future net cash flows from natural gas and oil reserves or their present value. For additional information concerning our natural gas and oil reserves and estimates of future net revenues, see Note 12 of our Notes to Combined and Consolidated Financial Statements.

	Proved natural
	gas and oil
	reserves for
	Atlas Energy		Proved natural gas and oil reserves for
	Resources at		Atlas America E&P Operations at
	December 31,		December 31,		September 30,
	2006		2005		2005		2004		2003
Natural gas reserves (Mmcf):
Proved developed reserves		107,683		108,674		104,786		95,788		87,760
Proved undeveloped reserves (1)		60,859		49,250		53,241		46,345		45,533
Total proved reserves of natural gas		168,542		157,924		158,027		142,133		133,293
Oil reserves (Mbbl):
Proved developed reserves		2,064		2,122		2,116		2,126		1,825
Proved undeveloped reserves		4		135		143		149		30
Total proved reserves of oil		2,068		2,257		2,259		2,275		1,855
Total proved reserves (Mmcfe)		180,950		171,466		171,581		155,782		144,423
PV-10 estimate of cash flows of proved reserves (in thousands) (2):
Proved developed reserves	$	279,330	$	465,459	$	617,445	$	265,516	$	164,617
Proved undeveloped reserves		4,111		131,678		228,206		54,863		26,802
Total PV-10 estimate (3)	$	283,441	$	597,137	$	845,651	$	320,379	$	191,419
Standardized measure of discounted future cash flows (in thousands) (2) (3)	$	283,441	$	429,272	$	606,697	$	232,998	$	144,351

(1)   Our ownership in these reserves is subject to reduction as we generally contribute leasehold acreage associated with our proved undeveloped reserves to our investment partnerships in exchange for an approximate 30% equity interest in these partnerships which effectively will reduce our ownership interest in these reserves from 100% to 30% as we make these contributions.

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(2)   Amounts shown for September 30, 2003, 2004 and 2005 and December 31, 2005 reflect values for Atlas America E&P Operations, which paid income taxes. Amounts shown for December 31, 2006 reflect values for our reserves. Since we are a limited liability company that allocates our taxable income to our unitholders, no provision for federal or state income taxes has been included in the December 31, 2006 calculation of standardized measure which is, therefore, the same as the PV-10 value. Amounts include physical hedges but not financial hedging transactions.

(3)   The following reconciles the PV-10 value to the standardized measure:

	Proved natural
	gas and oil
	reserves for
	Atlas Energy		Proved natural gas and oil reserves for
	Resources at		Atlas America E&P Operations at
	December 31,		December 31,			September 30,
	2006		2005			2005			2004			2003
PV-10 value	$	283,441	$	597,137		$	845,651		$	320,379		$	191,419
Income tax effect		—		(167,865	)		(238,954	)		(87,381	)		(47,068	)
Standardized measure	$	283,441	$	429,272		$	606,697		$	232,998		$	144,351

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

Projected natural gas and oil volumes for calendar 2007 and the remaining successive years are:

	Calendar		Remaining
	2007		successive years		Total
Natural gas (Mmcf)		10,329		158,213		168,542
Oil (Mbbl)		141		1,927		2,068

ITEM 3: LEGAL PROCEEDINGS

One of our subsidiaries, Resource Energy, LLC, together with Resource America, Inc. (NASDAQ: REXI) is 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 us. The complaint alleges that we are not paying landowners the proper amount of royalty revenues with respect to natural gas produced from the leased properties. The complaint seeks 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 October 2006 we reached a tentative settlement of this lawsuit, the settlement terms are subject to final approval by the court. Pursuant to the tentative settlement terms, we have agreed to pay $300,000, upgrade certain gathering systems and cap certain transportation expenses chargeable to the land owners.

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

ITEM 4: SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not applicable

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PART II

ITEM 5: MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common units are quoted on the New York Stock Exchange (“NYSE”) under the symbol "ATN." The following table sets forth the high and low sale prices, as reported by the NYSE, on a quarterly basis since our initial public offering in December 2006.

	High		Low
Fiscal 2006
Fourth Quarter	$	22.88	$	21.80

As of February 28, 2007, there were 36,674,365 common units outstanding held by three holders of record.

Our Cash Distribution Policy

Our limited liability company agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2006, we distribute all of our available cash to unitholders of record on the applicable record date.

Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter:

·   less the amount of cash reserves established by our board of directors to:

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

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

·   provide funds for distributions (1) to our unitholders for any one or more of the next four quarters or (2) 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 borrowings that are made under our credit facility or another arrangement and used solely for working capital purposes or to pay distributions to unitholders.

On January 24, 2007, we declared an initial quarterly cash distribution for the fourth quarter of 2006 of $0.06 per common unit, which was paid on February 14, 2007 to common unitholders of record as of February 7, 2007. This distribution represents a pro-rated distribution of $0.42 per common unit for the period from December 18, 2006, the date of our initial public offering, through December 31, 2006.

For information concerning common units authorized for issuance under our incentive plan, see Note 10 to our Combined and Consolidated Financial Statements.

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ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected historical combined financial and operating data for our predecessor, Atlas America E & P Operations, as of and for the periods indicated. Atlas America E & P Operations represented the subsidiaries of Atlas America which held its natural gas and oil development and production assets and liabilities, substantially all of which Atlas America transferred to us upon the completion of our initial public offering in December 2006. We derived the historical financial data as of December 31, 2005 and 2006 and for the years ended September 30, 2004 and 2005, the three month transition period ended December 31, 2005 resulting from changing our year end from September 30 to December 31, and the year ended December 31, 2006 from financial statements, which were audited by Grant Thornton LLP, independent registered public accounting firm, and are included in this report. We derived the historical financial data as of September 30, 2002 and 2003 and for the years ended September 30, 2002 and 2003 from Atlas America E & P Operations’ unaudited financial statements, which are not included in this report.

You should read the following financial data in conjunction with “Management’s discussion and analysis of financial condition and results of operations” and our financial statements and related notes appearing elsewhere in this report.

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				Three Months
	Year Ended			Ended			Years Ended
	December 31,			December 31,			September 30,
	2006			2005			2005			2004			2003			2002
	(in thousands)
Income statement data:
Revenues:
Gas and oil production	$	88,449		$	24,086		$	63,499		$	48,526		$	38,639		$	28,916
Partnership management:
Well construction and completion		198,567			42,145			134,338			86,880			52,879			55,736
Administration and oversight		11,762			2,964			9,590			8,396			5,090			4,805
Well services		12,953			2,561			9,552			8,430			7,635			7,585
Gathering (1)		9,251			1,407			4,359			4,191			3,898			3,497
Total revenues		320,982			73,163			221,338			156,423			108,141			100,539
Expenses:
Gas and oil production (1)		13,881			2,441			8,165			7,289			6,770			6,693
Partnership management:
Well construction and completion		172,666			36,648			116,816			75,548			45,982			48,443
Well services		7,337			1,487			5,167			4,398			3,773			3,747
Gathering (1)		—			38			52			53			29			48
Gathering fee - Atlas Pipeline (1)		29,545			7,930			21,929			17,189			14,564			10,756
General and administrative		23,367			5,818			13,202			11,708			10,106			10,616
Compensation reimbursement - affiliate		1,237			163			602			1,050			1,400			1,181
Depreciation, depletion and amortization		22,491			4,916			14,061			12,064			9,938			9,409
Total operating expenses		270,524			59,441			179,994			129,299			92,562			90,893
Operating income		50,458			13,722			41,344			27,124			15,579			9,646
Other income (expenses):
Interest income		966			32			317			250			251			686
Other - net		403			25			(238	)		194			107			865
Total other income		1,369			57			79			444			358			1,551
Net income before cumulative effect of accounting change		51,827			13,779			41,423			27,568			15,937			11,197
Cumulative effect of accounting change (2)		6,355			—			—			—			—			—
Net income	$	58,182		$	13,779		$	41,423		$	27,568		$	15,937		$	11,197
Cash flow data:
Cash provided by operating activities	$	63,788		$	31,783		$	65,444		$	42,523		$	20,365		$	783
Cash used in investing activities		(75,588	)		(17,185	)		(59,050	)		(32,709	)		(22,112	)		(15,943	)
Cash provided by (used in) financing activities		(285	)		74			(320	)		(14,916	)		34			2,289
Capital expenditures		75,635			17,187			59,124			33,252			22,607			16,832
Other financial information (unaudited):
EBITDA	$	74,318		$	18,695		$	55,484		$	39,632		$	25,875		$	20,606
Balance sheet data (at period end):
Total assets	$	415,463		$	315,052		$	270,402		$	198,454		$	178,451		$	161,464
Liabilities associated with drilling contracts		86,765			70,514			60,971			29,375			22,157			4,948
Advances from affiliates		12,502			4,257			13,897			30,008			34,776			75,602
Long-term debt, including current maturities		68			156			81			420			194			160
Total debt		12,570			4,413			13,978			30,428			34,970			75,762
Total equity		212,682			154,519			146,142			109,461			102,031			67,398

(1)   We charge gathering fees to our investment partnership wells that are connected to Atlas Pipeline’s gathering systems. We in turn paid these fees, plus an additional amount to bring the total gathering charge up to, generally, 16% of the gas sales price, to Atlas Pipeline in accordance with our gathering agreements with it. Upon 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. Atlas America E & P Operations also owned several small gathering systems. The expenses associated with these systems are shown as gathering fees on our combined statements of income. We do not own these gathering systems after the completion of our initial public offering.

(2)  The cumulative effect of accounting change results from our adoption of FIN 47 (see Notes 2 and 4)

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EBITDA

We define EBITDA as earnings before interest, taxes, depreciation, depletion and amortization. EBITDA is not a measure of performance calculated in accordance with GAAP. Although not prescribed under GAAP, we believe the presentation of EBITDA is relevant and useful because it helps our investors to understand our operating performance and makes it easier to compare our results with other companies that have different financing and capital structures or tax rates. EBITDA should not be considered in isolation of, or as a substitute for, net income as an indicator of operating performance or cash flows from operating activities as a measure of liquidity. EBITDA, as we calculate it, may not be comparable to EBITDA measures reported by other companies and may be different from the EBITDA calculation under our credit facility. In addition, EBITDA does not represent funds available for discretionary use. The following reconciles our net income before taxes to our EBITDA for the periods indicated:

			Three Months
	Year Ended		Ended		Years Ended
	December 31,		December 31,		September 30,
	2006		2005		2005		2004		2003		2002
	(in thousands)
Net income before cumulative effect of accounting change	$	51,827	$	13,779	$	41,423	$	27,568	$	15,937	$	11,197
Plus interest expense		—		—		—		—		—		—
Plus depreciation, depletion and amortization		22,491		4,916		14,061		12,064		9,938		9,409
EBITDA	$	74,318	$	18,695	$	55,484	$	39,632	$	25,875	$	20,606

ITEM 7: MANAGEMENT’S DICUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The historical financial statements prior to our initial public offering on December 18, 2006 included in this report reflect substantially all the assets, liabilities and operations of various wholly-owned subsidiaries of Atlas America, Inc. which were contributed to us upon the closing of that offering. We refer to these subsidiaries’ assets, liabilities and operations as Atlas America E & P Operations or our predecessor. The following discussion analyzes and includes the financial condition and results of operations of Atlas America E & P Operations before the date of our initial public offering and Atlas Energy Resources after the date of our initial public offering. You should read the following discussion of the financial condition and results of operations in conjunction with the historical combined and consolidated financial statements and notes to combined and consolidated financial statements included elsewhere in this report. Additionally, you should read Item 1A: “Risk Factors” for information regarding some of the risks inherent in our business

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.

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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., a wholly-owned subsidiary of Atlas America. Through our manager, Atlas America personnel are responsible for managing our assets and raising capital.

As of December 31, 2006, our principal assets consisted generally of:

·   Our investment partnership business, which includes equity interests in 92 investment partnerships and a registered broker-dealer which acts as the dealer-manager of our investment partnership offerings;

·   either directly or through our investment partnerhips, interests in 7,252 gross producing gas and oil wells, including overriding royalty interests in 634 gross producing gas and oil wells;

·   approximately 601,400 gross (547,700 net) acres, primarily in the Appalachian Basin, over half of which, or approximately 336,700 gross (323,300 net) acres, are undeveloped; and

·   an interest in a joint venture that gives us the right to drill up to an additional 200 net wells before December 31, 2007 on approximately 212,000 acres in Tennessee.

At December 31, 2006, we had proved reserves of 180.9 Bcfe, including the reserves net to our equity interest in the investment partnerships and our direct interests in producing wells.

For the year ended December 31, 2006, we produced approximately 27.0 Mmcfe/d, which includes our proportionate share of production from our investment partnerships as well as our direct interests in producing wells. This resulted in an average reserve life of approximately 18 years based on our proved reserves at December 31, 2006. As of December 31, 2006, 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.

We fund the drilling of natural gas and oil wells on our acreage by sponsoring and managing tax-advantaged investment partnerships. 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.

We derive substantially all of our revenues from our equity interest in the oil and gas produced by the investment partnerships as well as the fees paid by the partnerships to us for acting as the managing general partner as follows:

·   Gas and oil production. We receive an interest in each investment partnership proportionate to the value of our coinvestment in it and the value of the acreage we contribute to it, typically 27% to 33% of the overall capitalization of a particular partnership. We also receive an incremental interest in each partnership, typically 7%, for which we do not make any additional capital contribution. Consequently, our equity interest in the reserves and production of each partnership is typically between 34% and 40%.

·   Partnership management. As managing general partner of our investment partnerships, we receive the following fees:

·   Well construction and completion. For each well that is drilled by an investment partnership, we receive a 15% mark-up on those costs incurred to drill and complete the well.

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·   Administration and oversight. Each partnership pays us a monthly per well administrative fee of $75 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well. In addition, for each well drilled by an investment partnership, we receive a fixed administration fee of approximately $15,000.

·   Well services. Each partnership pays us a monthly per well operating fee, currently $100 to $457, for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

·   Gathering. Each partnership pays us a gathering fee for gathering services. Historically, this fee was typically insufficient to cover all of the gathering fees due to Atlas Pipeline Partners, L.P., under our master natural gas gathering agreement with it. After the closing, pursuant to the terms of our contribution agreement with Atlas America, our gathering revenues and costs will net to $0. Please read Item 1. “Business - Other Agreements with Atlas America and Its Affiliates - Contribution Agreement.”

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.

Change in Year End

On June 15, 2006, Atlas America’s Board of Directors changed our predecessor’s year-end from September 30 to December 31. The financial results now being reported by us relate to the twelve-month year ended December 31, 2006, and the three-month transitional period ended December 31, 2005. In order to compare the financial information for the year ended December 31, 2006 to a like period, we prepared financial information for the year ended December 31, 2005, which includes the three-month transitional period ended December 31, 2005, and the nine months ended September 30, 2005. Wherever practicable, the following discussion compares the consolidated financial statements for calendar year 2006 with the recast pro forma financial information for the year ended December 31, 2005. For purposes of Management’s Discussion and Analysis of Financial Condition and Results of Operations, we believe that this comparison provides a more meaningful analysis.

Throughout this discussion, data for all periods except for the year ended December 31, 2005 and three months ended December 31, 2004, are derived from our consolidated financial statements, which appear in this report.

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Comparability of Financial Statements

The historical financial statements of Atlas America E & P Operations included in this report may not be comparable to our results of operations following our initial public offering for the following reasons:

·   Historically, pursuant to an agreement with Atlas America, Atlas Pipeline received gathering fees generally equal to 16% of the gas sales price of gas gathered through its system. Each partnership pays us gathering fees generally equal to 10% of the gas sales price. After the closing of our initial public offering, we pay the amount we receive from the partnerships to Atlas America so that our gathering revenues and expenses within our partnership management segment net to $0. Atlas America then remits the full amount due to Atlas Pipeline pursuant to our contribution agreement with it. 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.

·   Atlas America retained a small gathering system, which accounted for the gathering expense in our predecessor’s income statement.

·   Because Atlas America did not previously allocate debt or interest expense to its subsidiaries, our historical results of operations do not include interest expense. We will incur indebtedness after the closing of our offering which will create interest expense.

·   We will incur additional general and administrative expense estimated to be $500,000 per year for costs associated with Schedule K-1 preparation and distribution.

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 December 31, 2006, we owned interests in 7,252 gross wells, principally in the Appalachian Basin, of which we operated 6,155. Over the two years ended September 30, 2005, three months ended December 31, 2005 and year ended December 31, 2006, we have drilled 2,074 gross (682 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 gave us an exclusive right to drill up to 300 net wells before June 30, 2007 on approximately 212,000 acres owned by Knox Energy. This agreement was amended and extended, giving us the right to drill an additional 200 net wells from January 1, 2007 to December 31, 2007 provided that we commence the drilling of a minimum of 75 wells before September 30, 2007. As of December 31, 2006, we had drilled 141 net wells under this agreement. As of December 31, 2006, 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.

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.

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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 December 31, 2006 we had financial hedges and physical hedges in place for approximately 79% of our expected production for the year ending December 31, 2007. Therefore, we have substantially reduced our exposure to commodity price movements with respect to those volumes under these types of contractual arrangements for this period. For additional information regarding our hedging activities, please read Item 7A:—“Quantitative and Qualitative Disclosures about Market Risk.”

