UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2007

OR

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

For the transition period from _________ to __________

Commission file number: 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.)
Westpointe Corporate Center One
1550 Coraopolis Heights Road
Moon Township, PA	15108
(Address of principal executive offices)	Zip Code
Registrant’s telephone number, including area code:	412-262-2830
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 xNo ¨

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 ¨No 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 xNo¨

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.¨

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¨ Accelerated filerx Non-accelerated filer¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x

The aggregate market value of common units held by non-affiliates of the registrant on June 30, 2007 was approximately $500.7 million.

DOCUMENTS INCORPORATED BY REFERENCE: None

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	20
	Item 1B:	Unresolved Staff Comments	33
	Item 2:	Properties	33
	Item 3:	Legal Proceedings	37
	Item 4:	Submission of Matters to a Vote of Security Holders	37
PART II	Item 5:	Market for Registrant's Common Equity and Related Shareholder Matters and Issuer Purchases of Equity Securities	38
	Item 6:	Selected Financial Data	39
	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	65
	Item 9:	Changes in and Disagreements with Accountants on Accounting andFinancial Disclosure	102
	Item 9A:	Controls and Procedures	102
	Item 9B:	Other Information	104
PART III	Item 10:	Directors and Executive Officers of the Registrant	104
	Item 11:	Executive Compensation	107
	Item 12:	Security Ownership of Certain Beneficial Owners and Management	117
	Item 13:	Certain Relationships and Related Transactions	119
	Item 14:	Principal Accounting Fees and Services	120
PART IV	Item 15:	Exhibits and Financial Statement Schedules	121
SIGNATURES			123

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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 year ended September 30, 2005, the three-month transition period ended December 31, 2005, and the years ended December 31, 2006 and 2007.

PART I

ITEM 1:BUSINESS

General

We are an independent developer and producer of natural gas and oil, with operations in northern Michigan’s Antrim Shale and the Appalachian Basin. We are a leading sponsor and manager of tax-advantaged direct investment natural gas and oil partnerships in the United States. We believe we have established a strong track record of growing our reserves, production and cash flows through a balanced mix of natural gas and oil exploitation and development and sponsorship of investment partnerships. As of December 31, 2007, our estimated proved reserves were 896.7 Bcfe, including the reserves net to our equity interest in our investment partnerships. Of our reserves, approximately 68% are proved developed and approximately 99% are natural gas. For the year ended December 31, 2007, our average daily production was approximately 89.5 Mmcfe per day and we generated revenues of $577.9 million and net income of $117.5 million.

In Michigan, as of December 31, 2007 we had reserves of approximately 666.8 Bcfe and our average daily production for the year ended December 31, 2007 was approximately 59.8 Mmcfe per day.

Since 2003, we have grown our Appalachian reserves and production at compound annual growth rates of approximately 8%. In Appalachia, as of December 31, 2007, we had proved reserves of approximately 229.9 Bcfe and our average daily production for the year ended December 31, 2007 was approximately 29.7 Mmcfe per day. We have experienced drilling success rates of approximately 99% over the last four years. We fund our Appalachian operations through sponsoring and managing investment partnerships. We generate both upfront and ongoing fees from the drilling, production, servicing, and administration of our Appalachian wells in these partnerships.

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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.We are managed by Atlas Energy Management, Inc., a wholly-owned subsidiary of Atlas America. On June 29, 2007, we acquired DTE Gas & Oil Company from DTE Energy Company (NYSE: DTE), which we refer to as DTE, for $1.273 billion in cash.

As of and for the year ended December 31, 2007, we had the following key assets:

In our Appalachia gas and oil operations:

·   proved reserves of 229.9 Bcfe including the reserves net to our equity interest in our investment partnerships and our direct interests in producing wells;

·   direct and indirect working interests in approximately 7,722 gross producing gas and oil wells;

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

·   net daily production of 29.7 Mmcfe per day;

·   approximately 797,800 gross (697,300 net) acres, of which approximately 508,600 gross (501,400 net) acres, are undeveloped; and

·   an interest in a joint venture that gave us the right to drill up to 77 additional net wells before March 31, 2008 on approximately 212,000 acres in Tennessee.

In our Michigan gas and oil operations:

·   proved reserves of 666.8 Bcfe

·   direct and indirect working interests in approximately 2,292 gross producing gas and oil wells;

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

·   net daily production of 59.8 Mmcfe per day; and

·   approximately 357,000 gross (285,100 net) acres, of which approximately 63,000 gross (53,300 net) acres, are undeveloped.

In our partnership management business:

·   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; and

·   managed total proved reserves of 503.7 Bcfe.

For the year ended December 31, 2007, we produced 89.5 Mcfe/d, which includes the proportionate share of production from our investment partnerships as well as our direct interests in producing wells.

Acquisition of DTE Antrim assets. On June 29, 2007, we acquired DTE Gas & Oil, now known as Atlas Gas & Oil Company, or AGO, from DTE Energy Company (“DTE” -NYSE:DTE) for $1.3 billion in cash. The assets acquired, which consisted principally of interests in natural gas wells in the Antrim Shale, are the basis for the formation of our gas and oil operations. We funded the purchase price from borrowings under a new credit facility with an initial borrowing base of $850.0 million that matures in June 2012. We intend to continue to expand our business through strategice acquisitions and internal growth projects that increase distributable cash flow.

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

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New credit facility. Upon the closing of the DTE Gas & Oil acquisition, we replaced our credit facility with a new 5-year, credit facility with an initial borrowing base of $850.0 million. The credit facility has a current borrowing base of $672.5 million, which will be redetermined semi-annually based on changes in our oil and gas reserves. The facility is secured by our assets and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR rate plus the applicable margin, elected at our option. The base rate for any day equals the higher of the federal funds rate plus 0.50% of the JPMorgan prime rate. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for Eurocurrency liabilities. The applicable margin ranges from 0.0% to 1.25% for base rate loans and 1.00% to 2.25% for LIBOR loans. At December 31, 2007, the weighted average interest rate on outstanding borrowings was 7.2%.

Recent Developments

Private debt offering. In January 2008, we issued $250.0 million of 10-year, 10.75% senior unsecured notes due 2018. We used the proceeds of the note offering to reduce the balance outstanding on our senior secured credit facility. Interest on the senior notes is payable semi-annually in arrears on February 1 and August 1 of each year. The senior notes are redeemable at any time at certain redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, before February 1, 2011, we may redeem up to 35% of the aggregate principal amount of the senior notes with the proceeds of certain equity offerings at a stated redemption price. The senior notes are also subject to repurchase by us at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if we do not reinvest the net proceeds within 360 days. The senior notes are junior in right of payment to our secured debt, including our obligations under our credit facility. The indenture governing the senior notes contains covenants, including limitations of our ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets.

New interest rate swap. In January 2008, we entered into an interest rate swap contract for $150 million, swapping the floating rate incurred on a portion of our existing senior secured credit facility for a fixed rate of approximately 4.36%, which includes an initial margin of 1.25% over the three year fixed swap rate of 3.11%. The interest rate swap contract will mature in January 2011. Combining the 4.36% interest rate on the new swap and the 10.75% interest rate on the new senior notes, we have fixed $400 million of our outstanding debt at a weighted average interest rate of approximately 8.35%.

Antrim Shale Overview

The Antrim Shale formation is a shallow late Devonian shale that occupies about 33,000 square miles under the northern half of Michigan’s Lower Peninsula. Most of the Michigan wells originally targeted oil and gas bearing reservoirs below the shale. While the Antrim Shale has produced oil and gas since the 1940s, it was not until the 1980s that it Antrim was purposely targeted for production on a large scale. The Antrim Shale is a low risk, organically rich black shale formation that is naturally fractured and primarily contains biogenic methane and water. Antrim production rates vary according to the intensity of the fracturing in the area immediately surrounding individual wells. The fractures provide the conduits for free gas and associated water to flow to the borehole through the black shale which otherwise has low permeability. Moreover, the fractures assist in the release of gas adsorbed on the shale surface.

Antrim Shale wells produce substantial volumes of water, especially during the early production stages, which must be removed from the formation to initiate gas production. The gas is transported from the well to a centrally located separation, compression and dehydration facility, where water is separated from it and disposed of, usually in a dedicated salt water disposal well to minimize water disposal costs.

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, 2007, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin was $.337 per MMBtu.

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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

At December 31, 2007, we owned interests in approximately 10,719 gross wells, of which we operated approximately 8,829. During the year ended December 31, 2007, we drilled 1,232 gross wells, 99% of which were successful in producing natural gas in commercial quantities.

Appalachia

In Appalachia, as of December 31, 2007, we owned interests in approximately 8,349 gross wells, of which we operated approximately 7,091. During the year ended December 31, 2007, average daily production from our wells was approximately 29.7 Mmcfe/d. During the year ended December 31, 2007, we drilled 1,117 gross (381.6 net) wells, 99% of which were successful in producing natural gas in commercial quantities. As of December 31, 2007, we had approximately 797,800 gross (697,300 net) acres, of which approximately 508,600 gross (501,400 net) acres are undeveloped. In September 2004, we expanded operations into Tennessee through a joint venture with Knox Energy, LLC that gave us an exclusive right to drill wells through December 31, 2007 on approximately 212,000 acres owned by Knox Energy. This agreement was extended through March 31, 2008; we are currently negotiating terms of a further joint venture agreement with Knox. As of December 31, 2007, we had drilled 321.0 net wells under this agreement. In addition, as of that date we had identified over 580 proved undeveloped drilling locations and approximately 2,600 additional potential drilling locations on our Appalachia acreage and the Tennessee joint venture acreage.

In the fourth quarter of 2006, we and our investment partnerships began drilling wells to multiple pay zones, including the Marcellus Shale of Western Pennsylvania. The Marcellus Shale is a black, organic rich shale formation located at depths between 6,000 and 8,500 feet and ranges in thickness from 75 to 150 feet on our acreage in Western Pennsylvania. As of February 20, 2008, we control approximately 483,000 Marcellus Shale acres in Pennsylvania, New York and West Virginia, and we continue to expand our position. As of that date, we had drilled 27 vertical wells and are currently producing 21 wells into a pipeline. The remaining 6 wells are scheduled to be completed and turned into line shortly. We are currently focused on our approximately 224,000 existing Marcellus acres in southwestern Pennsylvania, where we have drilled all but one of our Marcellus wells and have now, through this drilling, largely delineated our acreage. Almost all of this acreage in southwestern Pennsylvania has ample pipeline capacity that is controlled by our affiliate, Atlas Pipeline Partners, L.P. (NYSE: APL). Wright & Company, Inc., our independent petroleum engineering consultants, has evaluated our first 14 southwestern Pennsylvania Marcellus wells and assigned proved reserves that averaged 961 million cubic feet ("Mmcf") per well. These wells included five initial wells where we utilized. For the nine subsequent wells where we implemented our advanced drilling, completion and production techniques, Wright & Company assigned reserves that averaged 1.3 billion cubic feet ("Bcf") per well and were as high as 1.8 Bcf. Since implementing the advanced drilling, completion and production techniques, our initial daily rates (24 hours) into a pipeline have averaged 1.3 Mmcf per day in southwestern Pennsylvania. We plan to drill and complete at least 150 vertical Marcellus Shale wells over the next 18 months.

Michigan

In Michigan, as of December 31, 2007, we owned interests in approximately 2,370 gross wells, of which we operated approximately 1,738. During the six months ended December 31, 2007, average daily production from our wells was approximately 59.8 Mmcfe/d. During the six months ended December 31, 2007, we have drilled 102 gross (88.6 net) wells, 100% of which were successful in producing natural gas in commercial quantities. As of December 31, 2007, we had approximately 357,000 gross (285,100 net) acres, of which approximately 63,000 gross (53,300 net) acres are undeveloped.

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

Investment Partnerships

We generally fund our drilling activities, other than those of our Michigan business unit, through sponsorship of tax-advantaged investment partnerships. Accordingly, the amount of development activities we undertake depends in part upon our ability to obtain investor subscriptions to the partnerships. We raised $363.3 million in the year ended December 31, 2007 and $218.5 million in fiscal 2006. During the year ended December 31, 2007, our investment partnerships invested $423.1 million in drilling and completing wells, of which we contributed $137.6 million. During fiscal 2006, our investment partnerships invested $272.2 million in drilling and completing wells, of which we contributed $73.6 million.

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

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. For each well drilled by an investment partnership, we receive a fixed fee of approximately $15,000 ($45,000 for Marcellus wells). Additionally, the 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.

·   Well services. Each partnership pays us a monthly per well operating fee, currently $100 to $477, 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. Historically, each partnership paid us a gathering fee which was typically insufficient to cover all of the gathering fees due to Atlas Pipeline. Since the completion of our initial public offering in December 2006, 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.

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, but did subordinate $91,000 in fiscal 2005, $335,000 in fiscal 2004 and $362,000 in fiscal 2003. We 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.

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Natural Gas Sales

Appalachia

In Appalachia, we have a natural gas supply agreement with Hess Corporation, which is valid through March 31, 2009. Subject to certain exceptions, Hess Corporation 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 with 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.

A portion of our and our investment partnerships’ natural gas is subject to the agreement with Hess Corporation, with the following exceptions:

·   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.

Based on the most recent monthly production data available to us as of December 31, 2007, we anticipate that we and our affiliates, including our investment partnerships, will sell approximately 18% of our Appalachian natural gas production during the year ending December 31, 2008 under the Hess Corporation agreement. The agreement requires the parties to negotiate a new pricing arrangement at each annual delivery point. 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 Corporation does not match this price, then we may sell the natural gas to the third party. 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. See “—Major Customers.” During the year ended December 31, 2007, we received an average of $8.91 per Mcf of natural gas, compared to $8.83 per Mcf in fiscal 2006 and $8.34 per Mcf in fiscal 2005.

We expect that natural gas produced from our wells drilled in areas of the Appalachian Basin other than those 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.

Michigan

In Michigan, we have natural gas sales agreements with DTE, which are valid through December 31, 2012. DTE has the obligation to purchase all of the natural gas produced and delivered by us and our affiliates from specific projects at certain delivery points with the facilities of:

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·   Merit Plant/Michigan Consolidated Gas Company (MCGC) Kalkaska;

·   MCGC Jordan 4, Chestonia 17, Mancelona 19, Saginaw Bay and Woolfolk; and

·   Consumers Energy Goose Creek and Wilderness Plant,

Based on the most recent monthly production data available to us as of December 31, 2007, we anticipate that we and our affiliates will sell approximately 50% of our Michigan natural gas production during the year ending December 31, 2008 under the DTE agreements in most cases at NYMEX pricing. During the six months ended December 31, 2007, AGO received an average of $8.44 per Mcf of natural gas.

Crude Oil Sales

Crude oil produced from our wells flows directly into storage tanks where it is picked up by the oil company, a common carrier, or pipeline companies acting for the oil company, which is purchasing the crude oil. We sell any oil produced by our Appalachian wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil. In Michigan, the property operator typically markets the oil produced.

Asset Retirement Obligations

When we determine that a well is no longer capable of producing natural gas or oil in economic quantities, we must dismantle the well and restore and reclaim the surrounding area before we can abandon the well. We contract these operations to independent service providers to whom we pay a fee. The contractor will also salvage the equipment on the well, which we then sell in the used equipment market. Under the partnership agreements of our investment partnerships, which own the majority of our Appalachia wells, we are allocated abandonment costs in proportion to our partnership interest (generally between 27% and 35%) and are allocated between 65% and 100% of the salvage proceeds. As a consequence, we generally receive proceeds from salvaged equipment at least equal to, and typically exceeding, our share of the related costs.

Natural Gas Hedging

We seek to provide greater stability in our cash flows through our use of financial hedges and physical hedges. 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 six years in the future. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, we have 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, 2007, we had financial hedges and physical hedges in place for approximately 65% of our expected Appalachian production and for approximately 87% of our Michigan production for the twelve months ending December 31, 2008.

Hess Corporation and other third-party marketers to which we sell gas, such as Colonial Energy, Inc. and UGI Energy Services, also use NYMEX-based financial instruments to hedge their pricing exposure and make price hedging opportunities available to us through physical hedge transactions. These transactions 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 these third-party marketers for volumes of natural gas sold under these sales agreements may be significantly different from the underlying monthly spot market value.

Natural Gas Gathering

Appalachia

We conduct our natural gas transportation and processing operations through Atlas America’s affiliate, Atlas Pipeline Partners. Atlas Pipeline owns approximately 1,600 miles of gathering systems located in eastern Ohio, western New York and western Pennsylvania serving approximately 6,600 wells.

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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 extends 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:

·   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.

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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. 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 our investment partnerships and us, 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.

Michigan

We transport our natural gas from our Michigan wells through our 1,157 miles of polypropylene flow lines to centrally located separation, compression and dehydration facilities, which we refer to as CPFs, where water is separated from the natural gas and disposed of. We own interests in 81 CPFs, of which we operate 61. The wells generally produce natural gas and water for 3 to 12 months, after which they produce only gas.

We then transport the compressed and dehydrated gas stream from CPFs via our 181 miles of sales lines to the northern Michigan high pressure gathering system, which is composed of a number of gathering systems owned by third party transporters that deliver gas to delivery points. Compressed and dehydrated gas exiting the CPF typically has carbon dioxide (CO2) levels in excess of the 2% pipeline specifications required at the delivery point. Therefore, it is treated at CO2 processing plants located along the northern Michigan high pressure gathering system before delivery to the delivery points. The CO2 plants utilize either an amine or membrane treating process. We currently own and operate one amine processing plant and operate on behalf of DTE four other amine plants and one membrane plant. We pay third parties an average of $0.30/Mcfe on a net basis for these transportation and treating services.

Other Agreements with Atlas America and Its Affiliates

Contribution Agreement

Contribution of assets by Atlas America. The substantial majority of the Appalachian 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 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.

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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.

Atlas Energy Management, its stockholders, directors, officers, employees and affiliates will not be liable to us, our directors or unit holders for acts or omissions performed in good faith and in accordance with and pursuant to the management agreement, except because 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, 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 unit holders.

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 thesuccessor 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.

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Anthem Securities, Inc.

Anthem Securities is our registered broker-dealer subsidiary, which acts as the dealer-manager for our investment partnership offerings. Anthem Securities is registered as a broker-dealer solely involved in direct participation programs such as our investment partnerships, and does not maintain customer accounts or custody of securities. Anthem Securities has been a member of FINRA, formerly known as the National Association of Securities Dealers, Inc., since 1997.

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 fiscal 2007, we faced no shortage of these goods and services. We cannot predict the duration or stability of the current level of supply and demand for drilling rigs and other goods and services required for our operations with any certainty due to numerous factors affecting the energy industry, including the demand for natural gas and oil.

Major Customers

Our natural gas sold under contract to various purchasers. For the year ended September 30, 2005 and the years ended December 31, 2006 and 2007, gas sales to Hess Corporation (formerly First Energy Solutions Corp.) accounted for 12%, 10% and 18%, respectively, of our total Appalachian gas and oil production revenues. For the six months, ended December 31, 2007, sales to DTE accounted for 46% of our Michigan oil and gas production revenues. No other single customer accounted for more than 10% of our total revenues during these periods.

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 natural gas and oil.

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 “Risk factors” Product availability and price are the principal means of competition in selling natural gas and oil. During the year ended December 31, 2007, we did not experience problems in selling our natural gas and oil, although prices have varied significantly during this period.

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 a 87.5% net revenue interest to us, and in Michigan this amount is typically 1/6^th (16.67%) resulting in an 83.3% net revenue interest to us, for most leases directly acquired by us. In certain instances, this royalty amount may increase to 1/6^th in the Appalachian Basin and to 3/16^th (18.75%) in Michigan when leases are taken from larger landowners or mineral owners such as coal and timber companies.

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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 in the Appalachian Basin 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% and in Michigan from 3.33% to 5.33%, which further reduces the net revenue interest available to us to between 80.0% and 78.0%.

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 and Michigan, 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.

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 and Michigan. 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 because we have typically received the majority of funds from our investment partnerships during the fourth calendar quarter. Generally, but not always, 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;

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·   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.

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 overall 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 affect our properties or operations. For the years ended December 31, 2006 and 2007, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. We are not aware of any environmental issues or claims that will require material capital expenditures during 2008, or that will otherwise have a material impact on our financial position or results of operations.

Environmental laws and regulations that could have a material impact on the natural gas and oil exploration and production industry include the following:

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 affect 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 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 that 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 affect 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 affect 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 will 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.

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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.

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, Michigan imposes a 5.6% severance tax on natural gas and a 7.3% severance tax on oil, Tennessee imposes a 3% severance tax on natural gas and oil production and Ohio imposes a severance tax of $0.25 per Mcf of natural gas and $0.10 per 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.

Employees

We do not have any employees. To carry out our operations, our manager and its affiliates employed approximately 467 persons as of December 31, 2007.

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Available Information

We make our periodic reports under the Securities Exchange Act of 1934, including our annual report on Form 10-K, our quarterly reports on Form 10-Q and our current reports on Form 8-K, available through our website at www.atlasenergyresources.com. To view these reports, click on “Investor Relations”, then “SEC Filings”. You may also receive, without charge, a paper copy of any such filings by request to us at 1550 Coraopolis Heights Road, Moon Township, Pennsylvania 15108, telephone number (412) 262-2830. A complete list of our filings is available on the Securities and Exchange Commission’s website at www.sec.gov. Any of our filings are also available at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.

