Atlas Energy Resources 10-K 2008 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2008

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

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

Yes x                 No ¨

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 x  No¨

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       x Accelerated filer       ¨ 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, 2008 was approximately $1.28 billion.

DOCUMENTS INCORPORATED BY REFERENCE:  None

The number of Class B common member units outstanding at February 23, 2009 was 63,381,249.

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K

			Page
GLOSSARY OF TERMS
PART I	Item 1:	Business	5
	Item 1A:	Risk Factors	25
	Item 1B:	Unresolved Staff Comments	40
	Item 2:	Properties	41
	Item 3:	Legal Proceedings	44
	Item 4:	Submission of Matters to a Vote of Security Holders	44
PART II	Item 5:	Market for Registrant's Common Equity Related Unit holder Matters and Issuer Purchases of Equity Securities	45
	Item 6:	Selected Financial Data	46
	Item 7:	Management’s Discussion and Analysis of Financial Condition andResults of Operations	48
	Item 7A:	Quantitative and Qualitative Disclosures about Market Risk	64
	Item 8:	Financial Statements and Supplementary Data	68
	Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	103
	Item 9A:	Controls and Procedures	103
	Item 9B:	Other Information	106
PART III	Item 10:	Directors and Executive Officers and Corporate Governance	106
	Item 11:	Executive Compensation	106
	Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	106
	Item 13:	Certain Relationships and Related Transactions, and Director Independence	106
	Item 14:	Principal Accounting Fees and Services	106
PART IV	Item 15:	Exhibits and Financial Statement Schedules	107
SIGNATURES			109

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GLOSSARY OF TERMS

As commonly used in the oil and gas industry and as used in this Annual Report on Form 10-K, the following terms have the following meanings:

Bbl.  One stock tank barrel or 42 United States gallons liquid volume.

Bcf.  One billion cubic feet.

Bcfe.  One billion cubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl oil, condensate or natural gas liquids.

Btu.  One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Development well.  A well drilled within a proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dth.  One dekatherm, equivalent to one million British thermal units.

Developed acres.  Acres spaced or assigned to productive wells.

Dry hole or well.  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Exploratory well. Test hole drilled on land or in sea to ascertain the extent of recoverable gas and/or oil in a probable but yet unproved location.

Field.  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

FERC.  Federal Energy Regulatory Commission.

Gross acres or gross wells.  The total acres or wells, as the case may be, in which a working interest is owned.

MBbls.  One thousand barrels of oil or other liquid hydrocarbons.

Mcf.  One thousand cubic feet.

Mcfe.  One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.

Mcf/d.  One thousand cubic feet per day.

MMBls.  One million barrels of oil or other liquid hydrocarbons.

MMBtu.  One million British thermal units.

MMcf.  One million cubic feet.

MMcfe.  One million cubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.

MMcfe/d.  One Mmcfe per day.

Net acres or net wells.  The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NGL.  Natural gas liquids, which are the hydrocarbon liquids contained within gas.

NYMEX.  The New York Mercantile Exchange.

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Oil.  Crude oil, condensate and natural gas liquids.

Productive well.  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Proved developed reserves.  Reserves that can be expected to be recovered through existing wells with existing equipment and operating 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 are included in “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.

Proved reserves.  Proved oil and gas reserves are the estimated quantities of gas, natural gas liquids and oil 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 on future conditions.  The definition of proved reserves is in accordance with the Securities and Exchange commission’s definition set forth in Regulation S-X Rule 4-10 (a) and its subsequent staff interpretations and guidance.

Proved undeveloped drilling location.  A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves or PUDs.  Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.  Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled.  Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.  Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Recompletion.  The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reservoir.  A porous and permeable underground formation containing a natural accumulation of economically productive oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Standardized Measure.  Standardized Measure, or standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities, is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange commission (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%.  Our Standardized Measure does not include future income tax expenses because we are not subject to income taxes.

Successful well.  A well capable of producing oil and/or gas in commercial quantities.

Tcf.  One trillion cubic feet.

Tcfe.  One trillion cubic feet equivalent, determined using a ratio of six Mcf of gas, to one Bbl of oil, condensate, or natural gas liquids.

Undeveloped acreage.  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

Unproved reserves.  Lease acreage on which wells have not been drilled and where it is either probable or possible that the acreage contains reserves.

Working interest.  The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover.  Operations on a producing well to restore or increase production.

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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.

PART I

ITEM 1: BUSINESS

General

We are a publicly-traded Delaware limited partnership (NYSE: ATN) formed in June 2006.  We are an independent developer and producer of natural gas and oil, with operations in the Appalachian Basin, where we focus on the development of the Marcellus Shale, northern Michigan’s Antrim Shale, and Indiana’s New Albany Shale.  Our Appalachian Basin major operations are located in eastern Ohio, western Pennsylvania, and north central Tennessee, and we have additional operations  in New York, West Virginia and Kentucky.  We specialize in the development of these natural gas basins because they provide us with repeatable, low-risk drilling opportunities.  We are a leading sponsor and manager of tax-advantaged, direct investment natural gas and oil partnerships in the United States. Our focus is to increase our own reserves, production, and cash flows through a balanced mix of generating new opportunities of geologic prospects, natural gas and oil exploitation and development, and sponsorship of investment partnerships. We generate both upfront and ongoing fees from the drilling, production, servicing, and administration of our wells in these partnerships.

We have access to the gas gathering facilities owned by our affiliate Atlas Pipeline Partners, L.P. (NYSE: APL) (“Atlas Pipeline”), which is a subsidiary of our indirect parent company, Atlas America, Inc.  (NASDAQ: ATLS), (“Atlas America”) for our core Appalachian properties, providing ample capacity and deliverability directly from the wellhead to interstate pipelines serving major east coast natural gas markets. We have established expertise, recognition, and relationships with partners, suppliers and mineral interest owners in the region and believe our extensive geological and operating experience, coupled with our access to Atlas Pipeline’s gas gathering infrastructure, gives us competitive advantages in developing these natural resources to achieve annual volumetric growth and strong financial returns on a long-term basis.

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. We are managed by Atlas Energy Management, Inc., a wholly-owned subsidiary of Atlas America.  Our class B units are traded on the New York Stock Exchange under the symbol ATN. Unless otherwise indicated, references in this report to we, our or us include Atlas Energy Resources, LLC, our wholly owned subsidiaries and our interests in sponsored drilling programs.

Strategy

Our business is structured to achieve capital appreciation through growth of our natural gas production and reserves and ongoing fee generation through our investment partnerships. During 2008, we achieved record production of 34.9 Bcfe, an increase of 59% from the prior year, contributing to 73% growth in our production revenues to $311.8 million. We also increased our estimated proved reserves as of December 31, 2008 by 12% to 1.0 Tcfe, of which 40% were proved undeveloped reserves. Our undeveloped acreage position provides us with a multi-year inventory of drilling locations for future growth, which may be accelerated by emerging horizontal shale plays in our operating areas. Our strategy for capitalizing on these opportunities includes the following:

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Organic Growth through Drilling. Development drilling is the key component for production and reserve growth. During 2008, we drilled 838 gross (789 net) wells in Appalachia, compared to 1,117 gross (1,028 net) wells during 2007.  Our development activity in 2008 represents a shift from drilling a large quantity of wells in the shallow Upper Devonian Shale in 2007, to the deeper Marcellus Shale formation in 2008.  These wells were drilled primarily for our investment partnerships, in which we own an approximate 35% to 40% interest.  We also drilled 168 gross (141 net) wells in the Antrim Shale for our own account during 2008, an increase of 66 gross (50 net wells), compared to 2007.  Our growth strategy during 2009 will continue to focus on drilling in our key operated areas, as well as increasing our acreage position to take advantage of horizontal drilling opportunities on core properties.

Development of Additional Drilling Prospects. We follow a disciplined capital allocation process in selecting opportunities to expand our substantial inventory of drilling locations that meet our criteria for predictable, long-lived reserves. Our goal is to consolidate our position in the Appalachian Basin, while diversifying our asset base with similar plays outside the basin. As part of this strategy, we acquired several large acreage tracts during 2008, as follows:

· We established a position in the New Albany Shale of southwestern Indiana by acquiring 163,000 gross (120,000 net) acres and by entering into a farm-out agreement that will give us the right to drill on an additional 121,000 gross (78,000 net) acres.  The acreage is located in Sullivan, Knox, Green, Davies, Owen, Clay, and Lawrence counties, Indiana.  We began developing our New Albany shale acreage beginning in November 2008 and drilled 5.0 gross (4.0 net) wells.

· We added approximately 85,000 acres in Tennessee to consolidate our position in Campbell, Scott, and Morgan Counties.  We drilled 58 gross vertical and 10 gross horizontal wells on our acreage known as the Lake City area, during 2008.

· We have leased approximately 556,400 acres in the Marcellus Shale play in Pennsylvania, New York, and West Virginia, and have targeted 274,500 acres as our core area in southwestern Pennsylvania.  As of February 19, 2009, we drilled 126 net vertical and 5 horizontal wells.

We plan to continue capitalizing on opportunities to assemble or participate in developing large tracts with significant reserve potential.

Geographic and Geological Advantages

Our proved reserves, both developed and undeveloped, are concentrated in several areas.

Marcellus Shale Overview. 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 19, 2009, we control approximately 556,000 Marcellus Shale acres in Pennsylvania, New York and West Virginia, and we continue to expand our position. As of that date, we had drilled 126 vertical wells and 5 horizontal wells and are currently producing 105 wells into a pipeline.  The remaining 26 wells are scheduled to be completed and turned into line in the first half of 2009. We are currently focused on our approximately 274,000 existing Marcellus Shale acres in southwestern Pennsylvania, where we have drilled all but two of our Marcellus wells and have now, through this drilling, largely delineated our acreage. Almost all of this acreage in southwestern Pennsylvania has or is expected to have ample pipeline capacity using our or Atlas Pipeline’s gas gathering infrastructure.

Over the last 4 months, we have made great strides in optimizing our completion practices for vertical Marcellus Shale wells. We have initiated a multiple stage completion process that isolates various portions of the Marcellus package, giving a more effective stimulation of the reservoir. This technique has been used on 15 wells to date, and has consistently illustrated better-than-average peak 24-hour, 30-day, and 60-day cumulative production results. We anticipate that, where applicable, all future vertical wells will be stimulated in this fashion. With 8 multiple stage wells on line at year end, Wright & Company, Inc., our independent petroleum engineering consultants, assigned an average EUR of 1.423 Bcf  per well.  As of this date, we have  successfully drilled, cased, and cemented 3 additional horizontal wells in Washington County PA, with 2 of these wells stimulated and currently flowing back frac fluid.