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. Historically, our fund-raising cycle has been on a calendar year basis. We raised $218.5 million in the year ended December 31, 2006. During the year ended December 31, 2006 our investment partnerships invested $283.7 million in drilling and completing wells, of which we contributed $65.2 million. During the three months ended December 31, 2005, our investment partnerships invested $68.3 million in drilling and completing wells, of which we contributed $16.1 million. During fiscal 2005, our investment partnerships invested $206.0 million in drilling and completing wells, of which we contributed $57.3 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 general or managing partner. Additionally to provide 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 be also dependent on commodity prices and tax laws associated with natural gas and oil.

GENERAL TRENDS AND OUTLOOK

We expect our business to continue to be affected by the risks described in Item 1A: “Risk Factors” as well as the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

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

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

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, 2006. 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

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

	Years Ended						Three Months Ended						Years Ended
	December 31,						December 31,						September 30,
	2006			2005			2005			2004			2005			2004
Production revenues (in thousands):
Gas (1)	$	79,016		$	64,530		$	21,851		$	12,697		$	55,376		$	42,532
Oil	$	9,384		$	8,324		$	2,227		$	1,942		$	8,039		$	5,947
Production volumes:
Gas (Mcf/d) (1) (2)		24,511			21,190			21,468			20,286			20,892			19,905
Oil (Bbls/d)		413			429			431			447			433			495
Total (Mcfe/d)		26,989			23,764			24,054			22,968			23,490			22,875
Average sales prices:
Gas (per Mcf) (3)	$	8.83		$	8.34		$	11.06		$	6.80		$	7.26		$	5.84
Oil (per Bbl)	$	62.30		$	53.22		$	56.13		$	47.17		$	50.91		$	32.85
Production costs (4):
As a percent of production revenues		16	%		12	%		10	%		12	%		13	%		15	%
Per Mcfe	$	1.41		$	1.02		$	1.10		$	0.83		$	0.95		$	0.87
Depletion per Mcfe	$	2.08		$	1.61		$	2.01		$	1.28		$	1.42		$	1.22

(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 $7.90 for 2006; we did not have any financial hedges in the other periods presented.

(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 and gathering fees.

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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, segment margins and number of net wells drilled during the periods indicated (in thousands):

	Years Ended				Three Months Ended				Years Ended
	December 31,				December 31,				September 30,
	2006		2005		2005		2004		2005		2004
Average construction and completion revenue per well	$	307	$	219	$	225	$	224	$	218	$	193
Average construction and completion cost per well		267		191		196		195		190		168
Average construction and completion segment margin per well	$	40	$	28	$	29	$	29	$	28	$	25
Segment margin	$	25,901	$	19,034	$	5,497	$	3,985	$	17,552	$	11,332
Net wells drilled		647		666		187		136		615		450

Year ended December 31, 2006 compared to year ended December 31, 2005

Gas and Oil Production

Our natural gas revenues were $79.0 million in the year ended December 31, 2006, an increase of $14.5 million (22%) from $64.5 million in the year ended December 31, 2005. The increase was attributable to a 6% increase in the average sales price of natural gas and a 16% increase in production volumes. The $14.5 million increase in natural gas revenues consisted of $3.8 million attributable to increases in natural gas sales prices and $10.7 million attributable to increased production volumes. The increase in our gas production volumes of 3,321 Mcf/d resulted from production associated with new wells drilled for our investment partnerships. We believe that gas volumes will be favorably impacted in 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 $9.4 million in the year ended December 31, 2006, an increase of $1.1 million (13%) from $8.3 million in the year ended December 31, 2005. The increase resulted from a 17% increase in the average sales price of oil, partially offset by a 4% decrease in production volumes. The $1.1 million increase consisted of $1.5 million attributable to increases in sales prices, partially offset by $400,000 attributable to volume decreases, as we drill primarily for natural gas rather than oil.

Our production costs were $13.9 million in the year ended December 31, 2006, an increase of $5.0 million (56%) from $8.9 million in the year ended December 31, 2005. 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 from $0.29 to $0.35 per mcf to 10% of the gas sales price beginning in January 2006.

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Well Construction and Completion

Our well construction and completion segment margin was $25.9 million in the year ended December 31, 2006, an increase of $6.9 million (36%) from $19.0 million in the year ended December 31, 2005. During the year ended December 31, 2006, the increase of $6.9 million was attributable to an increase in the gross profit per well ($7.7 million) partially offset by a decrease in the number of wells drilled ($759,000). Since our drilling contracts are on a “cost plus” basis (typically cost plus 15%), an increase in our average cost per well also results in an increase in our average revenue per well. The increase in our average cost per well in the year ended December 31, 2006 resulted from an increase in the cost of tangible equipment, site preparation and reclamation expenses, as well as increased costs due to drilling to deeper formations.

It should be noted that “Liabilities associated with drilling contracts” on our balance sheet includes $71.6 million of funds raised in our investment programs that have not been applied to the completion of wells as of December 31, 2006 due to the timing of drilling operations, and thus have not been recognized as well construction and completion revenue. We expect to recognize this amount as revenue by March 31, 2007. During the year ended December 31, 2006, we raised $218.5 million. We anticipate raising $270.0 million in fiscal 2007. We anticipate oil and gas prices will continue to favorably impact our fundraising and therefore our drilling revenues in the year ending December 31, 2007.

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 $11.8 million in the year ended December 31, 2006, an increase of $1.4 million (13%) from $10.4 million in the year ended December 31, 2005. This increase resulted from an increase in the number of wells managed for our investment partnerships in the year ended December 31, 2006 as compared to the year ended December 31, 2005.

Well Services

Our well services revenues were $13.0 million in the year ended December 31, 2006, an increase of $3.1 million (31%) from $9.9 million in the year ended December 31, 2005. This increase resulted from an increase in the number of wells operated for our investment partnerships due to additional wells drilled in the year ended December 31, 2006.

Our well services expenses were $7.3 million in year ended December 31, 2006, an increase of $1.8 million (33%) from $5.5 million in the year ended December 31, 2005. 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, generally 10% of the gas sales price. 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 $29.5 million for the year ended December 31, 2006, an increase of $5.0 million (20%) from $24.5 in the year ended December 31, 2005. The increase in the year ended December 31, 2006 is primarily a result of higher natural gas prices and increased volumes of gas transported due to additional volumes associated with wells we drilled in the past twelve months. We also pay our proportional share of gathering fees based on our percentage interest in the well, which are included in gas and oil production expense. Atlas America E & P Operations owned several small gathering systems before our initial public offering; the expenses associated with these are shown as gathering fees on our combined and consolidated statements of income. We do not own these gathering systems after the date of our initial public offering.

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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.

General and Administrative

Our general and administrative expenses were $23.4 million in the year ended December 31, 2006, an increase of $6.6 million (39%) from $16.8 million in the year ended December 31, 2005. These expenses include, among other things, salaries and benefits not allocated to a specific activity, costs of running our corporate office, partnership syndication activities and outside services.

The increase of $6.6 million in the year ended December 31, 2006 is principally attributed to the following:

·   exploration costs increased $2.3 million due to the increase in activities of our land department as we acquire additional acreage and well sites;

·   salaries and wages, including non-cash stock compensation, increased $3.0 million due to the increase in executive salaries and in the number of employees as a result of Atlas America’s spin-off from Resource America;

·   professional, legal and insurance expenses increased $470,000 due to higher audit fees and implementation of Sarbanes-Oxley Section 404 compliance; and

·   directors’ fees increased $770,000 as a result of Atlas America’s spin-off from Resource America.

Net Expense Reimbursement—Affiliate

Our net expense reimbursement—affiliate was $1.2 million in the year ended December 31, 2006, an increase of $648,000 (117%) from $552,000 in the year ended December 31, 2005. This increase resulted from an increase in allocations from Resource America for executive management and administrative services, including rent allocations for our offices in Philadelphia, PA and New York City.

Depletion

Our depletion of oil and gas properties as a percentage of oil and gas revenues was 23% in the year ended December 31, 2006, compared to 19% in the year ended December 31, 2005. Depletion expense per Mcfe was $2.08 in the year ended December 31, 2006, an increase of $0.47 (29%) per Mcfe from $1.61 in the year ended December 31, 2005. Increases in our depletable basis and production volumes caused depletion expense to increase $6.6 million to $20.5 million in the year ended December 31, 2006 compared to $13.9 million in the year ended December 31, 2005. 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 income

Interest income was $966,000 in the year ended December 31, 2006, an increase of $618,000 (178%) compared to $348,000 in the year ended December 31, 2005. The increase is from interest earned from investments on the proceeds received by Atlas America from the initial public offering of Atlas Pipeline Holdings, L.P., which was allocated to us.

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Cumulative effect of accounting change

We adopted FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations”, or FIN 47 as of December 31, 2006 and recognized $6.4 million as the cumulative effect of an accounting change. FIN 47 required us to record our retirement obligation without considering the probability of whether our wells would either be sold or otherwise disposed of without incurring a disposal charge.

Three months ended December 31, 2005 compared to three months ended December 31, 2004

Gas and Oil Production

Our natural gas revenues were $21.9 million in the three months ended December 31, 2005, an increase of $9.2 million (72%) from $12.7 million in the three months ended December 31, 2004. The increase in the three months ended December 31, 2005 was attributable to an increase in the average sales price of natural gas of 63% for the three months ended December 31, 2005 and an increase of 6% in the volume of natural gas produced in the three months ended December 31, 2005. The $9.2 million increase in gas revenues in the three months ended December 31, 2005 as compared to the prior period consisted of $8.0 million attributable to increases in natural gas sales prices, and $1.2 attributable to increased production volumes.

Our oil revenues were $2.2 million in the three months ended December 31, 2005, an increase of $285,000 (15%), from $1.9 million in the three months ended December 31, 2004, primarily due to an increase in the average sales price of oil of 19% for the three months ended December 31, 2005. The $285,000 increase in oil revenues in three months ended December 31, 2005 as compared to the prior year period consisted of $369,000 attributable to increases in sales prices, partially offset by $84,000 attributable to decreased production volumes.

Our production costs were $2.4 million in the three months ended December 31, 2005, an increase of $691,000 (40%) from $1.7 million in the three months ended December 31, 2004. This increase includes an increase in pumping labor and an increase in transportation expenses associated with increased production volumes and natural gas sales prices, as a portion of our wells are charged transportation based on the sales price of the gas transported. The decrease in production costs as a percent of production revenues in the three months ended December 31, 2005 as compared to December 31, 2004 was the result of an increase in our average sales price which more than offset the increase in production costs per mcfe.

Well Construction and Completion

Our well construction and completion segment margin was $5.5 million in the three months ended December 31, 2005, an increase of $1.5 million (38%) from $4.0 million in the three months ended December 31, 2004. The increase of $1.5 million was attributable to an increase in the number of wells drilled during the three months ended December 31, 2005. The slight increase in the revenue and cost per well was a result of increases in the cost of tangible equipment, site preparation and reclamation expenses, as well as increased costs due to drilling to deeper formations.

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 $3.0 million in the three months ended December 31, 2005, an increase of $808,000 (37%) from $2.2 million in the three months ended December 31, 2004. This increase resulted from an increase in the number of wells managed for our investment partnerships in the three months ended December 31, 2005 as compared to the three months ended December 31, 2004.

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Well Services

Our well services revenues were $2.6 million in the three months ended December 31, 2005, an increase of $313,000 (14%) from $2.3 million in the three months ended December 31, 2004. This increase resulted from an increase in the number of wells operated for our investment partnerships due to additional wells drilled in the year ended December 31, 2005.

Our well services expenses were $1.5 million in three months ended December 31, 2005, an increase of $296,000 (25%) from $1.2 million in the three months ended December 31, 2004. 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

Our gathering fee to Atlas Pipeline was $7.9 million for the three months ended December 31, 2005, an increase of $2.6 million (49%) from $5.3 million in the three months ended December 31, 2004. The increase in the three months ended December 31, 2005 was primarily a result of higher natural gas prices and increased volumes of gas transported due to additional volumes associated with wells we drilled in the past twelve months. We also owned several small gathering systems; the expenses associated with these are shown as gathering fees on our combined and consolidated statements of income.

General and Administrative

Our general and administrative expenses were $5.8 million in the three months ended December 31, 2005, an increase of $3.6 million (164%) from $2.2 million in the three months ended December 31, 2004. These expenses include, among other things, salaries and benefits not allocated to a specific activity, costs of running our corporate office, partnership syndication activities and outside services.

The increase of $3.6 million in the three months ended December 31, 2005 is principally attributed to the following:

·   net syndication costs increased $1.1 million due to an increase in expenses related to our increased fund raising in our public and private investment partnerships;

·   professional and legal fees increased $680,000 primarily due to higher audit fees and implementation of Sarbanes-Oxley Section 404 compliance;

·   salaries and wages, including non-cash stock compensation, increased $1.2 million due to an increase in executive salaries and in the number of employees as a result of Atlas America’s spin-off from Resource America; and

·   directors’ fees increased $250,000 as a result of Atlas America’s spin-off from Resource America.

Net Expense Reimbursement—Affiliate

Our net expense reimbursement—affiliate was $163,000 in the three months ended December 31, 2005, a decrease of $50,000 (23%) from $213,000 in the three months ended December 31, 2004. This decrease resulted from a decrease in allocations from Resource America for executive management and administrative services, as we now directly employ many of the individuals previously allocated to us and therefore include their compensation in our general and administrative expenses.

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Depletion

Our depletion of oil and gas properties as a percentage of oil and gas revenues was 18% in the three months ended December 31, 2005 and December 31, 2004. Depletion expense per mcfe was $2.01 in the three months ended December 31, 2005, an increase of $.73 (57%) per mcfe from $1.28 in the three months ended December 31, 2004. Increases in our depletable basis and production volumes caused depletion expense to increase $1.7 million (63%) to $4.4 million in the three months ended December 31, 2005 as compared to $2.7 million in the three months ended December 31, 2004. 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.

Year ended September 30, 2005 compared to year ended September 30, 2004

Gas and Oil Production

Our natural gas revenues were $55.4 million in the year ended September 30, 2005, an increase of $12.9 million (30%) from $42.5 million in the year ended September 30, 2004. The increase was due to a 24% increase in the average sales price of natural gas and a 5% increase in production volumes. The $12.9 million increase in natural gas revenues consisted of $10.4 million attributable to price increases and $2.5 million attributable to volume increases.

Our oil revenues were $8.0 million in the year ended September 30, 2005, an increase of $2.1 million (35%) from $5.9 million in the year ended September 30, 2004. The increase resulted from a 55% increase in the average sales price of oil, partially offset by a 13% decrease in production volumes. The $2.1 million increase in oil revenues consisted of $3.3 million attributable to price increases, partially offset by $1.2 million attributable to volume decreases, as we drill primarily for natural gas rather than oil.

Our production costs were $8.2 million in the year ended September 30, 2005, an increase of $900,000 (12%) from $7.3 million in the year ended September 30, 2004. This increase includes normal operating expenses and coincides with the increased production volumes we realized from the increased number of wells we own. Additionally, there were increases in transportation expense as a result of increased natural gas prices as a portion of our wells are charged transportation based on the sales price of the gas transported. Rates charged to us for transportation vary based upon agreements put in place at the time the wells are drilled; some of these agreements have escalation clauses. Production costs as a percent of revenues decreased from 15% in 2004 to 13% in 2005 as a result of an increase in our average sales price which more than offset the increase in production costs per Mcfe.

Well Construction and Completion

Our well construction and completion segment margin was $17.5 million in the year ended September 30, 2005, an increase of $6.2 million (55%) from $11.3 million in year ended September 30, 2004. During the year ended September 30, 2005, the increase in segment margin was attributable to an increase in the number of wells drilled ($4.7 million) and an increase in the gross profit per well ($1.5 million). The increase in our average cost per well resulted from an increase in the cost of tangible equipment, site preparation and reclamation expenses, as well as increased costs due to drilling into deeper formations.

Administration and Oversight

Our administration and oversight fees were $9.6 million in the year ended September 30, 2005, an increase of $1.2 million (14%) from $8.4 million in the year ended September 30, 2004. This increase resulted from an increase in the number of wells drilled and managed for our investment partnerships in 2005 as compared to the prior year.

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Well Services

Our well services revenues were $9.6 million in the year ended September 30, 2005, an increase of $1.2 million (13%) from $8.4 million in the year ended September 30, 2004. This increase resulted from an increase in the number of wells operated for our investment partnerships due to additional wells drilled in 2005.

Our well services expenses were $5.2 million in the year ended September 30, 2005, an increase of $769,000 (17%) from $4.4 million in the year ended September 30, 2004. This increase resulted from an increase in wages, benefits, and field office expenses associated with an increase in employees due to the increase in number of wells operated for our investment partnerships in 2005 as compared to 2004.

Gathering

Our gathering fee to Atlas Pipeline was $21.9 million in the year ended September 30, 2005, an increase of $4.7 million (27%) from $17.2 million in the year ended September 30, 2004. This increase was primarily a result of higher natural gas prices and increased volumes of gas transported due to an increase in the number of wells drilled. We also pay our proportional share of gathering fees based on our percentage interest in the well, which are included in gas and oil production expense. We also owned several small gathering systems; the expenses associated with these are shown as gathering fees on our combined and consolidated statements of income.

General and Administrative

Our general and administrative expenses were $13.2 million in the year ended September 30, 2005, an increase of $1.5 million (13%) from $11.7 million in the year ended September 30, 2004. These expenses include, among other things, salaries and benefits not allocated to a specific activity, costs of running our corporate office, partnership syndication activities and outside services. The increase of $1.5 million in 2005 as compared to the prior year is attributable principally to increases in insurance and professional fees, including the implementation of Sarbanes-Oxley Section 404 compliance.