The NYSE requires the chief executive officer of each listed company to certify annually that he is not aware of any violation by the company of the NYSE corporate governance listing standards as of the date of the certification, qualifying the certification to the extent necessary. The Chief Executive Officer of our general partner provided such certification to the NYSE in 2007 without qualification. In addition, the certifications of the Chief Executive Officer and Chief Financial Officer of our general partner required by Sections 302 and 906 of the Sarbanes-Oxley Act have been included as exhibits to this report.

ITEM 1A:RISK FACTORS

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 unit holders 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;

·   fluctuations in our working capital needs;

·   timing and collectability of receivables;

·   restrictions on distributions imposed by lenders;

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·   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 unit holders 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. 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.

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, 2007, the NYMEX Henry Hub natural gas index price ranged from a high of $7.59 per MMBtu to a low of $5.43 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $95.10 per Bbl to a low of $51.13 per Bbl.

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 payments on our debt. 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, 2007 reserve reports, our average annual decline rate for proved developed producing reserves is approximately 8% during the first five years, approximately 5% in the next five years and less than 5% thereafter. Because total estimated proved reserves include proved undeveloped reserves at December 31, 2007, 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, including our investment partnerships, all of which are subject to the risks discussed elsewhere in this section.

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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. For example, if natural gas prices decline by $1.00 per Mcf, then the PV-10 value of our proved reserves as of December 31, 2007 would decrease from $1.5 billion to $1.2 billion. Our PV-10 is calculated using natural gas prices that include our physical hedges but not our financial hedges. 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;

·   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. In addition, 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. In addition, 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.

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 unit holders 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. 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:

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·   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 unit holders. 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 unit holders 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.

The scope and costs of the risks involved in making acquisitions may prove greater than estimated at the time of the acquisition. Any acquisition involves potential risks, including, among other things:

·   mistaken assumptions about revenues and costs, including synergies;

·   significant increases in our indebtedness and working capital requirements;

·   an inability to integrate successfully or timely the businesses we acquire;

·   the assumption of unknown liabilities;

·   limitations on rights to indemnity from the seller;

·   the diversion of management’s attention from other business concerns;

·   increased demands on existing personnel;

·   customer or key employee losses at the acquired businesses; and

·   the failure to realize expected growth or profitability.

The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition.  Further, our future acquisition costs may be higher than those we have achieved historically.  Any of these factors could adversely affect our future growth and our ability to increase distributions.

We may be unsuccessful in integrating the operations from our recent acquisition or any future acquisitions with our operations and in realizing all of the anticipated benefits of these acquisitions. We acquired DTE Gas & Oil in June 2007 and are currently in the process of integrating its operations with ours. We also have an active, on-going program to identify other potential acquisitions. The integration of previously independent operations with ours can be a complex, costly and time-consuming process. The difficulties of combining these systems, as well as any operations we may acquire in the future, with us include, among other things:

·   operating a significantly larger combined entity;

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·   the necessity of coordinating geographically disparate organizations, systems and facilities;

·   integrating personnel with diverse business backgrounds and organizational cultures;

·   consolidating operational and administrative functions;

·   integrating internal controls, compliance under Sarbanes-Oxley Act of 2002 and other corporate governance matters;

·   the diversion of management’s attention from other business concerns;

·   customer or key employee loss from the acquired businesses;

·   a significant increase in our indebtedness; and

·   potential environmental or regulatory liabilities and title problems.

We acquired DTE Gas & Oil with the expectation that combining it with our existing operations will result in benefits, including, among other things, increased geographic diversification and reserve life. There can be no assurance that we will realize any of these benefits or that the acquisition will not result in the deterioration or loss of our business. Costs incurred and liabilities assumed in connection with an acquisition and increased capital expenditures and overhead costs incurred to expand our operations could harm our business or future prospects, and result in significant decreases in our gross margin and cash flows.

The DTE Gas & Oil acquisition has substantially changed our business, making it difficult to evaluate our business based upon our historical financial information. The DTE Gas & Oil acquisition has significantly increased our size, redefined our business plan, expanded our geographic market and resulted in large changes to our revenues and expenses. As a result of this acquisition, and our continued plan to acquire and integrate additional companies that we believe present attractive opportunities, our financial results for any period or changes in our results across periods may continue to dramatically change. Our historical financial results, therefore, should not be relied upon to accurately predict our future operating results, thereby making the evaluation of our business more difficult.

We have limited experience in drilling wells to the Marcellus Shale, less information regarding reserves and decline rates in the Marcellus Shale than in other areas of our Appalachian operations and wells drilled to the Marcellus Shale will be deeper, more expensive and more susceptible to mechanical problems in drilling and completing than wells in the other areas. We have limited experience in drilling development wells to the Marcellus Shale. As of December 31, 2007, we have drilled 19 wells to the Marcellus Shale, 15 of which have been turned on-line, but those wells have been producing for only a short period of time. Other operators in the Appalachian Basin also have limited experience in drilling wells to the Marcellus Shale. Thus, we have much less information with respect to the ultimate recoverable reserves and the production decline rate in the Marcellus Shale than we have in our other areas of operation. In addition, the wells to be drilled in the Marcellus Shale will be drilled deeper than in our other primary areas, which makes the Marcellus Shale wells more expensive to drill and complete. The wells will also be more susceptible to mechanical problems associated with the drilling and completion of the wells, such as casing collapse and lost equipment in the wellbore. In addition, the fracturing of the Marcellus Shale will be more extensive and complicated than fracturing the geological formations in our other areas of operation.

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.

We have a substantial amount of indebtedness which could adversely affect ourfinancial position.We currently have a substantial amount of indebtedness. As of February 20, 2008, we had total debt of approximately $770.1 million, consisting of $250.0 million of senior notes, $520.0 million of borrowings under our credit facility, and $0.1 million of other debt. We may also incur significant additional indebtedness in the future. Our substantial indebtedness may:

• make it difficult for us to satisfy our financial obligations, including making scheduled principal and interest payments on the senior notes and our other indebtedness;

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• limit our ability to borrow additional funds for working capital, capital expenditures, acquisitions or other general business purposes;

• limit our ability to use our cash flow or obtain additional financing for future working capital, capital expenditures, acquisitions or other general business purposes;

• require us to use a substantial portion of our cash flow from operations to make debt service payments;

• limit our flexibility to plan for, or react to, changes in our business and industry;

• place us at a competitive disadvantage compared to our less leveraged competitors; and

• increase our vulnerability to the impact of adverse economic and industry conditions.

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.

Covenants in our debt agreements restrict our business in many ways. The indenture governing our senior notes and our credit facility contain various covenants that limit our ability and/or our subsidiaries’ ability to, among other things:

• incur or assume liens or additional debt or provide guarantees in respect of obligations of other persons;

• issue redeemable stock and preferred stock;

• pay dividends or distributions or redeem or repurchase capital stock;

• prepay, redeem or repurchase debt;

• make loans, investments and capital expenditures;

• enter into agreements that restrict distributions from our subsidiaries;

• sell assets and capital stock of our subsidiaries;

• enter into certain transactions with affiliates; and

• consolidate or merge with or into, or sell substantially all of our assets to, another person.

In addition, our credit facility contains restrictive covenants and requires us to maintain specified financial ratios. Our ability to meet those financial ratios can be affected by events beyond our control, and we may be unable to meet those tests. A breach of any of these covenants could result in a default under our credit facility and/or the senior notes. Upon the occurrence of an event of default under our credit facility, the lenders could elect to declare all amounts outstanding under our credit facility to be immediately due and payable and terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders could proceed against the collateral granted to them to secure that indebtedness. We have pledged a significant portion of our assets as collateral under our credit facility. If the lenders under our credit facility accelerate the repayment of borrowings, we may not have sufficient assets to repay our credit facility and our other indebtedness, including the notes. Our borrowings under our credit facility are, and are expected to continue to be, at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income would decrease.

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Changes in tax laws may impair our ability to obtain capital funds through investmentpartnerships. 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.

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 in Appalachia. Accordingly, the amount of development activities we undertake there 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 $148.7 million in fiscal 2005, and $52.2 million in the three months ended December 31, 2005 and $218.5 million and $363.3 million in calendar 2006 and 2007, respectively. 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.

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 unit holders 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.

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.

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 natural gas and oil. 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.

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We depend on certain key customers for sales of our natural gas. To the extent these customers reduce the volumes of natural gas they purchase from us, our revenues and cash available for distribution could decline. In Appalachia, our natural gas is sold under contracts with various purchasers. Under a natural gas supply agreement with Hess Corporation, which expires on March 31, 2009, Hess Corporation has a last right of refusal to buy all of the natural gas produced and delivered by our affiliates, and us including our investment partnerships. During fiscal 2007, natural gas sales to Hess Corporation accounted for approximately 18% of our total Appalachian oil and gas revenues. In Michigan, during the six months ended December 31, 2007, gas under contracts to a former affiliate of Atlas Gas & Oil, which expire at various dates through 2012, accounted for approximately 62% of our total Michigan oil and gas revenues. To the extent these and other key customers reduce the amount of natural gas they purchase from us, our revenues and cash available for distributions to unitholders could temporarily decline in the event we are unable to sell to additional purchasers.

Our Appalachia 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 Appalachia production and approximately 50% of our total 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 master gas gathering agreements 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 entered into at the completion of our initial public offering, 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, 2007, this excess amount was approximately $11.9 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 payments on the notes.

Shortages of drilling rigs, equipment and crews could delay our operations. 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 natural gas and oil 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.

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;

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·   RCRA and comparable state laws that impose requirements for the handling and disposal of waste from our facilities; and

·   CERCLA 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.

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. 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, 2007, we had identified over 3,950 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, our independent petroleum engineering consultants have not assigned any proved reserves to the over 2,650 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.

Some of our undeveloped leasehold acreage is subject to leases that may expire in the near future. Leases covering approximately 44,900 of our 1,037,300 net acres, or 4%, are scheduled to expire on or before December 31, 2008. If we are unable to renew these leases or any leases scheduled for expiration beyond December 31, 2008, 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 payments on the notes.

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. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

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·   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 will 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.

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 affect 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. In addition, 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 six years 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.

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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.

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. In addition, 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 who 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.

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 our unit holders and us. For example, our limited liability company agreement provides that:

·   our directors and officers will not have any liability to us or our unit holders 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 unit holders 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 unit holders 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:

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·   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 unit holders.

·   In some instances our board of directors may cause us to borrow funds in order to permit us to pay cash distributions to our unit holders, 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.

Our limited liability company agreement provides for a limited call right that may require unit holders 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 unit holders 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. Unit holders 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 unit holders. 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 unit holders 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.

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.

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Expense reimbursements due to our manager under our management agreement will reduce cash available for distribution to our unit holders. 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 unit holders 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 unit holders owning 20% or more of our common units. Our limited liability company agreement restricts the voting rights of common unit holders 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 unit holders to call meetings or to acquire information about our operations, as well as other provisions limiting common unit holders’ 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.

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 unit holders 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 unit holders 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.

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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 unit holders 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 unit holders receiving two Schedule K-1s, for one fiscal year and the cost of the preparation of these returns will be borne by all unit holders.

ITEM 1B:UNRESOLVED STAFF COMMENTS

None

ITEM 2:PROPERTIES

Office Properties

We lease a 27,000 square foot office building in Moon Township, Pennsylvania. We own a 17,000 square foot field office and warehouse facility in Jackson Center, Pennsylvania, a 24,000 square foot office in Fayette County, Pennsylvania and an office in Deerfield, Ohio. We lease a 13,800 square foot office building in Traverse City, Michigan under a lease expiring in 2012. We lease a 1,400 square foot field office in Ohio under a lease expiring in 2009. We also rent 17,200 square feet of office space in Uniontown, Ohio under a lease expiring in August 2008. We also lease other field offices in Ohio and New York on a month-to-month basis.

Natural Gas and Oil Reserves

The following tables summarize information regarding our estimated proved natural gas and oil reserves as of the dates indicated. 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 generally located in the Appalachian Basin and in Michigan’s Lower Peninsula. We base these estimated proved natural gas and oil reserves and future net revenues of natural gas and oil reserves upon reports prepared by independent petroleum engineers.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:

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	At December 31,						At September 30,
	2007		2006		2005		2005
Natural gas (per Mcf)	$	6.93	$	6.33	$	10.84	$	14.75
Oil (per Bbl)	$	90.30	$	57.26	$	57.54	$	63.29

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 our independent petroleum engineering firm in preparing their 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 “Item1A: 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.

	Proved natural				Proved natural
	gas and oil reserves for				gas and oil reserves for
	Atlas Energy Resources at				Atlas America E&P Operations at
	December 31,				December 31,		September 30,
	2007		2006		2005		2005
Natural gas reserves (Mmcf):
Proved developed reserves		594,709		107,683		108,674		104,786
Proved undeveloped reserves (1)		290,050		60,859		49,250		53,241
Total proved reserves of natural gas		884,759		168,542		157,924		158,027
Oil reserves (Mbbl):
Proved developed reserves		1,977		2,064		2,122		2,116
Proved undeveloped reserves		6		4		135		143
Total proved reserves of oil		1,983		2,068		2,257		2,259
Total proved reserves (Mmcfe)		896,657		180,950		171,466		171,581
PV-10 estimate of cash flows of proved reserves (in thousands) (2):
Proved developed reserves	$	1,264,309	$	279,330	$	465,459	$	617,445
Proved undeveloped reserves		216,869		4,111		131,678		228,206
Total PV-10 estimate (3)	$	1,481,178	$	283,441	$	597,137	$	845,651
Standardized measure of discounted future cash flows (in thousands) (2) (3)	$	1,481,178	$	283,441	$	429,272	$	606,697

___________

(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, 2005 and December 31, 2005 reflect values for Atlas America E&P Operations, which paid income taxes. Amounts shown for December 31, 2006 and 2007 reflect values for our reserves. Since we are a limited liability company that allocates our taxable income to our unit holders, no provision for federal or state income taxes has been included in the December 31, 2006 and 2007 calculations 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				Proved natural gas and oil reserves for
	Atlas Energy Resources at				Atlas America E&P Operations at
	December 31,				December 31,			September 30,
	2007		2006		2005			2005
PV-10 value	$	1,481,178	$	283,441	$	597,137		$	845,651
Income tax effect		—		—		(167,865	)		(238,954	)
Standardized measure	$	1,481,178	$	283,441	$	429,272		$	606,697

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.

Productive Wells

The following table sets forth information as of December 31, 2007, regarding productive natural gas and oil wells in which we have a working interest. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, directly or through our ownership interests in investment partnerships, and net wells are the sum of our fractional working interests in gross wells, based on the percentage interest we own in the investment partnership that owns the well.

	Number of productive wells
	Gross(1)		Net(1)
Oil wells		512		368
Gas wells		9,502		5,211
Total		10,014		5,579

____________

(1) Includes our proportionate interest in wells owned by 92 investment partnerships for which we serve as managing general partner and various joint ventures. Does not include royalty or overriding interests in 705 wells.

Gas and Oil 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, 2007		153,465		20,963,436	$	70.16	$	8.66	$	1.47
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

(1)   Average sales price before the effects of financial hedging was $7.22 and $7.90 for the year ended December 31, 2007 and 2006, respectively. 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.

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Developed and Undeveloped Acreage

The following table sets forth information about our developed and undeveloped natural gas and oil acreage as of December 31, 2007. The information in this table includes our proportionate interest in acreage owned by our investment partnerships. 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		—		—
Michigan		293,999		231,869		63,005		53,262
Mississippi		40		3		—		—
Montana		—		—		2,650		2,650
New York		20,517		14,972		45,123		45,123
North Dakota		639		96		—		—
Ohio		114,033		95,913		32,025		32,025
Oklahoma		4,323		468		—		—
Pennsylvania		123,898		123,898		376,002		376,002
Tennessee		14,689		13,411		31,177		31,177
Texas		4,520		329		—		—
West Virginia		1,078		539		12,530		9,852
Wyoming		—		—		80		80
		583,199		482,589		571,652		554,701

________________

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

(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 are 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.

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 $2.4 million in fiscal 2007 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.

Our properties are subject to royalty, overriding royalty and other outstanding interests customary in the industry. Our properties are also 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.

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Drilling Activity

The number of wells we drill will vary depending on the amount of money we raise through our investment partnerships, the cost of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. 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 we initiated drilling

	Development wells								Exploratory wells
	Productive				Dry				Productive				Dry
	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)
Appalachia:
Year ended December 31, 2007		1106.0		377.6		11.0		4.0		—		—		—		—
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		—		—		—		—
Michigan:
Year ended December 31, 2007		115.0		92.23		―		―		—		—		—		—

________________

(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.

ITEM 3:LEGAL PROCEEDINGS

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

Atlas Gas & Oil Company LLC, as successor to DTE Gas & Oil Company, was one of four defendants in a personal injury action filed in Antrim County Circuit Court in northern Michigan in August 2006.  The complaint alleged that plaintiff suffered serious personal injuries as a result of the defendants’ negligence. The Company paid $125,000 to the plaintiff in October 2007 in full settlement of this action.

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

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

On November 11, 2007 Atlas America, Inc. and Atlas Energy Management, Inc. took action by written resolutions in lieu of a special meeting of unitholders to approve (a) the change in the terms of our then outstanding Class D units to provide that each Class D unit would convert automatically into one of our common units and (b) the issuance of 16,702,827 common units to be issued upon such conversion. On that date, Atlas America and Atlas Energy Management collectively held 30,591,982 of our common units and Class A units, representing approximately 80.61% of our then outstanding voting units. We provided an information statement to each unitholder relating to this action on or about October 22, 2007.

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PART II

ITEM 5: MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED SHAREHOLDERMATTERS 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.

Fiscal 2007	High		Low
Fourth Quarter	$	36.00	$	28.50
Third Quarter	$	38.85	$	28.75
Second Quarter	$	37.47	$	26.26
First Quarter	$	27.46	$	22.10
Fiscal 2006		High		Low
Fourth Quarter	$	22.88	$	21.80

As of February 11, 2008, there were 60,710,749 common units outstanding held by 48 holders of record. For a description of our recent sale of unregistered securities, see our Current Report on Form 8-K filed June 29, 2007.

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 unit holders 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:

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

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

o   provide funds for distributions (1) to our unit holders 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 unit holders.

On January 28, 2008, we declared a quarterly cash distribution for the fourth quarter of 2007 of $0.57 per common unit, which was paid on February 14, 2008 to common unit holders of record as of February 7, 2008.

For information concerning common units authorized for issuance under our incentive plan, see “Item 12: Security Ownership or Certain Beneficial Owners and Management─Equity Compensation Plan Information.”

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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 before the date of our initial public offering on December 18, 2006 and our historical combined and consolidated financial and operating data after that date for the periods indicated. Atlas America E&P Operations were 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. We derived the historical financial data as of December 31, 2007 and 2006 and for the years ended December 31, 2007 and 2006, the three months ended December 31, 2005 and the year ended September 30, 2005 from Atlas Energy Resources, LLC and Atlas America E&P Operations’ financial statements, which were audited by Grant Thornton LLP, an independent registered public accounting firm, and are included in this report. We derived the historical financial data as of December 31, 2005, September 30, 2005 and 2004 and for the year ended September 30, 2004 from Atlas E&P Operations’ audited financial statements, which are not included in this report. We derived the historical financial data as of September 30, 2003, and for the year ended September 30, 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
							Ended
	Years Ended December 31,						December 31,			Years Ended September 30,
	2007			2006			2005			2005			2004			2003
	(in thousands)
Income statement data:
Revenues:
Gas and oil production	$	180,125		$	88,449		$	24,086		$	63,499		$	48,526		$	38,639
Partnership management:
Well construction and completion		321,471			198,567			42,145			134,338			86,880			52,879
Administration and oversight		18,138			11,762			2,964			9,590			8,396			5,090
Well services		17,592			12,953			2,561			9,552			8,430			7,635
Gathering (1)		14,314			9,251			1,407			4,359			4,191			3,898
Gain on mark-to-market derivatives		26,257			─			─			─			─			─
Total revenues		577,897			320,982			73,163			221,338			156,423			108,141
Expenses:
Gas and oil production (1)		32,193			13,881			2,441			8,165			7,289			6,770
Partnership management:
Well construction and completion		279,540			172,666			36,648			116,816			75,548			45,982
Well services		9,062			7,337			1,487			5,167			4,398			3,773
Gathering (1)		214			—			38			52			53			29
Gathering fee - Atlas Pipeline (1)		13,781			29,545			7,930			21,929			17,189			14,564
General and administrative		39,414			23,367			5,818			13,202			11,708			10,106
Net expense reimbursement - affiliate		─			1,237			163			602			1,050			1,400
Depreciation, depletion and amortization		56,942			22,491			4,916			14,061			12,064			9,938
Total operating expenses		431,146			270,524			59,441			179,994			129,299			92,562
Operating income		146,751			50,458			13,722			41,344			27,124			15,579
Other income (expenses):
Interest expense		(30,096	)		─			─			─			─			─
Other - net		849			1,369			57			79			444			358
Total other income(expense)		(29,247	)		1,369			57			79			444			358
Net income before cumulative effect of accounting change		117,504			51,827			13,779			41,423			27,568			15,937
Cumulative effect of accounting change (2)		─			6,355			—			—			—			—
Net income	$	117,504		$	58,182		$	13,779		$	41,423		$	27,568		$	15,937
Cash flow data:
Cash provided by operating activities	$	230,982		$	80,536		$	43,596		$	90,525		$	42,523		$	20,365
Cash used in investing activities		(1,468,434	)		(75,588	)		(17,185	)		(59,050	)		(32,709	)		(22,112	)
Cash provided by (used in) financing activities		1,253,877			(17,033	)		(11,739	)		(25,401	)		(14,916	)		34
Capital expenditures	$	196,735		$	75,635		$	17,187		$	59,124		$	33,252		$	22,607
Other financial information (unaudited):
EBITDA	$	204,542		$	74,318		$	18,695		$	55,484		$	39,632		$	25,875
Adjusted EBITDA	$	199,099		$	94,949		$	25,649		$	73,109		$	52,747		$	36,570
Balance sheet data (at period end):
Total assets	$	1,891,234		$	415,463		$	315,052		$	270,402		$	198,454		$	178,451
Liabilities associated with drilling contracts		132,517			86,765			70,514			60,971			29,375			22,157
Advances from affiliates		8,696			12,502			4,257			13,897			30,008			34,776
Long-term debt, including current maturities		740,030			68			156			81			420			194
Total equity	$	836,115		$	212,682		$	154,519		$	146,142		$	109,461		$	102,031

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_____________

(1)   We charge gathering fees to our investment partnership wells that are connected to Atlas Pipeline’s gathering systems. Historically, 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 5 to our combined and consolidated financial statements).