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Horizontal Drilling Overview. The value potential for many of our Appalachian properties may be enhanced by the use of horizontal drilling, which has been found to provide advantages in extracting natural gas in various environments, including shale and other tight reservoirs that are challenging to produce efficiently. In general, horizontal wells use directional drilling to create one or more lateral legs designed to allow the well bore to stay in contact with the reservoir longer and to intersect more vertical fractures in the formation than conventional methods. While substantially more expensive, horizontal drilling may improve overall returns on investment by increasing recovery volumes and rates, limiting the number of wells necessary to develop an area through conventional drilling and reducing the costs and surface disturbances of multiple vertical wells.

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, 2008, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin was $.235 per MMBtu. In addition, our Appalachian gas production also has the advantage of a high energy content, ranging from 1.0 to 1.15 Dth per Mcf. Historically, because our gas sales contracts yield upward adjustments from index based pricing for throughput with an energy content above 1 Dth per Mcf.  This higher energy content resulted in realized premiums averaging 6% over normal pipeline quality gas for the twelve months ended December 31, 2008.

During the first several years of production, shallow 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.  While the wells in this area are characterized by modest initial volumes and pressures, their geological features also account for the low annual decline rates demonstrated by vertical wells in the region, many of which are expected to produce for 30 years or more.

Shallow reserves in the Appalachian Basin are typically in blanket formations and have a high degree of step-out development success.  The primary pay zone throughout this region is the Devonian Shale formation. As the step-out 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.

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 the 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 absorbed 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. Each well’s gas is transported 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.

New Albany Shale Overview. The Devonian aged New Albany Shale is a blanket formation found at depths of 500 to 3,000 feet, with thicknesses ranging from 100 to 200 feet.  Like the Antrim Shale, the New Albany Shale in southwestern Indiana where our leasehold acreage is located is in the “biogenic gas window”.  However, unlike the Antrim Shale, where natural fracture patterns are low angle, the natural fracture patterns in the New Albany Shale are vertically oriented.  This vertical fracture orientation lends itself to a horizontal drilling approach.

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Recent Developments

Acquisition of Indiana Assets.  Beginning in July, 2008, we began establishing a position in the New Albany Shale in southwestern Indiana by investing approximately $15.0 million.  We acquired 120,000 net undeveloped acres and entered into a farm-out agreement that will give us rights to an additional 78,000 net undeveloped acres.  These leases are located in Sullivan, Knox, Greene, Owen, Davies, Clay and Lawrence counties, in Indiana.  In addition, we acquired a 50% undivided interest in a gas gathering system with related compression Co2 processing and fluid disposal facilities in Sullivan County.

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

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

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

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

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

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

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

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Key Performance Indicators as of and for the year ended December 31, 2008:

In our Appalachia gas and oil operations:

· we have proved reserves of 373.9 Bcfe, including the reserves net to our equity interest in our investment partnerships and our direct interests in producing wells;

· we own direct and indirect working interests in approximately 8,462 gross productive gas and oil wells;

· we own overriding royalty interests in approximately 624 gross productive gas and oil wells;

· our net daily production was 35.6 Mmcfe per day;

· we lease approximately 950,530 gross (904,890 net) acres, of which approximately 640,430 gross (633,490 net) acres are undeveloped;

· we have identified 3,626 geologically favorable shallow drilling locations;

· included in our undeveloped acreage are approximately 556,438 Marcellus acres in Pennsylvania, New York and West Virginia, of which approximately 274,495 acres are located in our core Marcellus Shale position in southwestern Pennsylvania

· we drilled 838 gross (789 net) wells of which 830 gross (781 net) wells were productive for our investment partnerships;

· as of February 19, 2009, we drilled 126 net vertical and 5 net horizontal Marcellus Shale wells (3 of which have been successfully drilled, cased and cemented); and

· we drilled and participated in 12 successful horizontal wells in the Chattanooga Shale of eastern Tennessee.

In our Michigan gas and oil operations:

· we have proved reserves of  617.0 Bcfe;

· we own direct and indirect working interests in approximately 2,458 gross producing gas and oil wells;

· we manage total proved reserves of 1,003 Bcfe;

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

· our net daily production was 59.7 Mmcfe per day;

· we lease approximately 345,680 gross (273,280 net) acres, of which approximately 42,390 gross (33,100 net) acres are undeveloped; and

· we drilled 168 gross wells (139 net wells).

In our Indiana gas and oil operations:

· we have proved reserves of 10.3 Bcfe;

· we own direct and indirect working interests in approximately 5 gross producing gas and oil wells;

· our net daily production was 0.2 Mmcfe per day;

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· we have leased approximately 161,140 gross (119,670 net) acres, of which approximately 160,480 gross (119,185 net) acres are undeveloped; and

· we drilled 5 gross (4 net) wells.

In our partnership management business:

· Our investment partnership business includes equity interests in 94 investment partnerships and a registered broker-dealer which acts as the dealer manager of our investment partnership offerings;

· we raised $438.4 million in investor subscriptions and formed two new public partnerships;

· we manage total Appalachia proved reserves of 706 Bcfe;

· we drilled 838 gross wells (789 net wells) on behalf of our investment partnerships (of which we contributed an approximately 35% interest).

Gas and Oil Production

Production Profile. The gas and oil wells in each geological basin in which we operate  share a relatively predictable production profile, producing high quality natural gas at low pressures from several pay zones. Wells in each region generally demonstrate moderate annual production declines throughout their economic life, which may continue for 30 years or more without significant remedial work or the use of secondary recovery techniques.

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Production Volumes. We increased our production volumes in 2008 by 59% over 2007 levels to a record 34.9 Bcfe. Our production in the fourth quarter of 2008 was 9.0 Bcfe, reflecting volumetric growth of 7% on a period-over-period basis and growth of 2% compared to our production volumes for the third quarter of 2008. The following table shows our total net gas and oil production volumes during the last three years (in thousands, except for production per day):

	Years Ended December 31,
	2008		2007			2006
Production (1):
Appalachia: (3)
Natural gas (MMcf)		12,086		9,912			8,946
Oil (000’s Bbls)		155		153			151
Total (MMcfe)		13,014		10,828			9,850
Michigan/Indiana: (2)
Natural gas (MMcf)		21,816		11,051			—
Oil (000’s Bbls)		4		1			—
Total (MMcfe)		21,839		11,056			—
Total:
Natural gas (MMcf)		33,902		20,963			8,946
Oil (000’s Bbls)		159		154			151
Total (MMcfe)		34,853		21,884			9,850
Production per day:
Appalachia:
Natural gas (Mcf/d)		33,023		27,156			24,511
Oil (Bbl)		423		418			413
Total (Mcfe/d)		35,558		29,666			26,989
Michigan/Indiana:
Natural gas (Mcf/d)		59,606		59,737	(2)		—
Oil (Bbl)		11		4			—
Total (Mcfe/d)		59,672		59,761			—
Total:
Natural gas (Mcf/d)		92,629		86,893			24,511
Oil (bpd)		434		422			413
Total (Mcfe/d)		95,227		89,425			26,989

(1) 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.

(2) Amounts represent production volumes related to DTE Gas & Oil, LLC, now known as “AGO”, from the acquisition date (June 29, 2007) to December 31, 2007.

(3) Appalachia includes our production located in Pennsylvania, Ohio, New York, West Virginia, and Tennessee.

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Production Revenues, Prices and Costs. Our production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised 99% of our proved reserves on an energy equivalent basis at the end of 2008. The following table shows our production revenues and our average sales prices for our oil and gas production during the last three years, along with our average production costs, taxes, and transmission and compression costs in each of the reported periods.

	Years Ended December 31,
	2008		2007		2006
Production Revenues (in thousands):
Appalachia:
Natural gas revenue	$	113,595	$	88,269	$	79,016
Oil revenue		14,275		10,704		9,433
Total revenues	$	127,870	$	98,973	$	88,449
Michigan/Indiana:
Natural gas revenue	$	183,550	$	81,045	$	—
Oil revenue		365		64		—
Total revenues	$	183,915	$	81,109	$	—
Total:
Natural gas revenue	$	297,145	$	169,314	$	79,016
Oil revenue		14,640		10,768		9,433
Total revenues	$	311,785	$	180,082	$	88,449
Average Sales Price:
Appalachia:
Natural gas (per Mcf)
Total realized price, after hedge	$	9.40	$	8.91	$	8.83
Total realized price, before hedge	$	9.63	$	7.71	$	7.90
Michigan/Indiana:
Natural gas (per Mcf)
Total realized price, after hedge	$	8.98	$	8.44	$	—
Total realized price, before hedge	$	9.01	$	6.78	$	—
Total:
Natural gas (per Mcf)
Total realized price, after hedge	$	9.13	$	8.66	$	8.83
Total realized price, before hedge	$	9.23	$	7.22	$	7.90
Appalachia:
Oil (per Bbl)
Total realized price, after hedge	$	92.28	$	70.11	$	62.30
Total realized price, before hedge	$	91.71	$	70.11	$	62.30
Michigan/Indiana:
Oil (per Bbl)
Total realized price, after hedge	$	94.93	$	80.66	$	—
Total realized price, before hedge	$	94.93	$	80.66	$	—
Total:
Oil (per Bbl)
Total realized price, after hedge	$	92.35	$	70.16	$	62.30
Total realized price, before hedge	$	91.79	$	70.16	$	62.30
Production Costs (per Mcfe):
Appalachia:
Lease operating expenses	$	1.03	$	0.86	$	0.83
Production taxes		0.03		0.03		0.03
Transportation and compression		0.87		0.74		0.55
	$	1.93	$	1.63	$	1.41
Michigan/Indiana:
Lease operating expenses	$	0.75	$	0.68	$	—
Production taxes		0.54		0.26		—
Transportation and compression		0.29		0.38		—
	$	1.58	$	1.32	$	—
Total:
Lease operating expenses	$	0.85	$	0.77	$	0.83
Production taxes		0.35		0.21		0.03
Transportation and compression		0.51		0.49		0.55
	$	1.71	$	1.47	$	1.41

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Investment Partnerships and Drilling Operations

Drilling Operations

At the end of 2008, we owned working interests in approximately 10,957 gross wells.  These wells are concentrated in the Appalachian Basin, where we operate and control 73% through our investment partnerships, and in Michigan’s Upper lower peninsula. We believe our long and successful operating history in Appalachia and proven ability to drill a large number of wells year after year have positioned us as a leading player in this region. 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 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 20% to 31% of the overall capitalization in a particular partnership. We also receive an additional interest in each partnership, typically 7%-10%, for which we do not make any additional capital contribution, for a total interest in our partnerships ranging from 27% to 40%.