Net Expense Reimbursement—Affiliate

Our net expense reimbursement—affiliate was $602,000 in the year ended September 30, 2005, a decrease of $448,000 (43%) from $1.1 million in the year ended September 30, 2004. This decrease resulted from a decrease in allocations from Resource America for executive management and administrative services as we now directly employ many of the individuals previously being allocated to us and therefore include their compensation in our general and administrative expenses.

Depletion

Depletion of oil and gas properties as a percentage of oil and gas revenues was 19% in the year ended September 30, 2005 compared to 21% in the year ended September 30, 2004. Depletion was $1.42 per Mcfe in 2005, an increase of $.20 per Mcfe (16%) from $1.22 per Mcfe in 2004. Increases in our depletable basis and production volumes caused depletion expense to increase $2.0 million to $12.2 million in 2005 compared to $10.2 million in 2004. The variances from period to period are directly attributable to changes in our oil and gas reserve quantities, product prices and changes in the depletable cost basis of our oil and gas properties.

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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 and, in the past, advances from Atlas America. The following table sets forth our sources and uses of cash (in thousands):

				Three Months
	Year Ended			Ended			Years Ended
	December 31,			December 31,			September 30,
	2006			2005			2005			2004
Provided by operations	$	63,788		$	31,783		$	65,444		$	42,523
Used in investing activities		(75,588	)		(17,185	)		(59,050	)		(32,709	)
Provided by (used in) financing activities		(285	)		74			(320	)		(14,916	)
Increase (decrease) in cash and cash equivalents	$	(12,085	)	$	14,672		$	6,074		$	(5,102	)

We had $8.8 million in cash and cash equivalents at December 31, 2006, compared to $20.9 million at December 31, 2005. We had a working capital deficit of $88.0 million at December 31, 2006, a decrease in working capital of $9.5 million from a working capital deficit of $78.5 million at December 31, 2005.

Capital Requirements

During the year ended December 31, 2006, our capital expenditures related primarily to investments in our investment partnerships, in which we invested $73.6 million. For the year ended December 31, 2006, we funded and expect to continue to fund these capital expenditures through cash on hand, from operations and amounts available under our credit facility. In fiscal 2005 and 2004 our capital expenditures related to investments in our investment partnerships totaled $57.9 million and $32.2 million, respectively.

The level of capital expenditures we must devote to our development and production operations depends upon the level of funds raised through our investment partnerships. In the year ended December 31, 2006, we had raised $218.5 million. 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. During the years ended September 30, 2005 and 2004 we raised $148.7 million and $107.7 million, respectively.

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 new credit facility and with the temporary use of funds raised in our investment partnerships in the period before we invest the funds. We estimate investment capital expenditures of $43.4 million during the twelve month period ending December 31, 2007, and no expansion capital expenditures, although that may change if opportunities are available to us in that period. We also 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 the IQD to unitholders through December 31, 2007.

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.

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Credit Facility

Simultaneously with the closing of our initial public offering, we entered into a $250 million senior secured credit facility (-0- outstanding at December 31, 2006) with Wachovia Bank, National Association, as administrative agent, Wachovia Capital Markets LLC, 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 initial borrowing base is $155 million. The borrowing base will be subject to redetermination on March 15, 2007 and on a semi-annual basis thereafter. The credit facility will mature in December 2011. For more information on the terms of our credit facility, please read Item 1: “Business— Credit Facility.”

CASH FLOWS

Year ended December 31, 2006

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 investment partnerships. Netcash provided by operating activities was $63.8 million in the year ended December 31, 2006, substantially as a result of the following:

·   net income before depreciation and amortization was $80.7 million, principally as a result of higher natural gas and oil prices and increased drilling profits; and

·   repayments to affiliates decreased operating cash flows by $16.7 million, principally due to an increase in cash generated by our operations.

Investing activities. Cash used in our investing activities was $75.6 million, primarily as a result of capital expenditures related to wells we drilled.

Financing activities. Cash used by our financing activities was $285,000 in the year ended December 31, 2006, primarily as a result of cash spent on deferred finance costs and repayments of debt.

Three months ended December 31, 2005

Operating activities. Net cash provided by operating activities was $31.8 million in the three months ended December 31, 2005, substantially as a result of the following:

·   net income before depreciation, depletion and amortization was $18.7 million, principally as a result of higher natural gas prices and drilling profits;

·   repayments to affiliates decreased operating cash flows by $11.8 million, principally due to an increase in cash generated by our operations; and

·   changes in operating assets and liabilities increased operating cash flows by $24.5 million, primarily due to an increase in accounts payable and liabilities associated with our drilling contracts of $26.5 million related to an increase in drilling activity.

Investing activities. Cash used by our investing activities was $17.2 million, primarily as a result of capital expenditures related to wells we drilled.

Financing activities. Cash provided by our financing activities was $74,000, as a result of net borrowings.

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Year ended September 30, 2005 compared to year ended September 30, 2004

Operating activities. Net cash provided by operating activities increased $22.9 million in the year ended September 30, 2005 to $65.4 million from $42.5 million in the year ended September 30, 2004, substantially as a result of the following:

·   an increase in net income before depreciation, depletion and amortization of $15.9 million in the year ended September 30, 2005 as compared to the prior fiscal year principally a result of higher natural gas prices and drilling profits;

·   changes in operating assets and liabilities increased operating cash flows by $19.9 million in the year ended September 30, 2005, compared to the year ended September 30, 2004, primarily due to an increase in liabilities associated with our drilling contracts of $23.7 million related to an increase in advance payments received. This increase was partially offset by an increase of $5.3 million in accounts receivable related to increased gas and oil production revenues. Our level of liabilities is dependent in part 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; and

·   an increase in repayments to affiliates decreased operating cash flows by $13.6 million in the year ended September 30, 2005 as compared to the prior year period principally as a result of an increase in cash generated by our operations.

Investing activities. Net cash used in our investing activities increased $26.3 million in the year ended September 30, 2005 to $59.0 million from $32.7 million in the year ended September 30, 2004 primarily from a $25.9 million increase in capital expenditures related to the increase in the number of wells drilled.

Financing activities. Net cash used in our financing activities decreased $14.6 million in the year ended September 30, 2005 to $320,000 from $14.9 million in the year ended September 30, 2004, as a result of proceeds we received of $37.0 million in the year ended September 30, 2004 from Atlas America’s initial public offering of common stock; there were no such offerings in 2005.

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. During the years ended December 31, 2006 and 2005, we received an average of $8.83 and $8.34 per Mcf of natural gas and $62.30 and $53.22 per Bbl of oil, respectively. During the three months ended December 31, 2005 and 2004, we received an average of $11.06 and $6.80 per Mcf of natural gas and $56.13 and $47.17 per Bbl of oil, respectively. During 2005, we received an average of $7.26 per Mcf of natural gas and $50.91 per Bbl of oil as compared to $5.84 per Mcf and $32.85 per Bbl in 2004.

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.

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ENVIRONMENTAL REGULATION

To date, compliance with environmental laws and regulations has not had a material impact on our capital expenditures, earnings or competitive position. For instance, we are evaluating the impact of spill prevention plan requirements on our operations, including pending changes by United Stated Environmental Protection Agency to the federal regulations that require compliance by October 31, 2007. 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. For more information on environmental regulation and our operations, please read Item 1: “Business—Environmental Matters and Regulation.”

DISTRIBUTIONS

Distributions made to Atlas America for the year ended December 31, 2006 were $139.9 million, representing the net proceeds of our initial public offering. Our limited liability company agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date. We intend to make cash distributions to our common units and Class A units at an initial distribution rate of $0.42 per unit per quarter ($1.68 per unit on an annualized basis). As a result of distributing all of our available cash, we expect that we will rely upon external financing sources, including commercial borrowings and other debt and common unit issuances, to fund any acquisitions or expansion capital expenditures.

On January 24, 2007, we declared our initial quarterly cash distribution for the fourth quarter 2006 of $0.06 per common unit, which represents a pro-rated distribution of $0.42 per common unit for the period from December 18, 2006, the date of our initial public offering, through December 31, 2006. The $2.2 million distribution was paid on February 14, 2007 to unit holders of record as of February 7, 2007.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The following table summarizes our contractual obligations at December 31, 2006 (in thousands):

			Payments due by period
			Less Than		2 - 3		4 - 5		After 5
	Total		1 Year		Years		Years		Years
Contractual cash obligations:
Total debt	$	68	$	38	$	30	$	—	$	—
Secured revolving credit facilities		—		—		—		—		—
Operating lease obligations		1,770		649		865		255		1
Capital lease obligations		—		—		—		—		—
Unconditional purchase obligations		—		—		—		—		—
Other long-term obligations		—		—		—		—		—
Total contractual cash obligations	$	1,838	$	687	$	895	$	255	$	1

			Payments due by period
			Less Than		2 - 3		4 - 5		After 5
	Total		1 Year		Years		Years		Years
Other commercial commitments:
Standby letters of credit	$	495	$	495	$	—	$	—	$	—
Guarantees		—		—		—		—		—
Standby replacement commitments		—		—		—		—		—
Other commercial commitments		—		—		—		—		—
Total commercial commitments	$	495	$	495	$	—	$	—	$	—

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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.

We have identified the following policies as critical to our business operations and the understanding of our results of operations.

Accounts Receivable and Allowance for Possible Losses

Through our business segments, we engage in credit extension, monitoring, and collection. In evaluating our allowance for possible losses, we perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by our review of our customer’s credit information. We extend credit on an unsecured basis to many of our energy customers. At December 31, 2006 and 2005, our credit evaluation indicated that we have no need for an allowance for possible losses for our oil and gas receivables.

Reserve Estimates

Our estimates of our proved natural gas and oil reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Any significant variance in these assumptions could materially affect the estimated quantity of our reserves. As a result, our estimates of our proved natural gas and oil reserves are inherently imprecise. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves may vary substantially from our estimates or estimates contained in the reserve reports and may affect our ability to pay amounts due under our credit facilities or cause a reduction in our energy credit facilities. Additionally, our proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas and oil prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control.

Impairment of Oil and Gas Properties

We review our producing oil and gas properties for impairment on an annual basis and whenever events and circumstances indicate a decline in the recoverability of their carrying values. We estimate the expected future cash flows from our oil and gas properties and compare such future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to their fair value in the current period. The factors used to determine fair value include estimates of reserves, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. Because of the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that will require us to record an impairment of our oil and gas properties. Any such impairment may affect or cause a reduction in our credit facilities.

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Dismantlement, Restoration, Reclamation and Abandonment Costs

As described in Note 4 to our combined and consolidated financial statements, we follow SFAS No. 143, “Accounting for Asset Retirement Obligations,” and on December 31, 2006, we adopted FASB Interpretation No. 47 “Accounting for Conditional Asset Retirement Obligations”, which resulted in a cumulative effect adjustment of $6.4 million in the year ended December 31, 2006. Under SFAS No. 143, estimated asset retirement costs are recognized when the asset is placed in service, and are amortized using the units-of-production method. On an annual basis, we review our estimates of the costs of future dismantlement, restoration, reclamation and abandonment of our natural gas and oil-producing properties. We also review our estimates of the salvage value of equipment recoverable upon abandonment. As of December 31, 2006 and 2005, our estimate of salvage values was greater than or equal to our estimate of the costs of future dismantlement, restoration, reclamation and abandonment. A decrease in our salvage value or an increase in dismantlement, restoration, reclamation and abandonment costs from those we have estimated could reduce our gross profit from operations.

Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including the estimated remaining lives of the wells, the estimated cost to plug and abandon the wells in the future, inflation factors, credit adjusted discount rates and changes in the legal regulatory requirements. To the extent future revisions to these assumptions impact the fair value of our existing asset retirement obligation, a corresponding adjustment is made to our oil and gas properties.

Goodwill and Other Long-Lived Assets

Goodwill and other intangibles with an indefinite useful life are no longer amortized, but instead are assessed for impairment annually. We have recorded goodwill of $35.2 million in connection with several acquisitions of assets. In assessing impairment of goodwill, we use estimates and assumptions in estimating the fair value of reporting units. If under these estimates and assumptions we determine that the fair value of a reporting unit has been reduced, the reduction can result in an “impairment” of goodwill. However, future results could differ from the estimates and assumptions we use. Events or circumstances which might lead to an indication of impairment of goodwill would include, but might not be limited to, prolonged decreases in expectations of long-term well servicing and/or drilling activity or rates brought about by prolonged decreases in natural gas or oil prices, changes in government regulation of the natural gas and oil industry or other events which could affect the level of activity of exploration and production companies.

In assessing impairment of long-lived assets other than goodwill, where there has been a change in circumstances indicating that the carrying amount of a long-lived asset may not be recoverable, we have estimated future undiscounted net cash flows from the use of the asset based on actual historical results and expectations about future economic circumstances, including natural gas and oil prices and operating costs. Our estimate of future net cash flows from the use of an asset could change if actual prices and costs differ due to industry conditions or other factors affecting our performance.

Revenue Recognition

We conduct certain activities through, and a portion of our revenues are attributable to, our investment partnerships. These investment partnerships raise capital from investors to drill gas and oil wells. We serve as the managing general partner of the investment partnerships and assume customary rights and obligations for them. As a general partner, we are liable for partnership liabilities and can be liable to limited partners if we breach our responsibilities with respect to the operations of the partnerships. The income from our general partner interest is recorded when the gas and oil are sold by a partnership.

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We contract with the investment partnerships to drill partnership wells. The contracts require that the investment partnerships must pay us the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed in less than 60 days. We classify the difference between the contract payments we have received and the revenue earned as a current liability, included in liabilities associated with drilling contracts.

We recognize gathering revenues at the time the natural gas is delivered to the purchaser.

We recognize well services revenues at the time the services are performed.

We are entitled to receive administration and oversight fees according to the respective partnership agreements. We recognize such fees as income when earned.

We record the income from the working interests and overriding royalties of wells we own an interest in when the gas and oil are delivered.

RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS

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. 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 the provisions of this Statement, and at this time we have not made any decisions in its application to us. We are currently evaluating the impact of the adoption of SFAS 159 on our financial position and results of operations.

In September 2006, the SEC staff issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements”, or SAB 108. SAB 108 was issued to provide consistency in how registrants quantify financial statement misstatements. We initially applied SAB 108 in connection with the preparation of our financial statements for the year ended December 31, 2006. The application of SAB 108 did not have a material effect on our financial position or results of operations.

In September 2006, the Financial Accounting Standards Board, or 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 or results of operations.

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109, (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements and provides guidance on the recognition, de-recognition and measurement of benefits related to an entity’s uncertain tax positions. FIN 48 is effective for us beginning January 1, 2007. We do not expect the adoption of FIN 48 to have a significant impact on our financial position or results of operations.

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ITEM 7A: 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 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 December 31, 2006. Only the potential impacts of hypothetical assumptions are analyzed. The analysis does not consider other possible effects that could impact our business.

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 year ending December 31, 2007, 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 $1.4 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 December 31, 2006, we had financial and physical hedges in place for approximately 79% of our expected production volumes for the twelve months ending December 31, 2007. At December 31, 2006, we had 234 open natural gas futures contracts related to natural gas sales covering 54.9 million MMBtus of natural gas, maturing through December 31, 2010 at an average settlement price of $8.48 per MMBtu. We recognized gains of $7.1 million on settled contracts covering natural gas production for the year ended December 31, 2006. There were no gains or losses recognized during this period for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges. There were no gains or losses recognized on hedging for the three months ended December 31, 2005, or for the years ended September 30, 2005 and 2004.

Of the $47.5 million net unrealized hedge gain, our portion is $21.1 million and $26.4 million has been allocated to our investment partnerships. Of the $21.1 million net gain in accumulated other comprehensive income at December 31, 2006, we will reclassify $12.2 million of gains to our consolidated statements of income over the next twelve month period as these contracts expire, and $8.9 million of gains will be reclassified in later periods if the fair values of the instruments remain at current market values.

As of December 31, 2006, we had the following natural gas volumes hedged:

Fixed Price Swaps

Twelve Month
Period Ending			Average
December 31,	Volumes		Fixed Price		Fair Value Asset
	(MMBtu)		(per MMBtu)		(in thousands) (1)
2007		14,650,000	$	8.60	$	25,935
2008		15,800,000	$	8.91		11,450
2009		15,720,000	$	8.31		7,690
2010		5,400,000	$	7.53		587
					$	45,662

Costless Collars

Twelve Month
Period Ending					Average
December 31,	Option Type		Volumes		Floor and Cap		Fair Value Asset
			(MMBtu)		(per MMBtu)		(in thousands) (1)
2007		Puts purchased		1,800,000	$	7.50 - 8.60	$	1,511
2007		Calls sold		1,800,000	$	7.50 - 8.60		-
2008		Puts purchased		1,560,000	$	7.50 - 9.40		281
2008		Calls sold		1,560,000	$	7.50 - 9.40		-
							$	1,792
Total Net Asset							$	47,454

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

Page 63

ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

Atlas Energy Resources, LLC

We have audited the accompanying combined and consolidated balance sheets of Atlas Energy Resources, LLC (a Delaware limited liability company) as of December 31, 2006 and 2005, and the related combined and consolidated statements of income, comprehensive income, equity, and cash flows for the year ended December 31, 2006, the three month period ended December 31, 2005 and the years ended September 30, 2005 and 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the combined and consolidated financial statements referred to above present fairly, in all material respects, the financial position of Atlas Energy Resources, LLC as of December 31, 2006 and 2005, and the results of its operations and its cash flows the year ended December 31, 2006, the three month period ended December 31, 2005 and the years ended September 30, 2005 and 2004 in conformity with accounting principles generally accepted in the United States of America.