EBITDA AND ADJUSTED EBITDA

We define EBITDA as earnings before interest, taxes, depreciation, depletion, and amortization and cumulative effect of accounting change. We calculate Adjusted EBITDA by adjusting EBITDA for other non-cash items such as equity compensation. EBITDA and Adjusted EBITDA are not measures of performance calculated in accordance with GAAP. Although not prescribed under GAAP, we believe the presentation of EBITDA and Adjusted EBITDA are relevant and useful because they help our investors to understand our operating performance and make it easier to compare our results with other companies that have different financing and capital structures or tax rates. EBITDA and Adjusted 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 and Adjusted EBITDA do not represent funds available for discretionary use. The following reconciles our net income before taxes and cumulative effect of accounting change to our EBITDA and Adjusted EBITDA for the periods indicated:

						Three Months
						Ended		Years Ended
	Years Ended December 31,					December 31,		September 30,
	2007			2006		2005		2005		2004		2003
	(in thousands)
Net income before cumulative effect of accounting change	$	117,504		$	51,827	$	13,779	$	41,423	$	27,568	$	15,937
Plus interest expense		30,096			—		—		—		—		—
Plus depreciation, depletion and amortization		56,942			22,491		4,916		14,061		12,064		9,938
EBITDA		204,542			74,318		18,695		55,484		39,632		25,875
Less gain on mark-to-market derivatives		(14,000	)		—		—		—		—		—
Plus non-recurring derivative fees		3,873
Plus non-cash stock compensation		4,684			337		393		300		64		—
Plus gathering fee		─			20,294		6,561		17,622		13,051		10,695
Adjusted EBITDA	$	199,099		$	94,949	$	25,649	$	73,109	$	52,747	$	36,570

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ITEM 7:Management’s Discussion and Analysis of Financial Condition and Results of Operations

GENERAL

Manner of Presentation

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, which were contributed to us upon the closing of our initial public 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 our results 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 “Forward-looking statements” and “Item 1A: Risk Factors” for information regarding some of the risks inherent in our business.

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. As a result, the financial results now being reported by us relate to the years ended December 31, 2007 and 2006, the three-month transitional period ended December 31, 2005, and the year ended September 30, 2005. Thus, our financial statements do not present a prior one-year financial period on which to base a comparative discussion with the year ended December 31, 2006.

Comparability of Financial Statements

The historical financial statements of Atlas America E & P Operations included in this report are not 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 13% 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 incurred indebtedness after the closing of our initial public offering, which created interest expense.

·   Because we report our items of taxable income, loss, deductions and credits as a master limited partnership, we now incur additional general and administrative expense each year for costs associated with Schedule K-1 preparation and distribution to our unitholders.

·   We acquired DTE Gas & Oil on June 29, 2007, which significantly increased our assets, debt and equity and will continue to significantly increase our revenues, expenses and cash flows in future periods.

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OVERVIEW

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

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

We operate three business segments:

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

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

As of and for the year ended December 31, 2007, we had the following key assets:

In our Appalachia gas and oil operations:

·   proved reserves of 229.9 Bcfe including the reserves net to our equity interest in the investment partnerships and our direct interests in producing wells;

·   direct and indirect working interests in approximately 7,722 gross producing gas and oil wells;

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

·   net daily production of 29.7 Mmcfe per day;

·   approximately 797,800 gross (697,300 net) acres, of which approximately 508,600 gross (501,400 net) acres, are undeveloped; and

·   an interest in a joint venture that gave us the right to drill up to 77 additional net wells before March 31, 2008 on approximately 212,000 acres in Tennessee.

In our Michigan gas and oil operations:

·   proved reserves of 666.8 Bcfe;

·   direct and indirect working interests in approximately 2,292 gross producing gas and oil wells;

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

·   net daily production of 59.8 Mmcfe per day; and

·   approximately 357,000 gross (285,100 net) acres, of which approximately 63,000 gross (53,300 net) acres, are undeveloped.

In our partnership management business:

·   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; and

·   managed total proved reserves of 503.7 Bcfe.

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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.

Acquisition of DTE Antrim assets

On June 29, 2007, we acquired DTE Gas & Oil Company, now known as Atlas Gas & Oil Company, or AGO, from DTE Energy Company (“DTE” -NYSE:DTE) for $1.3 billion in cash. The assets acquired, which consisted principally of interests in natural gas wells in the Antrim Shale, are the basis for the formation of our gas and oil operations. We funded the purchase price from borrowings under a new credit facility with an initial borrowing base of $850.0 million that matures in June 2012. We intend to continue to expand our business through strategice acquisitions and internal growth projects that increase distributable cash flow.

Private equity offering

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

New credit facility

Upon the closing of the DTE Gas & Oil acquisition, we replaced our credit facility with a new 5-year, credit facility with an initial borrowing base of $850.0 million ($740.0 million outstanding at December 31, 2007). In January 2008, the credit facility has a current borrowing base of $672.5 million, which will be redetermined semi-annually based on changes in our oil and gas reserves. The facility is secured by our assets and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR rate plus the applicable margin, elected at our option. The base rate for any day equals the higher of the federal funds rate plus 0.50% of the JPMorgan prime rate. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for Eurocurrency liabilities. The applicable margin ranges from 0.0% to 1.25% for base rate loans and 1.00% to 2.25% for LIBOR loans. At December 31, 2007, the weighted average interest rate on outstanding borrowings was 7.2%.

RECENT DEVELOPMENTS

Private debt offering

In January 2008, we issued $250.0 million of 10-year, 10.75% senior unsecured notes due 2018. We used the proceeds of the note offering to reduce the balance outstanding on our senior secured credit facility. Interest on the senior notes is payable semi-annually in arrears on February 1 and August 1 of each year. The senior notes are redeemable at any time at certain redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, before February 1, 2011, we may redeem up to 35% of the aggregate principal amount of the senior notes with the proceeds of certain equity offerings at a stated redemption price. The senior notes are also subject to repurchase by us at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if we do not reinvest the net proceeds within 360 days. The senior notes are junior in right of payment to our secured debt, including our obligations under our credit facility. The indenture governing the senior notes contains covenants, including limitations of our ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of our assets.

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New interest rate swap

In January 2008, we entered into an interest rate swap contract for $150.0 million, swapping the floating rate incurred on a portion of our existing senior secured credit facility for a fixed rate of approximately 4.36%, which includes an initial margin of 1.25% over the three year fixed swap rate of 3.11%. The interest rate swap contract will mature in January 2011. Combining the 4.36% interest rate on the new swap and the 10.75% interest rate on the new senior notes, we have fixed $400 million of our outstanding debt at a weighted average interest rate of approximately 8.35%.

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.

Commodity prices

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

In order to address, in part, volatility in commodity prices, we have implemented a hedging program that is intended to reduce the volatility in our revenues. This program mitigates, but does not eliminate, our sensitivity to short-term changes in commodity prices. Please read “Item 7A: -Quantitative and Qualitative Disclosures About Market Risk.”

Natural gas supply and outlook

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

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

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Reserve outlook

Our future oil and gas reserves, production, cash flow and our ability to make payments on our debt and distributions depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. In order to sustain and grow our level of distributions, we will need to make acquisitions that are accretive to distributable cash flow per unit. We intend to pursue acquisitions of producing oil and gas properties from third parties. In addition, we reserve a portion of our cash flow from operations to allow us to develop our oil and gas properties at a level that will allow us to maintain a flat production profile and reserve levels.

Impact of inflation

Inflation in the United States did not have a material impact on our results of operations for the three-year period ended December 31, 2007. It may in the future, however, increase the cost to acquire or replace property, plant and equipment, and may increase the costs of labor and supplies. To the extent permitted by competition and our existing agreements, we have and will continue to pass along increased costs to our investors and customers in the form of higher fees.

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RESULTS OF OPERATIONS

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

							Three Months
	Years Ended						Ended			Year Ended
	December 31,						December 31,			September 30,
Production revenues (in thousands):	2007			2006			2005			2005
Gas (1)(6)	$	169,314		$	79,016		$	21,851		$	55,376
Oil	$	10,768		$	9,384		$	2,227		$	8,039
Production volumes(2):
Appalachia:
Gas (Mcf/d) (1)		27,156			24,511			21,468			20,892
Oil (Bbls/d)		418			413			431			433
Michigan(5):
Gas (Mcf/d)		59,737			-			-			-
Oil (Bbls/d)		4			-			-			-
Total (Mcfe/d)		89,425			26,989			24,054			23,490
Average sales prices:
Gas (per Mcf) (3)(7)	$	8.66		$	8.83		$	11.06		$	7.26
Oil (per Bbl)	$	70.16			62.30			56.13		$	50.91
Production costs (4):
As a percent of production revenues		12	%		10	%		7	%		10	%
Per Mcfe-Appalachia	$	0.89		$	0.86		$	0.78		$	0.71
Per Mcfe-Michigan	$	1.06			-			-			-
Total per Mcfe	$	0.97		$	0.86		$	0.78		$	0.71
Transportation costs:
Per Mcfe-Appalachia	$	0.74		$	0.55		$	0.32		$	0.24
Per Mcfe-Michigan	$	0.26			-			-			-
Depletion per Mcfe	$	2.49		$	2.08		$	2.01		$	1.42

_______________

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

(2)   Production quantities consist of the sum of (i) our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells, and (ii) our proportionate share of production from wells owned by the investment partnerships in which we have an interest, based on our equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells.

(3)   Our average sales price before the effects of financial hedging were $7.22 per Mcf and $7.90 per Mcf for the years ended December 31, 2007 and 2006, respectively. 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.

(5)   Amounts represent production volumes related DTE Gas & Oil from the acquisition date (June 29, 2007).

(6)   Excludes non-qualifying hedge gains of $26.3 million associated with the DTE Gas & Oil acquisition in the year ended December 31, 2007.

(7)   Includes $12.3 million in derivative proceeds, which were not included as gas revenue in the year ended December 31, 2007.

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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 and number of net wells drilled during the periods indicated (dollars in thousands):

					Three Months
	Years Ended				Ended		Year Ended
	December 31,				December 31,		September 30,
	2007		2006		2005		2005
Average construction and completion revenue per well	$	317	$	307	$	225	$	218
Average construction and completion cost per well		276		267		196		190
Average construction and completion segment margin per well	$	41	$	40	$	29	$	28
Segment margin	$	41,931	$	25,901	$	5497	$	17,552
Net wells drilled		1,014		647		187		615

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Gas and Oil Production

Our natural gas revenues were $169.3 million in the year ended December 31, 2007, an increase of $90.3 million (114%) from $79.0 million in the year ended December 31, 2006. The increase was attributable to volumes associated with our Michigan operations acquired on June 29, 2007 and an 11% increase in the production volumes of our Appalachian operating area. The $90.3 million increase in natural gas revenues consisted of $97.1 million attributable to increases in production volumes partially, offset by $6.8 million attributable to decreases in natural gas prices.

We believe that gas volumes will continue to be favorably impacted in 2008 with the contribution of our Michigan business unit and as ongoing projects to extend and enhance the gathering systems of Atlas Pipeline are completed and wells drilled are connected in these areas of expansion.

Our oil revenues were $10.8 million in the year ended December 31, 2007, an increase of $1.4 million (15%) from $9.4 million in the year ended December 31, 2006. The increase resulted from a 13% increase in the average sales price of oil, and a 2% increase in production volumes. The $1.4 million increase consisted of $1.2 million attributable to increases in sales prices, and $199,000 attributable to volume increases. We drill primarily for natural gas rather than oil.

Our production costs were $32.2 million in the year ended December 31, 2007, an increase of $18.3 million (132%) from $13.9 million in the year ended December 31, 2006. This increase is attributable to $14.6 million of production costs associated with our acquisition of DTE Gas & Oil on June 29, 2007 and a $3.1 million increase in transportation charges, water hauling and labor and maintenance costs associated with an increase in the number of wells we own in Appalachia from the prior year period.

Partnership Management

Well Construction and Completion

Our well construction and completion segment margin was $41.9 million in the year ended December 31, 2007, an increase of $16.0 million (62%) from $25.9 million in the year ended December 31, 2006. During the year ended December 31, 2007, the increase of $16.0 million in segment margin was attributable to an increase in the number of wells we drilled ($15.2 million) and an increase in the gross profit per well ($864,000). The increase in the number of wells we drilled of 367 is a result of an increase in our fundraising in 2007. Since our drilling contracts are on a “cost plus” basis (typically cost-plus 15%), an increase in our average costs per well also results in an increase in our average revenue per well.

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It should be noted that “Liabilities associated with drilling contracts” on our balance sheet includes $118.0 million of funds raised in our investment programs that have not been applied to the completion of wells as of December 31, 2007 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 in the first half of 2008. During the year ended December 31, 2007, we raised $363.3 million and plan to raise approximately $400.0 million in fiscal 2008. We anticipate favorable oil and gas prices will continue to favorably impact our fundraising and therefore our drilling revenues in the year ending December 31, 2008.

Administration and Oversight

Administration and oversight represents supervision and administrative fees earned for the drilling and subsequent management of wells for our investment partnerships. Our administration and oversight fees were $18.1 million in the year ended December 31, 2007, an increase of $6.3 million (53%) from $11.8 million in the year ended December 31, 2006. This increase resulted from an increase in the number of wells drilled and managed for our investment partnerships in the year ended December 31, 2007 as compared to the year ended December 31, 2006.

Well Services

Our well services revenues were $17.6 million in the year ended December 31, 2007, an increase of $4.6 million (35%) from $13.0 million in the year ended December 31, 2006. This increase resulted from an increase in the number of wells operated for our investment partnerships due to additional wells drilled in the year ended December 31, 2007.

Our well services expenses were $9.1 million in year ended December 31, 2007, an increase of $1.8 million (25%) from $7.3 million in the year ended December 31, 2006. This increase was attributable to an increase in wages, benefits, and field office expenses associated with an increase in employees due to the increase in the number of wells we operate for our investment partnerships.

Gathering

We charge transportation fees to our investment partnership wells that are connected to Atlas Pipeline’s Appalachian gathering systems. Prior to our initial public offering, our predecessor 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 its gathering agreements with it. In connection with the completion of our initial public offering, Atlas America assumed our obligation to pay gathering fees to Atlas Pipeline. We are obligated to pay the gathering fees we receive from our investment partnerships to Atlas America, with the result that our Appalachian 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. During the year ended December 31, 2007, we also received $327,000 in transportation and natural gas liquid revenues from our Michigan operations.

Our gathering fee paid to Atlas Pipeline was $13.8 million for the year ended December 31, 2007, a decrease of $15.7 million (53%) from $29.5 million in the year ended December 31, 2006. The decrease in the year ended December 31, 2007 is primarily a result of the assumption by Atlas America of our obligation to pay Atlas Pipeline under our gas gathering agreement with it.

All Other Income, Costs and Expenses

Gain on mark-to-market derivatives

Our gain on mark-to-market derivatives represents non-cash gains recognized on derivatives. We recognized a $26.3 million non-cash gain related to the change in value of derivative contracts associated with the acquisition of AGO on June 29, 2007. The contracts entered into were derivative contracts to hedge the projected production volume of AGO before the closing of the acquisition. The production volumes of the assets to be acquired were not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the assets had not yet been completed. Accordingly, we recorded the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative values recorded within our combined and consolidated statements of income. Upon closing of the acquisition, the production volumes of the assets acquired was considered “probable forecasted production” under SFAS No. 133 and we evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133. For the year ended December 31, 2007, we received $18.4 million in proceeds on derivative contracts that settled, including, $12.3 million related to our mark-to-market non-cash derivative gain of $26.3 million, for a net gain included in gas revenues of $6.1 million.

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General and Administrative

Our general and administrative expenses were $39.4 million in the year ended December 31, 2007, an increase of $16.0 million (69%) from $23.4 million in the year ended December 31, 2006. These expenses include, among other things, salaries and benefits not allocated to a specific segment, costs of running our corporate offices, partnership syndication activities and outside services. The increase of $16.0 million in the year ended December 31, 2007 is principally attributed to the following:

·   costs associated with AGO were $3.3 million in the current year;

·   exploration costs in Appalachia increased $1.0 million due to an increase in activities of our land department as we acquire additional acreage and well sites;

·   salaries and wages increased $1.1 million due to an increase in executive salaries and in the number of employees as a result of our initial public offering and growth of our business;

·   noncash stock compensation increased $4.4 million as a result of options and units granted upon our initial public offering and the acquisition of AGO;

·   we paid $3.9 million in fees related to hedging natural gas volumes associated with the acquisition of AGO on June 29, 2007; and

·   accounting and professional fees increased $1.8 million due to the growth of our business, higher audit fees and the implementation of Sarbanes-Oxley Section 404 compliance.

Depletion

Our depletion of oil and gas properties as a percentage of oil and gas revenues was 30% in the year ended December 31, 2007, compared to 23% in the year ended December 31, 2006. Depletion expense was $2.49 per Mcfe in the year ended December 31, 2007, an increase of $0.41 (20%) from $2.08 per Mcfe in the year ended December 31, 2006. Increases in our depletable basis associated with the AGO acquisition and wells drilled for our investment partnerships and associated production volumes caused depletion expense to increase $33.9 million (165%) to $54.4 million in the year ended December 31, 2007 compared to $20.5 million in the year ended December 31, 2006. Depletion expense associated with our Michigan asset base was $28.3 million for the year ended December 31, 2007. The variances from period to period are directly attributable to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties.

Interest Expense

Interest expense was $30.1 million in the year ended December 31, 2007 which was incurred on our new credit facility. Atlas America did not allocate interest expense associated with its credit facility to us prior to our initial public offering in December 2006.

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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

Gas and Oil Production

 Our natural gas revenues were $21.9 million in the three months ended December 31, 2005. We experienced favorable natural gas prices which averaged $11.06 per Mcf for the quarter. Our oil revenues were $2.2 million in the three months ended December 31, 2005. Oil prices were also favorably impacted and averaged $56.13 per barrel for the quarter. Total gas and oil production volumes for the period were 24,054 Mcfe per day.

Our production costs, including transportation fees, were $2.4 million in the three months ended December 31, 2005. Production costs as a percentage of production revenue decreased to 10% of production revenue as a result of an increase in our average sales price. Additionally, we experienced an increase in production costs per mcfe due to increases in transportation and labor costs.

Partnership Management

Well Construction and Completion

Our well construction and completion segment margin was $5.5 million in the three months ended December 31, 2005. During this period, 187 wells (net to our interest) were drilled.

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. These fees have continued to increase as a result of the increase in the number of wells we manage for our investment partnerships.

Well Services

Our well services revenues and expenses were $2.6 million and $1.5 million, respectively, for a gross margin of $1.1 million in the three months ended December 31, 2005. These revenues and expenses are continuing to increase as the number of wells we operate for our investment partnerships increases.

Gathering

Our gathering fee to Atlas Pipeline was $7.9 million for the three months ended December 31, 2005, and represents fees paid to Atlas Pipeline prior to our initial public offering, which were generally 16% of the gas sales price.

All Other Income, Costs and Expenses

General and Administrative

Our general and administrative expenses were $5.8 million in the three months ended December 31, 2005, and consisted principally of the following:

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·   net syndication costs of $738,000 related to fund raising expenses in our public and private investment partnerships;

·   professional and legal fees of $1.0 million related to insurance, audit, and the Sarbanes-Oxley Section 404 compliance; and

·   salaries and wages of $3.8 million.

Depletion

Our depletion expense was $4.4 million in the three months ended December 31, 2005. Depletion of oil and gas properties as a percentage of oil and gas revenues was 18% and our depletion expense per Mcfe was $2.01 in the three months ended December 31, 2005.