We do not operate any of the rigs or related equipment used in our drilling operations, relying instead on specialized subcontractors or joint venture partners for all drilling and completion work. This enables us to streamline our operations and conserve capital for investments in new wells, infrastructure and property acquisitions, while generally retaining control over all geological, drilling, engineering and operating decisions. Other than our Marcellus Shale and horizontal wells, the geological characteristics of our Appalachian and Michigan  properties enable us to drill most of our vertical wells in seven to ten days, although we usually defer completion operations until the gathering lines are in place. We perform regular inspection, testing and monitoring functions on our operated wells and gathering systems with our own personnel.

Drilling Programs

Drilling Program Capital. During the last three years, we raised over $1.0 billion from outside investors for participation in our drilling partnerships. Net proceeds from these programs are used to fund the investors’ share of drilling and completion costs under our drilling contracts with the programs. These contract payments are recorded as “Liabilities associated with drilling contracts” at the time of receipt. We recognize revenues from drilling operations on the percentage-of-completion method as the wells are drilled, rather than when funds are received. “Liabilities associated with drilling contracts” are reflected as current liabilities in our consolidated financial statements and represent the net unapplied advance program payments for wells that were not yet drilled or are in progress as of the balance sheet dates. Our fund raising activities of sponsored drilling programs during the last three years are summarized in the following table:

	Drilling Program Capital (in thousands)
Years Ending December 31,	Investor Contributions		Our Contributions		Total Capital
2008	$	438.4	$	146.3	$	584.7
2007		363.3		137.6		500.9
2006		218.5		73.6		292.1
Total	$	1,020.2	$	357.5	$	1,377.7

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Drilling Program Results. 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 depth or type of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table shows the number of gross and net development wells we drilled for us and our investment partnerships during the last three years. During the fourth quarter of 2008, we drilled 104 gross (96 net) wells in Appalachia.  We did not drill any exploratory wells during the years ended December 31, 2008, 2007 and 2006, respectively.

					Our Share		Dry
Years Ended December 31,	Gross		Net		of Net(1)		Gross		Net
Appalachia
2008		830		786		279		8		3
2007		1,106		1,021		378		11		4
2006		711		655		235		4		1
Total		2,647		2,462		892		23		8
Michigan/Indiana
2008		173		143		140		—		—
2007		115		92		92		—		—
2006		—		—		—		—		—
Total		288		235		232		—		—

(1)  Includes (i) our percentage interest in wells in which we have a direct ownership interest and (ii) our percentage interest in the wells based on our percentage interest in our investment partnerships.

Drilling Program Revenue Streams.  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 an 18% mark-up on those costs incurred to drill and complete the well.  Prior to our most recent investment program, Atlas Resources Public #18-2008 Program, formed in November 2008, the mark-up was 15%.

· Administration and oversight. For each well drilled by an investment partnership, we receive a fixed fee of $15,700 for non-Marcellus Shale wells and $62,241 for Marcellus Shale wells. Prior to our most recent investment program, Atlas Resources Public #18-2008 Program, formed in November 2008, the administration and oversight fees were $15,000 for a non-Marcellus Shale well and $60,000 for a Marcellus Shale well.  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, increasing to $975 for Marcellus Shale wells, for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

· Gathering. Each partnership pays us a gathering fee.  We, in turn, pay this gathering fee to Atlas Pipeline pursuant to the terms of our contribution agreement with Atlas America, entered into at the time of our initial public offering in December 2006.  Therefore, 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.We do not believe any amounts which may be subordinated in the future will be material to our operations.

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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 taxable ordinary income. Intangible drilling costs include items that do not have salvage value, such as labor, fuel, repairs, supplies and hauling. Currently, under our most recent partnership agreement, Atlas Resources Public #18-2008 Program, approximately 85% of the subscription proceeds received have been used to pay 100% of the partnership’s intangible drilling costs. For example, an investment of $10,000 generally permits the investor to deduct from taxable ordinary income approximately $8,500 in the year in which the investor invests.  Prior to Atlas Resources Public #18-2008 Program, approximately 90% of the subscription proceeds received were used to pay 100% of the partnership’s intangible drilling costs.

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, 2008, we anticipate that we and our affiliates, including our investment partnerships, will sell approximately 16% of our Appalachian natural gas production during the year ending December 31, 2009 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, 2008, we received an average price, before the effects of financial hedges, of $9.63 per Mcf of natural gas, compared to $7.71 per Mcf in fiscal 2007 and $7.90 per Mcf in fiscal 2006, respectively, in our Appalachian operations.

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.

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Michigan

In Michigan, we have natural gas sales agreements with DTE Energy Company, 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:

· 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, 2008, we anticipate that we and our affiliates will sell approximately 49% of our Michigan natural gas production during the year ending December 31, 2009 under the DTE agreements in most cases, at NYMEX pricing.  During the year ended December 31, 2008 and the six months ended December 31, 2007, we received an average price before the effects of financial hedges of $9.01 and $6.78 per Mcf of natural gas, respectively, in our Michigan operations.

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, oil production is minimal and 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 15% and 38%) 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

Financial Hedges.We seek to provide greater stability in our cash flows through our use of financial 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 hedge 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.

Physical Hedges.  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.

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Natural Gas Gathering

Appalachia

We conduct our natural gas transportation and processing operations through Atlas Pipeline and, to a lesser extent, the transportation and processing facilities we own directly.  Atlas Pipeline owns approximately 1,835 miles of gathering systems located in eastern Ohio, western New York and western Pennsylvania serving approximately 7,440 wells.

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

Omnibus Agreement

Under the omnibus agreement, Atlas America and its affiliates agreed to add wells to Atlas Pipeline's gathering systems and provide consulting services when Atlas Pipeline constructs new gathering systems or 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 Mcf or 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 $0.35 per Mcf or 16% of the gross sales price of the natural gas transported; and

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

We receive gathering fees from contracts or other arrangements with the owners of well interests connected to Atlas Pipeline’s gathering systems. Pursuant to the contribution agreement described below under "—Other Agreements with Atlas America and its Affiliates—Contribution Agreement,” Atlas America agreed to assume our obligation to pay gathering fees to Atlas Pipeline. We, in turn, assigned to Atlas America the gathering fees we receive from our investment partnerships and gathering fees attributable to our production interest. The gathering fees payable to Atlas Pipeline generally exceed the amount we receive from our investment partnerships for gathering services.  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 1,230 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 82 CPFs, of which we operate 62.  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 186 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.

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Other Agreements with Atlas America and Its Affiliates

Contribution Agreement

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

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.

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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.

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 2008, 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 is sold under contract to various purchasers.  For the years ended December 31, 2008 and 2007 and 2006, gas sales to Hess Corporation (formerly First Energy Solutions Corp.) accounted for 10%, 10% and 18%, respectively, of our total Appalachian gas and oil production revenues.  For the year ended December 31, 2008 and the six months ended December 31, 2007, sales to DTE accounted for 49% and 46% of our Michigan oil and gas production revenues, respectively.  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 can be 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, 2008, we did not experience problems in selling our natural gas and oil, although prices have varied significantly during this period.

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Natural Gas and Oil Leases

General.  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 1/8th (12.5%) resulting in a 87.5% net revenue interest to us, and in Michigan this amount is typically 1/6th (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 1/6th in the Appalachian Basin and to 3/16th (18.75%) in Michigan when leases are taken from larger landowners or mineral owners such as coal and timber companies.

In almost all of the areas we operate in the Appalachian Basin and in 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.

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 1/32nd to 1/16th (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%.

Participation rights.  These rights give the mineral owner the right to joint venture with us and participate for up to 50% of the wells drilled on the covered acreage.  In this event, our working interest ownership will be reduced by the amount retained by the third party. In all other instances, we anticipate owning a 100% working interest in newly drilled wells.

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 and water treatment facilities;

· restrict the types, quantities and concentration of various substances including fracturing and brine water, 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, 2008, 2007 and 2006, 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 2009, 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 drilling 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.  These permits may require pretreatment of produced waters before discharge.  Compliance with such permits and requirements may be costly.  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 manner in which water necessary to develop wells is managed;

· 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 4.9% 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. While Pennsylvania has historically not imposed a severance tax, its governor recently proposed a tax of 5% on the value of natural gas at the wellhead plus $0.047 per Mcf beginning October 1, 2009.  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 unit holders.

Employees

We do not have any employees.  To carry out our operations, our manager and its affiliates employed approximately 602 persons as of December 31, 2008.

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 “ATN Unit Holders 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 provided such certification to the NYSE in 2008 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 quarterly distributions 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 quarterly distributions. 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:

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· 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;

· 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 initial quarterly distribution amount.

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

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· 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, 2008, the NYMEX Henry Hub natural gas index price ranged from a high of $13.11 per MMBtu to a low of $6.47 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $134.02 per Bbl to a low of $42.04 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, 2008 reserve reports, our average annual decline rate for proved developed producing reserves is approximately 7.8% during the first five years, approximately 5.3% in the next five years and less than 5.5% thereafter. Because our total estimated proved reserves include proved undeveloped reserves at December 31, 2008, 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.

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 long-term 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, 2008 would decrease from $1.128 billion to $800.0 million. 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.

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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:

· 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.

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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 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 have successfully integrated 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;

· 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.

If we have a future acquisition, there can be no assurance that any 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, increased our reserve life, expanded our geographic market and resulted in large increases 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 January 15, 2009, we have drilled 121 gross wells to the Marcellus Shale,  of which 121 gross wells have been turned on-line. 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 and requires greater volumes of water than conventional gas wells.  The management of water and the treatment of produced water from Marcellus Shale wells may be more costly than the management of produced water from other geologic formations.

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We have a substantial amount of indebtedness which could adversely affect our financial position.We currently have a substantial amount of indebtedness. As of December 31, 2008, we had total debt of approximately $873.7 million, consisting of $406.7 million of senior notes and $467.0 million of borrowings under our credit facility. 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;

• 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 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.

Recently proposed severance taxes in Pennsylvania could materially increase our liabilities.  In 2008, our liabilities for severance taxes in the states in which we operate, other than Pennsylvania, were approximately $12.2 million.  While Pennsylvania has historically not imposed a severance tax, with a focus on its budget deficit and the increasing exploitation of the Marcellus Shale, Pennsylvania’s governor recently proposed a tax of 5% of the value of natural gas at the wellhead plus $0.047 per Mcf beginning October 1, 2009.  If adopted, these taxes may materially increase our operating costs in Pennsylvania.