As also discussed in Note 2 to the combined and consolidated financial statements, the Company recorded a cumulative effect adjustment in connection with the adoption of FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.”

/s/ GRANT THORNTON LLP

Cleveland, Ohio

February 28, 2007

Page 64

ATLAS ENERGY RESOURCES, LLC  

COMBINED AND CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,		December 31,
	2006		2005
ASSETS
Current assets:
Cash and cash equivalents	$	8,833	$	20,918
Accounts receivable		31,280		22,092
Unrealized hedge gain		27,618		3,190
Prepaid expenses		3,251		3,318
Total current assets		70,982		49,518
Property and equipment, net		277,814		214,701
Other assets		26,290		9,577
Intangible assets, net		5,211		6,090
Goodwill		35,166		35,166
	$	415,463	$	315,052
LIABILITIES AND COMBINED EQUITY
Current liabilities:
Current portion of long-term debt	$	38	$	88
Accounts payable		37,931		41,160
Liabilities associated with drilling contracts		86,765		70,514
Advances from affiliates		12,502		4,257
Accrued liabilities		21,706		11,991
Total current liabilities		158,942		128,010
Long-term debt		30		68
Partnership hedge payable		13,248		—
Unrealized hedge loss		3,835		13,956
Asset retirement obligations		26,726		18,499
Commitments and contingencies (Note 7)
Owner’s equity/Members’ equity:
Owner’s equity		—		158,183
Common unitholders’ interests		187,769		—
Class A unitholder’s interests		3,825		—
Accumulated other comprehensive income (loss)		21,088		(3,664	)
Total equity		212,682		154,519
	$	415,463	$	315,052

See accompanying notes to combined and consolidated financial statements

Page 65

ATLAS ENERGY RESOURCES, LLC  

COMBINED AND CONSOLIDATED STATEMENTS OF INCOME

(in thousands except per unit data)

			Three Months
	Year Ended		Ended		Years Ended
	December 31,		December 31,		September 30,
	2006		2005		2005			2004
REVENUES
Gas and oil production	$	88,449	$	24,086	$	63,499		$	48,526
Well construction and completion		198,567		42,145		134,338			86,880
Administration and oversight		11,762		2,964		9,590			8,396
Well services		12,953		2,561		9,552			8,430
Gathering		9,251		1,407		4,359			4,191
Total revenues		320,982		73,163		221,338			156,423
COSTS AND EXPENSES
Gas and oil production		13,881		2,441		8,165			7,289
Well construction and completion		172,666		36,648		116,816			75,548
Well services		7,337		1,487		5,167			4,398
Gathering		—		38		52			53
Gathering fee - Atlas Pipeline		29,545		7,930		21,929			17,189
General and administrative		23,367		5,818		13,202			11,708
Net expense reimbursement - affiliate		1,237		163		602			1,050
Depreciation, depletion and amortization		22,491		4,916		14,061			12,064
Total operating expenses		270,524		59,441		179,994			129,299
Operating income		50,458		13,722		41,344			27,124
OTHER INCOME (EXPENSES)
Interest income		966		32		317			250
Other - net		403		25		(238	)		194
Total other income		1,369		57		79			444
Net income before cumulative effect of accounting change		51,827		13,779		41,423			27,568
Cumulative effect of accounting change		6,355		—		—			—
Net income	$	58,182	$	13,779	$	41,423		$	27,568
Allocation of net income attributable to members’ interests/owners:
Portion applicable to owner’s interest (period prior to the initial public offering on December 18, 2006)	$	55,375	$	13,779	$	41,423		$	27,568
Portion applicable to members’ interests (period subsequent to the initial public offering on December 18, 2006)		2,807		—		—			—
Net income	$	58,182	$	13,779	$	41,423		$	27,568
Allocation of net income attributable to members’ interests:
Common units	$	2,751
Class A units		56
	$	2,807
Basic and diluted net income per common unit	$	.08
Weighted average common units outstanding:
Basic		36,627
Diluted		36,638		—		—			—

See accompanying notes to combined and consolidated financial statements

Page 66

ATLAS ENERGY RESOURCES, LLC  

COMBINED AND CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

				Three Months
	Year Ended			Ended			Years Ended
	December 31,			December 31,			September 30,
	2006			2005			2005		2004
Net income before taxes	$	58,182		$	13,779		$	41,423	$	27,568
Other comprehensive income:
Unrealized holding gains (losses) on hedging contracts		31,834			(3,664	)		—		—
Less: reclassification adjustment for gains realized in net income		(7,082	)		—			—		—
		24,752			(3,664	)		—		—
Comprehensive income	$	82,934		$	10,115		$	41,423	$	27,568

See accompanying notes to combined and consolidated financial statements

Page 67

ATLAS ENERGY RESOURCES, LLC  

COMBINED AND CONSOLIDATED STATEMENTS OF EQUITY

(in thousands, except unit data)

																			Total
													Accumulated						Owner’s
													Other			Net			Equity/
	Owner’s			Class A Units				Common Units					Comprehensive			Affiliate			Members’
	Equity			Units		Amount		Units		Amount			Income (Loss)			Investment			Equity
Balance, September 30, 2003	$	102,031			-	$	-		-	$	-		$	-		$	102,031		$	102,031
Net change in affiliate advances		(20,138	)		-		-		-		-			-			(20,138	)		(20,138	)
Net income		27,568			-		-		-		-			-			27,568			27,568
Balance, September 30, 2004		109,461			-		-		-		-			-			109,461			109,461
Net change in affiliate advances		(4,742	)		-		-		-		-			-			(4,742	)		(4,742	)
Net income		41,423			-		-		-		-			-			41,423			41,423
Balance, September 30, 2005		146,142			-		-		-		-			-			146,142			146,142
Net change in affiliate advances		(1,738	)		-		-		-		-			-			(1,738	)		(1,738	)
Other comprehensive income		-			-		-		-		-			(3,664	)		-			(3,664	)
Net income		13,779			-		-		-		-			-			13,779			13,779
Balance, December 31, 2005		158,183			-		-		-		-			(3,664	)		158,183			154,519
Net income attributable to owner prior to IPO on December 18, 2006		55,375			-		-		-		-			-			55,375			55,375
Net assets retained by owner		(25,108	)		-		-		-		-			-			(25,108	)		(25,108	)
Net assets contributed by owner		(188,450	)		748,456		3,769		29,352,996		184,681			-			(188,450	)		-
Issuance of common units in IPO		-			-		-		7,273,750		139,944			-			-			139,944
Distribution to owner		-			-		-		-		(139,944	)		-			-			(139,944	)
Stock option compensation		-			-		-		-		337			-			-			337
Net income attributable to unit holders subsequent to IPO		-			-		56		-		2,751			-			-			2,807
Other comprehensive income		-			-		-		-		-			24,752			-			24,752
Balance, December 31, 2006	$	-			748,456	$	3,825		36,626,746	$	187,769		$	21,088		$	-		$	212,682

See accompanying notes to combined and consolidated financial statements

Page 68

ATLAS ENERGY RESOURCES, LLC  

COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

				Three Months
	Year Ended			Ended			Years Ended
	December 31,			December 31,			September 30,
	2006			2005			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income before taxes	$	58,182		$	13,779		$	41,423		$	27,568
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		22,491			4,916			14,061			12,064
Write down of note receivable		3			—			487			—
Non-cash compensation on long-term incentive plans		337			393			300			64
Gain on asset dispositions		(39	)		(2	)		(52	)		(43	)
Cumulative effect of accounting change		(6,355	)		—			—			—
Advances to affiliates		(16,748	)		(11,813	)		(25,081	)		(11,517	)
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(9,092	)		(4,378	)		(4,942	)		377
Decrease in prepaid expenses		230			149			2,392			2,576
Increase (decrease) in accounts payable		(3,229	)		16,940			4,340			4,460
Increase in liabilities associated with drilling contracts		16,251			9,543			31,596			7,922
Increase (decrease) in other operating assets and liabilities		1,757			2,256			920			(948	)
Net cash provided by operating activities		63,788			31,783			65,444			42,523
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(75,635	)		(17,187	)		(59,124	)		(33,252	)
Proceeds from sale of assets		47			3			111			218
Decrease (increase) in other assets		—			(1	)		(37	)		325
Net cash used in investing activities		(75,588	)		(17,185	)		(59,050	)		(32,709	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings		—			91			—			282
Principal payments on borrowings		(88	)		(17	)		(339	)		(56	)
Issuance of common stock by AAI		—			—			—			36,991
Distributions net of capital contributions to AAI		(139,944	)		—			—			—
Net proceeds from issuance of common units		139,944			—			—			—
Dividend to Resource America, Inc.		—			—			—			(52,133	)
Increase in deferred financing costs		(197	)		—			—			—
Decrease in other assets		—			—			19			—
Net cash provided by (used in) financing activities		(285	)		74			(320	)		(14,916	)
Increase (decrease) in cash and cash equivalents		(12,085	)		14,672			6,074			(5,102	)
Cash and cash equivalents at beginning of period		20,918			6,246			172			5,274
Cash and cash equivalents at end of period	$	8,833		$	20,918		$	6,246		$	172

See accompanying notes to combined and consolidated financial statements

Page 69

ATLAS ENERGY RESOURCES, LLC  

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

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 region of the Appalachian Basin. The Company sponsors and manages tax-advantaged investment partnerships, in which it coinvests to finance the exploitation and development of its acreage (“the Partnerships”).

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 common stock, 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, Atlas America contributed all of the stock of its natural gas and oil development and production subsidiaries and its development and production assets in exchange for 29,352,996 common units and 748,456 Class A units. For periods prior to the completion of the Company’s initial public offering, the combined and consolidated financial statements include the AAI subsidiaries which then held the Company’s assets.

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. Because a direct ownership relationship did not exist among all the various entities comprising the Company, AAI’s net investment in the Company was shown as combined equity in the combined and consolidated financial statements. Transactions between the Company and other AAI operations have been identified in the combined and consolidated financial statements as transactions between affiliates (see Note 5). 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 investment partnerships in which it has an interest. All significant intercompany balances and transactions within the Company have been eliminated.

Change in Year End

On June 15, 2006, AAI’s Board of Directors changed the Company’s year end from September 30 to December 31. The combined and consolidated statements of income, comprehensive income, equity and cash flows reflect audited results for the year ended December 31, 2006, the three-month transition period ended December 31, 2005 and the years ended September 30, 2005 and 2004. The combined and consolidated balance sheets reflect the audited financial position of the Company at December 31, 2006 and 2005.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

Page 70

ATLAS ENERGY RESOURCES, LLC  

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Stock-Based Compensation

The Company applies SFAS No. 123(R), “Share-Based Payment,” as revised (“SFAS No. 123(R)”), to account for its Long-Term Incentive Plan (see Note 10). Generally, the approach to accounting for Statement 123(R) requires all unit-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.

The Company did not have any unit-based payments outstanding prior to the adoption of SFAS No. 123(R), and has only granted restricted units and unit options. The restricted units have no exercise price and, as such, the Company recognized compensation expense based upon 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 of the unit options to calculate compensation expense.

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 common unit holders, which is determined after the deduction of the net income allocable to AAI Class A units, by the Company’s weighted average number of common unit holder units outstanding during the period. The Company’s diluted net income attributable to common unit holders per unit is calculated by dividing the Company’s net income attributable to common unit holders by the sum of the weighted average number of the Company’s common unit holder 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 10). Prior to the closing of the Company’s initial public offering on December 18, 2006, there were no common unit holder units outstanding. As such, the Company’s net income attributable to common unit holders per unit is only presented for the period from December 18, 2006 to December 31, 2006. The cumulative effect adjustment was allocated to the owner’s interest prior to the date of the Company’s initial public offering, as substantially all of the adjustment related to that period. 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):

	Period from
	December 18, 2006 to
	December 31, 2006
Weighted average number of common unit holder units - basic		36,627
Add effect of dilutive unit incentive awards		11
Weighted average number of common unit holder units - diluted		36,638

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.

Page 71

ATLAS ENERGY RESOURCES, LLC 

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Accounts Receivables 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 December 31, 2005 and 2006, the Company’s credit evaluation indicated that it had no need for an allowance for possible losses.

Property and Equipment

Property and equipment is stated at cost. Depreciation, depletion and amortization is 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 and equipment are as follows:

Land, buildings and improvements	10-40 years
Furniture and equipment	3-7 years
Other	3-10 years

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

	December 31,
	2006			2005
Mineral interests:
Proved properties	$	1,290		$	2,308
Unproved properties		1,002			1,002
Wells and related equipment		348,742			273,855
Land, building and improvements		4,169			4,146
Support equipment		5,541			4,173
Other		4,698			4,173
		365,442			289,657
Accumulated depreciation, depletion and amortization:
Oil and gas properties		(83,216	)		(71,059	)
Other		(4,412	)		(3,897	)
		(87,628	)		(74,956	)
	$	277,814		$	214,701

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

Page 72

ATLAS ENERGY RESOURCES, LLC 

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

The Company’s long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. If the carrying value exceeds such cash flows, an impairment loss is recognized for the difference between the estimated fair market value, (as determined by discounted future cash flows) and the carrying value of the assets.

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.

Asset Retirement Obligations

The Company accounts for asset retirement obligations as required under FAS No. 143, “Accounting for Retirement Asset Obligations” (“SFAS 143”). SFAS 143 requires 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.

In March 2005, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”). FIN 47 clarified that the term “conditional asset retirement obligation” as used in FAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset obligation should be recognized if that fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation under FAS No. 143.

Under FASB No.143, the Company had recorded its asset retirement obligation based on a probability factor which considered the Company’s history of selling its wells or otherwise disposing of them without incurring a disposal cost. FIN 47 requires the Company to record its retirement obligation without regard to its prior practice and accrue for obligations for all wells owned by the Company without regard to their probability of being sold or otherwise disposed of without incurring a disposal cost.

Accordingly, the Company adopted FIN 47 as of December 31, 2006 and recognized $6.4 million in 2006 as a cumulative effect of an accounting change. Additionally, the Company’s balance sheet recognized an increase as of December 31, 2006 in its asset retirement obligation of $8.0 million, and a net increase in property and equipment of approximately $14.4 million.

Page 73

ATLAS ENERGY RESOURCES, LLC 

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Had the Company implemented FIN 47 retroactively to October 1, 2002, the following pro forma information summarizes the impact for the periods presented (in thousands):

			Three Months
	Year Ended		Ended		Years Ended
	December 31,		December 31,		September 30,
	2006		2005		2005		2004
Net income as reported	$	51,827	$	13,779	$	41,423	$	27,568
Proforma asset retirement obligation adjustment		1,414		576		1,576		1,338
Proforma net income	$	53,241	$	14,355	$	42,999	$	28,906
Proforma asset retirement obligation at year end	$	26,726	$	26,086	$	25,126	$	11,357

Fair Value of Financial Instruments

The Company used the following assumptions in estimating the fair value of each class of financial instrument for which it is practicable to estimate fair value:

·   For receivables and payables, the carrying amounts approximate fair value because of the short maturity of these instruments.

·   For derivatives the carrying value approximates fair value because the Company marks to market all derivatives.

·   For debt the carrying value approximates fair value because of the substantially short maturity of these instruments.

Derivative Instruments

The Company applies the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and its various amendments (“SFAS 133”). SFAS 133 requires each derivative instrument to be recorded in the balance sheet as either an asset or liability measured at fair value. Changes in a derivative instrument’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. All derivative activity reflected in the combined financial statements prior to the Company’s initial public offering was transacted by AAI with third parties and allocated to the Company. At the date of the initial public offering, all open derivative contracts were assumed by the Company.

Concentration of Credit Risk

Financial instruments, which potentially subject the Company to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Company places its temporary cash investments in high-quality short- term money market instruments and deposits with high-quality financial institutions and brokerage firms. At December 31, 2006 and 2005, the Company had $13.5 million and $27.4 million, respectively in deposits at various banks, of which $13.0 million and $26.7 million, respectively, was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date.

Environmental Matters

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.

Page 74

ATLAS ENERGY RESOURCES, LLC 

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

The Company accounts for environmental contingencies in accordance with SFAS No. 5 “Accounting for Contingencies.” Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities for environmental contingencies are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. The Company maintains insurance which may cover in whole or in part certain types of environmental contingencies. For the year ended December 31, 2006, the three months ended December 31, 2005 and two years ended September 30, 2005, the Company had no environmental contingencies requiring specific disclosure or the recording of a liability.

Revenue Recognition

The Company conducts certain energy activities through, and a portion of its revenues are attributable to, investment partnerships. The Company contracts with the investment partnerships to drill partnership wells. The contracts require that the investment partnerships must pay the Company the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed in less than 60 days. On an uncompleted contract, the Company classifies the difference between the contract payments it has received and the revenue earned as a current liability.

The Company recognizes gathering revenues at the time the natural gas is delivered.

The Company recognizes well services revenues at the time the services are performed.

The Company is entitled to receive administration and oversight fees according to the respective partnership agreements. The Company recognizes such fees as income when services are performed.

The Company records the income from the working interests and overriding royalties of wells in which it owns an interest when the gas and oil are delivered.

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 December 31, 2006 and 2005 of $19.4 million and $19.5 million, respectively, which are included in Accounts Receivable on its Combined and Consolidated Balance Sheets.

Supplemental Cash Flow Information

The Company considers temporary investments with a maturity at the date of acquisition of 90 days or less to be cash equivalents. The Company did not pay cash for income taxes in any period presented. Amounts paid for interest in all periods was not material.