Year Ended September 30, 2005

Gas and Oil Production

Our natural gas revenues were $55.4 million in the year ended September 30, 2005.  Our natural gas prices averaged $7.26 per Mcf for the fiscal year. Our oil revenues were $8.0 million in the year ended September 30, 2005. Our oil prices averaged $50.91 per barrel for the fiscal year.  Total gas and oil production volumes for the period were 23,490 Mcfe per day.

Our production costs were $8.2 million in the year ended September 30, 2005. Production costs, including transportation as a percent of revenues, were 13% for the fiscal year.

Partnership Management

Well Construction and Completion

Our well construction and completion segment margin was $17.6 million in the year ended September 30, 2005. During this period, 615 wells (net to our interest) were drilled.

Administration and Oversight

Our administration and oversight fees were $9.6 million in the year ended September 30, 2005. These fees represent charges to manage the wells drilled for our investment partnerships.

Well Services

Our well services revenues and expenses were $9.6 million and $5.2 million, respectively, for a gross margin of $4.4 million in the year ended September 30, 2005.

Gathering

Our gathering fee to Atlas Pipeline was $21.9 million in the year ended September 30, 2005, and represents fees paid to Atlas Pipeline prior to our initial public offering, which were generally 16% of the natural gas sales price.

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All Other Income, Costs and Expenses

General and Administrative

Our general and administrative expenses were $13.2 million in the year ended September 30, 2005 and consisted principally of the following:

·   net syndication costs of $3.1 million related to our fundraising expenses in our public and private partnerships;

·   professional and legal fees of $5.7 million related to insurance, audit and implementation of Sarbanes-Oxley Section 404 compliance; and

·   salaries and wages of $2.0 million.

Depletion

Our depletion expense was $12.2 million in the year ended September 30, 2005. Depletion of oil and gas properties as a percentage of oil and gas revenues was 19% in the year ended September 30, 2005 and our depletion expense was $1.42 per Mcfe in the year ended September 30, 2005.

LIQUIDITY AND CAPITAL RESOURCES

General

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

							Three Months
	Years Ended						Ended			Year Ended
	December 31,						December 31,			September 30,
	2007			2006			2005			2005
Provided by operations	$	230,982		$	80,536		$	43,596		$	90,525
Used in investing activities		(1,468,434	)		(75,588	)		(17,185	)		(59,050	)
Provided by (used in) financing activities		1,253,877			(17,033	)		(11,739	)		(25,401	)
Increase (decrease) in cash and cash equivalents	$	16,425		$	(12,085	)	$	14,672		$	6,074

We had $25.3 million in cash and cash equivalents at December 31, 2007, as compared to $8.8 million at December 31, 2006. We had a working capital deficit of $102.0 million at December 31, 2007, an increase of $14.0 million from a working capital deficit of $88.0 million at December 31, 2006.  The increase in our working capital deficit is due to an increase of $45.8 million in liabilities associated with drilling contracts, partially offset by an increase of $26.2 million in accounts receivable primarily due to the AGO acquisition. Our level of liabilities associated with drilling contracts is dependent upon the remaining amount of our drilling obligations at any balance sheet date, which is dependent upon the timing and level of funds raised through our investment partnerships. At December 31, 2007, we have $108.9 million available under our credit facility to fund working capital obligations.

Capital Requirements

Capital expenditures. During the year ended December 31, 2007, our capital expenditures consisted of maintenance capital expenditures and expansion capital expenditures, as defined below:

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

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

During the year ended December 31, 2007, our capital expenditures related primarily to investments in our investment partnerships, in which we invested $137.6 million. For the years ended December 31, 2006, the three months ended December 30, 2005 and the year ended September 30, 2005, our capital expenditures related primarily to investments in our partnerships, which totaled $73.6 million, $15.2 million and $57.9 million, respectively. We funded and expect to continue to fund these capital expenditures through cash on hand, from operations and from amounts available under our credit facility.

The level of capital expenditures we devote to our exploration and production operations depends upon any acquisitions made and the level of funds raised through our investment partnerships.  During the year ended December 31, 2007, we raised $363.3 million. For the years ended December 31, 2006 and September 30, 2005, we had raised $218.5 million and $148.7 million, respectively. We believe cash flows from operations and amounts available under our credit facility will be adequate to fund our capital expenditures.  However, the amount of funds we raise and the level of our capital expenditures will vary in the future depending on market conditions for natural gas and other factors.  

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

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

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

					Three Months
	Years Ended				Ended		Year Ended
	December 31,				December 31,		September 30,
	2007		2006		2005		2005
Maintenance capital expenditures (1)	$	43,450	$	─	$	─	$	─
Expansion capital expenditures (1)		1,421,186		─		─		─
Total	$	1,464,636	$	75,635	$	17,187	$	59,124

___________________

⁽¹⁾We did not characterize capital expenditures as maintenance or expansion and did not plan capital expenditures in a manner intended to maintain or expand our asset base or production before our initial public offering on December 31, 2006.

Credit Facility

Simultaneously with the closing of our acquisition of DTE Gas & Oil, we entered into a senior secured credit facility with an initial borrowing base of $850.0 million ($740.0 million outstanding at December 31, 2007) with JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities, Inc., as lead arranger, and other lenders. The credit facility allows us to borrow up to the determined amount of the borrowing base, which is based upon the loan collateral value assigned to our various natural gas and oil properties. The credit facility borrowing base will redetermined based on changes in our oil and gas reserves. The credit facility will mature in June 2012. In January 2008, the borrowing base for Atlas Energy Operating Company was reduced from $850.0 million to $672.5 million upon our issuance of $250.0 million in senior notes. See Item 7: “Management’s Discussion and Analysis of Financial Condition and Results of Operations, RECENT DEVELOPMENTS”.

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CASH FLOWS

Year ended December 31, 2007 compared to year ended December 31, 2006

Cash flows from operating activities.Cash provided by operations is an important source of short-term liquidity for us.  It is directly affected by changes in the price of natural gas and oil, interest rates and our ability to raise funds from our drilling investment partnerships.  Netcash provided by operating activities increased $150.5 million in the year ended December 31, 2007 to $231.0 million from $80.5 million in the year ended December 31, 2006, substantially as a result of the following:

·   an increase in net income before depreciation, depletion and amortization of $96.8 million in the year ended December 31, 2007 as compared to the prior year period, principally due to the contribution of our Michigan operations acquired on June 29, 2007 and increases in net income from our partnership management operations and our Appalachian production segment;

·   a decrease in non-cash items of $3.3 million related to our compensation expense resulting from grants under long-term incentive plans, non-cash gains of derivatives and the impact of cumulative change in accounting principle; and

·   changes in operating assets and liabilities increased operating cash flows by $56.6 million in the year ended December 31, 2007, compared to the year ended December 30, 2006.

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

· a decrease of $12.1 million in accounts receivable and prepaid expenses;

· an increase of $15.0 million in accounts payable and accrued expenses; and

· an increase of $29.5 million in liabilities associated with our drilling contracts. Our level of liabilities associated with drilling contracts is dependent upon the remaining amount of our drilling obligations at any balance sheet date, which is dependent upon the timing and level of funds raised through our investment partnerships.

Cash flows used in investing activities.Cash used in our investing activities increased $1.4 billion in the year ended December 31, 2007 to $1.5 billion from $75.6 million in the year ended December 31, 2006 primarily from our $1.3 billion acquisition of DTE Gas & Oil and a $121.1 million increase in capital expenditures related to the increase in the number of wells we drilled in fiscal 2007.

Cash flows from financing activities. Cash provided by our financing activities increased $1.3 billion in the year ended December 31, 2007 to $1.3 billion from cash used of $17,000 in the year ended December 31, 2006, principally as a result of the following: 

·   to fund the acquisition of DTE Gas & Oil on June 29, 2007, we borrowed $713.9 million on our credit facility;

·   we borrowed additional funds on our credit facility, net of repayments of $26.1 million, to fund our investments in our partnerships;

·   net monies remitted to Atlas America during the year ended December 31, 2007 as compared to the year ended December 31, 2006 increased financing cash flows by $12.9 million;

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·   in the year ended December 31, 2006, we distributed $139.9 million to Atlas America;

·   net proceeds of from issuances of units increased $457.6 million in the year ended December 31, 2007 as compared to December 31, 2006;

·   deferred financing costs increased $10.3 million in the year ended December 31, 2007 due to our new credit facility used to fund our acquisition of AGO; and

·   we paid $69.3 million in distributions to our unit holders in the year ended December 31, 2007.

Three months ended December 31, 2005

Cash flows from operating activities. Net cash provided by operating activities was $43.6 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;

·   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.

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

Cash flows used in financing activities. Cash used in our financing activities was $11.7 million primarily due to funds paid to our affiliate.

Year ended September 30, 2005

Cash flows from operating activities.Net cash provided by operating activities was $90.5 million in the year ended September 30, 2005 as a result of the following:

· net income before depreciation, depletion and amortization was $55.5 million; and

· changes in operating assets and liabilities increased operating cash flows by $34.3 million in the year ended September 30, 2005, and relates primarily to $31.6 million in liabilities associated with our drilling contracts.

Cash flows used in investing activities. Net cash used in our investing activities was $59.1 million in the year ended September 30, 2005 primarily related to capital expenditures we made in our investment partnerships.

Cash flows used in financing activities. Net cash used in our financing activities was $25.4 million primarily due to funds paid to our affiliate.

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, 2007 and 2006, we received on average of $8.66 and $8.83 per Mcf of natural gas and $70.16 and $62.30 per Bbl of oil, respectively. During the three months ended December 31, 2005, we received an average of $11.06 per Mcf of natural gas and $56.13 per Bbl of oil, respectively. During the year ended September 30, 2005, we received an average of $7.26 per Mcf of natural gas and $50.91 per Bbl of oil.

Although certain of our costs and expenses are affected by general inflation, inflation has not normally had a significant effect on us. However, inflationary trends may occur if the price of natural gas were to increase since such an increase may increase the demand for acreage and for energy equipment and services, thereby increasing the costs of acquiring or obtaining such equipment and services.

ENVIRONMENTAL REGULATION

To date, compliance with environmental laws and regulations has not had a material impact on our capital expenditures, earnings or competitive position. We have complied with the spill prevention plan requirements on our operations, including pending changes by United States Environmental Protection Agency to the federal regulations that required 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.

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CASH DISTRIBUTIONS

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

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

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

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

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

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

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

Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to unitholders. We seek to maintain a coverage ratio for our distributions of at least 1.2x on a rolling 4-quarter basis. Our coverage ratio for the quarter ended December 31, 2007 was 1.3x. We calculate our coverage ratio as the amount of all of our cash receipts less disbursements, including interest expense and estimated maintenance capital expenditures, divided by the amount of distributions to our unitholders.

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

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

On January 28, 2008, we declared our quarterly cash distribution for the fourth quarter of 2007 of $0.57 per common unit. The $35.6 million distribution was paid on February 14, 2008 to unitholders of record as of February 7, 2008.

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.

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CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The following table summarizes our contractual obligations at December 31, 2007:

			Payments due by period
			(in thousands)
			Less than		2 - 3		4 - 5		After 5
Contractual cash obligations:	Total		1 Year		Years		Years		Years
Long-term debt(1)	$	740,030	$	30	$	—	$	740,000	$	—
Secured revolving credit facilities		—		—		—		—		—
Operating lease obligations		7,103		1,282		2,098		1,222		2,501
Capital lease obligations		—		—		—		—		—
Unconditional purchase obligations		—		—		—		—		—
Other long-term obligation		—		—		—		—		—
Total contractual cash obligations	$	747,133	$	1,312	$	2,098	$	741,222	$	2,501

___________

(1) Not included in the table above are estimated interest payments calculated at the rates in effect at December 31, 2007 of: 2008 - $53.3 million; 2009 - $53.3 million; 2010 - $53.3 million; 2011 - $53.3 million and 2012 - $26.5 million.

			Payments due by period
			(in thousands)
			Less than		1 - 3		4 - 5		After 5
Other commercial commitments:	Total		1 Year		Years		Years		Years
Standby letters of credit	$	1,109	$	1,109	$	—	$	—	$	—
Guarantees		32,857		5,434		11,045		10,689		5,689
Standby replacement commitments		—		—		—		—		—
Other commercial commitments		—		—		—		—		—
Total commercial commitments	$	33,966	$	6,543	$	11,045	$	10,689	$	5,689

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, 2007 and 2006 our credit evaluation indicated that we have no need for an allowance for possible losses for our oil and gas receivables.

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Derivative Instruments

We apply the provisions of SFAS No. 133, “Accounting for Derivative Instruments and HedgingActivities”, or  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. See Note 7 to our combined and consolidated financial statements.

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. In addition, 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, but are not limited to, 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.

Asset Retirement Obligations

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, 2007 and 2006, 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.

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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.

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 generally sell natural gas and crude oil at prevailing market prices. Revenue is recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which we have an interest with other producers is recognized on the basis of our percentage ownership of working interest or overriding royalty. Generally, our sales contracts are based on pricing provisions that are tied to a market index, with certain adjustments based on proximity to gathering and transmission lines and the quality of our natural gas.

Income Taxes

We are a limited liability company and have elected to be treated as a partnership for income tax purposes.  As a result, we are not subject to U.S. federal and most state income taxes.  Our unitholders are liable for income taxes on their distributive share of our taxable income.  Such taxable income may vary substantially from net income reported in the accompanying combined and consolidated financial statements.   Certain of our corporate subsidiaries are subject to federal and state income tax.  The federal and state income taxes related to us and these corporate subsidiaries were immaterial to the combined and consolidated financial statements and are recorded in pre-tax income on a current basis only.  Accordingly, no federal or state deferred income tax has been provided for in the accompanying combined and consolidated financial statements. 

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In June 2006, the FASB released FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes”, an Interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 provides guidance for how uncertain tax positions should be recognized, measured, presented and disclosed in the financial statements. FIN 48 requires the evaluation of tax positions taken or expected to be taken in the course of preparing our tax returns to determine whether the tax positions have met a “more-likely-than-not” threshold of being sustained by the applicable tax authority. Tax benefits related to tax positions not deemed to meet the more-likely-than-not threshold are not permitted to be recognized in the financial statements.  The provisions of FIN 48 were adopted by us effective January 1, 2007.  Implementation of FIN 48 had no impact on our combined and consolidated financial statements for the year ended December 31, 2007.  Our policy is to reflect interest and penalties related to uncertain tax positions as part of income tax expense, when and if they become applicable.

We file income tax returns in the U.S. federal and various state jurisdictions. With limited exceptions, we are no longer subject to income tax examinations by major tax authorities for years before 2006. 

RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS

In December 2007, the Financial Accounting Standards Board, or FASB, issued SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements”, or SFAS 160. This statement amends Accounting Research Bulletin 51, “Consolidated Financial Statements,” to establish accounting and reporting standards for the noncontrolling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This statement is effective for fiscal periods beginning on or after December 15, 2008. We do not expect the adoption of SFAS 160 to have a significant impact on our financial position or results of operations.

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

In September 2007, the Emerging Issues Task Force, or EITF, reached consensus on EITF Issue No. 07-4, “Application of the two-class method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships”, or EITF No. 07-4, an update of EITF No. 03-6. EITF No. 07-4 requires the calculation of a Master Limited Partnership’s (“MLPs”) net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings as if all of the earnings for that period had been distributed. In periods with undistributed earnings above specified levels, the calculation per the two-class method results in an increased allocation of such undistributed earnings to the general partner and a dilution of earnings to the limited partners. EITF No. 07-4 is effective for fiscal years beginning after December 15, 2007. The application of EITF 07-4 is not expected to have an effect on our earnings per unit calculation.

In April 2007, the FASB issued FASB Staff Position FIN 39-1, “Amendment of FASB Interpretation No. 39,” or FSP FIN 39-1, which refers to FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts” or FIN 39. FSP FIN 39-1 amends FIN 39, which allows an entity to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. FSP FIN 39-1 was effective for fiscal years beginning after November 15, 2007. We do not expect the adoption of FSP FIN 39-1 to have an impact on our financial position or results of operations.

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In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” or SFAS 159. SFAS 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. 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 do not expect the adoption of FASB 159 to have a significant impact 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. In February 2008, the FASB issued Final FASB Staff Position, or FSP No. FAS 157-2. The FSP, which was effective upon issuance, delays the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value at least once a year, to fiscal years beginning after November 15, 2008. The FSP also covers interim periods within the fiscal years for items within its scope. The delay is intended to allow the FASB and its constituents the time to consider the various implementation issues associated with SFAS 157. We do not expect the adoption of SFAS 157 to have a significant impact on our financial position or results of operations.

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 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, 2007. Only the potential impacts of hypothetical assumptions are analyzed. The analysis does not consider other possible effects that could impact our business.

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Interest Rate Risk

At December 31, 2007, we have a revolving credit facility with an initial borrowing base of $850.0 million, of which $741.1 million was outstanding (including $1.1 million in letters of credit). The weighted average interest rate for borrowings under this credit facility was 7.2% at December 31, 2007.

New Interest Rate Swap

In January 2008, we entered into an interest rate swap contract for $150.0 million, swapping the floating rate incurred on a portion of our existing senior secured credit facility for a fixed rate of approximately 4.36%, which includes an initial margin of 1.25% over the three year fixed swap rate of 3.11%. The interest rate swap contract will mature in January 2011. Combining the 4.36% interest rate on the new swap and the 10.75% interest rate on the new senior notes, we have fixed $400 million of our outstanding debt at a weighted average interest rate of approximately 8.35%. With the subsequent changes in our debt structure above, a hypothetical 10% change in the weighted average interest rate would change our net income by approximately $5.5 million.

Commodity Price Risk

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

Our risk management objective is to lock in a range of pricing for expected production volumes. Considering those volumes for which we have entered into financial hedge agreements for the year ending December 31, 2008, and current indices, a theoretical 10% upward or downward change in the price of natural gas would result in a change in net income of approximately $5.7 million.

We formally document all relationships between hedging instruments and the items being hedged, including the risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. We assess, both at the inception of the hedge and on an ongoing basis, whether the derivatives are highly effective in offsetting changes in the fair value of hedged items. Historically these contracts have qualified and been designated as cash flow hedges in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, or SFAS 133, and are recorded at their fair values. Gains or losses on future contracts are determined as the difference between the contract price and a reference price, generally prices on NYMEX. 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.

As of December 31, 2007, we had financial hedges in place for approximately 80% of our expected production volumes for the year ending December 31, 2008. At December 31, 2007, we had 360 open natural gas futures contracts related to natural gas sales covering 130.6 million MMBtus of natural gas, (which includes 72.6 million MMBtus covering natural gas production assets acquired from AGO), maturing through December 31, 2012 at an average settlement price of $8.32 per MMBtu. On May 18, 2007, we signed a definitive agreement to acquire AGO (see Note 3 to our combined and consolidated financial statements). In connection with the financing of this transaction, we agreed as a condition precedent to closing that we would hedge 80% of our projected natural gas volumes for no less than three years from the closing date of the transaction. During May 2007, we entered into derivative instruments to hedge 80% of the projected production of the assets to be acquired as required under the financing agreement. The production volume of the assets to be acquired was not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the assets had not yet been completed. Accordingly, we recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within revenues in our combined and consolidated statements of income. We recognized non-cash income of $26.3 million related to the change in value of these derivatives from May 22, 2007 to June 28, 2007, which is shown as “Gain on mark-to-market derivatives” in the combined and consolidated statements of income for the years ended December 31, 2007 and 2006. Upon closing of the acquisition on June 29, 2007, the production volumes of the assets acquired were considered “probable forecasted production” under SFAS No. 133 and we evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133. In addition, we recognized gains on settled contracts covering natural gas production of $17.6 million and $7.1 million for the years ended December 31, 2007 and 2006, respectively. As the underlying prices and terms in our hedge contracts were consistent with the indices used to sell our natural gas, there were no gains or losses recognized during the years ended December 31, 2007 and 2006, respectively for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges. We did not enter into any hedging contracts in the three months ended December 31, 2005 or year ended September 30, 2005.

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Of the $5.1 million net loss in accumulated other comprehensive income (loss) at December 31, 2007, we will reclassify $21.1 million of gains to our consolidated statements of income over the next twelve month period as these contracts expire and $26.2 million of losses will be reclassified in later periods if the fair values of the instruments remain at current market values.

Of the $5.5 million net unrealized hedge asset at December 31, 2007, our portion is $8.9 million, and $3.4 million of unrealized hedge losses have been reallocated to our investment partnerships.