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. During the fourth quarter of 2008, we began development drilling activities for us and our partnership investors in Indiana.  Accordingly, the amount of development activities we undertake depends in large part upon our ability to obtain investor subscriptions to invest in these partnerships. During the past three years we have raised successively larger amounts of funds through these investment partnerships, raising $218.5 million, $363.3 million and $438.4 million, in calendar 2006, 2007 and 2008, 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.

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Furthermore, competition arises not only from numerous domestic and foreign sources of natural gas and oil but also from other industries that supply alternative sources of energy. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. Product availability and price are the principal means of competition in selling 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.

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 calendar year 2008, natural gas sales to Hess Corporation accounted for approximately 10% of our total Appalachian oil and gas revenues. In Michigan, during calendar year 2008, gas under contracts to a former affiliate of Atlas Gas & Oil, which expire at various dates through 2012, accounted for approximately 49% 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 unit holders 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, 2008, this excess amount was approximately $24.4 million. If Atlas America defaulted on its obligation to us under the assumption agreement to pay gathering fees to Atlas Pipeline, we would be liable to Atlas Pipeline for the payment of the fees, which would reduce our income and cash available for distributions and payments on our debt.

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.

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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;

· RCRA and comparable state laws that impose requirements for the handling and disposal of waste, including produced waters, 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, 2008, we had identified over 3,626 potential shallow drilling locations in Appalachia. 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. Of the 3,626 potential shallow drilling locations, our independent petroleum engineering consultants have assigned reserves to 358 proved undeveloped locations.  Of the remaining drilling locations we have identified, 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 85,140 of our 422,900 shallow net acres, or 20%, are scheduled to expire on or before December 31, 2009.  An additional 33% of our shallow net acres are scheduled to expire in the years 2010 and 2011.  If we are unable to renew these leases or any leases scheduled for expiration beyond December 31, 2009, 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 future distribution payments on our debt.  We do not expect that we will have significant difficulty in renewing or replacing these leases or similar leasehold acreage.

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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:

· 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.

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Hedging transactions may limit our potential gains or cause us to lose money. Pricing for natural gas and oil has been volatile and unpredictable for many years. To limit exposure to changing natural gas and oil prices, we use financial and physical hedges for our natural gas, and to a lesser extent, our oil 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, and to a lesser extent, our oil production, we have reduced, but not eliminated, the potential effects of changing natural gas and oil prices on our cash flow from operations for those periods. Furthermore, while intended to help reduce the effects of volatile natural gas and oil prices, such transactions, depending on the hedging instrument used, may limit our potential gains if natural gas and oil 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 or oil prices, we may be exposed to the risk of financial loss.

We may be exposed to financial and other liabilities as the managing general partner in investment partnerships. We serve as the managing general partner of 94 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.

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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:

· 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 unit holder 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 29,952,996 Class B 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, our manager has no direct employees.  If our management agreement terminates with Atlas America, we may be unable to find a suitable replacement for them.

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

Expense reimbursements due to our manager under our management agreement will reduce cash available for distribution to our 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. We may terminate our 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.

We may issue additional units without the approval of the common unit holders, which would dilute the common unit holder’s existing ownership interests.  Our limited liability company agreement permits us to issue an unlimited number of units of any type, including common units, without the approval of our unit holders.  The issuance of additional units or other equity securities may have the following effects:

· the proportionate ownership of the existing common unit holders’ interest in us may decrease;

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

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

· the market price of the common units may decline.

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An increase in interest rates may cause the market price of our common units to decline. Like all equity investments, an investment in our common units is subject to risks.  In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments.  Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly-traded limited liability company interests.  Reduced demand for our common units resulting from investors seeking other investment opportunities may cause the trading price of our common units to decline.

Unit holders may have liability to repay distributions.  Under certain circumstances, unit holders may have to repay amounts wrongfully returned or distributed to them.  Under Section 18-607 of the Delaware Revised Limited Liability Company Act, we may not make a distribution to the common unit holders if the distribution would cause our liabilities to exceed the fair value of our assets.  Delaware law provides that for a period of three years from the date of an impermissible distribution, unit holders who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited liability company for the distribution amount.  A purchaser of common units who becomes a unit holder is liable for the obligations of the transferring unit holder to make contributions to the limited liability company that are known to such purchaser of units at the time it became a member and for unknown obligations if the liabilities could be determined from our limited liability company agreement.

If our unit price declines, the common unit holders could lose a significant part of their investment. The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control including:

· Changes in securities analysts’ recommendations and their estimates of our financial performance;

· The public’s reaction to our press releases, announcements and our filings with the SEC;

· Fluctuations in broader securities market prices and volumes, particularly among securities of natural gas and oil companies and securities of publicly-traded limited partnerships and limited liability companies;

· Changes in market valuations of similar companies;

· Departures of key personnel;

· Commencement of or involvement in litigation;

· Variations in our quarterly results of operations or those of other natural gas and oil companies;

· Variations in the amount of our quarterly cash distributions;

· Future issuances and sales of our units; and

· Changes in general conditions in the U.S. economy, financial markets or the natural gas and oil industry.

In recent years the securities market has experienced extreme price and volume fluctuations.  This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies.  Future market fluctuations may result in a lower price of our common units.

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

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Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution.  The anticipated after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed as corporate distributions, and no income, gain, loss, deduction or credit would flow through to you. Because a tax may be imposed on us as a corporation, our cash available for distribution to our 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 cash distribution amounts and the incentive distribution amounts will be adjusted to reflect the impact of that law on us.

Our common unit holders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.  Our common unit holders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us.  Our common unit holders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

A successful IRS contest of the federal income tax positions we take may harm the market for our common units, and the costs of any contest will reduce cash available for distribution.  We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter that affects us.  The IRS may adopt positions that differ from the positions we take.  It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and a court may disagree with some or all of those positions.  Any contest with the IRS may lower the price at which our common units trade.  In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution to our unit holders and thus will be borne indirectly by our unit holders.

Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.  Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts, or IRAs, and non-U.S. persons raises issues unique to them.  For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unit holder.  Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

We will treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased.  The IRS may challenge this treatment, which could reduce the value of the common units.  Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations.  A successful IRS challenge to those positions could reduce the amount of tax benefits available to our unit holders.  It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unit holders’ tax returns.

39

Tax gain or loss on the disposition of our common units could be more or less than expected because prior distributions in excess of allocations of income will decrease your tax basis in your units.  If our common unit holders sell any of your common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those units.  Prior distributions to them in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that unit, will, in effect, become taxable income to them if the unit is sold at a price greater than their tax basis in that unit, even if the price they receive is less than their original cost.  A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to them.  In addition, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Our common unit holders may be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.  In addition to federal income taxes, our common unit holders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if they do not reside in any of those jurisdictions.  Our common unit holders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions.  Further, they may be subject to penalties for failure to comply with those requirements.  It is the responsibility of each unit holder to file all United States federal, foreign, state and local tax returns that may be require of such unit holder.  Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred.  The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unit holders.  We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred.  The use of this proration method may not be permitted under existing IRS Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method.  If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unit holders.

A unit holder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units.  If so, the unit holder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.  Because a unit holder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unit holder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unit holder may recognize gain or loss from such disposition.  Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unit holder and any cash distributions received by the unit holder as to those units could be fully taxable as ordinary income.  Our counsel has not rendered an opinion regarding the treatment of a unit holder where common units are loaned to a short seller to cover a short sale of common units; therefore, unit holders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We will be considered to have terminated our business 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 unit holder 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

40

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 2010, an 1,800 square foot field office in Gaylord, Michigan under a lease expiring in 2010 and a 1,200 square foot field office in Sullivan, Indiana under a lease expiring in 2010. We also lease a 6,500 square foot field office in Knoxville, Tennessee under a lease expiring in 2014, and a 1,400 square foot field office in Ohio under a lease expiring in 2009.  We rent 17,200 square feet of office space in Uniontown, Ohio and lease other field offices in Ohio, Philadelphia 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, in Michigan’s Lower Peninsula and in the southwestern corner of Indiana. 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:

	At December 31,
	2008		2007		2006
Natural gas (per Mcf)	$	5.71	$	6.93	$	6.33
Oil (per Bbl)	$	44.80	$	90.30	$	57.26

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. The following table presents our reserve information for the previous three years.  We base the estimates on operating methods and conditions prevailing as of the dates indicated.

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	Proved natural
	gas and oil reserves at December 31,
	2008			2007		2006
Proved reserves (in thousands):
Michigan/Indiana:
Natural gas reserves(Mmcf):
Proved developed reserves		446,996			463,609		—
Proved undeveloped reserves (1)		180,220			203,074		—
Total proved reserves of natural gas		627,216			666,683		—
Oil reserves (Mbbl):
Proved developed reserves		8			11		—
Proved undeveloped reserves		—			—		—
Total proved reserves of oil		8			11		—
Appalachia:
Natural gas reserves (Mmcf):
Proved developed reserves		139,659			131,100		107,683
Proved undeveloped reserves (1)		223,930			86,976		60,859
Total proved reserves of natural gas		363,589			218,076		168,542
Oil reserves (Mbbl):
Proved developed reserves		1,678			1,966		2,064
Proved undeveloped reserves		48			6		4
Total proved reserves of oil		1,726			1,972		2,068
Total natural gas reserves (Mmcf):
Proved developed reserves		586,655			594,709		107,683
Proved undeveloped reserves(1)		404,150			290,050		60,859
Total proved reserves of natural gas		990,805			884,759		168,542
Total oil reserves (Mbbl):
Proved developed reserves		1,686			1,977		2,064
Proved undeveloped reserves		48			6		4
Total proved reserves of oil		1,734			1,983		2,068
Total proved reserves (Mmcfe)		1,001,209			896,657		180,950
Total  PV-10 estimate of cash flows of proved reserves (in thousands) (2):
Michigan/Indiana:
Proved developed reserves	$	728,245		$	869,310	$	—
Proved undeveloped reserves		149,239			208,056		—
Total PV-10 estimate	$	877,484		$	1,077,366	$	—
Appalachia:
Proved developed reserves	$	288,637		$	394,999	$	279,330
Proved undeveloped reserves		(34,180	)(3)		8,813		4,111
Total PV-10 estimate	$	254,457		$	403,812	$	283,441
Proved developed reserves	$	1,016,882		$	1,264,309	$	279,330
Proved undeveloped reserves		115,059			216,869		4,111
Total PV-10 estimate	$	1,131,941		$	1,481,178	$	283,441
Standardized measure of discounted future cash flows (in thousands) (2)	$	1,131,941		$	1,481,178	$	283,441

(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.