Page 75

ATLAS ENERGY RESOURCES, LLC 

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Income Taxes

The Company is a limited liability company and has elected to be treated as a partnership for federal income tax reporting. As a result, the Company’s income for federal income tax purposes is reportable on the tax returns of the individual unitholders. Accordingly, no recognition has been given to income taxes in the accompanying combined and consolidated financial statements of the Company.

Net income, for financial statement purposes, may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the limited liability company agreement. These different allocations can and usually will result in significantly different tax capital account balances in comparison to the capital accounts on the combined and consolidated financial statements.

The following table reconciles net income before taxes to pro forma federal taxable income for the periods indicated (in thousands, unaudited):

				Three Months
	Year Ended			Ended			Year Ended
	December 31, 2006			December 31, 2005			September 30, 2005
Net income before taxes	$	51,827		$	13,779		$	41,423
Depreciation, depletion and amortization for tax reporting purposes		16,886			(3,206	)		(10,981	)
Deferred revenues		3,964			(130	)		3,061
Accrued expenses		(3,884	)		(255	)		(29	)
Other		490			257			32
Pro forma federal taxable income	$	69,283		$	10,445		$	33,506

The Company’s financial reporting bases of its net assets exceeded the tax bases of its net assets by $122.3 million (unaudited) and $108.3 million (unaudited) at December 31, 2006 and 2005, respectively.

Recently Issued Financial Accounting Standards

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. 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 the provisions of this Statement, 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.

Page 76

ATLAS ENERGY RESOURCES, LLC 

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

In September 2006, the SEC staff issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements”, or SAB 108. SAB 108 was issued to provide consistency in how registrants quantify financial statement misstatements. The Company initially applied SAB 108 in connection with the preparation of its financial statements for the year ended December 31, 2006. The application of SAB 108 did not have a material impact on the Company’s financial position or results of operations.

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109, (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements and provides guidance on the recognition, de-recognition and measurement of benefits related to an entity’s uncertain tax positions. FIN 48 is effective for the Company beginning January 1, 2007. The Company does not expect the adoption of FIN 48 to have a significant impact on its financial position or results of operations.

NOTE 3—OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL

Other Assets

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

	At December 31,		At December 31,
	2006		2005
Long-term hedge receivable from Partnerships	$	2,131	$	9,340
Long-term hedge receivable		23,843		—
Other		316		237
	$	26,290	$	9,577

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 year ended December 31, 2006, three months ended December 31, 2005 and years ended September 30, 2005 and 2004 was $879,000, $220,000, $933,000, and $1.0 million, respectively.

The aggregate estimated annual amortization expense of partnership management and operating contracts for the next five years ending December 31 is as follows: 2007—$819,000; 2008—$778,000; 2009—$742,000; 2010—$710,000 and 2011—$664,000.

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

	At December 31,			At December 31,
	2006			2005
Cost	$	14,343		$	14,343
Accumulated amortization		(9,132	)		(8,253	)
	$	5,211		$	6,090

Page 77

ATLAS ENERGY RESOURCES, LLC 

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Goodwill

The Company applies the provisions of SFAS No. 142 (“SFAS 142”) “Goodwill and Other Intangible Assets,” 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 year ended December 31, 2006. 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 consolidated statements of income in the period in which the impairment is indicated.

NOTE 4—ASSET RETIREMENT OBLIGATIONS

The Company follows SFAS No 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”) and FASB Interpretation No. 47 “Accounting for Conditional Asset Retirement Obligations”, which require the Company to recognize an estimated liability for the plugging and abandonment of its oil and gas wells. Under SFAS 143, the Company must currently recognize a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. SFAS 143 requires the Company to consider estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The increase in asset retirement obligations in 2005 was due to an upward revision in the estimated cost of plugging and abandoning wells.

The Company has no assets legally restricted for purposes of settling asset retirement obligations. Except for the item previously referenced, the Company has determined that there are no other material retirement obligations associated with tangible long-lived assets.

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

				Three Months
	Year Ended			Ended		Years Ended
	December 31,			December 31,		September 30,
	2006			2005		2005			2004
Asset retirement obligations, beginning of period	$	18,499		$	17,651	$	4,889		$	3,131
Cumulative effect of adoption of FIN 47		8,042			—		—			—
Liabilities incurred		1,570			725		770			1,725
Liabilities settled		(194	)		—		(137	)		(58	)
Revision in estimates		(2,411	)		—		11,788			(205	)
Accretion expense		1,220			123		341			296
Asset retirement obligations, end of period	$	26,726		$	18,499	$	17,651		$	4,889

Page 78

ATLAS ENERGY RESOURCES, LLC 

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

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

NOTE 5—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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

Relationship with 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 comprises substantially all of AAI’s operations, other than Atlas Pipeline Partners, L.P. (“Atlas Pipeline”), and therefore the Company bears 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 affiliates on the Company’s Combined and Consolidated Balance Sheets.

A reconciliation of the Company’s Advances from affiliates for the periods indicated is as follows (in thousands):

Balance, October 1, 2003	$	(34,776	)
Transportation expense due to affiliates		(1,687	)
Payment on debt to affiliate		6,000
Net operational settlement		455
Balance, September 30, 2004		(30,008	)
Transportation expense due to affiliate		(401	)
Payment on debt to affiliate		17,000
Net operational settlement		(488	)
Balance, September 30, 2005		(13,897	)
Transportation expense due to affiliate		(720	)
Payment on debt to affiliate		8,000
Net operational settlement		2,360
Balance, December 31, 2005		(4,257	)
Transportation expense due to affiliate		(5,382	)
Payment on debt to affiliate		—
Net operational settlement		(2,863	)
Balance, December 31, 2006	$	(12,502	)

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

Page 79

ATLAS ENERGY RESOURCES, LLC 

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Relationship with Atlas Pipeline. The Company has a master gas gathering agreement with Atlas Pipeline which governs the transportation of substantially all of the natural gas the Company produces from the wells it operates. 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 Combined and 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 10% 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 partnership management segment net to $0.

NOTE 6—DERIVATIVE INSTRUMENTS

From time to time, the Company enters into natural gas futures and option 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 production 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.

A portion of the Company’s future natural gas sales is periodically hedged through the use of swaps and collar contracts. Realized gains and losses on these derivative instruments that are classified as effective hedges are reflected in the contract month being hedged as an adjustment to revenue.

At December 31, 2006, the Company had 234 open natural gas futures contracts related to natural gas sales covering 54.9 million MMBtus of natural gas, maturing through December 31, 2010 at a combined average settlement price of $8.48 per MMBtu. The Company recognized a gain of $7.1 million on settled contracts covering natural gas production for the year ended December 31, 2006. There were no gains or losses recognized during the year ended December 31, 2006 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges. There were no gains or losses recognized on hedging in the years ended September 30, 2004 and 2005 and the three months ended December 31, 2005.

Of the $21.1 million net gain in accumulated other comprehensive income at December 31, 2006, the Company will reclassify $12.2 million of gains to its Combined and Consolidated Statements of Income over the next twelve month period as these contracts expire and $8.9 million of gains will be reclassified in later periods if the fair values of the instruments remain at current market values.

Page 80

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

As of December 31, 2006, the Company had the following natural gas volumes hedged:

Fixed Price Swaps

Twelve Month
Period Ending			Average
December 31	Volumes		Fixed Price		Fair Value Asset
	(MMBtu)		(per MMBtu)		(in thousands) (1)
2007		14,650,000	$	8.60	$	25,935
2008		15,800,000	$	8.91		11,450
2009		15,720,000	$	8.31		7,690
2010		5,400,000	$	7.53		587
					$	45,662

Costless Collars

Twelve Month
Period Ending					Average
December 31	Option Type		Volumes		Floor and Cap		Fair Value Asset
			(MMBtu)		(per MMBtu)		(in thousands) (1)
2007		Puts purchased		1,800,000	$	7.50 - 8.60	$	1,511
2007		Calls sold		1,800,000	$	7.50 - 8.60		-
2008		Puts purchased		1,560,000	$	7.50 - 9.40		281
2008		Calls sold		1,560,000	$	7.50 - 9.40		-
							$	1,792
Total Net Asset							$	47,454

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

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

	December 31, 2006
	Book Value			Fair Value
Assets
Derivative instruments	$	51,461		$	51,461
	$	51,461		$	51,461
Liabilities
Derivative instruments	$	(4,007	)	$	(4,007	)
	$	(4,007	)	$	(4,007	)
	$	47,454		$	47,454

The fair value of the derivatives is included in the Combined and Consolidated Balance Sheets as follows (in thousands):

Unrealized hedge gain - short-term	$	27,618
Other assets - long-term		23,843
Accrued liabilities - short-term		(172	)
Unrealized hedge loss - long-term		(3,835	)
	$	47,454

Page 81

ATLAS ENERGY RESOURCES, LLC 

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Of the $47.5 million net unrealized hedge gain at December 31, 2006, the Company’s retained portion of $21.1 million is included in accumulated other comprehensive income and $26.4 million has been allocated to the Partnerships and included in the Combined and Consolidated Balance Sheets as follows (in thousands):

Unrealized hedge gain - short-term	$	96
Other assets - long-term		2,131
Accrued liabilities - short-term		(15,345	)
Unrealized hedge loss - long-term		(13,248	)
	$	(26,366	)

NOTE 7—COMMITMENTS AND CONTINGENCIES

The Company leases office space and equipment under leases with varying expiration dates through 2014. Rental expense was $670,000, $136,000, $1.2 million and $479,000 for the year ended December 31, 2006, three months ended December 31, 2005, and years ended September 30, 2005 and 2004, respectively. Future minimum rental commitments for the next five annual periods are as follows (in thousands):

2007	$	649
2008		536
2009		329
2010		148
2011		107

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 and certain other benefits. The agreements also provide for severance payments under certain circumstances in which some of these obligations may be allocable to the Company.

One of the Company’s subsidiaries, Resource Energy, LLC, together with Resource America, is 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 us. The complaint alleges that the defendants are not paying landowners the proper amount of royalty revenues with respect to natural gas produced from the leased properties. The complaint seeks 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 October 2006 a tentative settlement of this lawsuit was reached, the terms of which are subject to final approval by the court. Pursuant to the tentative settlement terms, AAI 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 legal action pursuant to the contribution agreement.

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

Page 82

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 8—LONG-TERM DEBT

Upon the closing of its initial public offering in December 2006, the Company entered into a $250 million senior secured credit facility, which is led by Wachovia Bank, N.A. (“Wachovia”). The revolving credit facility has a current borrowing base of $155.0 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 ($495,000 outstanding at December 31, 2006). 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 Wachovia 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 Company is in compliance with these covenants as of December 31, 2006. The facility terminates in December 2011, when all outstanding borrowings must be repaid.

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

	At December 31,			At December 31,
	2006			2005
Loans secured by vehicles and equipment	$	68		$	156
Less current maturities		(38	)		(88	)
Long-term debt	$	30		$	68

Maturities of long-term debt are as follows (in thousands):

Years ended December 31,
2007	$	38
2008		30
	$	68

NOTE 9—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):

Page 83

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

			Three Months
	Year Ended		Ended		Years Ended
	December 31,		December 31,		September 30,
	2006		2005		2005		2004
Gas and oil production
Revenues	$	88,449	$	24,086	$	63,499	$	48,526
Costs and expenses		13,881		2,441		8,165		7,289
Segment profit	$	74,568	$	21,645	$	55,334	$	41,237
Partnership management
Revenues	$	232,533	$	49,077	$	157,839	$	107,897
Costs and expenses		209,548		46,103		143,964		97,188
Segment profit	$	22,985	$	2,974	$	13,875	$	10,709

				Three Months
	Year Ended			Ended			Years Ended
	December 31,			December 31,			September 30,
	2006			2005			2005			2004
Reconciliation of segment profit to net income
Segment profit
Gas and oil production	$	74,568		$	21,645		$	55,334		$	41,237
Partnership management		22,985			2,974			13,875			10,709
Total segment profit		97,553			24,619			69,209			51,946
General and administrative		(23,367	)		(5,818	)		(13,202	)		(11,708	)
Compensation reimbursement - affiliate		(1,237	)		(163	)		(602	)		(1,050	)
Depreciation, depletion and amortization		(22,491	)		(4,916	)		(14,061	)		(12,064	)
Other income - net		1,369			57			79			444
Net income before cumulative effect of accounting change	$	51,827		$	13,779		$	41,423		$	27,568
Capital expenditures
Gas and oil production	$	74,075		$	16,610		$	57,894		$	32,172
Partnership management		1,042			445			747			599
Corporate		518			132			483			481
	$	75,635		$	17,187		$	59,124		$	33,252
Balance sheets
Goodwill
Gas and oil production	$	21,527		$	21,527		$	21,527		$	21,527
Partnership management		13,639			13,639			13,639			13,639
	$	35,166		$	35,166		$	35,166		$	35,166
Total assets
Gas and oil production	$	377,807		$	254,831		$	233,855		$	168,715
Partnership management		26,474			37,050			27,115			28,563
Corporate		11,182			23,171			9,432			1,176
	$	415,463		$	315,052		$	270,402		$	198,454

Page 84

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

For the years ended September 30, 2004 and 2005, gas sales to Hess Corporation (formerly FirstEnergy Solutions Corp.) accounted for 18% and 13%, respectively, of total revenues. No other operating segments had revenues from a single customer which exceeded 10% of total revenues.

NOTE 10 - BENEFIT PLANS

Stock 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 AAI’s compensation committee, which may grant awards of either restricted stock units or unit options for an aggregate of 3,742,000 common units.

Restricted Stock Units. Under the ATN LTIP, 47,619 restricted stock units were awarded in 2006, each unit representing the right to receive one share of the Company’s common units upon vesting. Units will vest 25% per year over a four year service period. The fair value of the grants is based on the price of closing stock price on the grant date, and is being charged to operations over the requisite service periods. Upon termination of service by a grantee, all unvested units are forfeited. The Company recognized $187,000 in compensation expense related to restricted stock units for the year ended December 31, 2006. At December 31, 2006, the Company had approximately $813,000 million of unrecognized compensation expense related to the unvested portion of the restricted stock units.

The following table summarizes the activity of restricted stock units for the year ended December 31, 2006:

					Weighted
			Weighted		Average		Aggregate
			Average		Remaining		Intrinsic
			Grant Date		Contractual		Value
	Units		Fair Value		Term (in years)		(in thousands)
Non-vested shares outstanding at December 31, 2005		-	$	-		-
Granted		47,619	$	21.00		3.3
Vested		-	$	-		-
Forfeited		-	$	-		-
Non-vested shares outstanding at December 31, 2006		47,619	$	21.00		3.3	$	1,080

Stock Options. In December 2006, 373,752 unit options were awarded under the ATN LTIP. Unit option awards expire 10 years from the date of grant, and will vest 25% each year from the date of grant. The Black-Scholes option pricing model was used to estimate the weighted average fair value of $2.14 per unit 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. The Company recognized $150,000 in compensation expense related to options granted for the year ended December 31, 2006. At December 31, 2006, the Company had approximately $650,000 of unrecognized compensation expense related to the unvested portion of the option units.

Page 85

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

The following table sets forth ATN LTIP’s option unit activity for the year ended December 31, 2006:

					Weighted
					Average		Aggregate
			Weighted		Remaining		Intrinsic
			Average		Contractual		Value
	Shares		Exercise Price		Term (in years)		(in thousands)
Outstanding at December 31, 2005		-	$	-		-
Granted		373,752	$	21.00		9.3
Exercised		-	$	-		-
Forfeited or expired		-	$	-		-
Outstanding at December 31, 2006		373,752	$	21.10		9.3	$	624
Options exercisable at December 31, 2006		0
Available for grant		3,320,629

NOTE 11 - DISTRIBUTIONS

On January 24, 2007, the Company declared its initial quarterly cash distribution for the fourth quarter 2006 of $0.06 per common unit, which represents a pro-rated distribution of $0.42 per common unit for the period from December 18, 2006, the date of its initial public offering, through December 31, 2006. The $2.2 million distribution was paid on February 14, 2007 to unit holders of record as of February 7, 2007.

NOTE 12—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Results of operations from oil and gas producing activities for the periods indicated are as follows (in thousands):

				Three Months
	Year Ended			Ended			Years Ended
	December 31,			December 31,			September 30,
	2006			2005			2005			2004
Revenues	$	88,449		$	24,086		$	63,499		$	48,526
Production costs		(13,881	)		(2,441	)		(8,165	)		(7,289	)
Exploration expenses		(3,016	)		(17	)		(904	)		(1,549	)
Depreciation, depletion and amortization		(20,600	)		(4,477	)		(12,288	)		(10,319	)
Results of operations from oil and gas producing activities	$	50,952		$	17,151		$	42,142		$	29,369

Page 86

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to the Company’s oil and gas producing activities at the dates indicated are as follows (in thousands):

	At December 31,			At December 31,
	2006			2005
Mineral interests:
Proved properties	$	1,290		$	2,308
Unproved properties		1,002			1,002
Wells and related equipment		348,691			273,804
Support equipment		5,541			4,173
Uncompleted well equipment and facilities		51			51
		356,575			281,338
Accumulated depreciation, depletion and amortization		(83,216	)		(71,059	)
Net capitalized costs	$	273,359		$	210,279

Costs Incurred in Oil and Gas Producing Activities. The costs incurred by the Company in its oil and gas activities for the periods indicated are as follows (in thousands):

			Three Months
	Year Ended		Ended		Years Ended
	December 31,		December 31,		September 30,
	2006		2005		2005		2004
Property acquisition costs:
Proved properties	$	1,322	$	—	$	308	$	1,700
Unproved properties		—		—		—		439
Exploration costs		6,847		1,312		904		1,549
Development costs		76,687		17,380		72,308		39,978
	$	84,856	$	18,692	$	73,520	$	43,666

The development costs above were substantially all incurred for the development of proved undeveloped properties.