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

Fixed Price Swaps

Twelve Month			Average		Fair Value
Period Ending	Volumes		Fixed Price		Asset (Liability)
December 31,	(MMBtu)		(per MMBtu)		(in thousands) (1)
2008		35,960,000	$	8.86	$	37,457
2009		32,720,000		8.50		170
2010		23,000,000		8.01		(11,398	)
2011		17,600,000		7.79		(10,939	)
2012		9,000,000		7.74		(5,242	)
					$	10,048

Costless Collars

Twelve Month					Average		Fair Value
Period Ending			Volumes		Floor and Cap		Asset (Liability)
December 31,	Option Type		(MMBtu)		(per MMBtu)		(in thousands)(1)
2008		Puts purchased		1,560,000	$	7.50	$	368
2008		Calls sold		1,560,000		9.40		—
2010		Puts purchased		2,880,000		7.75		—
2010		Calls sold		2,880,000		8.75		(948	)
2011		Puts purchased		7,200,000		7.50		—
2011		Calls sold		7,200,000		8.45		(3,495	)
2012		Puts purchased		720,000		7.00		—
2012		Calls sold		720,000		8.37		(470	)
								(4,545	)
						Total net asset	$	5,503

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

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ITEM 8:FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

[THE REMAINDER OF THIS PAGE IS INTENTIONALLY LEFT BLANK]

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Atlas Energy Resources, LLC

We have audited the accompanying consolidated balance sheets of Atlas Energy Resources, LLC and subsidiaries (a Delaware limited liability company) as of December 31, 2007 and 2006, and the related combined and consolidated statements of income, comprehensive income, equity, and cash flows for the years ended December 31, 2007 and 2006, the three month period ended December 31, 2005 and the year ended September 30, 2005. 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.An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.An audit also includes 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 and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for the years ended December 31, 2007 and 2006, the three month period ended December 31, 2005 and the year ended September 30, 2005 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Atlas Energy Resources, LLC’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 27, 2008 expressed an unqualified opinion.

As also discussed in Note 2 to the combined and consolidated financial statements, the Company recorded a cumulative effect adjustment in 2006 in connection with the adoption of FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.”

/s/ GRANT THORNTON LLP

Cleveland, Ohio

February 27, 2008

66

ATLAS ENERGY RESOURCES, LLC

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,
	2007			2006
ASSETS
Current assets:
Cash and cash equivalents	$	25,258		$	8,833
Accounts receivable		57,524			31,280
Current portion of hedge asset		38,181			27,618
Prepaid expenses and other		8,265			3,251
Total current assets		129,228			70,982
Property, plant and equipment, net		1,693,467			277,814
Other assets, net		28,312			26,290
Intangible assets, net		5,061			5,211
Goodwill		35,166			35,166
	$	1,891,234		$	415,463
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	30		$	38
Accounts payable		55,051			37,931
Liabilities associated with drilling contracts		132,517			86,765
Current portion of hedge liability		356			172
Accrued liabilities		34,535			21,534
Total current liabilities		222,489			146,440
Long-term debt		740,000			30
Other long-term liabilities		2,372			13,248
Advances from affiliates		8,696			12,502
Long-term hedge liability		39,204			3,835
Asset retirement obligations		42,358			26,726
Commitments and contingencies (Note 8)
Members’ equity:
Class B common unit holders		835,447			187,769
Class A unit holder		5,770			3,825
Accumulated other comprehensive income (loss)		(5,102	)		21,088
Total members’ equity		836,115			212,682
	$	1,891,234		$	415,463

See accompanying notes to combined and consolidated financial statements

67

ATLAS ENERGY RESOURCES, LLC

COMBINED AND CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per unit data)

						Three Months		Year
	Years Ended					Ended		Ended
	December 31,					December 31,		September 30,
	2007			2006		2005		2005
REVENUES
Gas and oil production	$	180,125		$	88,449	$	24,086	$	63,499
Well construction and completion		321,471			198,567		42,145		134,338
Administration and oversight		18,138			11,762		2,964		9,590
Well services		17,592			12,953		2,561		9,552
Gathering		14,314			9,251		1,407		4,359
Gain on mark-to-market derivatives		26,257			—		—		—
Total revenues		577,897			320,982		73,163		221,338
COSTS AND EXPENSES
Gas and oil production		32,193			13,881		2,441		8,165
Well construction and completion		279,540			172,666		36,648		116,816
Well services		9,062			7,337		1,487		5,167
Gathering		214			—		38		52
Gathering fee - Atlas Pipeline		13,781			29,545		7,930		21,929
General and administrative		39,414			23,367		5,818		13,202
Net expense reimbursement - affiliate		—			1,237		163		602
Depreciation, depletion and amortization		56,942			22,491		4,916		14,061
Total operating expenses		431,146			270,524		59,441		179,994
OPERATING INCOME		146,751			50,458		13,722		41,344
OTHER INCOME (EXPENSE)
Interest expense		(30,096	)		—		—		—
Other - net		849			1,369		57		79
Total other income (expense)		(29,247	)		1,369		57		79
Net income before cumulative effect of accounting change		117,504			51,827		13,779		41,423
Cumulative effect of accounting change		─			6,355		—		—
Net income	$	117,504		$	58,182	$	13,779	$	41,423
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
Portion applicable to members’ interests (period subsequent to the initial public offering on December 18, 2006)		117,504			2,807		—		—
	$	117,504		$	58,182	$	13,779	$	41,423
Allocation of net income attributable to members’ interests:
Class A units	$	4,099			56
Class B common units		113,405		$	2,751
Net income attributable to members’ interests	$	117,504		$	2,807
Net income per Class B common unit:
Basic	$	2.32		$	.08
Diluted	$	2.29		$	.08
Weighted average Class B common units outstanding:
Basic		48,909			36,627
Diluted		49,449			36,638

See accompanying notes to combined and consolidated financial statements

68

ATLAS ENERGY RESOURCES, LLC

COMBINED AND CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

							Three Months
	Years Ended						Ended			Year Ended
	December 31,						December 31,			September 30,
	2007			2006			2005			2005
Net income before taxes	$	117,504		$	58,182		$	13,779		$	41,423
Other comprehensive income:
Unrealized holding gains (losses) on hedging contracts		(8,582	)		31,834			(3,664	)		—
Less: reclassification adjustment for gains realized in net income		(17,608	)		(7,082	)		—			—
		(26,190	)		24,752			(3,664	)		—
Comprehensive income	$	91,314		$	82,934		$	10,115		$	41,423

See accompanying notes to combined and consolidated financial statements

69

ATLAS ENERGY RESOURCES, LLC

COMBINED AND CONSOLIDATED STATEMENTS OF EQUITY

(in thousands, except unit data)

																				Accumulated						Total
																				Other						Owner's
																				Comprehensive			Net			Equity/
	Owner's			Class A Units					Class B Common Units					Class D Units						Income			Affiliate			Members'
	Equity			Units		Amount			Units		Amount			Units			Amount			(Loss)			Investment			Equity
Balance, October 1, 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 compensation income		—			—		—			—		—			—			—			24,752						24,752
Balance, December 31, 2006	$	—			748,456	$	3,825			36,626,746	$	187,769			—		$	—		$	21,088		$	—		$	212,682
Units issued		—			490,530		—			7,380,800		181,179			16,702,828			416,316			—			—			597,495
Stock based compensation		—			—		—			—		4,684			—			—			—			—			4,684
Distributions to members		—			—		(2,154	)		—		(57,941	)		—			(9,187	)		—			—			(69,282	)
Distributions paid on unissued
units under incentive plan		—			—		—			—		(778	)		—			—			—			—			(778	)
Other comprehensive income		—			—		—			—		—			—			—			(26,190	)		—			(26,190	)
Conversion of Class D units		—			—		—			16,702,828		415,845			(16,702,828	)		(415,845	)		—			—			—
Net income		—			—		4,099					104,689			—			8,716			—			—			117,504
Balance, December 31, 2007	$	—			1,238,986	$	5,770			60,710,374	$	835,447		$	—		$	—		$	(5,102	)	$	—		$	836,115

See accompanying notes to combined and consolidated financial statements

70

ATLAS ENERGY RESOURCES, LLC

COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

							Three Months
	Years Ended						Ended			Year Ended
	December 31,						December 31,			September 30,
	2007			2006			2005			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	117,504		$	58,182		$	13,779		$	41,423
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of deferred finance costs		3,040			─			─			─
Depreciation, depletion and amortization		56,942			22,491			4,916			14,061
Write down of note receivable		─			3			─			487
Non-cash compensation on long-term incentive plans		4,684			337			393			300
Loss (gain) on asset dispositions		111			(39	)		(2	)		(52	)
Cumulative effect of accounting change		─			(6,355	)		─			─
Non-cash gain on derivatives		(14,000	)		─			─			─
Equity in loss of unconsolidated subsidiary		158			─			─			─
Minority interest		32			─			─			─
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable and prepaid expenses		3,239			(8,862	)		(4,229	)		(2,550	)
Increase (decrease) in accounts payable		6			(3,229	)		16,940			4,340
Increase in liabilities associated with drilling contracts		45,752			16,251			9,543			31,596
Increase in other operating assets and liabilities		13,514			1,757			2,256			920
Net cash provided by operating activities		230,982			80,536			43,596			90,525
CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash paid for acquisition		(1,272,518	)		─			─			─
Capital expenditures		(196,735	)		(75,635	)		(17,187	)		(59,124	)
Proceeds from sale of assets		1,092			47			3			111
Increase in other assets		(273	)		─			(1	)		(37	)
Net cash used in investing activities		(1,468,434	)		(75,588	)		(17,185	)		(59,050	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings		951,891			─			91			─
Principal payments on borrowings		(211,929	)		(88	)		(17	)		(339	)
Distributions to unitholders		(69,282	)		─			─			─
Distributions net of capital contributions to AAI		─			(139,944	)		─			─
Net proceeds from issuance of units		597,495			139,944			─			─
Advances to affiliates		(3,806	)		(16,748	)		(11,813	)		(25,081	)
Increase in deferred financing costs		(10,492	)		(197	)		─			─
Decrease in other assets		─			─			─			19
Net cash provided by (used in) financing activities		1,253,877			(17,033	)		(11,739	)		(25,401	)
Increase (decrease) in cash and cash equivalents		16,425			(12,085	)		14,672			6,074
Cash and cash equivalents at beginning of period		8,833			20,918			6,246			172
Cash and cash equivalents at end of period	$	25,258		$	8,833		$	20,918		$	6,246

See accompanying notes to combined and consolidated financial statements

71

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

The Company was formed in June 2006 to own and operate substantially all of the natural gas and oil assets and the investment partnership management business of Atlas America, Inc. (“AAI”) (NASDAQ: ATLS). AAI has been involved in the energy industry since 1968, expanding its operations in 1998 when it acquired The Atlas Group, Inc. and in 1999 when it acquired Viking Resources Corporation, both engaged in the development and production of natural gas and oil and the sponsorship of investment partnerships. In December 2006, the Company completed an initial public offering of 7,273,750 units of its Class B common units, representing a 19.4% interest, at a price of $21.00 per common unit. The net proceeds of the offering of $139.9 million, after deducting underwriting discounts and costs, were distributed to AAI in the form of a non-taxable dividend and to repay debt. Concurrent with this transaction, Atlas America contributed all of the stock of its natural gas and oil development and production subsidiaries and its development and production assets in exchange for 29,352,996 common units and 748,456 Class A units. On June 29, 2007, Atlas Energy acquired DTE Gas and Oil Company from DTE Energy Company (“DTE”) for $1.273 billion in cash (See Note 3). On June 29, 2007, the Company also completed a private placement of 7,298,181 Class B common units and 16,702,828 Class D units to a group of institutional investors to fund the acquisition of DTE Gas and Oil Company. After the completion of the offering and private placement, AAI owns 49.4% of the Company. 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.

Principles of Combination and Consolidation

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 6). 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. Such interests typically range from 30% to 35%. 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 to December 31 from September 30. Accordingly, the Company’s combined and consolidated financial statements include its operations for the years ended December 31, 2007 and 2006, the three-month transition period ended December 31, 2005 and the year ended September 30, 2005.

72

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

Reclassifications

Certain reclassifications have been made to the combined and consolidated financial statements to conform to the 2007 presentation.

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 11). 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 and phantom units and unit options in 2007 and 2006. The restricted and phantom 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

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

Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of the Company’s restricted unit and unit option awards, as calculated by the treasury stock method. Restricted units and unit options consist of common units issuable under the terms of the Company’s Long-Term Incentive Plan (See Note 11).

Prior to the closing of the Company’s initial public offering on December 18, 2006, there were no common units outstanding. As such, the Company’s 2006 net income attributable to common unit holders is only presented for the period from December 18, 2006 to December 31, 2006. The cumulative effect adjustment related to the adoption of FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”)  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):

73

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

			Period from
	Year Ended		December 18, 2006
	December 31, 2007		to December 31, 2006
Weighted average number of common unit holder units - basic		48,909		36,627
Add effect of dilutive unit incentive awards		540		11
Weighted average number of common unit holder units - diluted		49,449		36,638

Comprehensive Income (Loss)

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

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

Property, Plant and Equipment

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

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

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

74

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

	December 31,
	2007			2006
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,043,687		$	11,302
Wells and related equipment		752,184			338,580
		1,795,871			349,882
Unproved properties		16,380			1,002
Support equipment		6,936		$	5,541
		1,819,187			356,425
Land, buildings and improvements		5,881			4,169
Other		9,653			4,848
		1,834,721			365,442
Accumulated depreciation, depletion and amortization:		(141,254	)		(87,628	)
	$	1,693,467		$	277,814

Oil and Gas Properties

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

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

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, 2007 indicated there was no impairment loss and no impairment indicators arose during the year ended December 31, 2007. The Company will continue to evaluate its goodwill at least annually or when impairment indicators arise, and will reflect the impairment of goodwill, if any, within the combined and consolidated statements of income in the period in which the impairment is indicated.

75

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Impairment of Long-Lived Assets

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 of the Company’s oil and gas properties 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 current contracts in place at December 31, 2007 adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future 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.

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.

Capitalized Interest

The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and gas wells and other capital projects. Interest is capitalized only during the periods in which these assets are brought to their intended use. The weighted average interest rate used to capitalize interest was 6.7% for the year ended December 31, 2007, which resulted in interest capitalized of $2.7 million. There was no interest capitalized for the year ended December 31, 2006.

Asset Retirement Obligations

The Company accounts for asset retirement obligations as required under SFAS 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 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 SFAS 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.

76

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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 Consolidated 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.

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):

	Year		Three Months		Year
	Ended		Ended		Ended
	December 31,		December 31,		September 30,
	2006		2005		2005
Net income as reported	$	51,827	$	13,779	$	41,423
Proforma asset retirement obligation adjustment		1,414		576		1,576
Proforma net income as adjusted		53,241		14,355		42,999
Proforma asset retirement obligation	$	26,726	$	26,086	$	25,126

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.

·   For debt the carrying value approximates fair value because of the substantially short maturity of these instruments and variable interest rates in the related debt agreements.

Derivative Instruments

The Company applies the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“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 (see Note 7).

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, 2007 and 2006, the Company had $41.8 million and $13.5 million, respectively, in deposits at various banks, of which $40.9 million and $13.0 million, respectively, was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date.

77

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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.

The Company accounts for environmental contingencies in accordance with SFAS No. 5 “Accounting for Contingencies.” Environmental expenditures that relate to current operations are expensed as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are also 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 years ended December 31, 2007 and 2006, the three months ended December 31, 2005 and year ended September 30, 2006, 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 generally sells natural gas and crude oil at prevailing market prices. Revenue is recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which the Company has an interest with other producers are recognized on the basis of the Company’s percentage ownership of working interest or overriding royalty. Generally, the Company’s sales contracts are based on pricing provisions that are tied to a market index, with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas .

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, 2007 and 2006 of $44.9 million and $19.4 million, respectively, which are included in Accounts Receivable on its Consolidated Balance Sheets.

78

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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.

Supplemental disclosure of cash flow information (in thousands):

	Years Ended					Three Months Ended		Year Ended
	December 31,					December 31,		September 30,
	2007			2006		2005		2005
Cash paid for interest (net of amount capitalized of $2.8 million in 2007)	$	23,151		$	─	$	─	$	─
Non-cash investing activities include the following:
Current assets		34,279			─		─		─
Property, plant and equipment and other		1,268,791			─		─		─
Fair value of assets acquired		1,303,070			─		─		─
Liabilities assumed		(30,552	)		─		─		─
Net cash paid	$	1,272,518		$	─	$	─	$	─

Income Taxes

The Company is a limited liability company and has elected to be treated as a partnership for income tax purposes.  As a result, the Company is not subject to U.S. federal and most state income taxes.  The unit holders of the Company are liable for income taxes in regards to their distributive share of the Company’s taxable income.  Such taxable income may vary substantially from net income reported in the accompanying combined and consolidated financial statements.   Certain corporate subsidiaries of the Company are subject to federal and state income tax.  The federal and state income taxes related to the Company and these corporate subsidiaries were immaterial to the combined and consolidated financial statements and are recorded in pre-tax income on a current basis only.  Accordingly, no federal or state deferred income tax has been provided for in the accompanying combined and consolidated financial statements. 

In June 2006, the FASB released FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes”, an Interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 provides guidance for how uncertain tax positions should be recognized, measured, presented and disclosed in the financial statements. FIN 48 requires the evaluation of tax positions taken or expected to be taken in the course of preparing the Company’s tax returns to determine whether the tax positions have met a “more-likely-than-not” threshold of being sustained by the applicable tax authority. Tax benefits related to tax positions not deemed to meet the more-likely-than-not threshold are not permitted to be recognized in the financial statements.  The provisions of FIN 48 were adopted by the Company effective January 1, 2007.  Implementation of FIN 48 had no impact on the combined and consolidated financial statements of the Company for the year ended December 31, 2007.  The Company’s policy is to reflect interest and penalties related to uncertain tax positions as part of income tax expense, when and if they become applicable.

The Company files income tax returns in the U.S. federal and various state jurisdictions. With limited exceptions, the Company is no longer subject to income tax examinations by major tax authorities for years before 2006. 

79

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Issued Financial Accounting Standards

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

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

In September 2007, the Emerging Issues Task Force (“EITF”) reached consensus on EITF Issue No. 07-4, “Application of the two-class method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF No. 07-4”), an update of EITF No. 03-6. EITF No. 07-4 requires the calculation of a Master Limited Partnership’s (“MLPs”) net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings as if all of the earnings for that period had been distributed. In periods with undistributed earnings above specified levels, the calculation per the two-class method results in an increased allocation of such undistributed earnings to the general partner and a dilution of earnings to the limited partners. EITF No. 07-4 is effective for fiscal years beginning after December 15, 2007. The application of EITF 07-4 is not expected to have an effect on the Company’s earnings per unit calculation.

In April 2007, the FASB issued FASB Staff Position FIN 39-1, “Amendment of FASB Interpretation No. 39” (“FSP FIN 39-1”), which refers to FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts,” (“FIN 39”). FSP FIN 39-1 amends FIN 39, which allows an entity to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. FSP FIN 39-1 was effective for fiscal years beginning after November 15, 2007. The Company does not expect the adoption of FSP FIN 39-1 to have an impact on its financial position or results of operations.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. 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. The Company does not expect the adoption of SFAS 159 to have an impact on its financial position or results of operations.

80

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

In September 2006, the Financial Accounting Standards Board, or FASB, issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurement,” (“SFAS 157”). SFAS 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements. In February 2008, the FASB issued Final FASB Staff Position, or FSP No. FAS 157-2. The FSP, which was effective upon issuance, delays the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value at least once a year, to fiscal years beginning after November 15, 2008. The FSP also covers interim periods within the fiscal years for items within its scope. The delay is intended to allow the FASB and its constituents the time to consider the various implementation issues associated with SFAS 157. The Company does not expect the adoption of SFAS 157 to have a significant impact on its financial position or results of operations.

NOTE 3 — ACQUISITION OF DTE GAS & OIL COMPANY

On June 29, 2007, the Company acquired all of the outstanding equity interests of DTE Gas & Oil Company (“DGO”) from DTE Energy Company (NYSE:DTE) and MCN Energy Enterprises for $1.273 billion, including adjustments for working capital of $15.0 million and current year capital expenditures of $19.0 million. Assets acquired include interests in approximately 2,150 natural gas wells with estimated proved reserves of approximately 613.7 billion cubic feet of natural gas equivalents located in the northern lower peninsula of Michigan, 228,000 developed acres, and 66,000 undeveloped acres. With this acquisition, the Company increased its natural gas and oil production as well as entered into a new region that offers additional opportunities to expand its operations. Subsequent to the acquisition of DGO, the Company changed DGO’s name to Atlas Gas & Oil Company (“AGO”).

To fund the acquisition, the Company borrowed $713.9 million on its new credit facility (See Note 9) and received net proceeds of $597.5 million from a private placement of its Class B common and new Class D units (See Note 12). Proceeds of $52.5 million were used to pay the outstanding balance of the Company’s then existing credit facility. The acquisition was accounted for using the purchase method of accounting under SFAS No. 141, Business Combinations (“SFAS No. 141”). The table on the following page presents the purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed based on their estimated fair market value at the date of acquisition (in thousands):

81

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

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

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

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

The following data presents pro forma revenues, net income and basic and diluted net income per unit for the Company as if the AGO acquisition, Class B common unit and Class D unit equity offerings (See Note 12) and new revolving credit facility (See Note 9) had occurred on January 1, 2006. The Company has prepared these unaudited pro forma financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the Company had completed the acquisition at January 1, 2006 or the results that will be attained in the future. Net income for the year ended December 31, 2006 includes periods prior to the Company’s initial public offering on December 18, 2006, and therefore, no earnings per unit has been presented (in thousands, except per unit amounts):

	Year Ended
	December 31, 2007
	As Reported		Pro Forma Adjustments			Pro Forma
Revenues	$	577,897	$	15,888		$	593,785
Net income	$	117,504	$	(57,877	)	$	59,627
Net income attributable to Class B unit holders	$	113,405	$	(54,971	)	$	58,434
Net income per Class B common unit outstanding - basic	$	2.32	$	(1.36	)	$	0.96
Weighted average Class B common units outstanding - basic		48,909		11,801			60,710
Net income per Class B common unit - diluted	$	2.29	$	(1.34	)	$	0.95
Weighted average Class B common units outstanding - diluted		49,449		11,740			61,189

	Year Ended
	December 31, 2006
	As Reported		Pro Forma Adjustments		Pro Forma
Revenues	$	320,982	$	291,346	$	612,328
Net income before cumulative effect of accounting change		51,827		145,923		197,750
Net income		58,182		145,923		204,105

82

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

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

Pro forma adjustments to revenues include substantial losses and gains on derivatives realized by AGO of $54.1 million and $149.5 million in fiscal 2007 and 2006, respectively. All existing derivatives were canceled upon the acquisition of AGO by the Company and the Company entered into new derivative contracts covering future AGO production. Pro forma adjustments include financial hedges between AGO and its affiliate. In addition, pro forma adjustments include depreciation, depletion and amortization related to assets acquired and interest expense associated with debt entered into to acquire such assets.