(2)	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, 2008, 2007, and 2006 calculations of standardized measure which is, therefore, the same as the PV-10 value. Amounts include physical hedges but not financial hedging transactions.
(3)	Represents increased projected higher capital costs related to deeper wells and horizontal drilling techniques.

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.

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Productive Wells

The following table sets forth information as of December 31, 2008, 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 an investment partnership or with other joint venturers that own an interest in the well.

	Number of Productive Wells
	Gross (1)		Net (1)
Oil wells:
Michigan/Indiana		—		—
Appalachia		509		366
		509		366
Gas wells:
Michigan/Indiana		2,495		1,947
Appalachia		7,953		3,636
		10,448		5,583
Total		10,957		5,949

(1) Includes our proportionate interest in wells owned by 94 investment partnerships for which we serve as managing general partner and various joint ventures. Does not include royalty or overriding interests in 717 wells.

Developed and Undeveloped Acreage

The following table sets forth information about our developed and undeveloped natural gas and oil acreage as of December 31, 2008.  The information in this table includes our proportionate interest in acreage owned by our investment partnerships.

	Developed acreage				Undeveloped acreage
	Gross		Net		Gross		Net
Arkansas		2,560		403		0		0
Indiana		673		483		160,480		119,185
Kansas		160		20		0		0
Kentucky		924		462		9,060		4,530
Louisiana		1,819		206		0		0
Michigan		303,290		240,180		42,390		33,100
Mississippi		40		3		0		0
Montana		0		0		2,650		2,650
New York		20,517		14,989		45,035		45,035
North Dakota		639		96		0		0
Ohio		113,529		95,408		31,984		31,984
Oklahoma		4,323		468		0		0
Pennsylvania		140,692		140,692		428,476		428,476
Tennessee		19,303		17,785		108,783		108,783
Texas		4,520		329		0		0
West Virginia		1,078		539		14,362		11,948
Wyoming		0		0		80		80
		614,067		512,063		843,300		785,771

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 $3.9 million in fiscal 2008 to maintain our leases.

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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 drilling participation rights 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.

ITEM 3: LEGAL PROCEEDINGS

On June 20, 2008, our wholly-owned subsidiary, Atlas America, LLC, was named as a co-defendant in the matter captioned CNX Gas Company, LLC (“CNX”) v. Miller Petroleum, Inc. (“Miller”), et al. (Chancery Court, Campbell County, Tennessee).  In its complaint, CNX alleged that Miller breached a contract to assign to CNX certain leasehold rights (“Leases”) representing approximately 30,000 acres in Campbell County, Tennessee and that we and another defendant, Wind City Oil & Gas, LLC, interfered with the closing of this assignment on June 6, 2008.  We purchased the Leases from Miller for approximately $19.1 million.  On December 15, 2008, the Chancery Court dismissed the matter in its entirety, holding that there had been no breach of the contract by Miller and, therefore, that Atlas America could not have tortuously interfered with the contract.  The Chancery Court dismissed all claims against Atlas America, LLC; however, CNX has appealed this decision.

One of our subsidiaries, Resource Energy, LLC, together with Resource America, Inc., (the former parent of Atlas America), 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 Atlas America 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.  We 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

No matters were submitted to a vote of security holders during the fourth quarter of 2008.

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PART II

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

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

Fiscal 2008	High		Low
Fourth Quarter	$	26.50	$	10.23
Third Quarter	$	40.25	$	22.41
Second Quarter	$	45.40	$	31.76
First Quarter	$	34.87	$	23.65
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 23, 2009, there were 63,381,249 Class B common units outstanding held by 67 holders of record.  For a description of our recent sale of unregistered securities, see our Form 8-K filed May 5, 2008.

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, 2009, we declared a quarterly cash distribution for the fourth quarter of 2008 of $0.61 per common unit, which was paid on February 13, 2009 to common unit holders of record as of February 9, 2009.

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 and consolidated financial 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 represents 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, 2008 and 2007, and for the years ended December 31, 2008, 2007, and 2006 from Atlas Energy Resources, LLC’s and Atlas America’s 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 and for the three months ended December 31, 2005 and, as of and for the years ended September 30, 2005 and 2004, respectively, from the Atlas America E&P Operation’s 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.

										Three Months
										Ended
	Years Ended December 31,									December 31,			Years Ended September 30,
	2008			2007			2006			2005			2005			2004
	(in thousands)
Income statement data:
Revenues:
Gas and oil production	$	311,850		$	180,125		$	88,449		$	24,086		$	63,499		$	48,526
Partnership management:
Well construction and completion		415,036			321,471			198,567			42,145			134,338			86,880
Administration and oversight		19,362			18,138			11,762			2,964			9,590			8,396
Well services		20,482			17,592			12,953			2,561			9,552			8,430
Gathering (1)		20,670			14,314			9,251			1,407			4,359			4,191
Gain on mark-to-market derivatives		—			26,257			–			–			–			–
Total revenues		787,400			577,897			320,982			73,163			221,338			156,423
Expenses:
Gas and oil production (1)		59,579			32,193			13,881			2,441			8,165			7,289
Partnership management:
Well construction and completion		359,609			279,540			172,666			36,648			116,816			75,548
Well services		10,654			9,062			7,337			1,487			5,167			4,398
Gathering (1)		441			214			—			38			52			53
Gathering fee – Atlas Pipeline (1)		19,098			13,781			29,545			7,930			21,929			17,189
General and administrative		44,659			39,414			23,367			5,818			13,202			11,708
Net expense reimbursement – affiliate		—			–			1,237			163			602			1,050
Depreciation, depletion and amortization		95,434			56,942			22,491			4,916			14,061			12,064
Total operating expenses		589,474			431,146			270,524			59,441			179,994			129,299
Operating income		197,926			146,751			50,458			13,722			41,344			27,124
Other income (expenses):
Interest expense		(56,306	)		(30,096	)		–			–			–			–
Other – net		1,159			849			1,369			57			79			444
Total other income(expense)		(55,147	)		(29,247	)		1,369			57			79			444
Net income before cumulative effect of accounting change		142,779			117,504			51,827			13,779			41,423			27,568
Cumulative effect of accounting change (2)		—			–			6,355			—			—			—
Net income	$	142,779		$	117,504		$	58,182		$	13,779		$	41,423		$	27,568
Cash flow data:
Cash provided by operating activities	$	249,923		$	230,982		$	80,536		$	43,596		$	90,525		$	42,523
Cash used in investing activities		(341,108	)		(1,468,434	)		(75,588	)		(17,185	)		(59,050	)		(32,709	)
Cash provided by (used in) financing activities		71,582			1,253,877			(17,033	)		(11,739	)		(25,401	)		(14,916	)
Capital expenditures	$	340,975		$	196,735		$	75,635		$	17,187		$	59,124		$	33,252
Other financial information (unaudited):
EBITDA	$	294,519		$	204,542		$	74,318		$	18,695		$	55,484		$	39,632
Adjusted EBITDA	$	312,434		$	199,099		$	94,949		$	25,649		$	73,406		$	52,747
Balance sheet data (at period end):
Total assets	$	2,270,685		$	1,891,234		$	415,463		$	315,052		$	270,402		$	198,454
Liabilities associated with drilling contracts		96,700			132,517			86,765			70,514			60,971			29,375
Advances from affiliates		1,712			8,696			12,502			4,257			13,897			30,008
Long-term debt, including current maturities		873,655			740,030			68			156			81			420
Total equity	$	1,039,336		$	836,115		$	212,682		$	154,519		$	146,142		$	109,461

(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).

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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,
	2008		2007			2006		2005		2005		2004
	(in thousands)
Net income before cumulative effect of accounting change	$	142,779	$	117,504		$	51,827	$	13,779	$	41,423	$	27,568
Interest expense		56,306		30,096			—		—		—		—
Depreciation, depletion and amortization		95,434		56,942			22,491		4,916		14,061		12,064
EBITDA		294,519		204,542			74,318		18,695		55,484		39,632
Adjustment to reflect cash impact of derivatives (1)		12,430		12,257			—		—		—		—
Gain on mark-to-market derivatives (2)		—		(26,257	)		—		—		—		—
Non-recurring derivative fees		—		3,873
Non-cash stock compensation		5,485		4,684			337		393		300		64
Gathering fee		—		–			20,294		6,561		17,622		13,051
Adjusted EBITDA	$	312,434	$	199,099		$	94,949	$	25,649	$	73,406	$	52,747

(1) Represents cash proceeds received from the settlement of ineffective derivative gains recognized in fiscal 2007 associated with the acquisition of AGO from natural gas produced during the year but not reflected in the twelve months ended December 31, 2008 and 2007 consolidated statements of income.

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

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

GENERAL

We had record revenues of $787.4 million and record net income of $142.8 million in 2008.  Our well construction and completion margin of $55.4 million and gas and oil production margin of $252.3 million both contributed to an increase in net income of $25.3 million.

We also experienced increases in costs associated with drilling and leasing activities due to the increased competition for the availability of drilling rigs and development activities of the Marcellus Shale formation in southwestern Pennsylvania.

Manner of Presentation

The historical financial statements for the year ended December 31, 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 on December 18, 2006. 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 both Atlas America E & P Operations before the date of our initial public offering on December 18, 2006 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.

Comparability of Financial Statements

The historical financial statements of Atlas America E & P Operations (from January 1, 2006 to December 17, 2006) included in this report are not comparable to our results of operations following our initial public offering on December 18, 2006 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 unit holders.

· We acquired DTE Gas & Oil, which we refer to as AGO, on June 29, 2007, which significantly increased our assets, debt and equity, revenues, expenses and cash flows from June 29, 2007 to December 31, 2007 and for the full fiscal year 2008.

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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, Indiana, and the Appalachian Basin. In northern Michigan, we drill wells for our own account. In the Appalachian Basin and Indiana, 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 two oil and gas production business segments in Michigan/Indiana (“Michigan”) and Appalachia as well as our partnership management segment.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Gas and Oil Production

Our natural gas revenues were $297.1 million in the year ended December 31, 2008, an increase of $127.8 million (75%) from $169.3 million in the year ended December 31, 2007. The increase was generally attributable to volumes associated with our Michigan operations, acquired on June 29, 2007, of $102.4 million and a 22% increase in the production volumes of our Appalachian operating area. The $127.8 million increase in natural gas revenues consisted of $113.4 million attributable to increases in production volumes and $14.4 million attributable to increases in natural gas prices.