Oil and Gas Reserve Information.  The estimates of the Company’s proved and unproved gas and oil reserves are based upon evaluations made by management and verified by Wright & Company, Inc., an independent petroleum engineering firm, as of September 30, 2004 and 2005 and as of December 31, 2005 and 2006. All reserves are located within the United States. Reserves are estimated in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board which require that reserve estimates be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

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ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Proved oil and gas reserves are the estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

·   Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

·   Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

·   Estimates of proved reserves do not include the following: (a) oil that may become available from known reservoirs but is classified separately as “indicated additional reservoirs”; (b) crude oil and natural gas, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (c) crude oil and natural gas, that may occur in undrilled prospects; and natural gas, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operation methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. Additionally, the standardized measure of discounted future net cash flows may not represent the fair market value of the Company’s oil and gas reserves or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors for effects have not been proved.

Page 88

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

The Company’s reconciliation of changes in proved reserve quantities is as follows:

	Gas			Oil
	(Mcf)			(Bbls)
Balance September 30, 2003		133,292,755			1,854,674
Current additions		28,761,902			245,509
Sales of reserves in-place		(3,439	)		(1,669	)
Purchase of reserves in-place		232,429			4,000
Transfers to limited partnerships		(10,132,616	)		(29,394	)
Revisions		(2,732,385	)		382,613
Production		(7,285,281	)		(181,021	)
Balance September 30, 2004		142,133,365			2,274,712
Current additions		33,364,097			95,552
Sales of reserves in-place		(226,237	)		(1,010	)
Purchase of reserves in-place		116,934			575
Transfers to limited partnerships		(7,104,731	)		(148,899	)
Revisions		(2,631,044	)		196,263
Production		(7,625,695	)		(157,904	)
Balance September 30, 2005		158,026,689			2,259,289
Current additions		8,357,940			36,931
Sales of reserves in-place		(59,873	)		-
Purchase of reserves in-place		6,132			16
Transfers to limited partnerships		(4,740,605	)		-
Revisions		(1,690,863	)		653
Production		(1,975,070	)		(39,678	)
Balance December 31, 2005		157,924,350			2,257,211
Current additions		46,205,382			12,920
Sales of reserves in-place		(127,472	)		(703	)
Purchase of reserves in-place		305,433			1,675
Transfers to limited partnerships		(6,671,754	)		(19,235	)
Revisions		(20,147,989	)		(33,594	)
Production		(8,946,376	)		(150,628	)
Balance December 31, 2006		168,541,574			2,067,646
Proved developed reserves at:
September 30, 2003		87,760,113			1,825,280
September 30, 2004		95,788,656			2,125,813
September 30, 2005		104,786,047			2,116,412
December 31, 2005		108,674,675			2,122,568
December 31, 2006		107,683,343			2,064,276

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ATLAS ENERGY RESOURCES, LLC 

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

The following schedule presents the standardized measure of estimated discounted future net cash flows relating to proved oil and gas reserves. The estimated future production is priced at year-end prices, adjusted only for fixed and determinable increases in natural gas and oil prices provided by contractual agreements. The resulting estimated future cash inflows are reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows are reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at September 30, 2004 and 2005 and December 31, 2005 and 2006 and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations. Amounts shown for December 31, 2005, September 30, 2005 and 2004 reflect values for Atlas America E&P Operations, which were subject to Federal and state income taxes. Amounts shown for December 31, 2006 reflect values for the Company. Since it is a limited liability company that allocates taxable income to the individual unit holders, no provisions for Federal or state income taxes have been included in the December 31, 2006 calculation of standardized measure.

				Three Months
	Year Ended			Ended			Years Ended
	December 31,			December 31,			September 30,
	2006			2005			2005			2004
	(in thousands)
Future cash inflows	$	1,262,161		$	1,874,432		$	2,503,644		$	1,096,047
Future production costs		(334,062	)		(290,600	)		(296,015	)		(227,738	)
Future development costs		(149,610	)		(107,784	)		(117,256	)		(92,079	)
Future income tax expense		−			(445,004	)		(607,624	)		(227,862	)
Future net cash flows		778,489			1,031,044			1,482,749			548,368
Less 10% annual discount for estimating timing of cash flows		(495,048	)		(601,772	)		(876,052	)		(315,370	)
Standardized measure of discounted future net cash flows	$	283,441		$	429,272		$	606,697		$	232,998

The future cash flows estimated to be spent to develop proved undeveloped properties in the years ended December 31, 2007, 2008 and 2009 are $48.1 million, $50.8 million and $50.7 million, respectively.

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ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

The following table (in thousands) summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes for the three months ended December 31, 2005 and the years ended September 30, 2005 and 2004. Since the Company allocates taxable income to unitholders, no recognition has been given to income taxes for the year ended December 31, 2006, and the balance at the beginning of the period has been adjusted to exclude income taxes.

				Three Months
	Year Ended			Ended			Years Ended
	December 31,			December 31,			September 30,
	2006			2005			2005			2004
Balance, beginning of period	$	597,137		$	606,697		$	232,998		$	144,351
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs		(74,567	)		(21,645	)		(55,333	)		(41,237	)
Net changes in prices and production costs		(273,631	)		(245,838	)		417,798			97,161
Revisions of previous quantity estimates		(30,058	)		(4,571	)		(6,073	)		6,265
Development costs incurred		3,426			2,727			4,224			4,838
Changes in future development costs		(8,505	)		(1,159	)		(1,577	)		(1,033	)
Transfers to limited partnerships		(8,449	)		(8,563	)		(24,750	)		(9,499	)
Extensions, discoveries, and improved recovery less related costs		44,820			22,597			154,215		��	54,979
Purchases of reserves in place		660			24			596			594
Sales of reserves in place, net of tax effect		(572	)		(243	)		(672	)		(33	)
Accretion of discount		59,714			21,141			32,038			19,142
Net changes in future income taxes		−			71,614			(151,882	)		(40,504	)
Estimated settlement of asset retirement obligations		(8,226	)		(848	)		(12,763	)		(1,757	)
Estimated proceeds on disposals of well equipment		10,007			998			12,740			2,055
Other		(28,315	)		(13,659	)		5,138			(2,324	)
Balance, end of period	$	283,441		$	429,272		$	606,697		$	232,998

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ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 13 - QUARTERLY RESULTS (Unaudited)

	March 31,		June 30		September 30,		December 31,
	(in thousands, except unit data)
Year ended December 31, 2006
Revenues	$	80,320	$	65,036	$	81,556	$	94,070
Income from continuing operations before cumulative effect of accounting change:
Portion applicable to owner’s interest	$	12,509	$	12,559	$	11,466	$	12,486
Portion applicable to common unit holders		—		—		—		2,751
Portion applicable to Class A unit holder		—		—		—		56
Net income before cumulative effect of accounting change	$	12,509	$	12,559	$	11,466	$	15,293
Net income before cumulative effect of accounting change per common unit - basic and diluted	$	—	$	—	$	—	$	0.08
Cumulative effect of accounting change		—		—		—		6,355
Net income	$	12,509	$	12,559	$	11,466	$	21,648

	December 31		March 31		June 30		September 30
	(in thousands)
Year ended September 30, 2005
Revenues	$	50,780	$	60,431	$	49,737	$	60,390
Net income	$	10,388	$	9,519	$	11,191	$	10,325

Page 92

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Management’s Report on Internal Control Over Financial Reporting

As of the end of the period covered by this annual report on Form 10-K, our chief executive officer and chief financial officer conducted an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) of the Securities Exchange Act). Based upon this evaluation, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective in alerting them in a timely manner of any material information relating to us that is required to be disclosed by us in the reports we file or submit under the Securities Exchange Act.

This annual report 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.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

As set forth in our Company Governance Guidelines and in accordance with NYSE listing standards, the non-management members of the board of directors will meet in executive session regularly without management. The director who presides at these meetings will rotate each meeting. The purpose of these executive sessions is to promote open and candid discussion among the non-management directors. Interested parties wishing to communicate directly with the non-management directors may contact the chairman of the audit committee, Walter Jones. Correspondence to Mr. Jones should be marked “Confidential” and sent to Mr. Jones’s attention, c/o Atlas Energy Resources, LLC, 1845 Walnut Street, 10th Floor, Philadelphia, PA 19103.

The independent directors comprise all of the members of both of the board of directors’ committees: the conflicts committee and the audit committee. The conflicts committee has the authority to review specific matters as to which the board believes there may be a conflict of interest to determine if the resolution of the conflict is fair and reasonable to us. Any matters approved by the conflicts committee are conclusively judged to be fair and reasonable to us, approved by all our unitholders and not a breach of obligation to us or to our unitholders. The audit committee reviews the external financial reporting by our management, the audit by our independent public accountants, the procedures for internal auditing and the adequacy of our internal accounting controls.

Page 93

We have entered into a management agreement with our manager, Atlas Energy Management, Inc., pursuant to which it is responsible for managing our day-to-day operations, subject to the supervision and direction of our board of directors. Neither we nor our manager directly employ any of the persons responsible for our operations. Rather, personnel of Atlas America manage and operate our business. Our officers and those of our manager may spend a substantial amount of time managing the business and affairs of Atlas America and its affiliates and may face a conflict regarding the allocation of their time between our business and affairs and their other business interests.

Board of Directors and Executive Officers

Our board of directors is comprised of seven directors, each serving a one year term. There are no family relationships among the directors and executive officers except that Edward E. Cohen, our Chairman and Chief Executive Officer, is the father of Jonathan Z. Cohen, the Vice Chairman of our Board of Directors. The following table sets forth information regarding our executive officers and directors:

Name	Age	Title
Edward E. Cohen	68	Chairman of the Board and Chief Executive Officer
Jonathan Z. Cohen	36	Vice Chairman of the Board
Matthew A. Jones	45	Chief Financial Officer and Director
Richard D. Weber	43	President, Chief Operating Officer and Director
Nancy J. McGurk	51	Chief Accounting Officer
Lisa Washington	39	Chief Legal Officer and Secretary
Walter C. Jones	43	Director
Ellen F. Warren	50	Director
Bruce M. Wolf	58	Director

Edward E. Cohen has been our Chairman of the Board and Chief Executive Officer since our formation in 2006 and Chairman of the Board and Chief Executive Officer of Atlas Energy Management since its formation in 2006. He has been the Chief Executive Officer and President of Atlas America since its formation in September 2000. Mr. Cohen has been Chairman of the managing board of Atlas Pipeline Partners GP, LLC, the general partner of Atlas Pipeline Partners, L.P., since its formation in 1999, and Chairman of the Board and Chief Executive Officer of Atlas Pipeline Holdings GP, LLC, the general partner of Atlas Pipeline Holdings, L.P., since its formation in January 2006. In addition, he has been Chairman of the board of directors of Resource America, Inc. (a publicly-traded specialized asset management company) since 1990 and was its Chief Executive Officer from 1988 until 2004; Chairman of the Board of Resource Capital Corp. (a publicly-traded real estate investment trust) since its formation in September 2005; a director of TRM Corporation (a publicly-traded consumer services company) since 1998; Chairman of the Board of Brandywine Construction & Management, Inc. (a property management company) since 1994. Mr. Cohen is the father of Jonathan Z. Cohen.

Jonathan Z. Cohen has been Vice Chairman of the Board since our formation in 2006 and Vice Chairman of Atlas Energy Management since its formation in 2006. He has been the Vice Chairman of Atlas America since its formation in September 2000. Mr. Cohen has been Vice Chairman of the managing board of Atlas Pipeline Partners GP since its formation in 1999, and Vice Chairman of the Board of Atlas Pipeline Holdings GP since its formation in January 2006. In addition, he has been a senior officer of Resource America since 1998, serving as the Chief Executive Officer since 2004, President since 2003 and a director since 2002, Chief Executive Officer, President and a director of Resource Capital Corp. since its formation in 2005. Mr. Cohen was a trustee and secretary of RAIT Financial Trust (a publicly-traded real estate investment trust) from 1997, and its Vice Chairman from 2003, until December 2006. Mr. Cohen is a son of Edward E. Cohen.

Page 94

Matthew A. Jones has been our Chief Financial Officer and a director since our formation and Chief Financial Officer of Atlas Energy Management since its formation. He has been the Chief Financial Officer of Atlas America and of Atlas Pipeline Partners GP since March 2005. He has been the Chief Financial Officer of Atlas Pipeline Holdings GP since January 2006 and a director since February 2006. From 1996 to 2005, Mr. Jones worked in the Investment Banking group at Friedman Billings Ramsey, which we refer to as FBR, concluding as Managing Director. Mr. Jones worked in FBR’s Energy Investment Banking Group from 1999 to 2005 and in FBR’s Specialty Finance and Real Estate Group from 1996 to 1999. Mr. Jones is a Chartered Financial Analyst.

Richard D. Weber has been our President, Chief Operating Officer and a director since our formation in 2006 and President, Chief Operating Officer and a director of Atlas Energy Management since its formation in 2006. Mr. Weber served from June 1997 until March 2006 as Managing Director and Group Head of the Energy Group of KeyBanc Capital Markets, a division of KeyCorp, and its predecessor, McDonald & Company Securities, Inc. As part of his duties, he oversaw the bank’s activities with oil and gas producers, pipeline companies and utilities.

Nancy J. McGurk has been our Chief Accounting Officer since our formation in 2006 and Chief Accounting Officer of Atlas Energy Management since its formation. She has been the Chief Accounting Officer of Atlas America since January 2001 and Senior Vice President since January 2002. Ms. McGurk was a Vice President of Resource America from 1992 until May 2004, and its Treasurer and Chief Accounting Officer from 1989 until May 2004. Ms. McGurk has been Senior Vice President since January 2002, and Chief Financial Officer and Chief Accounting Officer since January 2001, of Atlas Resources.

Lisa Washington has been our Chief Legal Officer and Secretary since our formation in 2006 and Chief Legal Officer and Secretary of Atlas Energy Management since its formation. Ms. Washington has been the Vice President, Chief Legal Officer and Secretary of Atlas America and Atlas Pipeline Partners GP since November 2005. She has been the Chief Legal Officer and Secretary of Atlas Pipeline Holdings GP since January 2006. From 1999 to November 2005, Ms. Washington was an attorney in the business department of the law firm of Blank Rome LLP.

Independent Directors

Walter C. Jones has been the General Counsel and Senior Director of Private Equity for GRAVITAS Capital Advisors, LLC, an independent investment advisory firm since May 2005. From May 1994 to May 2005, Mr. Jones was at the Overseas Private Investment Corporation, where he served as Manager for Asia, Africa, the Middle East, Latin America and the Caribbean, as well as for seven years a senior officer in the Finance Department.

Ellen F. Warren is founder and President of OutSource Communications, a marketing communications firm that services corporate and nonprofit clients. Prior to founding OutSource Communications in August 2005, she was President of Levy Warren Marketing Media, a public relations and marketing firm she co-founded in March 1998. Before that, she was Vice President of Marketing/Communications for Jefferson Bank, a Philadelphia-based financial institution from September 1992 to February 1998.

Bruce M. Wolf has been President of Homard Holdings, LLC, a wine manufacturer and distributor, since September 2003. Mr. Wolf has been of counsel with Picadio, Sneath, Miller & Norton, P.C., Pittsburgh, PA, since May 2003. Additionally, since June 1999, Mr. Wolf has been a consultant in connection with energy and securities matters, conducting research and providing expert testimony and litigation support. Mr. Wolf was a Senior Vice President of Atlas America from October 1998 to May 1999 and, before that, Secretary and General Counsel of Atlas Energy Group from 1980.

Information Concerning the Audit Committee

Our board of directors has a standing audit committee. All of the members of the audit committee are independent directors as defined by NYSE rules. The members of the audit committee are Messrs. W. Jones and Wolf, and Ms. Warren, with Mr. Jones acting as the chairman. Our Board of Directors has determined that Mr. Jones is an “audit committee financial expert,” as defined by SEC rules. The audit committee reviews the scope and effectiveness of audits by the independent accountants, is responsible for the engagement of independent accountants and reviews the adequacy of our internal controls.

Page 95

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires our officers, directors and persons who own more than ten percent of a registered class of our equity securities to file reports of ownership and changes in ownership with the SEC and to furnish us with copies of all such reports.

Based solely on our review of the reports we have received, written representations from certain reporting persons that no filings were required for those persons, we believe that during 2006, our executive officers, directors and greater than 10% stockholders complied with all applicable filing requirements of Section 16(a) of the Securities Exchange Act, except Messrs. M. Jones, Weber and Wolf and Ms. Washington inadvertently each filed one Form 4 late.

Compensation Committee Interlocks and Insider Participation

We do not have a compensation committee. Compensation of the personnel of Atlas America and its affiliates who provide us with services is set by Atlas America.

Mr. Wolf was a Senior Vice President of Atlas America from October 1998 to May 1999. On December 12, 2006, the Board determined Mr. Wolf to be an independent board member pursuant to NYSE listing standards and Rule 10A-3(b) promulgated under the Securities Exchange Act of 1934. None of the other independent directors is an employee or former employee of ours or of our parent. No executive officer of ours is a director or executive officer of any entity in which an independent director is a director or executive officer.