NOTE 4 - OTHER ASSETS AND INTANGIBLE ASSETS

Other Assets

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

	At December 31,
	2007		2006
Long-term hedge receivable from Partnerships	$	13,542	$	2,131
Long-term derivative asset		6,882		23,843
Deferred finance costs, net of accumulated amortization of $2,708 and $0		7,650		194
Other		238		122
	$	28,312	$	26,290

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

Intangible Assets

Included in intangible assets are partnership management and operating contracts acquired through previous acquisitions which were recorded at fair value on their acquisition dates. In addition, in 2007 the Company entered into a two-year non-compete agreement in connection with the acquisition of AGO. The Company amortizes these contracts on the declining balance and straight-line methods, over their respective estimated lives, ranging from two to thirteen years. Amortization expense for these contracts for the years ended December 31, 2007 and 2006, three months ended December 31, 2005 and year ended September 30, 2005 was $1.0 million, $879,000, $220,000, and $933,000, respectively.

The aggregate estimated annual amortization expense of partnership management and operating contracts and the non-compete agreement for the next five years ending December 31 is as follows: 2008—$1.2 million; 2009—$964,000; 2010—$710,000; 2011─$664,000 and 2012—$180,000.

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

	At December 31,
	2007			2006
Management and operating contracts	$	14,343		$	14,343
Non-compete agreement		890			―
Total costs		15,233			14,343
Accumulated amortization		(10,172	)		(9,132	)
	$	5,061		$	5,211

83

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 5—ASSET RETIREMENT OBLIGATIONS

The Company follows SFAS No 143 and FIN 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 the year ended September 30, 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
	Years Ended						Ended		Year Ended
	December 31,						December 31,		September 30,
	2007			2006			2005		2005
Asset retirement obligations, beginning of period	$	26,726		$	18,499		$	17,651	$	4,889
Cumulative effect of adoption of FIN 47		—			8,042			—		—
Liabilities acquired		11,109			—			—		—
Liabilities incurred		2,582			1,570			725		770
Liabilities settled		(91	)		(194	)		—		(137	)
Revision in estimates		—			(2,411	)		—		11,788
Accretion expense		2,032			1,220			123		341
Asset retirement obligations, end of period	$	42,358		$	26,726		$	18,499	$	17,651

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

NOTE 6—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. These costs are reflected in general and administrative expense in the Company’s combined and consolidated statements of income.

84

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 6—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS (Continued)

The Company participates in AAI’s cash management program. Any cash activity performed by AAI on behalf of the Company has been recorded as a long-term liability as parent advances and included in Advances from affiliates on the Company’s Consolidated Balance Sheets.

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

Balance, October 1, 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.

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 13% of the sales price received for the natural gas transported. Under the terms of its contribution agreement with AAI, the Company remits this amount to AAI. Therefore, after the closing of its initial public offering, the gathering revenues and costs within the partnership management segment net to $0.

NOTE 7—DERIVATIVE INSTRUMENTS

From time to time, the Company enters into natural gas future option contracts, and collar contracts to hedge its exposure to changes in natural gas prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas.

85

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 7—DERIVATIVE INSTRUMENTS (Continued)

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). Realized gains and losses are 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, the Company will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings.

At December 31, 2007, the Company had 360 open natural gas futures contracts related to natural gas sales covering 130.6 million MMBtus of natural gas (which includes 72.6 million MMBtus covering natural gas production acquired from AGO) maturing through December 31, 2012 at a combined average settlement price of $8.32 per MMBtu. On May 18, 2007, the Company signed a definitive agreement to acquire AGO (see Note 3). In connection with the financing of this transaction, the Company agreed as a condition precedent to closing that it would hedge 80% of its projected natural gas volumes for no less than three years from the closing date of the transaction. During May 2007, the Company entered into derivative instruments to hedge 80% of the projected production of the assets to be acquired as required under the financing agreement. The production volume of the assets to be acquired was not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the assets had not yet been completed. Accordingly, the Company recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within revenues in its combined and consolidated statements of income. The Company recognized non-cash income of $26.3 million related to the change in value of these derivatives from May 22, 2007 to June 28, 2007, which is shown as “Gain on mark-to-market derivatives” in the Combined and Consolidated Statements of Income for the year ended December 31, 2007. Upon closing of the acquisition on June 29, 2007, the production volume of the assets acquired was considered “probable forecasted production” under SFAS No. 133 and the Company evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133. In addition, the Company recognized gains on settled contracts covering natural gas production of $17.6 million and $7.1 million for the years ended December 31, 2007 and 2006, respectively.

As the underlying prices and terms in the Company’s hedge contracts were consistent with the indices used to sell its natural gas, 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 any cash flow hedges. The Company did not enter into any hedging contracts in the three months ended December 31, 2005 or year ended September 30, 2005.

Of the $5.1 million net loss in accumulated other comprehensive income (loss) at December 31, 2007, the Company will reclassify $21.1 million of gains to its Combined and Consolidated Statements of Income over the next twelve month period as these contracts expire and $26.2 million of losses will be reclassified in later periods if the fair values of the instruments remain at current market values.

86

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 7—DERIVATIVE INSTRUMENTS (Continued)

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

Fixed Price Swaps

Twelve Month
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset (Liability)
	(MMBtu)		(per MMBtu)		(in thousands) (1)
2008		35,960,000	$	8.86	$	37,457
2009		32,720,000	$	8.50		170
2010		23,000,000	$	8.01		(11,398	)
2011		17,600,000	$	7.79		(10,939	)
2012		9,000,000	$	7.74		(5,242	)
					$	10,048

Costless Collars

Twelve Month
Period Ending					Average		Fair Value
December 31,	Option Type		Volumes		Floor and Cap		Asset (Liability)
			(MMBtu)		(per MMBtu)		(in thousands) (1)
2008		Puts purchased		1,560,000	$	7.50	$	368
2008		Calls sold		1,560,000	$	9.40		—
2010		Puts purchased		2,880,000	$	7.75		—
2010		Calls sold		2,880,000	$	8.75		(948	)
2011		Puts purchased		7,200,000	$	7.50		—
2011		Calls sold		7,200,000	$	8.45		(3,495	)
2012		Puts purchased		720,000	$	7.00		—
2012		Calls sold		720,000	$	8.37		(470	)
								(4,545	)
						Total Net Asset	$	5,503

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

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

	December 31,
	2007			2006
Current portion of hedge asset	$	38,181		$	27,618
Long-term hedge asset		6,882			23,843
Current portion of hedge liability		(356	)		(172	)
Long-term hedge liability		(39,204	)		(3,835	)
	$	5,503		$	47,454

87

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 7—DERIVATIVE INSTRUMENTS (Continued)

In addition, $3.4 million of unrealized losses and $26.4 million of unrealized hedge gains have been allocated to the Partnerships at December 31, 2007 and 2006, respectively, based on the Partnerships share of estimated future gas production related to the hedges not yet settled and is included in the Consolidated Balance Sheets as follows (in thousands):

	December 31,
	2007			2006
Unrealized hedge loss - short-term	$	213		$	96
Other assets - long-term		13,542			2,131
Accrued liabilities - short-term		(9,013	)		(15,345	)
Unrealized hedge gain - long-term		(1,348	)		(13,248	)
	$	3,394		$	(26,366	)

NOTE 8—COMMITMENTS AND CONTINGENCIES

The Company leases office space and equipment under leases with varying expiration dates through 2014. Rental expense was $980,000, $670,000, $136,000 and $1.2 million for the years ended December 31, 2007 and 2006, three months ended December 31, 2005, and year ended September 30, 2005, respectively. Future minimum rental commitments for the next five annual periods are as follows (in thousands):

2008	$	1,282
2009		1,171
2010		927
2011		611
2012		611

The Company is the managing general partner of the Partnerships, and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Partnership assets. Subject to certain conditions, investor partners in certain Partnerships have the right to present their interests for purchase by the Company, as managing general partner. The Company is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on past experience, the Company believes that any liability incurred would not be material.

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

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

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

88

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 8—COMMITMENTS AND CONTINGENCIES (Continued)

Atlas Gas & Oil Company LLC, as successor to DTE Gas & Oil Company, was one of four defendants in a personal injury action filed in Antrim County Circuit Court in northern Michigan in August 2006.  The complaint alleged that plaintiff suffered serious personal injuries as a result of the defendants’ negligence. The Company paid $125,000 to the plaintiff in October 2007 in full settlement of this action.

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

NOTE 9—LONG-TERM DEBT

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

	December 31,
	2007			2006
Revolving credit facility	$	740,000		$	—
Other debt		30			68
		740,030			68
Less current maturities		(30	)		(38	)
	$	740,000		$	30

Revolving Credit Facility. Upon the closing of its acquisition of DTE Gas & Oil (See Note 3), the Company replaced its credit facility with a new 5-year credit facility with an initial borrowing base of $850.0 million with J.P. Morgan Chase Bank, N.A. (“J.P. Morgan”) as administrative agent, Wachovia Bank, N. A. as syndication agent, and other lenders. The borrowing base will be redetermined semiannually on April 1 and October 1 subject to changes in the Company’s oil and gas reserves. The initial borrowing base was reduced to $672.5 million in January 2008, upon the issuance by the Company of $250.0 million in senior unsecured notes. See Note 14 for a discussion of the Company’s sale of these notes. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by substantially all of the Company’s assets and is guaranteed by each of the company’s subsidiaries and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at the Company’s option. At December 31, 2007, the weighted average interest rate on outstanding borrowings was 7.2%.

The base rate for any day equals the higher of the federal funds rate plus 0.50% or the J.P. Morgan prime rate. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for Eurocurrency liabilities. The applicable margin ranges from 0.0% to 1.25% for base rate loans and 1.00% to 2.25% for LIBOR loans.

The credit facility requires the Company to maintain specified financial ratios of current assets to current liabilities and debt to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”) as disclosed in the agreement. In addition, the agreement limits sales, leases or transfers of assets and the incurrence of additional indebtedness. The agreement limits the distributions payable by the Company if an event of default has occurred and is continuing or would occur as a result of such distribution. The Company is in compliance with these covenants as of December 31, 2007. The facility terminates in June 2012, when all outstanding borrowings must be repaid. At December 31, 2007 and 2006, $740.0 million and $0 million, respectively, were outstanding under this facility and the previous credit facility. In addition, letters of credit of $1.1 million and $495,000 were outstanding at each date, which are not reflected as borrowings on the Company’s Consolidated Balance Sheets.

89

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

December 31, 2007

NOTE 9—LONG-TERM DEBT (Continued)

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

2008	$	30
2009		―
2010		―
2011		―
2012		740,000
	$	740,030

NOTE 10—OPERATING SEGMENT INFORMATION

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

The Company organizes its oil and gas production segments by geographic location. The Appalachia segment represents the Company’s well interests in the states of Pennsylvania, Ohio, New York, West Virginia and Tennessee. The Michigan segment represents the Company’s well interests in the Antrium Shale, located in Michigan’s northern, lower peninsula.

90

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 10—OPERATING SEGMENT INFORMATION (Continued)

Operating segment data for the periods indicated are as follows (in thousands):

						Three Months
	Years Ended					Ended		Year Ended
	December 31,					December 31,		September 30,
	2007			2006		2005		2005
Gas and oil production
Appalachia:
Revenues	$	99,015		$	88,449	$	24,086	$	63,499
Costs and expenses		17,638			13,881		2,441		8,165
Segment profit	$	81,377		$	74,568	$	21,645	$	55,334
Michigan:
Revenues	$	107,367(2	)
Costs and expenses		14,555
Segment profit	$	92,812
Partnership management
Revenues	$	370,053		$	232,533	$	49,077	$	157,839
Costs and expenses		302,382			209,548		46,103		143,964
Segment profit	$	67,671		$	22,985	$	2,974	$	13,875

							Three Months
	Years Ended						Ended			Year Ended
	December 31,						December 31,			September 30,
	2007			2006			2005			2005
Reconciliation of segment profit to net income
Segment profit
Gas and oil production-Appalachia	$	81,377		$	74,568		$	21,645		$	55,334
Gas and oil production-Michigan		92,812
Partnership management		67,671			22,985			2,974			13,875
Total segment profit		241,860			97,553			24,619			69,209
General and administrative		(39,414	)		(23,367	)		(5,818	)		(13,202	)
Compensation reimbursement - affiliate		─			(1,237	)		(163	)		(602	)
Depreciation, depletion and amortization		(56,942	)		(22,491	)		(4,916	)		(14,061	)
Interest expense		(30,096	)		─			─			─
Other − net (1)		2,096			1,369			57			79
Net income before cumulative effect of accounting change	$	117,504		$	51,827		$	13,779		$	41,423

⁽¹⁾ Includes revenues and expenses for AGO well services and transportation of $1.2 million that do not meet the quantitative threshold for reporting segment information for the year ended December 31, 2007.

⁽²⁾ Includes ineffective derivative gains of $26.3 million.

91

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 10—OPERATING SEGMENT INFORMATION (Continued)

					Three Months
	Years Ended				Ended		Year Ended
	December 31,				December 31,		September 30,
	2007		2006		2005		2005
Capital expenditures
Gas and oil production
Appalachia	$	146,605	$	74,075	$	16,610	$	57,894
Michigan		40,878		─		─		─
Partnership management		4,499		1,042		445		747
Corporate		4,753		518		132		483
	$	196,735	$	75,635	$	17,187	$	59,124
Balance sheets
Goodwill
Gas and oil production - Appalachia	$	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
Appalachia	$	491,199	$	377,807	$	254,831	$	233,855
Michigan		1,330,432		─		─		─
Partnership management		30,359		26,474		37,050		27,115
Corporate		39,244		11,182		23,171		9,432
	$	1,891,234	$	415,463	$	315,052	$	270,402

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

NOTE 11 - 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, phantom units or unit options for an aggregate of 3,742,000 common units. Awards granted in 2007 vest 25% after three years and 100% upon the four year anniversary of grant, except for awards of 1,500 units to board members which vest 25% per year over four years. Awards granted in 2006 vest 25% per year over four years. Upon termination of service by a grantee, all unvested awards are forfeited. A restricted stock or phantom unit entitles a grantee to receive a common unit of the Company upon vesting of the unit or, at the discretion of AAI’s compensation committee, cash equivalent to the then fair market value of a common unit of the Company. In tandem with phantom unit grants, AAI’s compensation committee may grant a distribution equivalent right (“DER”), which is the right to receive cash per restricted unit in an amount equal to, and at the same time as, the cash distributions the Company makes on a common unit during the period such phantom unit is outstanding.

Restricted Stock and Phantom Units. Under the ATN LTIP, 590,950 and 47,619 units of restricted stock and phantom units were awarded in 2007 and 2006, respectively. The fair value of the grants is based on the closing stock price on the grant date, and is being charged to operations over the requisite service periods using a straight-line attribution method.

92

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 11 - BENEFIT PLANS (Continued)

The following table summarizes the activity of restricted stock and phantom units for the periods indicated:

				Weighted
				Average
				Grant Date
	Units			Fair Value
Non-vested shares outstanding at December 31, 2005		—		$	—
Granted		47,619		$	21.00
Non-vested shares outstanding at December 31, 2006		47,619		$	21.00
Granted		590,950		$	24.63
Vested		(11,904	)	$	21.00
Forfeited		(2,000	)	$	23.06
Non-vested shares outstanding at December 31, 2007		624,665		$	24.42

Unit Options. In fiscal 2007 and 2006, 1,532,000 and 373,752 unit options, respectively, were awarded under the ATN LTIP. Option awards expire 10 years from the date of grant and are generally granted with an exercise price equal to the market price of the Company’s stock at the date of grant. The Company uses the Black-Scholes option pricing model to estimate the weighted average fair value per option granted with the following assumptions:

	Years Ended December 31,
	2007			2006
Expected life (years)		6.25			6.25
Expected volatility		25	%		25	%
Risk-free interest rate		4.7	%		4.4	%
Expected dividend yield		5.1-8.0	%		8.0	%
Weighted average fair value of stock options granted	$	2.96		$	2.14

The following table sets forth option activity for the periods indicated:

						Weighted
						Average
				Weighted		Remaining		Aggregate
				Average		Contractual		Intrinsic
				Exercise		Term		Value
	Shares			Price		(in years)		(in thousands)
Outstanding at December 31, 2005		—		$	—
Granted		373,752		$	21.00
Outstanding at December 31, 2006		373,752		$	21.00
Granted		1,532,000		$	24.84
Exercised		—			—
Forfeited or expired		(10,700	)	$	23.06
Outstanding at December 31, 2007		1,895,052		$	24.09		8.9	$	13,256
Options exercisable at December 31, 2007		93,438		$	21.00		9.0
Available for grant at December 31, 2007		1,210,379

93

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 11 - BENEFIT PLANS (Continued)

The following tables summarize information about stock options outstanding and exercisable at December 31, 2007:

	Options Outstanding						Options Exercisable
Range of Exercise Prices	Number of Shares Outstanding		Weighted -Average Remaining Contractual Life in Years		Weighted- Average Exercise Price		Number of Shares Exercisable		Weighted - Average Exercise Price
$21.00-$23.06		1,659,452		9.0	$	22.60		93,438	$	21.00
$34.18-$35.00		235,600		9.5	$	34.65		—		—
		1,895,052		8.9	$	24.09		93,438	$	21.00

The Company recognized $4.7 million and $337,000 in compensation expense related to restricted stock units, phantom units and stock options for the years ended December 31, 2007 and 2006, respectively. There was no such expense for the three months ended December 31, 2005 or the ended September 30, 2005. The Company paid $778,000 with respect to its LTIP DERs for the year ended December 31, 2007. This amount was recorded as a reduction of members’ equity on the Company’s Consolidated Balance Sheet. At December 31, 2007, the Company had approximately $15.8 million of unrecognized compensation expense related to the unvested portion of the restricted stock units, phantom units and options.

NOTE 12 - PRIVATE PLACEMENT OF CLASS B COMMON AND CLASS D UNITS

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

94

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 13 - CASH DISTRIBUTIONS

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

			Cash
			Distribution			Total Cash		Total		Manager
Date Cash			Per			Distribution		Cash		Incentive
Distribution			Common			to Common		Distribution		Distribution
Paid or Payable	For Quarter Ended		Unit			Unitholders (2)		to the Manager		Payable
						(in thousands)		(in thousands)		(in thousands)
February 14, 2007		December 31, 2006	$	0.06(1	)	$	2,231	$	45
May 15, 2007		March 31, 2007	$	0.43		$	15,989	$	322
August 14, 2007		June 30, 2007	$	0.43		$	15,989	$	322
November 14, 2007		September 30, 2007	$	0.55		$	33,697	$	681	$	784
February 14 , 2008		December 31, 2007	$	0.57		$	34,921	$	706	$	965

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

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

NOTE 14 - SUBSEQUENT EVENTS

Private debt offering. In January 2008, the Company issued $250.0 million of senior unsecured notes due 2018 in a private placement at a coupon rate of 10.75%. The Company used the proceeds of the note offering to reduce the balance outstanding on its senior secured credit facility. Interest on the senior notes is payable semi-annually in arrears on February 1 and August 1 of each year. The senior notes are redeemable at any time at certain redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, before February 1, 2011, the Company may redeem up to 35% of the aggregate principal amount of the senior notes with the proceeds of certain equity offerings at a stated redemption price. The senior notes are also subject to repurchase by the Company at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if the Company does not reinvest the net proceeds within 360 days. The senior notes are junior in right of payment to the Company’s secured debt, including its obligations under its credit facility. The indenture governing the senior notes contains covenants, including limitations of the Company’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets.

New interest rate swap. In January 2008, the Company entered into an interest rate swap contract for $150 million, swapping the floating rate incurred on a portion of its existing senior secured credit facility for a fixed rate of approximately 4.36%, which includes an initial margin of 1.25% over the three year fixed swap rate of 3.11%. The interest rate swap contract will mature in January 2011.

95

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 15—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
	Years Ended						Ended			Year Ended
	December 31,						December 31,			September 30,
	2007			2006			2005			2005
Revenues	$	206,382(1	)	$	88,449		$	24,086		$	63,499
Production costs		(32,193	)		(13,881	)		(2,441	)		(8,165	)
Exploration expenses		(4,065	)		(3,016	)		(17	)		(904	)
Depreciation, depletion and amortization		(54,383	)		(20,600	)		(4,477	)		(12,288	)
Results of operations from oil and gas producing activities	$	115,741		$	50,952		$	17,151		$	42,142

____________________

⁽¹⁾ Includes gains from mark-to-market derivatives of $26.3 million.