We believe that gas volumes will continue to be favorably impacted in 2009 with a planned expansion of our Marcellus Shale drilling efforts, the acquisition of acreage in Indiana added to our Michigan business unit, the expansion of acreage and operations in our Tennessee area and continued enhancement in our Appalachian operations as ongoing projects to extend and enhance the gathering systems of Atlas Pipeline are completed and recently drilled wells are connected to these systems.

Our oil revenues were $14.7 million in the year ended December 31, 2008, an increase of $3.9 million (36%) from $10.8 million in the year ended December 31, 2007.  The increase resulted from a 33% increase in the average sales price of oil, and a 3% increase in production volumes. The $3.8 million increase consisted of $3.4 million attributable to increases in sales prices, and $468,000 attributable to volume increases.

Our production costs were $59.6 million in the year ended December 31, 2008, an increase of $27.4 million (85%) from $32.2 million in the year ended December 31, 2007. This increase is attributable to an increase of $19.9 million of production costs associated with our acquisition of AGO on June 29, 2007 which we have owned for a full calendar year, compared to a six-month period in calendar year 2007, and a $7.5 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.

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Partnership Management

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):

	Years Ended December 31,
	2008		2007		2006
Average construction and completion revenue per well	$	535	$	317	$	307
Average construction and completion cost per well		463		276		267
Average construction and completion segment margin per well	$	72	$	41	$	40
Gross profit margin	$	55,427	$	41,931	$	25,901
Net wells drilled		776		1,014		647

Well Construction and Completion

Our well construction and completion margin was $55.4 million in the year ended December 31, 2008, an increase of $13.5 million (32%) from $41.9 million in the year ended December 31, 2007. During the year ended December 31, 2008, the increase of $13.5 million in segment margin was attributable to an increase in the gross profit per well ($30.5 million), partially offset by a decrease in the number of wells we drilled ($17.0 million). Since our drilling contracts are on a “cost-plus” basis (typically cost plus 15% to 18%), an increase in our average costs per well also results in an increase in our average revenue per well.  Our average costs and revenues per well has increased due to an increase in the number of Marcellus Shale and horizontal wells drilled during the year ended December 31, 2008.

It should be noted that “Liabilities associated with drilling contracts” on our balance sheet includes $96.7 million of funds raised in our investment programs that have not been applied to the completion of wells as of December 31, 2008 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 2009. During the year ended December 31, 2008, we raised $438.4 million and we have budgeted to raise approximately $400.0 million in fiscal 2009.

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 $19.4 million in the year ended December 31, 2008, an increase of $1.3 million (7%) from $18.1 million in the year ended December 31, 2007. This increase resulted from an increase in the fee we charge to drill Marcellus Shale and horizontal wells in comparison to our shallow well administrative fee.  The number of wells we manage for our investment partnerships has also increased by approximately 630 net wells (15%) in the year ended December 31, 2008, as compared to the year ended December 31, 2007.

Well Services

Our well services revenues were $20.5 million in the year ended December 31, 2008, an increase of $2.9 million (16%) from $17.6 million in the year ended December 31, 2007. This increase resulted from an increase in the number of wells operated for our investment partnerships due to additional wells drilled in the year ended December 31, 2008.

Our well services expenses were $10.7 million in year ended December 31, 2008, an increase of $1.6 million (18%) from $9.1 million in the year ended December 31, 2007. This increase was attributable to an increase in wages, benefits, and field office expenses associated with an increase in employees due to the increase in the number of wells we operate for our investment partnerships.

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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, Atlas America, 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 100% of 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, 2008, we also received $1.6 million in transportation and natural gas liquid revenues from our Michigan operations.

Our gathering fee paid to Atlas Pipeline was $19.1 million for the year ended December 31, 2008, an increase of $5.3 million (39%) from $13.8 million in the year ended December 31, 2007. The increase in the year ended December 31, 2008 is primarily a result of the increase in the number of wells drilled, completed, and connected to Atlas Pipeline’s gathering systems.

Other Income, Costs and Expenses

General and Administrative

Our general and administrative expenses were $44.7 million in the year ended December 31, 2008, an increase of $5.3 million (13%) from $39.4 million in the year ended December 31, 2007. 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 $5.3 million in the year ended December 31, 2008 is principally attributed to the following:

· costs associated with  AGO were $8.1 million in the current year, an increase of $4.8 million from the prior year.  The prior year included costs from our acquisition date, June 29, 2007 to December 31, 2007;

· land and leasing costs in Appalachia increased $1.6 million due to an increase in activities of our land department as we acquired additional acreage and well sites;

· outside services, professional fees, insurance and office operations increased $2.9 million due to the growth of our business and syndication activities; and

· partially offset by the payment of $3.9 million in fees in 2007 related to hedging natural gas volumes associated with the acquisition of AGO on June 29, 2007; we did not pay any hedging fees during the year ended December 31, 2008.

Depletion

Our depletion (including accretion of our asset retirement obligations) of oil and gas properties as a percentage of oil and gas revenues was 29% in the year ended December 31, 2008, compared to 30% in the year ended December 31, 2007. Depletion expense was $2.64 per Mcfe in the year ended December 31, 2008, an increase of $0.15 (6%) from $2.49 per Mcfe in the year ended December 31, 2007. 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 $37.6 million (69%) to $92.0 million in the year ended December 31, 2008 compared to $54.4 million in the year ended December 31, 2007. Depletion expense associated with our Michigan asset base was $54.8 million for the year ended December 31, 2008, compared to $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

Our interest expense was $56.3 million in the year ended December 31, 2008, an increase of $26.2 million (87%) compared to $30.1 million in the year ended December 31, 2007.  This increase consists of an increase of $36.1 million associated with the issuance of our senior notes in January and May 2008, offset by a decrease of $9.9 million in interest expense on our revolving credit facility.  The borrowings on our credit facility were used to fund the acquisition of AGO in June 2007 and to fund our acreage and drilling capital expenditures.  The issuance of our senior notes was used to pay down borrowings on our revolving credit facility.

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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.

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 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. During the year ended December 31, 2007, we raised $363.3 million.

Administration and Oversight

Administration and oversight represents supervision and administrative fees earned for the drilling and subsequent management of wells for our investment partnerships. 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.

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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.

Other Income, Costs and Expenses

Gain on mark-to-market derivatives

Our gain on mark-to-market derivatives represents a $26.3 million non-cash gain recognized on derivatives 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.

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;

· land and leasing 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;

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· 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 (including accretion of our asset retirement obligations) 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.

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.

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 equity, issuance of Senior Unsecured Notes, and use of our credit facility. The following table sets forth our sources and uses of cash (in thousands):

	Years Ended December 31,
	2008			2007			2006
Provided by operations	$	249,923		$	230,982		$	80,536
Used in investing activities		(341,108	)		(1,468,434	)		(75,588	)
Provided by (used in) financing activities		71,582			1,253,877			(17,033	)
Increase (decrease) in cash and cash equivalents	$	(19,603	)	$	16,425		$	(12,085	)

We had $5.7 million in cash and cash equivalents at December 31, 2008, compared to $25.3 million at December 31, 2007.  We had a working capital deficit of $69.3 million at December 31, 2008, a decrease of $24.0 million from a working capital deficit of $93.3 million at December 31, 2007.  The decrease in our working capital deficit is principally due to the following:

· an increase of $16.7 million in accounts receivable and prepaid expenses;

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· net current unrealized hedge receivables increased $34.0 million;

· a decrease of $35.8 million in liabilities associated with drilling contracts;

· a decrease of cash and cash equivalents of $19.6 million;

· an increase in accounts payable and accrued liabilities of $26.9 million; and

· an increase in accrued interest payable of $16.1 million.

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, 2008, we have $229.3 million available under our credit facility to fund working capital obligations.

Capital Requirements

Capital expenditures. During the year ended December 31, 2008, our capital expenditures consisted of maintenance capital expenditures and expansion capital expenditures, as defined below:

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

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

During the year ended December 31, 2008, 2007 and 2006, our capital expenditures in Appalachia related primarily to investments in our investment partnerships, in which we invested $146.3 million, $137.6 million, and $73.6 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, 2008, we raised $438.4 million.  For the years ended December 31, 2007 and 2006, we had raised $363.3 million and $218.5 million, respectively.

We expect to fund our maintenance capital expenditures with cash flow from operations and the temporary use of funds raised in our investment partnerships in the period before we invest these funds.  We also expect to fund 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 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 believe that we have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, distribution requirements, contingencies and anticipated capital expenditures. However, we are subject to business and operational risks that could adversely affect our cash flow. We may need to supplement our cash generation with proceeds from financing activities, including borrowings under our credit facilities and other borrowings and the issuance of additional common units.

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

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

	Years Ended December 31,
	2008		2007		2006
Maintenance capital expenditures (1)	$	51,900	$	43,450	$	–
Expansion capital expenditures (1)		289,075		1,421,186		–
Total	$	340,975	$	1,464,636	$	75,635

(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

At December 31, 2008, we have a credit facility with a syndicate of banks with a borrowing base of $697.5 million that matures in June 2012 ($467.0 million outstanding at December 31, 2008).  The borrowing base is redetermined semiannually on April 1 and October 1 subject to changes in the our oil and gas reserves.  The facility is secured by substantially all of our assets and is guaranteed by each of our subsidiaries and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at our option.  At December 31, 2008, the weighted average interest rate on outstanding borrowings was 2.8%.  The credit facility requires us to maintain a ratio of current assets (as defined in the credit facility) to current liabilities (as defined in the credit facility) of not less than 1.0 to 1.0, and a ratio of total debt (as defined in the credit facility) to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”, as defined in the credit facility) of 4.0 to 1.0, decreasing to 3.75 to 1.0 commencing January 1, 2009, and decreasing to 3.5 to 1.0 commencing January 1, 2010 and thereafter.  According to the definitions contained in our credit facility, our ratio of current assets to current liabilities was 1.6 to 1.0 and our ratio of total debt to EBITDA was 2.9 to 1.0, at December 31, 2008.

CASH FLOWS

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

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 $18.9 million in the year ended December 31, 2008 to $249.9 million from $231.0 million for the prior year due principally to the following:

· an increase in net income before depreciation, depletion and amortization of $63.6 million during the year ended December 31, 2008 as compared to the prior year period, principally due to the contribution of our Michigan operations acquired in June 2007 and increases in net income from our partnership management operations and our Appalachian production segment; and

· an increase in non-cash items of $27.2 million related to our compensation expense resulting from grants under long-term incentive plans and non-cash gains on mark-to-market derivatives; and

· partially offset by changes in operating assets and liabilities which decreased operating cash flows by $71.2 million in the year ended December 31, 2008, compared to the prior year.