Page 96

Code of Business Conduct and Ethics, Company Governance Guidelines and Audit Committee Charter

We have adopted a code of business conduct and ethics that applies to the principal executive officer, principal financial officer and principal accounting officer, as well as to persons performing services for us generally. We have also adopted Company Governance Guidelines and a charter for the audit committee. We will make a printed copy of our code of ethics, our Company Governance Guidelines and our audit committee charter available to any unitholder who so requests. Requests for print copies may be directed to us as follows: Atlas Energy Resources, LLC, 311 Rouser Road, Moon Township, Pennsylvania 15108, Attention: Secretary. Each of the code of business conduct and ethics, the Company Governance Guidelines and the audit committee charter are posted on our website at www.atlasenergyresources.com.

ITEM 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

The compensation committee of Atlas America, our parent, is responsible for formulating and presenting recommendations to its Board of Directors and our board with respect to the compensation of our named executive officers. We do not directly compensate our named executive officers. Rather, Atlas America allocates the compensation of the executive officers between activities on behalf of us and activities on behalf of itself and its affiliates based upon an estimate of the time spent by such persons on activities for us and for Atlas America and its affiliates. We reimburse Atlas America for the compensation allocated to us. The compensation committee is also responsible for administering our employee benefit plans, including incentive plans. The compensation committee is comprised solely of independent directors of Atlas America.

Compensation Objectives

We believe that our compensation program must support our strategy, be competitive, and provide both significant rewards for outstanding performance and clear financial consequences for underperformance. We also believe that a significant portion of our named executive officers’ compensation should be “at risk” in the form of annual and long-term incentive awards that are paid, if at all, based on individual and company accomplishment.

The compensation awarded to our named executive officers for fiscal 2006 specifically was intended:

·   to encourage and reward strong performance; and

·   to motivate our named executive officers by providing them with a meaningful equity stake in our company.

Accounting and cost implications of compensation programs are considered in program design; however, the main driver of design is alignment with our business needs.

Overview of Compensation Process

The compensation committee retained Mercer Human Resource Consulting in June 2006 to analyze and review the competitiveness and appropriateness of all elements of the total compensation (base salary and annual and long-term incentives) paid by Atlas America to its executive officers, including our named executive officers, individually and as a group. Mercer was asked to review compensation Atlas America awarded during 2005 and to assist the compensation committee in its analysis of 2006 awards. Mercer and the compensation committee looked not only to the oil and energy industry (adjusted for scope by position) in evaluating Atlas America’s compensation levels but also, as appropriate, to the financial services industry.

The compensation committee focused on Atlas America’s equity performance, market capitalization, corporate developments, business performance and financial position in determining the compensation for those executive officers who provided services to both Atlas America and to us.

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Our chief executive officer provided the compensation committee with statistical data and recommendations to assist it in determining compensation levels. While the compensation committee utilized this information and valued Mr. E. Cohen’s observations with regard to Atlas America’s performance, our performance and the performance of the named executive officers, the compensation committee also considered the analysis, recommendations, and review provided by Mercer. Ultimately the decisions regarding executive compensation were made by the compensation committee after extensive discussion regarding appropriate compensation and were approved by Atlas America’s Board of Directors and our board.

In addition to making decisions regarding compensation for the named executive officers, during 2006, the compensation committee also developed and articulated a compensation philosophy based on Atlas America’s and our business strategy, significant growth, organizational structure, and future objectives. The compensation philosophy includes a frame of reference for compensation comparisons, target positioning, and objectives by pay element.

Additionally, the compensation committee established a formalized process for approving future compensation decisions, including base salary increases and annual and long-term incentive awards.

Elements of our Compensation Program

Base Salary

Base salary is intended to provide fixed compensation to the named executive officers for their performance of core duties that contributed to the success of Atlas America and us as measured by the elements of corporate performance mentioned above. Mercer’s analysis of compensation of executive officers within the energy industry (adjusted for scope by position) confirmed that the base salaries paid to the named executive officers in fiscal 2006 fall between the median and the 75^th percentile of the energy industry. Mercer also referenced financial services data where appropriate.

Salary allocations to us by Atlas America for 2006 reflect the fact that we completed our initial public offering in December 2006.

Annual Incentives

Annual incentives are intended to tie a significant portion of each of the named executive officer’s compensation to Atlas America’s annual performance and, our annual performance and/or to the performance of one of Atlas America’s subsidiaries or divisions for which he or she is responsible. Additionally, the annual incentive allows Atlas America to recognize an individual’s performance in relation to Atlas America’s performance or that of one of its subsidiaries or divisions. Generally, the higher the level of responsibility of the executive within Atlas America, the greater is the incentive component of that executive’s target total cash compensation.

Long-Term Incentives

We believe that our long term success depends upon aligning executives’ and unitholders’ interests. To support this objective, we will provide our executives with the opportunity to become significant shareholders, through our long-term incentive programs. These awards are usually a combination of stock options, restricted units and phantom units which vest over four years to support long-term retention of executives and reinforce our longer-term goals. Our named executive officers who do not work full time for us also are eligible to receive awards under the Atlas America Stock Incentive Plan, which we refer to as the Atlas Plan, the Atlas Pipeline Partners Long-Term Incentive Plan, which we refer to as the APL Plan, and the Atlas Pipeline Holdings Long-Term Incentive Plan, which we refer to as the AHD Plan.

Historically, the date upon which equity awards have been granted has not been fixed. If we do grant equity awards in the future, we shall do so in February of each year.

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Supplemental Benefits, Deferred Compensation and Perquisites

We do not emphasize supplemental benefits for executives, and perquisites are discouraged. None of our named executive officers have deferred any portion of their compensation.

Compensation Determination

In determining compensation amounts awarded, the compensation committee focused on specific contributions by the named executive officers to the overall performance of Atlas America and its subsidiaries, including us during 2006.

The following table sets forth the compensation allocation for fiscal year 2006 for our Chief Executive Officer and Chief Financial Officer, and each of our other most highly compensated executive officers whose allocated total compensation exceeded $100,000. As required by SEC guidance, the table also discloses awards under the Atlas Plan, the APL Plan and the AHD Plan.

2006 Summary Compensation Table

					Stock			Option			All Other
Name and			Salary		Awards			Awards			Compensation			Total
Principal Position	Year		($)		($)			($)			($)			($)
Edward E. Cohen, Chairman of the Board and Chief Executive Officer		2006	$	27,391	$	674,625	(1)	$	84,861	(2)	$	32,300	(3)	$	819,177
Matthew A. Jones, Chief Financial Officer		2006	$	13,696	$	276,546	(1)	$	324,172	(2)	$	7,650	(4)	$	622,064
Richard D. Weber, President and Chief Operating Officer		2006	$	15,217	$	187,504	(5)	$	347,779	(6)	$	—		$	550,500

(1)	Represents the dollar amount of (i) expense recognized by Atlas Pipeline Holdings for financial statement reporting purposes with respect to phantom units granted under the AHD Plan, and (ii) expense recognized by Atlas Pipeline for financial statement reporting purposes with respect to phantom units granted under the APL Plan, all in accordance with FAS 123R.
(2)	Represents the dollar amount of (i) expense recognized for financial statement reporting purposes by Atlas Pipeline Holdings for options granted under the AHD Plan and (ii) for Mr. Jones, also includes expense recognized for financial reporting purposes by Atlas America for options granted under the Atlas Plan, all in accordance with FAS 123R.
(3)	Represents payments on distribution equivalent rights (“DERs”) of $17,000 with respect to the phantom units awarded under the APL Plan and $15,300 with respect to phantom units awarded under the AHD Plan.
(4)	Represents payments on DERs of $4,250 with respect to the phantom units awarded under the APL Plan and $3,400 with respect to phantom units awarded under the AHD Plan.
(5)	Represents the dollar amount of expense we recognized for financial statement reporting purposes with respect to restricted units granted under our Plan (see Note 10 to our combined and consolidated financial statements), in accordance with FAS 123R.
(6)	Represents the dollar amount of (i) expense we recognized for financial statement reporting purposes with respect to options granted under our Plan (see Note 10 to our combined and consolidated financial statements) and (ii) expense recognized by Atlas America for financial statement reporting purposes with respect to options granted under the Atlas Plan, all in accordance with FAS 123R.

As required by SEC guidance, the following table discloses awards under the Atlas Plan, the APL Plan , and the AHD Plan.

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2006 GRANTS OF PLAN-BASED AWARDS TABLE

					All Other			All Other
					Stock Awards:			Option Awards:
					Number of Shares			Number of Securities			Exercise or Base			Grant Date Fair Value of
	Grant		Approval		Of Stock or Units			Underlying Options			Price of Option Awards			Stock and Option Awards
Name	Date		Date		(#)			(#)			($ / unit)
Edward E. Cohen		11/01/06		10/31/06		20,000	(1)		—			—	$	943,800	(1)
		11/10/06		10/31/06		90,000	(2)		500,000	(3)	$	22.56	$	2,030,400	(2)
													$	1,880,000	(3)
Matthew A. Jones		11/01/06		10/31/06		5,000	(1)		—			—	$	235,950	(1)
		11/10/06		10/31/06		20,000	(2)		100,000	(3)	$	22.56	$	451,200	(2)
													$	376,000	(3)
Richard D. Weber		4/17/06		4/03/06		—			50,000	(4)	$	47.86	$	1,055,000	(4)

(1)	Represents grants of phantom units under the APL Plan, which vest 25% per year on the anniversary of the grant, valued in accordance with FAS 123R at the closing price of Atlas Pipeline’s common units on the grant date of $47.19.
(2)	Represents grants of phantom units under the AHD Plan, which vest 25% on the third anniversary and 75% on the fourth anniversary of the grant, valued in accordance with FAS 123R at the closing price of Atlas Pipeline Holdings’ common units on the grant date of $22.56.
(3)	Represents grants of stock options under the AHD Plan, which vest 25% on the third anniversary and 75% on the fourth anniversary of the grant valued at $3.76 per option using the Black-Scholes option pricing model to estimate the weighted average fair value of each unit option granted with weighted average assumptions for (a) expected dividend yield of 4.0%, (b) risk-free interest rate of 4.5%, (c) expected volatility of 20.0%, and (d) an expected life of 6.9 years.
(4)	Represents grants of stock options under the Atlas Plan, in accordance with Mr. Weber’s employment agreement, which vest 25% per year on the anniversary of the commencement of Mr. Weber’s employment on April 17, 2006, except as described below under “—Richard D. Weber Employment Agreement”, valued at $21.10, per share using the Black-Scholes option pricing model to estimate the weighted average fair value of each option granted for 50,000 shares with weighted average assumptions for (a) expected dividend yield of $-0-, (b) risk-free interest rate of 4.8%, (c) expected volatility of 35%, and (d) an expected life of 6.25 years.

Richard D. Weber Employment Agreement

Atlas America entered into an employment agreement in April 2006 with Richard Weber, who serves as President and Chief Operating Officer of us and of our manager, Atlas Energy Management. The agreement has a two year term and, after the first year, the term automatically renews daily so that on any day that the agreement is in effect, the agreement will have a remaining term of one year. Mr. Weber is required to devote substantially all of his working time to Atlas Energy Management and its affiliates. The agreement provides for an annual base salary of not less than $300,000 and a bonus of not less than $700,000 during the first year. After that, bonuses will be awarded solely at the discretion of the compensation committee. The agreement provides for equity compensation as follows:

· Upon execution of the agreement, Mr. Weber was granted options to purchase 50,000 shares of Atlas America stock at $47.86.

· In January 2007, Mr. Weber was granted 47,619 shares of our restricted units with a value of $1,000,000.

· In January 2007, Mr. Weber was granted options to purchase 373,752 of our common units at $21.00.

All of the securities described above vest 25% per year on each anniversary of the date Mr. Weber commenced his employment, April 17, 2006. All securities will vest immediately upon a change of control or termination by Mr. Weber for good reason or by Atlas Energy Management other than for cause. Change of control is defined as:

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· the acquisition of beneficial ownership, as defined in the Securities Exchange Act, of 50% or more of Atlas America’s or our voting securities or all or substantially all of Atlas America’s or our assets by a single person or entity or group of affiliated persons or entities, other than an entity of which either Mr. E. Cohen or Mr. J. Cohen is an officer, manager, director or participant;

· we or Atlas America consummate a merger, consolidation, combination, share exchange, division or other reorganization or transaction with an unaffiliated entity after which Atlas Energy Management is not our manager; or

· our or Atlas America’s shareholders approve a plan of complete liquidation of winding up, or agreement of sale of all or substantially all of our or Atlas America’s assets other than an entity of which either Mr. E. Cohen or Mr. J. Cohen is an officer, manager, director or participant.

The reason for the change of control triggering events relating to the disaffiliation of Messrs. Cohen from our company or Atlas America is that Mr. Weber believed that Messrs. Cohen effectively controlled us at the time of his employment and their separation from us would therefore constitute a change of control. Good reason is defined as a material breach of the agreement, reduction in his base pay, a demotion, a material reduction in his duties or his failure to be elected to our board of directors. Cause is defined as fraud in connection with his employment, conviction of a crime other than a traffic offense, material failure to perform his duties after written demand by Atlas America’s board or breach of the representations made by Mr. Weber in the employment agreement if the breach impacts his ability to fully perform his duties.

Atlas Energy Management may terminate Mr. Weber without cause upon 45 days written notice or for cause upon written notice. Mr. Weber may terminate his employment for good reason or for any other reason upon 30 days’ written notice. Key termination benefits are as follows:

· If Mr. Weber’s employment is terminated due to death, Atlas Energy Management will (a) pay to Mr. Weber’s designated beneficiaries a lump sum cash payment in an amount equal to the bonus that Mr. Weber received from the prior fiscal year pro rated for the time employed during the current fiscal year and (b) Mr. Weber’s family will receive health insurance coverage for one year.

· If Mr. Weber’s employment is terminated by Mr. Weber other than for good reason, all stock and option awards will automatically vest.

· If Atlas Energy Management terminates Mr. Weber’s employment other than for cause, or, Mr. Weber terminates his employment for good reason, (a) Atlas Energy Management will pay amounts and benefits otherwise payable to Mr. Weber as if Mr. Weber remained employed for one year, except that the bonus amount shall be prorated and based on the bonus awarded in the prior fiscal year, and (b) all stock and option awards will automatically vest.

Mr. Weber is entitled to a gross-up payment if any payments made to him would constitute an excess parachute payment under Section 280G of the Code such that the net amount Mr. Weber receives after the deduction of any excise tax, any federal, state and local income tax, and any FICA and Medicare withholding tax is the same amount he would have received had such taxes not been deducted. The agreement includes standard restrictive covenants for a period of two years following termination, including non-compete and non-solicitation provisions.

If a termination event had occurred as of December 31, 2006, we estimate that the value of the benefits to Mr. Weber would have been as follows:

						Accelerated
	Lump Sum					Vesting of Stock
	Severance					Awards and		Tax
Reason for Termination	Payment			Benefits(1)		Option Awards(2)		Gross-up
Death	$	800,000	(3)	$	18,185	$	—	$	—
Disability		—			22,131		—		—
Termination by us without cause (including for disability) or by Mr. Weber for good reason		1,923	(4)		22,131		1,055,000		—
Change of control		—			—		1,055,000		—
Termination by Mr. Weber without cause		—			—		—		—

(1)   Represents rates currently in effect for COBRA insurance benefits for 12 months.

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(2)   Represents the value of unvested and accelerated option awards disclosed in the “Outstanding Equity Awards at Fiscal Year-End Table,” calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of our stock on December 29, 2006.

(3)   Calculated as the sum of Mr. Weber’s 2006 base salary and bonus.

(4)   Represents Mr. Weber’s 2006 bonus.

Our Long-Term Incentive Plan

Our Plan provides performance incentive awards to our officers and directors, and the employees, directors and consultants of our manager and its affiliates, consultants and joint-venture partners who perform services for us. Our Plan is administered by Atlas America’s compensation committee under delegation from our board. The compensation committee may grant awards of common units, restricted units, phantom units, unit options for an aggregate of 3,742,000 common units.

Restricted Units and Phantom Units. A restricted unit is a common unit that is subject to forfeiture prior to the vesting of the award. A phantom unit entitles a participant to receive a common unit upon vesting of the phantom unit or, at the discretion of the compensation committee, cash equivalent to the then fair market value of a common unit. In tandem with phantom unit grants, the compensation committee may grant a DER. The compensation committee determines the vesting period for both restricted units and phantom units.

Unit Options. A unit option entitles a participant to receive a common unit upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of a common unit as determined by the compensation committee on the date of grant of the option. The compensation committee determines the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant.

The vesting of these types of awards mentioned above may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the compensation committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control, as defined in our Plan.

Atlas Plan

The Atlas Plan authorizes the granting of up to 2.0 million shares of Atlas common stock to its employees, affiliates, consultants and directors in the form of incentive stock options, non-qualified stock options, stock appreciation rights (“SARs”), restricted stock and deferred units. SARs represent a right to receive cash in the amount of the difference between the fair market value of a share of Atlas America common stock on the exercise date and the exercise price, and may be free-standing or tied to grants of options. A deferred unit represents the right to receive one share of Atlas common stock upon vesting. Awards under the Atlas Plan generally become exercisable as to 25% each anniversary after the date of grant, except that deferred units awarded to our non-executive board members vest 33 1/3% on the second, third and fourth anniversaries of the grant, and expire not later than ten years after the date of grant. Options and units will vest sooner upon a change in control of Atlas America or death or disability of a grantee, provided the grantee has completed at least six months service from the date of grant.

AHD Plan

The AHD Plan provides performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners who perform services for Atlas Pipeline Holdings. The AHD Plan is administered by Atlas America’s compensation committee under delegation from Atlas Pipeline Holding’s board. The compensation committee may grant awards of either phantom units or unit options for an aggregate of 2.1 million common limited partner units.