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,
	2007			2006
Natural gas and oil properties:
Proved properties	$	1,795,871		$	349,882
Unproved properties		16,380			1,002
Support equipment		6,936			5,541
		1,819,187			356,425
Accumulated depreciation, depletion and amortization(1)		(136,603	)		(83,182	)
Net capitalized costs	$	1,682,584		$	273,243

_____________

⁽¹⁾ Costs related to unproved properties are excluded from amortization as they are assessed for impairment.

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
	Years Ended				Ended		Year Ended
	December 31,				December 31,		September 30,
	2007		2006		2005		2005
Property acquisition costs:
Proved properties	$	1,243,877	$	1,322	$	—	$	308
Unproved properties		50,100		—		—		—
Exploration costs		4,065		6,847		1,312		904
Development costs		168,253		76,687		17,380		72,308
	$	1,466,295	$	84,856	$	18,692	$	73,520

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

96

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 15—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued)

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 an independent petroleum engineering firm. All reserves are generally located in the Appalachian Basin and in Michigan’s Lower Peninsula. 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.

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. The increase in the Company’s reserves for the year ended December 31, 2007, is primarily due to the purchase of reserves in-place as a result of the acquisition of DTE Gas and Oil Company on June 29, 2007.

97

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 15—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued)

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

	Gas			Oil
	(Mcf)			(Bbls)
Balance September 30, 2004		142,133,365			2,274,712
Extensions, discoveries and other 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
Extensions, discoveries and other 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
Extensions, discoveries and other 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
Extensions, discoveries and other additions		126,613,549			23,358
Sales of reserves in-place		(62,699	)		(625	)
Purchase of reserves in-place		622,851,730			48,634
Transfers to limited partnerships		(11,507,307	)		—
Revisions		(714,501	)		(2,517	)
Production		(20,963,436	)		(153,465	)
Balance December 31, 2007		884,758,910			1,983,031
Proved developed reserves at:
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
December 31, 2007		594,708,965			1,977,446

98

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 15—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (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, 2005 and December 31, 2005, 2006 and 2007 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 and September 30, 2005 reflect values for Atlas America E&P Operations, which were subject to federal and state income taxes. Amounts shown for December 31, 2006 and 2007 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 and 2007 calculation of standardized measure.

							Three Months
	Years Ended						Ended			Year Ended
	December 31,						December 31,			September 30,
	2007			2006			2005			2005
	(in thousands)
Future cash inflows	$	6,408,367		$	1,262,161		$	1,874,432		$	2,503,644
Future production costs		(1,804,199	)		(334,062	)		(290,600	)		(296,015	)
Future development costs		(388,111	)		(149,610	)		(107,784	)		(117,256	)
Future income tax expense		—			—			(445,004	)		(607,624	)
Future net cash flows		4,216,057			778,489			1,031,044			1,482,749
Less 10% annual discount for estimating timing of cash flows		(2,734,879	)		(495,048	)		(601,772	)		(876,052	)
Standardized measure of discounted future net cash flows	$	1,481,178		$	283,441		$	429,272		$	606,697

The future cash flows estimated to be spent to develop proved undeveloped properties in the years ended December 31, 2008, 2009, 2010, 2011 and 2012 are $112.2 million, $113.1 million, $108.5 million, $37.0 million and $17.3 million, respectively.

99

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 15—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (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 year ended September 30, 2005. Since the Company allocates taxable income to unit holders, no recognition has been given to income taxes for the years ended December 31, 2007 and 2006, and the balance at the beginning of the period has been adjusted to exclude income taxes.

							Three
							Months
	Years Ended						Ended			Year Ended
	December 31,						December 31,			September 30,
	2007			2006			2005			2005
Balance, beginning of period	$	283,441		$	597,137		$	606,697		$	232,998
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs		(147,982	)		(74,567	)		(21,645	)		(55,333	)
Net changes in prices and production costs		45,261			(273,631	)		(245,838	)		417,798
Revisions of previous quantity estimates		(1,208	)		(30,058	)		(4,571	)		(6,073	)
Development costs incurred		98,424			3,426			2,727			4,224
Changes in future development costs		(14,128	)		(8,505	)		(1,159	)		(1,577	)
Transfers to limited partnerships		(13,998	)		(8,449	)		(8,563	)		(24,750	)
Extensions, discoveries, and improved recovery less related costs		170,349			44,820			22,597			154,215
Purchases of reserves in place		957,137			660			24			596
Sales of reserves in place, net of tax effect		(105	)		(572	)		(243	)		(672	)
Accretion of discount		74,685			59,714			21,141			32,038
Net changes in future income taxes		—			—			71,614			(151,882	)
Estimated settlement of asset retirement obligations		(4,523	)		(8,226	)		(848	)		(12,763	)
Estimated proceeds on disposals of well equipment		5,168			10,007			998			12,740
Other		28,657			(28,315	)		(13,659	)		5,138
Balance, end of period	$	1,481,178		$	283,441		$	429,272		$	606,697

100

ATLAS ENERGY RESOURCES, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 16 - QUARTERLY RESULTS (UNAUDITED)

	March 31,		June 30,		September 30,		December 31,
	(in thousands, except unit data)
Year ended December 31, 2007
Revenues	$	105,191	$	128,055	$	180,269	$	164,382
Net income	$	19,941	$	41,665	$	31,612	$	24,286
Net income per common unit:
Basic	$	.53	$	1.10	$	.50	$	.38
Diluted		.53	$	1.08	$	.49	$	.37
Year ended December 31, 2006
Revenues	$	82,111	$	63,608	$	81,193	$	94,070
Income from continuing operations before cumulative effect of accounting change
Portion applicable to owner’s interest	$	12,469	$	12,599	$	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	$	12,469	$	12,599	$	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	$	12,469	$	12,599	$	11,466	$	21,648

101

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

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

Under the supervision of our Chief Executive Officer and Chief Financial Officer, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2007, our disclosure controls and procedures were effective at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of internal control over financial reporting based upon criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework (COSO framework).

An effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, effectiveness of an internal control system in future periods cannot be guaranteed because the design of any system of internal controls is based in part upon assumptions about the likelihood of future events. There can be no assurance that any control design will succeed in achieving its stated goals under all potential future conditions. Over time certain controls may become inadequate because of changes in business conditions, or the degree of compliance with policies and procedures may deteriorate. As such, misstatements due to error or fraud may occur and not be detected.

In conducting management’s evaluation of the effectiveness of its internal control over financial reporting, management has excluded, due to the transaction size and complexity and timing of the acquisition, the operations of Atlas Gas and Oil, LLC (AGO), which we acquired in June 2007, from its December 31, 2007 Sarbanes-Oxley 404 review. AGO constituted approximately 72% of our total assets as of December 31, 2007 and 16% of our total revenues for the year ended December 31, 2007.

Based on our evaluation under the COSO framework, management concluded that our internal control over financial reporting as of December 31, 2007 was effective.

Grant Thornton, LLP, an independent registered public accounting firm, has issued an attestation report on our internal control over financial reporting as of December 31, 2007.

102

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Atlas Energy Resources, LLC

We have audited Atlas Energy Resources, LLC’s (a Delaware limited liability company) internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Atlas Energy Resources, LLC’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Atlas Energy Resources, LLC’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting, in conducting management’s assessment of and conclusion on the effectiveness of internal controls over financial reporting, management has excluded Atlas Energy Resources, LLC’s subsidiary Atlas Gas & Oil Company, which was acquired on June 29, 2007. Atlas Gas & Oil Company represented approximately 72% of Atlas Energy Resources, LLC’s total assets and approximately 16% of its total revenues at December 31, 2007. Management did not assess the effectiveness of internal controls over financial reporting at this subsidiary due to the transaction size and complexity and timing of the acquisition. Our audit of internal controls over financial reporting of Atlas Energy Resources, LLC did not include an evaluation of the internal control over financial reporting of Atlas Gas & Oil Company.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Atlas Energy Resources, LLC maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the accompanying consolidated balance sheets of Atlas Energy Resources, LLC and subsidiaries (a Delaware limited liability company) as of December 31, 2007 and 2006, and the related combined and consolidated statements of income, comprehensive income, equity, and cash flows for the years ended December 31, 2007 and 2006, the three month period ended December 31, 2005 and the year ended September 30, 2005 and our report dated February 27, 2008 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

February 27, 2008

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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 all of the board of directors’ committees: the conflicts committee, the audit committee, the nominating and corporate governance committee and the compensation 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 unit holders and not a breach of obligation to us or to our unit holders. 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. The nominating and corporate governance committee assists the company and the board by identifying qualified candidates for director positions and in developing recommendations to improve the company’s corporate governance. Starting with the 2008 calendar year, the compensation committee will assist the board in carrying out its responsibilities with respect to the compensation allocated to those individuals who perform services for us.

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	69	Chairman of the Board and Chief Executive Officer
Jonathan Z. Cohen	37	Vice Chairman of the Board
Matthew A. Jones	46	Chief Financial Officer and Director
Richard D. Weber	44	President, Chief Operating Officer and Director
Nancy J. McGurk	52	Chief Accounting Officer
Lisa Washington	40	Chief Legal Officer and Secretary
Daniel C. Herz	31	Senior Vice President, Corporate Development
Walter C. Jones	45	Director
Ellen F. Warren	51	Director
Bruce M. Wolf	59	Director

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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) from 1998 to July 2007; and 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.

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.

Daniel C. Herz has been our Senior Vice President of Corporate Development since August 2007. He has also been the Senior Vice President of Corporate Development of Atlas America, Atlas Pipeline Partners GP and Atlas Pipeline Holdings GP since August 2007. Before that, he was Vice President of Corporate Development of Atlas America and Atlas Pipeline Partners GP from December 2004 and of Atlas Pipeline Holdings GP from its formation in January 2006. Mr. Herz joined Atlas America and Atlas Pipeline Partners GP in January 2004. He was an Associate Investment Banker with Banc of America Securities from 2002 to 2003 and an Analyst from 1999 to 2002.

Independent Directors

Walter C. Jones has been a member of the Board of Directors since December 2006. Since June 2007, Mr. Jones has been an advisor to GRAVITAS Capital Advisors, LLC, an independent advisory firm where from May 2005, he was the General Counsel and Senior Director of Private Equity for the firm. 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 a Senior Investment Officer in the Finance Department. Prior to that, Mr. Jones was an International Consultant at the Washington, DC firm of Neill & Co. Mr. Jones began his career at the law firm of Sidley & Austin.

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Ellen F. Warren has been a member of the Board of Directors since December 2006. Ms. 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 a member of the Board of Directors since December 2006. Mr. 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.

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 2007, our executive officers, directors and greater than 10% stockholders complied with all applicable filing requirements of Section 16(a) of the Securities Exchange Act.

Compensation Committee Interlocks and Insider Participation

We did not have a compensation committee in 2007. Compensation of the personnel of Atlas America and its affiliates who provide us with services was 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.

Code of Business Conduct and Ethics, Company Governance Guidelines and Committee Charters

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 charters for each of the audit, compensation and nominating and corporate governance committees. We will make a printed copy of our code of ethics, our Company Governance Guidelines, our audit committee charter, our compensation committee charter and our nominating and corporate governance charter available to any unit holder who so requests. Requests for print copies may be directed to us as follows: Atlas Energy Resources, LLC, 1550 Coraopolis Heights Road—2^nd Floor, Moon Township, Pennsylvania 15108, Attention: Secretary. Each of the code of business conduct and ethics, the Company Governance Guidelines, the audit committee charter, the compensation committee charter and the nominating and corporate governance charter are posted, and any waivers we grant under our code of business conduct and ethics will be posted, on our website at www.atlasenergyresources.com.

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ITEM 11. EXECUTIVE COMPENSATION

COMPENSATION DISCUSSION AND ANALYSIS

We are required to provide information regarding the compensation program in place as of December 31, 2007, for our CEO, CFO and the three other most highly-compensated executive officers. In this report, we refer to our CEO, CFO and the other three most highly-compensated executive officers as our “Named Executive Officers” or “NEOs.” This section should be read in conjunction with the detailed tables and narrative descriptions below.

Through the end of 2007, the compensation committee of Atlas America, our parent, has been 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 business 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 the NEOs’ 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 NEOs for fiscal 2007 specifically was intended:

•To encourage and reward strong performance; and

•To motivate our NEOs by providing them with a meaningful equity stake in our company and our publicly-traded subsidiaries, as appropriate.

Accounting and cost implications of compensation programs are considered in program design; however, the essential consideration is that a program is consistent with our business needs.

Compensation Methodology

The compensation committee makes recommendations to the Atlas America board on compensation amounts during the month after the close of its (and our) fiscal year. In the case of base salaries, it recommends the amounts to be paid for that year. In the case of annual bonus and long-term incentive compensation, the committee recommends the amount of awards based on the then concluded fiscal year. We typically pay cash awards and issue equity awards in February of the following fiscal year. The compensation committee has the discretion to recommend the issuance of equity awards at other times during the fiscal year. In addition, some of our NEOs who also perform services for Atlas America and its other publicly-traded subsidiaries, Atlas Pipeline Partners and Atlas Pipeline Holdings, may receive stock-based awards from these subsidiaries, each of which have delegated compensation decisions to the compensation committee since neither we, nor the other subsidiaries, have employees.

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Each year, Atlas America’s (and our) Chief Executive Officer provides the compensation committee with key elements of Atlas America’s performance and the NEOs’ performance as well as recommendations to assist it in determining compensation levels. The compensation committee focuses on Atlas America’s equity performance, market capitalization, corporate developments, business performance (including production of energy and replacement of reserves) and financial position in recommending the compensation for those NEOs who provided services to both Atlas America and to us.

In June 2006, the compensation committee retained Mercer Human Resource Consulting to analyze and review the competitiveness and appropriateness of all elements of the compensation paid by Atlas America to its executive officers, including our NEOs, individually and as a group, for fiscal 2006. The purpose of retaining Mercer was to determine whether Atlas America’s compensation practices were within the norm for companies of similar size and focus. Because of the importance to Atlas America and to us of our direct-placement energy investment programs and Atlas America’s creation of new initiatives entities, Mercer looked not only to the energy industry in evaluating our compensation levels but also to the financial services and alternative asset industries. Mercer’s analysis established that Atlas America’s fiscal 2006 compensation amounts fell between the median and the 75^th percentile of the peer group it used, which the compensation committee found acceptable in the context of its evaluation of the performance of the NEOs.

Ultimately, the decisions regarding executive compensation are made by the compensation committee after extensive discussion regarding appropriate compensation and are approved by the Atlas America board of directors.

Elements of our Compensation Program

Our executive officer compensation package includes a combination of annual cash and long-term incentive compensation. Annual cash compensation is comprised of base salary plus cash bonus. Long-term incentives consist of a variety of equity awards. Both the annual cash incentives and long-term incentives may be performance-based.

Base Salary

Base salary is intended to provide fixed compensation to the NEOs 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. Base salaries are not intended to compensate individuals for extraordinary performance or for above average company performance.

Annual Incentives

Annual incentives are intended to tie a significant portion of each of the NEO’s compensation to Atlas America’s annual performance and /or that of one of Atlas America’s subsidiaries or divisions for which the officer is responsible. 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. The compensation committee may recommend awards of performance-based bonuses and discretionary bonuses.

Performance-Based Bonuses— The Atlas America Annual Incentive Plan for Senior Executives, which we refer to as the Senior Executive Plan, provides awards for the achievement of predetermined, objective performance measures over a specified 12-month performance period, generally Atlas America’s fiscal year. Awards under the Senior Executive Plan are paid in cash. Notwithstanding the existence of the Senior Executive Plan, the compensation committee believes that stockholder interests are best served by not restricting its discretion and flexibility in crafting compensation, even if the compensation amounts result in non-deductible compensation expense. Therefore, the committee reserves the right to approve compensation that is not fully deductible.

In February 2007, the compensation committee set the performance goals for the Atlas America’s executive offers, some of whom are also our NEOs. Specifically, the committee decided that if Atlas America’s 2007 net income, which was defined as net income before income taxes and compensatory bonuses paid, exceeded $18,000,000, a bonus pool equal to 15% of the 2007 net income would be established, from which bonus awards would be made. Pursuant to the terms of the Senior Executive Plan, in determining whether and to what extent the performance target was achieved, the compensation committee relies on information contained in the Atlas America’s audited financial statements and other objectively determinable information. If the performance target was not achieved, no annual incentives would be awarded. Pursuant to the terms of the Senior Executive Plan, the compensation committee has the discretion to recommend the reduction, but not the increase, of the annual incentive awards.

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Discretionary Bonuses—Discretionary bonuses may be awarded to recognize individual and group performance.

Long-Term Incentives

We believe that our long-term success depends upon aligning our executives’ and stockholders’ interests. To support this objective, we provide our executives with various means to become significant stockholders, including 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 NEOs are eligible to receive awards under our Long-Term Incentive Plan, which we refer to as our Plan, 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, as appropriate.

Grants under our Plan: The compensation committee may recommend grants of equity awards in the form of options, restricted units, and/or phantom units. In May 2007, our Plan was amended to meet the deductibility requirements of Section 162(m) when the awards are granted pursuant to pre-established performance goals.

Options—Options have a ten-year term and, in general, vest 25% on the third anniversary of the grant date and 75% on the fourth anniversary of the grant date.

Phantom Units—A phantom unit is a notional unit which, upon vesting, converts into a common unit in our company. Phantom units may be granted with or without tandem distribution equivalent rights, which we refer to as DERs. In general, grants of our phantom units vest 25% on the third anniversary of the grant date and 75% on the fourth anniversary of the grant date.

Restricted Units—From time to time, restricted units of our company may be granted to selected NEOs or employees.

Grants under Other Plans: As described above, our NEOs who perform services for us and one or more of Atlas America’s publicly-traded subsidiaries may receive stock-based awards under the Atlas Plan, the APL Plan or the AHD Plan.

Supplemental Benefits, Deferred Compensation and Perquisites

We do not emphasize supplemental benefits for executives other than Mr. E. Cohen, and perquisites are discouraged. None of our NEOs have deferred any portion of their compensation.

Determination of 2007 Compensation Amounts

As described above, after the end of our 2007 fiscal year, the compensation committee set the base salaries of the Atlas America executives for the 2008 fiscal year and recommended incentive awards based on the prior year’s performance. In carrying out its function, the compensation committee acted in consultation with Mercer.

In determining the actual amounts to be paid to the Atlas America executives, the compensation committee looked to both the individual’s performance as well as to the overall performance of our company and our publicly-held subsidiaries during fiscal 2007. As described above, Atlas America allocates the cash compensation for our NEOs to us based upon an estimate of the time spent by such persons on activities for us and for Atlas America and its affiliates.

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Base Salary. Consistent with its preference for having a significant portion of our NEOs’ overall compensation package be incentive compensation, the compensation committee decided to recommend that base salaries for 2008 be maintained at the same levels as 2007.

Annual Incentives.

Performance-Based Bonuses. The compensation committee reviewed Atlas America’s financial statements and determined that the 2007 net income exceeded the pre-determined minimum threshold. It accordingly recommended for approval awards under the Senior Executive Plan. The amount of these awards that were allocated to us were as follows: Edward E. Cohen, $2,250,000; Jonathan Z. Cohen, $1,434,783; Matthew A. Jones, $900,000; and Richard D. Weber, $1,500,000.

Discretionary Bonuses. Based on the record-breaking performance of our direct-placement energy investment programs, the compensation committee recommended that Atlas America award Mr. Kotek a cash bonus of which $750,000 was allocable to us.

Long-Term Incentives. Additionally, the compensation committee recognized the importance of a long-term incentive component as a part of the 2007 compensation. The compensation committee recommended the award of Atlas America stock options as follows: Mr. E. Cohen—200,000 options; Mr. J. Cohen—160,000 options; Mr. M. Jones—80,000 options; Mr. Weber—60,000 options; and Mr. Kotek—40,000 options. These awards are not reflected in the Summary Compensation Table because we did not recognize expense for them in fiscal 2007. The compensation committee determined that it would not recommend that awards be made to our NEOs under our Plan, the APL Plan or the AHD Plan because it felt that previous awards were adequate.

The following table sets forth the compensation allocation for fiscal year 2007 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.

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2007 Summary Compensation Table

Name and Principal Position	Year		Salary ($)		Bonus ($)		Stock Awards ($) (1)		Option Awards ($) (2)		Non-Equity Incentive Plan Compensation ($)		All Other Compensation ($)		Total ($)
Edward E. Cohen, Chairman of the Board and Chief Executive Officer		2007	$	405,000		—	$	1,153,000	$	301,250	$	2,250,000	$	294,000(3)	$	4,403,250
		2006	$	27,391		—	$	674,625	$	84,861		—	$	32,300	$	819,177
Matthew A. Jones, Chief Financial Officer		2007	$	135,000		—	$	115,300	$	337,295	$	900,000	$	29,400(3)	$	1,516,995
		2006	$	13,696		—	$	276,546	$	324,172		—	$	7,600	$	622,064
Jonathan Z. Cohen, Vice Chairman		2007	$	33,750		—	$	576,500	$	120,500	$	1,434,783	$	147,000(3)	$	2,312,533
Richard D. Weber, President and Chief Operating Officer of Atlas Energy Resources, LLC		2007	$	300,000		—	$	250,000	$	463,770	$	1,500,000	$	2,857	$	2,516,627
		2006	$	15,217		—	$	187,504	$	347,779		—		—	$	550,500
Freddie M. Kotek, Executive Vice President of Atlas America		2007	$	225,000	$	750,000	$	115,300	$	183,710		—	$	29,400(3)	$	1,303,410

⁽¹⁾ Represents the dollar amount of expense we recognized for financial statement reporting purposes with respect to phantom units and/or restricted units granted under our Plan, all in accordance with FAS 123R. See Note 11 to our combined and consolidated financial statements for an explanation of the assumptions we make for this valuation.