The decrease in operating cash flows from changes in operating assets and liabilities is primarily a result of the following:

· an increase of $19.7 million in accounts receivable and prepaid expenses; and

· a decrease of $81.6 million in liabilities associated with our drilling contracts.  Our level of liabilities associated with drilling contracts is dependent upon the remaining amount of our drilling obligations at any balance sheet date, which is dependent upon the timing and level of funds raised through our investment partnerships;

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· These amounts were partially offset by an increase of $30.1 million in accounts payable and accrued expenses

Cash flows used in investing activities. Cash used in our investing activities decreased $1.13 billion during the year ended December 31, 2008 to $341.1 million from $1.47 billion in the year ended December 31, 2007 due to our $1.27 billion acquisition of AGO on June 29, 2007, partially offset by a $144.2 million increase in capital expenditures related to the increase in the number of wells we drilled in during the year ended December 31, 2008.

Cash flows provided by financing activities. Cash provided by our financing activities decreased $1.18 billion for the year ended December 31, 2008 to $71.6 million from $1.25 billion in the year ended December 31, 2007, primarily as a result of the following: 

· net borrowing decreased $1.01 billion in the year ended December 31, 2008, due to the funding of our AGO acquisition on June 29, 2007 during the prior year;

· we received proceeds of $107.7 million from the sale of our Class B common units in the year ended December 31, 2008 compared to proceeds of $597.5 million received in the year ended December 31, 2007;

· net monies borrowed from Atlas America decreased $3.2 million in the year  ended December 31, 2008, compared to the year ended December 31, 2007;

· we paid $151.1 million in distributions to our unit holders in the year ended December 31, 2008, an increase of $81.8 million from $69.3 million in the year ended December 31, 2007; and

· These amounts were partially offset by the proceeds of $407.1 million we received from the issuance of our Senior Notes including a premium of $7.1 million in the year ended December 31, 2008.

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

Cash flows from operating activities.Netcash provided by operating activities increased $150.5 million during the year ended December 31, 2007 to $231.0 million from $80.5 million for the year ended December 31, 2006, due principally to the following:

· an increase in net income before depreciation, depletion and amortization of $96.8 million during the year ended December 31, 2007 as compared to the prior year, principally due to the contributions from our Michigan operations acquired in June 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 which increased operating cash flows by $56.6 million in the year ended December 31, 2007, compared to the prior year.

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.

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Cash flows used in investing activities.Cash used in our investing activities increased $1.4 billion during the year ended December 31, 2007 to $1.5 billion from $75.6 million for the prior year due primarily to our $1.3 billion acquisition of DTE Gas & Oil and a $121.1 million increase in capital expenditures when compared to the prior year 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;

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

· net proceeds 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.

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 market prices. Natural gas and oil prices are subject to significant fluctuations that are beyond our ability to control or predict.

Inflation affects the operating expenses of our operations.  In addition, inflationary trends may occur if commodity prices were to increase since such an increase may cause the demand of energy equipment and services to increase, thereby increasing the costs of acquiring or obtaining such equipment and services.  Increases in those expenses are not necessarily offset by increases in revenues and fees that our operations are able to charge.  While we anticipate that inflation will affect our future operating costs, we cannot predict the timing or amounts of any such effects

ENVIRONMENTAL REGULATION

Our operations are subject to federal, state and local laws and regulations governing the release of regulated materials into the environment or otherwise relating to environmental protection or human health or safety. We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of remedial requirements, and issuance of injunctions as to future compliance or other mandatory or consensual measures. We have ongoing environmental compliance programs. However, risks of accidental leaks or spills are associated with our operations. There can be no assurance that we will not incur significant costs and liabilities relating to claims for damages to property, the environment, natural resources, or persons resulting from the operation of our business. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies hereunder, could result in increased costs and liabilities to us.

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Environmental laws and regulations have changed substantially and rapidly over the last 25 years, and we anticipate that there will be continuing changes. One trend in environmental regulation is to increase reporting obligations and place more restrictions and limitations on activities, such as emissions of pollutants, generation and disposal of wastes and use, storage and handling of chemical substances, that may impact human health, the environment and/or endangered species. Increasingly strict environmental restrictions and limitations have resulted in increased operating costs for us and other similar businesses throughout the United States. It is possible that the costs of compliance with environmental laws and regulations may continue to increase. We will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly, but there can be no assurance that we will identify and properly anticipate each such charge, or that our efforts will prevent material costs, if any, from arising.

CASH DISTRIBUTIONS

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

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

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

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

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

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

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

Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to unit holders.

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

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

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CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The following table summarizes our contractual obligations at December 31, 2008 (in thousands):

			Payments due by period
			(in thousands)
			Less than		2 - 3		4 - 5		After 5
Contractual cash obligations:	Total		1 Year		Years		Years		Years
Senior unsecured notes	$	400,000	$	—	$	—	$	—	$	400,000
Revolving credit facilities		467,000		—		—		467,000		—
Operating lease obligations		14,368		3,178		4,841		2,496		3,853
Capital lease obligations		—		—		—		—		—
Interest payments		445,222		58,614		117,228		93,797		175,583
Unconditional purchase obligations		—		—		—		—		—
Other long-term obligation		—		—		—		—		—
Total contractual cash obligations	$	1,326,590	$	61,792	$	122,069	$	563,293	$	579,436

			Payments due by period
			(in thousands)
			Less than		2 - 3		4 - 5		After 5
Other commercial commitments:	Total		1 Year		Years		Years		Years
Standby letters of credit	$	1,159	$	1,159	$	—	$	—	$	—
Guarantees		5,110		525		1,116		1,001		2,468
Standby replacement commitments		—		—		—		—		—
Other commercial commitments		41,124		41,124		—		—		—
Total commercial commitments	$	47,393	$	42,808	$	1,116	$	1,001	$	2,468

OFF BALANCE SHEET ARRANGEMENTS

As of December 31, 2008, our off balance sheet arrangements are limited to our guarantee of Crown Drilling of Pennsylvania, LLC’s $5.1 million credit arrangement and our letters of credit outstanding of $1.2 million.  In addition, our estimated capital contribution for the drilling and completion costs related to Atlas Resources Public #18-2008 Program is approximately $41.1 million.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

We consider accounting policies related to fair value of derivative instruments; oil and gas properties and reserve estimates and impairment, asset retirement obligations; goodwill and other long-lived assets  to be critical policies.  These policies are summarized below and in “Note 2 – Summary of Significant Accounting Policies”, to our financial statements included herein on our annual Form 10-K for the year ended December 31, 2008.

Fair Value of Financial Instruments

The Company adopted the provisions of SFAS No. 157 at January 1, 2008. SFAS No. 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS No. 157’s hierarchy defines three levels of inputs that may be used to measure fair value:

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

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

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

The Company uses the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities for its outstanding derivative contracts. All of the Company’s derivative contracts are defined as Level 2. The Company’s natural gas and crude oil derivative contracts are valued based on prices quoted on the NYMEX or WTI and adjusted by the respective counterparty using various assumptions including quoted forward prices, time value, volatility factors, and contractual prices for the underlying instruments. The Company’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model. 

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. See — “Impairment of Oil and Gas Properties” in Note 2, under Item 8, “Financial Statements and Supplementary Data” for more information.

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, 2008 and 2007, 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.

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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.

Impairment of Long-Lived Assets and Goodwill

We have recorded goodwill of $35.2 million in connection with several acquisitions of assets.  Goodwill and intangibles with infinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. Under the principles of SFAS No. 142, an impairment loss should be recognized if the carrying value of an entity’s reporting units exceeds its estimated fair value.  Because quoted market prices for our reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units.  Management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets.  A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to our market capitalization.  The principles of SFAS No. 142 and its interpretations acknowledge that the observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole.  Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity.  Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity’s individual equity securities.  In most industries, including ours, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest.  Therefore, once the above fair value calculations have been determined, we also consider a control premium to the calculations.  This control premium is judgmental and is based on, among other items, observed acquisitions in our industry.  The resultant fair values calculated for the reporting units are then compared to observable metrics on large mergers and acquisitions in our industry to determine whether those valuations appear reasonable in management’s judgment.  Our evaluation of goodwill at December 31, 2008, 2007 and 2006, respectively, indicated there was no impairment loss.

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.

GENERAL TRENDS AND OUTLOOK

Drilling Activities

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

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Financial Markets

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

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.

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

Natural Gas Supply and Outlook

We believe that current natural gas demand 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. The areas in which we operate are experiencing significant drilling activity as a result of promising prospects from the drilling into deeper natural gas formations  and the implementation of new exploration and production techniques, including horizontal and multiple fracturing techniques .

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

Reserve Outlook

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

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.

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General

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

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

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

Interest Rate Risk

At December 31, 2008, we had an outstanding balance of $467.0 million on our revolving credit facility with a current borrowing base at December 31, 2008 of $697.5 million. The weighted average interest rate for borrowings under this credit facility was 4.5% for the twelve months ended December 30, 2008 and 7.2% at December 31, 2007.  At December 31, 2008, we had interest rate derivative contracts having aggregate notional principal amounts of $150.0 million.  Under the terms of this agreement, we will pay weighted average interest rates of 3.11% plus the applicable margin as defined under the terms of our revolving credit facility, and will receive LIBOR, plus the applicable margin on the notional principal amounts.  These derivatives effectively convert $150.0 million of our floating rate debt under our revolving credit facility to fixed rate debt.  The interest rate swap agreements are effective as of December 31, 2008, and expire during periods through January 2011.

Holding all other variables constant, including the effect of interest rate derivatives, a hypothetical 10% change in the weighted average interest rate would change our net income by $907,000.

Commodity Price Risk

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

Our risk management objective regarding commodity price risk is to utilize available instruments, including financial derivatives and physical forward contracts, to maximize the value of the company’s production while also reducing its exposure to the volatility of commodity markets. Considering those volumes for which we have entered into financial derivative agreements for the twelve-month period ending December 31, 2009, and current indices, a theoretical 10% upward or downward change in the price of natural gas and crude oil would result in a change in net income of approximately $4.8 million.

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We formally document all relationships between derivative instruments and the items being hedged, including the risk management objective and strategy for undertaking the derivative transactions. This includes matching the natural gas and oil futures and options contracts to the forecasted transactions. We assess, both at the inception of the derivative transaction 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, and are recorded at their fair values. Gains or losses on future contracts are determined as the difference between the contract price and a reference price, generally prices on NYMEX or WTI. Changes in fair value are recognized in consolidated equity and recognized within the consolidated statements of income in the month the hedged commodity is sold. If it is determined that a derivative is not highly effective as a hedge or it has ceased to be a highly effective derivative, due to the loss of correlation between changes in reference prices underlying a derivative 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.