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Partnership Phantom Units. A phantom unit entitles a participant to receive a common unit upon vesting of the phantom unit or, at the discretion of the compensation committee, cash equivalent to the then fair market value of a common unit. In tandem with phantom unit grants, the compensation committee may grant a DER. The compensation committee determines the vesting period for phantom units. Through December 31, 2006, phantom units granted under the AHD Plan generally vest 25% three years from the date of grant and 100% four years from the date of grant.

Partnership Unit Options. A unit option entitles a participant to receive a common unit upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of a common unit as determined by the compensation committee on the date of grant of the option. The compensation committee determines the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through December 31, 2006, unit options granted generally will vest 25% three years from the date of grant and 100% four years from the date of grant.

The vesting of both types of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the compensation committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control, as defined in the AHD Plan. This year, the compensation committee approved grants under the AHD Plan conditioned upon the filing of a Registration Statement on Form S-8.

APL Plan

The APL Plan provides incentive awards to officers, employees and non-employee managers of its general partner and officers and employees of its general partner’s affiliates, consultants and joint venture partners who perform services for APL or in furtherance of its business. The APL Plan is administered by the Atlas America compensation committee, under delegation from APL’s general partner’s managing board. Under the APL Plan, the compensation committee may make awards of either phantom units or options covering an aggregate of 435,000 common units.

APL Phantom Units. A phantom unit entitles the participant to receive a common unit upon the vesting of the phantom unit or, at the discretion of the compensation committee, cash equivalent to the value of a common unit. In tandem with phantom unit grants, the compensation committee may grant a DER. The compensation committee determines the vesting period for phantom units. Through December 31, 2006, phantom units granted under the APL Plan generally vested over a 4-year period at the rate of 25% per year.

APL Unit Options. A unit option entitles the participant to purchase APL common units at an exercise price determined by the compensation committee, which may be less than, equal to or more than the fair market value of APL common units on the date of grant. The compensation committee will also have discretion to determine how the exercise price may be paid. No unit options have been granted under the APL Plan.

Each non-employee manager of APL’s general partner is awarded the lesser of 500 phantom units, with DERs, or that number of phantom units, with DERs, equal to $15,000 divided by the then fair market value of a common unit for each year of service on the managing board. Up to 10,000 phantom units may be awarded to non-employee managers. Except for phantom units awarded to non-employee managers of APL’s general partner, the compensation committee will determine the vesting period for phantom units and the exercise period for options. Phantom units awarded to non-employee managers will generally vest over a 4-year period at the rate of 25% per year. Both types of awards will automatically vest upon a change of control, as defined in the APL Plan.

As required by SEC guidelines, the following table discloses awards under our Plan as well as under each of the Atlas Plan, the APL Plan and the AHD Plan.

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OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END TABLE

	Option Awards										Stock Awards
														Market
											Number of			Value of
											Shares or			Shares or
	Number of										Units of			Units of
	Securities Underlying						Option				Stock That			Stock That
	Unexercised Options						Exercise		Option		Have Not			Have Not
	(#)						Price		Expiration		Vested			Vested
Name	Exercisable			Unexercisable			($)		Date		(#)			($)
Edward E. Cohen		450,000	(1)		—		$	25.47		7/1/2015		47,500	(2)	$	2,280,000	(3)
—		—			500,000	(4)	$	22.56		11/10/2016		90,000	(5)	$	2,149,200	(6)
Matthew A. Jones		30,000	(7)		90,000	(8)	$	25.47		7/1/2015		16,250	(9)	$	780,000	(3)
—		—			100,000	(10)	$	22.56		11/10/2016		20,000	(11)	$	472,600	(6)
Richard D. Weber		—			50,000	(12)	$	47.86		4/17/2016		—			—

(1)	Represents options to purchase Atlas America stock, granted on 7/1/05, which vested immediately.
(2)	Represents APL phantom units, which vest as follows: 3/16/07 - 5,000; 6/8/07 - 6,250; 11/1/07 - 5,000; 3/16/08 - 5,000; 6/8/08 - 6,250; 11/1/08 - 5,000; 3/16/09 - 5,000; 11/1/09 - 5,000 and 11/1/10 - 5,000; includes 20,000 units reported in “2006 Grants of Plan-Based Awards Table.”
(3)	Based on closing market price of APL common units on December 29, 2006 of $48.00.
(4)	Represents options to purchase AHD units (all of which are reported in “2006 Grants of Plan-Based Awards Table”), which vest as follows: 11/10/09 - 125,000 and 11/10/10 - 375,000.
(5)	Represents AHD phantom units (all of which are reported in “2006 Grants of Plan-Based Awards Table”), which vest as follows: 11/10/09 - 22,500 and 11/10/10 - 67,500.
(6)	Based on closing market price of AHD common units on December 29, 2006 of $23.88.
(7)	Represents options to purchase Atlas America stock.
(8)	Represents options to purchase Atlas America stock, which vest as follows: 7/1/07 - 30,000; 7/1/08 - 30,000 and 7/1/09 - 30,000.
(9)	Represents APL phantom units, which vest as follows: 3/16/07 - 3,750; 11/1/07 - 1,250; 3/16/08 - 3,750; 11/1/08 - 1,250; 3/16/09 - 3,750; 11/1/09 - 1,250 and 11/1/10 - 1,250; includes 5,000 units reported in “2006 Grants of Plan-Based Awards Table.”
(10)	Represents AHD options (all of which are reported in “2006 Grants of Plan-Based Awards Table”), which vest as follows: 11/10/09 - 25,000 and 11/10/10 - 75,000.
(11)	Represents AHD phantom units (all of which are reported in “2006 Grants of Plan-Based Awards Table”), which vest as follows: 11/10/09 - 5,000 and 11/10/10 - 15,000.
(12)	Represents options to purchase Atlas America stock (all of which are reported in “2006 Grants of Plan-Based Awards Table”), which vest as follows: 4/17/07 - 12,500; 4/17/08 - 12,500; 4/17/09 - 12,500 and 4/17/10 - 12,500.

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2006 OPTION EXERCISES AND STOCK VESTED TABLE

	Stock Awards(1)
	Number of Units		Value Realized
Name	Acquired on Vesting		on Vesting
	(#)		($)
Edward E. Cohen		11,250	$	454,612
Matthew A. Jones		3,750	$	151,537

⁽¹⁾Awards under the APL Plan.

DIRECTOR COMPENSATION TABLE

Name	Fees Earned or Paid in Cash
	($)
Walter C. Jones	$	1,342
Ellen F. Warren	$	1,342
Bruce M. Wolf	$	1,342

Director Compensation

We do not pay additional remuneration to officers or employees of Atlas America who also serve as members of our board of directors. Each non-employee director received in fiscal year 2006, a pro-rated portion of the annual retainer of $35,000 in cash and, in January 2007, an annual grant of phantom units with DERs in an amount equal to the lesser of 500 units or $15,000 worth of units (based upon the market price of our common units) pursuant to our Plan. In addition, we reimburse each non-employee director for out-of-pocket expenses in connection with attending meetings of the board or committees. We reimburse Atlas America for these expenses and indemnify our directors for actions associated with serving as directors to the extent permitted under Delaware law.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the number and percentage of our common units owned by beneficial owners of 5% or more of our common units, by our executive officers and directors and by all of the executive officers and directors as a group as of March 12, 2007. The address for each director and executive officer and Atlas America is 311 Rouser Road, P.O. Box 611, Moon Township, Pennsylvania 15108.

Beneficial Owner	Common Unit Amount and Nature of Beneficial Ownership				Percent of Class
Directors
Edward E. Cohen		—				—
Jonathan Z. Cohen		—				—
Matthew A. Jones		1,100				*
Walter C. Jones		—				—
Ellen F. Warren		—				—
Richard D. Weber		1,100				*
Bruce M. Wolf		3,000				*
Non-Director Executive Officers
Nancy J. McGurk		—				—
Lisa Washington		100				*
All executive officers and directors as a group (9 persons)		5,300				*
Other Owners of More Than 5% of Outstanding Shares
Atlas America, Inc.		29,352,996	(1	)		80.04	%

* Less than 1%

⁽¹⁾ This information is based upon a Schedule 13D which was filed with SEC on December 27, 2006. The address for Atlas America, Inc. is 311 Rouser Road, Moon Township, Pennsylvania 15108.

Equity Compensation Plan Information

The following table contains information about our Plan as of December 31, 2006:

	(a)		(b)	(c)
Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans not approved by security holders		-0-			3,742,000	(1)

⁽¹⁾ Includes 47,619 restricted units and 373,752 unit options granted in January, 2007.

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The following table contains information about the AHD Plan as of December 31, 2006:

	(a)		(b)		(c)
Plan category	Number of securities to be issued upon exercise of equity instruments		Weighted Average exercise price of outstanding Equity instruments		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans not approved by security holders - phantom units		220,492	$	0.00
Equity compensation plans not approved by security holders - unit options		1,215,000	$	22.56
Equity compensation plans not approved by security holders - Total		1,435,492				664,508

The following table contains information about the APL Plan as of December 31, 2006:

	(a)		(b)		(c)
Plan category	Number of securities to be issued upon exercise of phantom units		Weighted Average exercise price of outstanding phantom units		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders		159,067	$	0.00		275,933

The following table contains information about the Atlas Plan as of December 31, 2006:

	(a)		(b)		(c)
Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted Average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders		1,241,511	$	26.59		754,348

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Anthem Securities, our wholly-owned subsidiary is a registered broker-dealer which serves as the dealer-manager of investment programs sponsored by Resource America’s real estate and equipment finance segments. Salaries of the personnel performing services for Anthem are paid by Resource America and Anthem reimburses Resource America for the allocable costs of such personnel. In addition, Resource America agreed to cover some of the operating costs for Anthem’s office of supervisory jurisdiction, principally licensing fees and costs. In fiscal 2006, Resource America paid $1.3 million toward such operating costs of Anthem and Anthem reimbursed it $2.7 million.

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Our board of directors has determined that Messrs. W. Jones and Wolf, and Ms. Warren each satisfy the requirement for independence set out in Section 303A.02 of the rules of the New York Stock Exchange (the “NYSE”) including those set forth in Rule 10A-3(b)(1) of the Securities Exchange Act, and meet the definition of an independent member set forth in our Governance Guidelines. In making theses determinations, the board of directors reviewed information from each of these non-management directors concerning all their respective relationships with us and analyzed the materiality of those relationships.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

For the year ended December 31, 2006, Grant Thornton LLP’s accounting fees and services were as follows (in thousands)⁽⁴⁾:

Audit fees(1)	$	100
Audit-related fees		-
Tax fees(2)		-
All other fees(3)		-
Total accounting fees and services	$	100

⁽¹⁾   Audit fees include professional services rendered for the annual audit of our financial statements.

⁽²⁾   There were no fees for tax services rendered to us during the year ended December 31, 2006.

⁽³⁾   There were no other fees rendered to us during the year ended December 31, 2006.

⁽⁴⁾   Prior to our initial public offering on December 18, 2006, all Grant Thornton audit, audit-related and tax fees were billed to, paid by, and reported by Atlas America, Inc.

Audit Committee Pre-Approval Policies and Procedures

The audit committee, on at least an annual basis, reviews audit and non-audit services performed by Grant Thornton, LLP as well as the fees charged by Grant Thornton, LLP for such services. Our policy is that all audit and non-audit services must be pre-approved by the audit committee. All of such services and fees were pre-approved by Atlas America’s audit committee during 2005 and 2004.

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PART IV

ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)(1)Financial Statements

Report of Independent Registered Public Accounting Firm

Combined and Consolidated Balance Sheets at December 31, 2006 and 2005

Combined and Consolidated Statements of Income for the year ended December 31, 2006, three months ended December 31, 2005 and years ended September 30, 2005 and 2004

Combined and Consolidated Statements of Comprehensive Income for the year ended December 31, 2006, three months ended December 31, 2005 and years ended September 30, 2005 and 2004

Combined and Consolidated Statements of Equity for the year ended December 31, 2006, three months ended December 31, 2005 and years ended September 30, 2005 and 2004

Combined and Consolidated Statements of Cash Flows for the year ended December 31, 2006, three months ended December 31, 2005 and years ended September 30, 2005 and 2004

Notes to Combined and Consolidated Financial Statements − December 31, 2006

(2)Financial Statement Schedules

(3)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)
4.1	Form of common unit certificate (included as Exhibit A to the Amended and Restated Limited Liability Company Agreement of Atlas Energy Resources, LLC) (1)
10.1	Contribution, Conveyance and Assumption Agreement, dated as of December 18, 2006, among Atlas America, Inc., Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC(1)
10.2	Omnibus Agreement, dated as of December 18, 2006, between Atlas America, Inc. and Atlas Energy Resources, LLC(1)
10.3	Management Agreement, dated as of December 18, 2006, among Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC and Atlas Energy Management, Inc. (1)
10.4(a)	Master Natural Gas Gathering Agreement, dated February 2, 2000, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc. and Viking Resources Corporation(2)
10.4(b)	Natural Gas Gathering Agreement, dated January 1, 2002, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas Resources, Inc., Atlas Energy Group, Inc., Atlas Noble Corporation, Resource Energy, Inc. and Viking Resources Corporation(2)
10.4(c)	Amendment to Master Natural Gas Gathering Agreement and Natural Gas Gathering Agreement, dated October 25, 2005, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc., Viking Resources Corporation, Atlas Noble Corp. and Atlas Resources, Inc. (2)
10.4(d)	Amendment and Joinder to Gas Gathering Agreements, dated as of December 18, 2006, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, LLC, Viking Resources, LLC, Atlas Noble, LLC, Atlas Resources, LLC, Atlas America, LLC, Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC(1)

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10.5(a)	Omnibus Agreement, dated February 2, 2000, among Atlas America, Inc., Resource Energy, Inc., Viking Resources Corporation, Atlas Pipeline Partnership, L.P., and Atlas Pipeline Partners, L.P. (2)
10.5(b)	Amendment and Joinder to Omnibus Agreement, dated as of December 18, 2006 among Atlas Pipeline, Atlas America, Resource Energy, LLC, Viking Resources, LLC, Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC(1)
10.6	Agreement for Services among Atlas America, Inc. and Richard Weber, dated April 5, 2006(2)
10.7	Atlas Energy Resources Long-Term Incentive Plan(3)
10.8	Drilling and Operating Agreement, dated September 15, 2004, between Atlas America, Inc. and Knox Energy, LLC(2)
10.9(a)	Revolving Credit Agreement, dated as of December 18, 2006, among Atlas Energy Operating Company, LLC, its subsidiaries, Wachovia National Bank, as Administrative Agent and the other lenders signatory thereto(1)
10.9(b)	Guaranty, dated as of December 18, 2006, from Atlas Energy Resources, LLC in favor of Wachovia Bank, National Association, as administrative agent(1)
10.10	Services Agreement, dated as of December 18, 2006, between Anthem Securities, Inc. and Atlas America, Inc.(1)
10.11(a)	Gas Purchase Agreement, dated March 31, 1999, between Northeast Ohio Gas Marketing, Inc. and Atlas Energy Group, Inc.(2)
10.11(b)	Amendment to Gas Purchase Agreement, dated February 1, 2001, between FirstEnergy Services Corp., an assign of Northeast Ohio Gas Marketing, Inc., Atlas Energy Group, Inc. and Resource Energy Inc.(2)
10.11(c)	Second Amendment to Base Gas Purchase Agreement, dated July 16, 2003, between FirstEnergy Solutions Corp. and Atlas Energy Group, Inc., Atlas Resources, Inc. and Resource Energy, Inc.(2)
10.11(d)	Assignment and Novation of Transactions, dated April 1, 2005, between FirstEnergy Solutions Corp., Amerada Hess Corporation and the Atlas parties named therein (2)
10.11(e)	Third Amendment to Base Gas Purchase Agreement(4)
10.12	Form of Unit Award Agreement(5)
10.13	Limited Liability Company Agreement of Atlas Energy Operating Company, LLC dated June 29, 2006(2)
10.14	Form of Non-Employee Director Grant Agreement(5)
10.15	Form of Phantom Unit Grant Agreement(5)
10.16	Form of Option Grant Agreement(5)
21.1	Subsidiaries of Atlas Energy Resources, LLC(2)
23.1	Consent of Grant Thornton LLP
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 (Registration No. 333-136094)
(3)	Previously filed as an exhibit to our Form 8-K filed December 18, 2006
(4)	Previously filed as an exhibit to our Form 8-K filed January 10, 2007
(5)	Previously filed as an exhibit to our Form 8-K filed January 22, 2007

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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: March 27, 2007	By:	/s/ Edward E. Cohen
		Edward E. Cohen
		Chairman and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.

/s/ Edward E. Cohen	Chairman and Chief Executive Officer	March 27, 2007
Edward E. Cohen
/s/ Richard D. Weber	President and Chief Operating Officer	March 27, 2007
Richard D. Weber
/s/ Matthew A. Jones	Chief Financial Officer	March 27, 2007
Matthew A. Jones
/s/ Nancy J. McGurk	Chief Accounting Officer	March 27, 2007
Nancy J. McGurk
/s/ Jonathan Z. Cohen	Director	March 27, 2007
Jonathan Z. Cohen
/s/ Walter C. Jones	Director	March 27, 2007
Walter C. Jones
/s/ Ellen F. Warren	Director	March 27, 2007
Ellen F. Warren
/s/ Bruce M. Wolf	Director	March 27, 2007
Bruce M. Wolf

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