⁽²⁾ Represents the dollar amount of (i) expense recognized by Atlas for financial statement reporting purposes with respect to options granted under the Atlas Plan; and/or (ii) expense we recognized for financial statement reporting purposes for options granted under our Plan, all in accordance with FAS 123R. See Note 11 to our combined and consolidated financial statements for an explanation of the assumptions we make for this valuation.

⁽³⁾ Represents payments on DERs with respect to the phantom units awarded under our Plan, as reported in the Stock Awards column.

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The following table discloses awards under our Plan.

2007 GRANTS OF PLAN-BASED AWARDS TABLE

Name	Grant Date		Approval Date		All Other Stock Awards: Number of Shares Of Stock or Units (#)		All Other Option Awards: Number of Securities Underlying Options (#)		Exercise or Base Price of Option Awards ($ / Sh)		Grant Date Fair Value of Stock and Option Awards
Edward E. Cohen		1/24/07		1/22/07		200,000 (1)		500,000 (2)	$	23.06	$	4,612,000(1)
											$	1,250,000(2)
Matthew A. Jones		1/24/07		1/22/07		20,000 (1)		50,000 (2)	$	23.06	$	461,200(1)
											$	120,500(2)
Jonathan Z. Cohen		1/24/07		1/22/07		100,000 (1)		200,000 (2)	$	23.06	$	2,306,000(1)
											$	482,000(2)
Richard D. Weber		1/24/07(3)		4/3/06		47, 619 (4)		373,752 (5)	$	21.00	$	999,999(1)
											$	900,742(2)
Freddie Kotek		1/24/07		1/22/07		20,000 (1)		50,000 (2)	$	23.06	$	461,200(1)
											$	120,500(2)

⁽¹⁾ Represents grants of phantom units under our 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 our common units on the grant date of $23.06.

⁽²⁾ Represents grants of stock options under our Plan, which vest 25% on the third anniversary and 75% on the fourth anniversary of the grant, valued at $ 2.41 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 8.0%, (b) risk-free interest rate of 4.7%, (c) expected volatility of 25.0%, and (d) an expected life of 6.3 years.

⁽³⁾ Pursuant to Mr. Weber’s employment agreement entered into on April 17, 2006, upon the completion of our initial public offering we were obligated to award him the restricted units and options shown in the table. However, we did not grant the awards until our registration statement on Form S-8, covering unit awards was declared effective by the SEC.

⁽⁴⁾ Represents grants of phantom units under our 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, valued in accordance with FAS 123R at the closing price of our common units on the grant date of $21.00.

⁽⁵⁾ Represents grants of options under our 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, valued at $ 2.41 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 8.0%, (b) risk-free interest rate of 4.7%, (c) expected volatility of 25.0%, and (d) an expected life of 6.3 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:

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• 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:

• 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 change of control triggering events relating to the possible absence of Messrs. Cohen reflects that Mr. Weber’s belief that Messrs. Cohen effectively controlled us at the time of his employment and their separation 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 the Atlas Energy Resources 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 our 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. Disability is defined as becoming disabled by reason of physical or mental disability for more than 180 days in the aggregate or a period of 90 consecutive days during any 365-day period and the good faith determination by our Board based upon medical evidence that Mr. Weber is unable to perform his duties under his employment agreement.

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, (a) Atlas Energy Management will 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, (b) Mr. Weber’s family will receive health insurance coverage for one year; and (c) all Atlas Energy Resources stock and option awards will automatically vest.

• 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 (including termination by reason of disability), 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.

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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, 2007, we estimate that the value of the benefits to Mr. Weber would have been as follows:

	Lump Sum				Accelerated Vesting of
	Severance				Stock Awards and
Reason for Termination	Payment		Benefits(1)		Option Awards (2)
Death	$	1,500,000 (3)	$	17,193	$	—
Disability		—		19,719		—
Termination by us other than for cause (including for disability) or by Mr. Weber for good reason		1,800,000 (4)		19,719		5,472,900
Change of control		—		—		5,472,900
Termination by Mr. Weber without cause		—		—		—

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

(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 31, 2007.

(3)   Represents Mr. Weber’s 2007 bonus.

(4)   Calculated as the sum of Mr. Weber’s 2007 base salary and 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. In May 2007, the Atlas America stockholders approved an amendment to our Plan which provides for performance-based awards criteria for purposes of complying with Section 162(m) of the Internal Revenue Code (“Section 162(m)”).

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Atlas Plan

The Atlas Plan authorizes the granting of up to 3.0 million shares of Atlas America 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.

As required by SEC guidelines, the following table discloses awards under our Plan as well as under the Atlas Plan.

2007 OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END TABLE

Option Awards Stock Awards 

	Number of Securities Underlying Unexercised Options (#)		Number of Securities Underlying Unexercised Options (#)		Option Exercise Price ($)		Option Expiration Date		Number of Shares or Units of Stock That Have Not Vested (#)		Market Value of Shares or Units of Stock That Have Not Vested ($)
Name	Exercisable		Unexercisable
Edward E. Cohen		675,000 (1)		—	$	16.98		7/1/2015
		—		500,000 (2)	$	23.06		1/24/2017		200,000 (3)	$	6,218,000 (4)
Matthew A. Jones		90,000 (5)		90,000 (6)	$	16.98		7/1/2015
		—		50,000 (7)	$	23.06		1/24/2017		20,000 (8)	$	621,800 (4)
Jonathan Z. Cohen		450,000 (9)		—	$	16.98		7/1/2015
		—		200,000 (10)	$	23.06		1/24/2017		100,000 (11)	$	3,109,000 (4)
Richard D. Weber		18,750 (12)		56,250 (13)	$	31.91		4/17/2016
		93,438 (14)		280,314 (15)	$	21.00		4/17/2016		35,715 (16)	$	1,110,379 (4)
Freddie M. Kotek		45,000 (17)		45,000 (18)	$	16.98		7/1/2015
		—		50,000 (19)	$	23.06		1/24/2017		20,000 (20)	$	621,800 (4)

⁽¹⁾ Represents 675,000 options to purchase Atlas America stock, granted on 7/1/05 in connection with its spin-off from Resource America, which vested immediately. Reflects a 3-for-2 stock split which was effected on May 29, 2007.

⁽²⁾ Represents options to purchase our common units, which vest as follows: 1/24/10 - 125,000 and 1/24/11 - 375,000.

⁽³⁾ Represents our phantom units, which vest as follows: 1/24/10 - 50,000 and 1/24/17 - 150,000.

⁽⁴⁾ Based upon closing price of our common units on December 31, 2007 of $31.09.

⁽⁵⁾ Represents 90,000 options to purchase Atlas America stock, granted on 7/1/05 in connection with its spin-off from Resource America. Reflects a 3-for-2 stock split which was effected on May 29, 2007.

⁽⁶⁾ Represents options to purchase Atlas America stock, which vest as follows: 7/1/08 - 45,000 and 7/1/09 - 45,000.

⁽⁷⁾ Represents options to purchase our common units, which vest as follows: 1/24/10 - 12,500 and 1/24/11 - 37,500.

⁽⁸⁾ Represents our phantom units, which vest as follows: 1/24/10—5,000 and 1/24/11—15,000.

⁽⁹⁾ Represents 450,000 options to purchase Atlas America stock, granted on 7/1/05 in connection with its spin-off from Resource America, which vested immediately. Reflects a 3-for-2 stock split which was effected on May 29, 2007.

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⁽¹⁰⁾ Represents options to purchase our common units, which vest as follows: 1/24/10 - 50,000 and 1/24/11 - 150,000.

⁽¹¹⁾ Represents our phantom units, which vest as follows: 1/24/10—25,000 and 1/24/11—75,000.

⁽¹²⁾ Represents 18,750 options to purchase Atlas America stock. Reflects a 3-for-2 stock split which was effected on May 29, 2007.

⁽¹³⁾ Represents options to purchase Atlas America stock, which vest as follows: 4/17/08 - 18,750; 4/17/09 - 18,750 and 4/17/10 - 18,750.

⁽¹⁴⁾ Represents 93,438 options to purchase our common units.

⁽¹⁵⁾ Represents options to purchase our common units, which vest as follows: 4/17/08—93,438; 4/17/09—93,438 and 4/17/10—93,438.

⁽¹⁶⁾ Represents our restricted units, which vest as follows: 4/17/08—11,905; 4/17/09—11,905 and 4/17/10—11,905.

⁽¹⁷⁾ Represents 45,000 options to purchase Atlas America stock, granted on 7/1/05 in connection with its spin-off from Resource America. Reflects a 3-for-2 stock split which was effected on May 29, 2007.

⁽¹⁸⁾ Represents options to purchase Atlas America stock, which vest as follows: 7/1/08 - 22,500 and 7/1/09 - 22,500.

⁽¹⁹⁾ Represents options to purchase our common units, which vest as follows: 1/24/10 - 12,500 and 1/24/11 - 37,500.

⁽²⁰⁾ Represents our phantom units, which vest as follows: 1/24/10—5,000 and 1/24/11—15,000.

2007 OPTION EXERCISES AND STOCK VESTED TABLE

	Stock Awards
Name	Number of Shares Acquired on Vesting		Value Realized on Vesting ($)
Richard D. Weber		11,904 (1)	$	330,574

⁽¹⁾   Represents awards under our Plan.

2007 DIRECTOR COMPENSATION TABLE

	Fees Earned or	Stock Awards	All Other	Total
	Paid in Cash	($)	Compensation	($)
Name	($)	(1)	($)(2)
Walter C. Jones	$35,000	$2,883	$735	$38,618
Ellen F. Warren	$35,000	$2,883	$735	$38,618
Bruce M. Wolf	$35,000	$2,883	$735	$38,618

(1)   Represents the dollar amount of expense we recognized for financial statement reporting purposes with respect to phantom units granted under our Plan in accordance with FAS 123R. Represents 500 phantom units granted to each of Messrs. Jones and Wolf and Ms. Warren, which vest 25% on each of the first through fourth anniversaries of the date of grant. The vesting schedule for the phantom units is as follows: 1/24/08 -125; 1/24/09 -125; 1/24/10 -125; and 1/24/11 -125.

(2)   Represents payments on DERs of $735 with respect to the phantom units awarded under our Plan.

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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 2007, an annual retainer of $35,000 in cash and, in January 2007, a grant of 500 phantom units with DERs 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.

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 February 25, 2008. The address for each director and executive officer and Atlas America is 1550 Coraopolis Heights Road—2nd Floor, Moon Township, Pennsylvania 15108.

	Class B Common Units
	Amount and Nature of		Percent of
Beneficial Owner	Beneficial Ownership		Class B Units
Directors
Edward E. Cohen	700,000	(1)	1.15%
Jonathan Z. Cohen	300,000	(2)	*
Matthew A. Jones	71,100	(3)	*
Walter C. Jones	1,000	(4)	*
Ellen F. Warren	1,000	(4)	*
Richard D. Weber	422,471	(5)	*
Bruce M. Wolf	4,000	(4)	*
Non-Director Executive Officers
Nancy J. McGurk	25,000	(6)	*
Lisa Washington	13,100	(7)	*
Daniel C. Herz	40,000	(8)	*
All executive officers and directors as a group (10 persons)	1,577,671		2.60%
Other Owners of More Than 5% of Outstanding Shares
Atlas America, Inc.	29,352,996	(9)	48.35%
Cobalt Capital Management, Inc.	3,094,930	(10)	5.10%
Lehman Brothers Holdings Inc.	3,940,161	(11)	6.49%

______________

*	Less than 1%
(1)	Includes 200,000 phantom units and 500,000 unit options granted pursuant to our Plan on January 24, 2007. Each phantom unit represents the right to receive, upon vesting, one common unit. Each unit option represents the right to purchase, upon vesting, one common unit. The phantom units and unit options vest 25% on the third anniversary of the grant and 75% on the fourth anniversary of the grant.
(2)	Includes 100,000 phantom units and 200,000 unit options granted pursuant to our Plan on January 24, 2007. Each phantom unit represents the right to receive, upon vesting, one common unit. Each unit option represents the right to purchase, upon vesting, one common unit. The phantom units and unit options vest 25% on the third anniversary of the grant and 75% on the fourth anniversary of the grant.
(3)	Includes 20,000 phantom units and 50,000 unit options granted pursuant to our Plan on January 24, 2007. Each phantom unit represents the right to receive, upon vesting, one common unit. Each unit option represents the right to purchase, upon vesting, one common unit. The phantom units and unit options vest 25% on the third anniversary of the grant and 75% on the fourth anniversary of the grant.

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(4)	Includes 875 phantom units granted pursuant to our Plan. Each phantom unit represents the right to receive, upon vesting, either one common unit or its then fair market value in cash. The phantom units vest as follows: 1/24/09—250; 1/24/10—250; 1/24/11—250; and 1/24/12—125.
(5)	Includes 35,715 phantom units and 280,314 unit options granted pursuant to the terms of Mr. Weber’s employment agreement dated April 17, 2006. Each phantom unit represents the right to receive, upon vesting, one common unit. Each unit option represents the right to purchase, upon vesting, one common unit. The phantom units and the unit options vest as follows: 4/17/08—11,905 phantom units and 93,438 unit options; 4/17/09—11,905 phantom units and 93,438 unit options; and 4/17/10—11,905 phantom units and 93,438 unit options.
(6)	Includes 10,000 phantom units and 15,000 unit options granted pursuant to our Plan on January 24, 2007. Each phantom unit represents the right to receive, upon vesting, one common unit. Each unit option represents the right to purchase, upon vesting, one common unit. The phantom units and unit options vest 25% on the third anniversary of the grant and 75% on the fourth anniversary of the grant.
(7)	Includes 5,000 phantom units and 8,000 unit options granted pursuant to our Plan on January 24, 2007. Each phantom unit represents the right to receive, upon vesting, one common unit. Each unit option represents the right to purchase, upon vesting, one common unit. The phantom units and unit options vest 25% on the third anniversary of the grant and 75% on the fourth anniversary of the grant.
(8)	Includes 10,000 phantom units and 30,000 unit options granted pursuant to our Plan on January 24, 2007. Each phantom unit represents the right to receive, upon vesting, one common unit. Each unit option represents the right to purchase, upon vesting, one common unit. The phantom units and unit options vest 25% on the third anniversary of the grant and 75% on the fourth anniversary of the grant.
(9)	This information is based upon a Schedule 13D/A which was filed with SEC on February 15, 2008. The address for Atlas America, Inc. is 1550 Coraopolis Heights Road—2nd Floor, Moon Township, Pennsylvania 15108.
(10)	This information is based upon a Schedule 13G/A which was filed with the SEC on February 14, 2008. The address for Cobalt Capital Management, Inc. is 237 Park Avenue, Suite 900, New York, NY 10012.
(11)	This information is based upon a Schedule 13G/A which was filed with the SEC on February 13, 2008. The address for Lehman Brothers Holdings, Inc. is 745 Seventh Avenue, New York, NY 10019.

As of February 25, 2008, 100% of our outstanding Class A units were owned by our manager, Atlas Energy Management, Inc. (the “Manager”).

Equity Compensation Plan Information

The following table contains information about our Plan as of December 31, 2007:

	(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 and restricted units		624,665		n/a
Equity compensation plans not approved by security holders - unit options		1,895,052	$	24.09
Equity compensation plans not approved by security holders - Total		2,519,717				1,210,379

The following table contains information about the Atlas Plan as of December 31, 2007:

	(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 approved by security holders - restricted units		4,263		n/a
Equity compensation plans approved by security holders - options		1,810,254	$	18.15
Equity compensation plans approved by security holders - Total		1,814,517				1,112,565

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The following table contains information about the AHD Plan as of December 31, 2007:

	(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 approved by security holders - phantom units		220,825		n/a
Equity compensation plans approved by security holders - unit options		1,215,000	$	22.56
Equity compensation plans approved by security holders - Total		1,435,825				663,800

The following table contains information about the APL Plan as of December 31, 2007:

	(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 approved by security holders - phantom units		129,746		n/a		208,055

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 2007, Resource America paid $5.2 million toward such operating costs of Anthem and Anthem reimbursed it $3.2 million.

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.

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ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES

For the years ended December 31, 2007 and 2006, Grant Thornton LLP’s accounting fees and services were as follows (in thousands):

	2007		2006 (1)
Audit fees(2)	$	1,180	$	100
Audit-related fees(3)		372		—
Tax fees		—		—
All other fees		—		—
Total accounting fees and services	$	1,552	$	100

____________

⁽¹⁾   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.

⁽²⁾   Audit fees include professional services rendered for the annual audit of our financial statements and the reviews of the financial statements included in our quarterly reports of Form 10-Q.

⁽³⁾   Represents fees related to the historical audits of DTE Gas & Oil Company.

Audit Committee Pre-Approval Policies and Procedures

Our 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 before December 18, 2006 and by our audit committee after that date.

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PART IV

ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)(1)Financial Statements

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets at December 31, 2007 and 2006

Combined and Consolidated Statements of Income for the years ended December 31, 2007 and 2006, three months ended December 31, 2005 and year ended September 30, 2005

Combined and Consolidated Statements of Comprehensive Income for the years ended December 31, 2007 and 2006, three months ended December 31, 2005 and year ended September 30, 2005

Combined and Consolidated Statements of Equity for the years ended December 31, 2007 and 2006, three months ended December 31, 2005 and year ended September 30, 2005

Combined and Consolidated Statements of Cash Flows for the years ended December 31, 2007 and 2006, three months ended December 31, 2005 and year ended September 30, 2005

Notes to Combined and Consolidated Financial Statements − December 31, 2007

(2)Financial Statement Schedules

(3)Exhibits:

Exhibit No.	Description
2.1	Purchase Agreement dated as of May 18, 2007 among MCN Energy Enterprises, Inc., DTE Energy Company, ATN Michigan, Inc. and Atlas Energy Resources, LLC1
3.1	Certificate of Formation of Atlas Energy Resources, LLC2
3.2	Amended and Restated Limited Liability Company Agreement of Atlas Energy Resources, LLC3
3.2(a)	Amendment No. 1 to Amended and Restated Operating Agreement of Atlas Energy Resources, LLC4
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) 3
10.1	Revolving Credit Agreement, dated as of June 29, 2007, among Atlas Energy Operating Company, LLC, its subsidiaries, J.P. Morgan Chase Bank, N.A., as Administrative Agent and the other lenders signatory thereto4
10.1(a)	First Amendment to Credit Agreement, dated as of October 25, 20075
10.2	Employment Agreement, dated May 18, 2007, by and between Atlas America, Inc. and Richard L. Redmond Jr. 4
10.3	Voting Agreement dated as of June 29, 2007 between Atlas America, Inc. and Atlas Energy Management, Inc.4
10.4	Registration Rights Agreement dated as of June 29, 2007 by and among Atlas Energy Resources, LLC ad the purchasers named therein 4
10.5	Class D and Common Unit Purchase Agreement1

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10.6	Atlas Energy Resources Long-Term Incentive Plan6
10.6(a)	Form of Unit Award Agreement7
10.6(b)	Form of Non-Employee Director Grant Agreement7
10.6(c)	Form of Phantom Unit Grant Agreement7
10.6(d)	Form of Option Grant Agreement7
10.7	Third Amendment to Base Gas Purchase Agreement8
14.1	Pre-Clearance Procedures Memorandum, as amended on October 23, 20075
21.1	Subsidiaries of Atlas Energy Resources, LLC
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 May 21, 2007.

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 22, 2006.

⁴ Previously filed as an exhibit to our Form 8-K filed June 29, 2007.

⁵ Previously filed as an exhibit to our Form 8-K filed October 26, 2007.

⁶ Previously filed as an exhibit to our Form 8-K filed December 18, 2006.

⁷ Previously filed as an exhibit to our Form 8-K filed January 22, 2007.

⁸ Previously filed as an exhibit to our Form 8-K filed January 10, 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 6, 2008	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 6, 2008
Edward E. Cohen
/s/ Richard D. Weber	President and Chief Operating Officer	March 6, 2008
Richard D. Weber
/s/ Matthew A. Jones	Chief Financial Officer	March 6, 2008
Matthew A. Jones
/s/ Nancy J. McGurk	Chief Accounting Officer	March 6, 2008
Nancy J. McGurk
/s/ Jonathan Z. Cohen	Director	March 6, 2008
Jonathan Z. Cohen
/s/ Walter C. Jones	Director	March 6, 2008
Walter C. Jones
/s/ Ellen F. Warren	Director	March 6, 2008
Ellen F. Warren
/s/ Bruce M. Wolf	Director	March 6, 2008
Bruce M. Wolf

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