We recognized a loss of $25.1 million and gains of $17.6 million and $7.1 million on settled contracts covering natural gas production for the years ended December 31, 2008, 2007 and 2006, respectively. We recognized a loss of $312,000 on settled oil production for the year ended December 31, 2008. There were no gains (losses) on oil settlements for the year ended December 31, 2007 and 2006.  As the underlying prices and terms in our derivative contracts were consistent with the indices used to sell our natural gas and oil, there were no gains or losses recognized during the years ended December 31, 2008 and 2007 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

On May 18, 2007, we signed a definitive agreement to acquire AGO.  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 consolidated statements of income. We recognized a non-cash gain on mark-to-market derivatives of $26.3 million related to the change in value of these derivatives from May 22, 2007 through June 28, 2007. Upon closing of the acquisition on June 29, 2007, the production volume of the assets acquired was considered “probable forecasted production” under SFAS No. 133 and we evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133.

We have a $106.1 million net unrealized asset related to financial hedges in accumulated other comprehensive loss associated with commodity derivatives at December 31, 2008, compared to a net unrealized liability of $5.1 million at December 31, 2007.  If the fair values of the instruments remain at current market values, we will reclassify $63.7 million of unrealized gains to our consolidated statements of income over the next twelve-month period as these contracts settle and $42.4 million of unrealized gains will be reclassified in later periods.

The fair value of the derivatives at December 31, 2008 is a net unrealized hedge asset of $159.5 million, of which our portion is $107.7 million and $51.8 million of unrealized hedge gains have been reallocated to our investment partnerships. At January 31, 2009, commodity prices for natural gas and crude oil have declined further. We estimate that our unrealized net asset has increased by approximately $50.8 million to an estimated unrealized net asset of $210.3 million at January 31, 2009, from a $159.5 million net asset at December 31, 2008.

As of December 31, 2008, we had the following natural gas and crude oil volumes hedged:

Natural Gas Fixed Price Swaps

Twelve Month
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset
	(MMBtu)		(per MMBtu)		(in thousands) (1)
2009		38,120,000	$	8.55	$	93,246
2010		26,360,000	$	8.11		25,537
2011		18,680,000	$	7.84		9,670
2012		13,800,000	$	8.05		10,851
2013		1,500,000	$	8.73		2,098
					$	141,402

66

Natural Gas Costless Collars

Twelve Month
Period Ending				Average		Fair Value
December 31,	Option Type	Volumes		Floor and Cap		Asset
		(MMBtu)		(per MMBtu)		(in thousands) (1)
2009	Puts purchased		240,000	$	11.00	$	1,182
2009	Calls sold		240,000	$	15.35		—
2010	Puts purchased		3,360,000	$	7.84		3,340
2010	Calls sold		3,360,000	$	9.01		—
2011	Puts purchased		7,500,000	$	7.48		3,708
2011	Calls sold		7,500,000	$	8.44		—
2012	Puts purchased		1,020,000	$	7.00		223
2012	Calls sold		1,020,000	$	8.32		—
2013	Puts purchased		300,000	$	7.00		72
2013	Calls sold		300,000	$	8.25		—
						$	8,525

Crude Oil Fixed Price Swaps

Twelve Month
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset
	(Bbl)		(per Bbl)		(in thousands) (2)
2009		59,900	$	100.14	$	2,790
2010		48,900	$	97.40		1,624
2011		42,600	$	96.44		1,141
2012		33,500	$	96.00		785
2013		10,000	$	96.06		221
					$	6,561

Crude Oil Costless Collars

Twelve Month
Period Ending				Average		Fair Value
December 31,	Option Type	Volumes		Floor and Cap		Asset
		(Bbl)		(per Bbl)		(in thousands) (2)
2009	Puts purchased		36,500	$	85.00	$	1,200
2009	Calls sold		36,500	$	118.63		—
2010	Puts purchased		31,000	$	85.00		754
2010	Calls sold		31,000	$	112.92		—
2011	Puts purchased		27,000	$	85.00		538
2011	Calls sold		27,000	$	110.81		—
2012	Puts purchased		21,500	$	85.00		379
2012	Calls sold		21,500	$	110.06		—
2013	Puts purchased		6,000	$	85.00		100
2013	Calls sold		6,000	$	110.09		—
							2,971
				Total Net Asset		$	159,459

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

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

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ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

[THE REMAINDER OF THIS PAGE IS INTENTIONALLY LEFT BLANK]

68

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unit holders

Atlas Energy Resources, LLC

We have audited the accompanying consolidated balance sheets of Atlas Energy Resources, LLC (a Delaware limited liability company) and subsidiaries as of December 31, 2008 and 2007, and the related combined and consolidated statements of income, comprehensive income, members' equity, and cash flows for each of the three years in the period ended December 31, 2008. 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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, 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), Atlas Energy Resources, LLC’s internal control over financial reporting as of December 31, 2008, 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 March 2, 2009 expressed an unqualified opinion on the effectiveness of internal control over the financial reporting.

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

March 2, 2009

69

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,
	2008		2007
ASSETS
Current assets:
Cash and cash equivalents	$	5,655	$	25,258
Accounts receivable		70,573		57,524
Current portion of derivative asset		107,766		38,181
Prepaid expenses and other		14,714		8,265
Total current assets		198,708		129,228
Property, plant and equipment, net		1,945,119		1,693,467
Other assets, net		18,403		21,430
Long-term derivative asset		69,451		6,882
Intangible assets, net		3,838		5,061
Goodwill		35,166		35,166
	$	2,270,685	$	1,891,234
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	—	$	30
Accounts payable		74,262		55,051
Accrued liabilities – interest		19,878		3,816
Accrued liabilities – other		29,369		21,706
Liabilities associated with drilling contracts		96,700		132,517
Derivative payable to Partnerships – short-term		34,932		9,013
Current portion of derivative liability		12,829		356
Total current liabilities		267,970		222,489
Long-term debt, less current portion		873,655		740,000
Other long-term liabilities		6,524		1,024
Derivative payable to Partnerships – long-term		22,581		1,348
Advances from affiliates		1,712		8,696
Long-term derivative liability		10,771		39,204
Asset retirement obligations		48,136		42,358
Commitments and contingencies
Members’ equity:
Class B members’ interests		932,804		835,447
Class A member’s interest		6,257		5,770
Accumulated other comprehensive income (loss)		100,275		(5,102	)
Total members’ equity		1,039,336		836,115
	$	2,270,685	$	1,891,234

See accompanying notes to combined and consolidated financial statements

70

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

COMBINED AND CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per unit data)

	Years Ended December 31,
	2008			2007			2006
REVENUES
Well construction and completion	$	415,036		$	321,471		$	198,567
Gas and oil production		311,850			180,125			88,449
Administration and oversight		19,362			18,138			11,762
Well services		20,482			17,592			12,953
Gathering		20,670			14,314			9,251
Gain on mark-to-market derivatives		—			26,257			—
Total revenues		787,400			577,897			320,982
COSTS AND EXPENSES
Well construction and completion		359,609			279,540			172,666
Gas and oil production		59,579			32,193			13,881
Well services		10,654			9,062			7,337
Gathering		441			214			—
Gathering fee – Atlas Pipeline		19,098			13,781			29,545
General and administrative		44,659			39,414			23,367
Net expense reimbursement – affiliate		—			—			1,237
Depreciation, depletion and amortization		95,434			56,942			22,491
Total operating expenses		589,474			431,146			270,524
OPERATING INCOME		197,926			146,751			50,458
OTHER INCOME (EXPENSE)
Interest expense		(56,306	)		(30,096	)		—
Other – net		1,159			849			1,369
Total other income		(55,147	)		(29,247	)		1,369
Net income before cumulative effect of accounting change		142,779			117,504			51,827
Cumulative effect of accounting change		—			–			6,355
Net income	$	142,779		$	117,504		$	58,182
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
Portion applicable to members’ interests (period subsequent to the initial public offering on December 18, 2006)		142,779			117,504			2,807
	$	142,779		$	117,504		$	58,182
Allocation of net income attributable to members’ interests:
Class A member’s interests	$	9,062		$	4,099		$	56
Class B members’ interests		133,717			113,405			2,751
Net income attributable to members’ interests	$	142,779		$	117,504		$	2,807
Net income attributable to Class B members per unit:
Basic	$	2.14		$	2.32		$	.08
Diluted	$	2.12		$	2.29		$	.08
Weighted average Class B members’ units outstanding:
Basic		62,409			48,909			36,627
Diluted		63,023			49,449			36,638

See accompanying notes to combined and consolidated financial statements

71

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

COMBINED AND CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

	Years Ended December 31,
	2008		2007			2006
Net income	$	142,779	$	117,504		$	58,182
Other comprehensive income:
Unrealized holding gains (losses) on hedging contracts		79,478		(8,582	)		31,834
Less: reclassification adjustment for losses (gains) realized in net income		25,899		(17,608	)		(7,082	)
		105,377		(26,190	)		24,752
Comprehensive income	$	248,156	$	91,314		$	82,934

See accompanying notes to combined and consolidated financial statements

72

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

COMBINED AND CONSOLIDATED STATEMENTS OF MEMBERS’ 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,  January 1, 2006	$	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-based compensation		—			—		—			—		337			—			—			—			—			337
Other compensation income		—			—		—			—		—			—			—			24,752			—			24,752
Net income attributable to unit holders subsequent to IPO		—			—		56			—		2,751			—			—			—			—			2,807
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
Distributions to members		—			—		(2,154	)		—		(57,941	)		—			(9,187	)		—			—			(69,282	)
Distributions paid on unissued
units under incentive plan		—			—		—			—		(778	)		—			—			—			—			(778	)
Stock-based compensation		—			—		—			—		4,684			—			—			—			—			4,684
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
Units issued		—			54,500		—			2,670,375		107,697			—			—			—			—			107,697
Distribution to members		—			—		(8,575	)		—		(148,104	)		—			—			—			—			(156,679	)
Distributions paid on unissued units under incentive plan		—			—		—			—		(1,438	)		—			—			—			—			(1,438	)
Stock-based  compensation		—			—		—			—		5,485			—			—			—			—			5,485
Other comprehensive income		—			—		—			—		—			—			—			105,377			—			105,377
Net income		—			—		9,062			—		133,717			—			—			—			—			142,779
Balance, December 31, 2008	$	—			1,293,486	$	6,257			63,380,749	$	932,804			—		$	—		$	100,275		$	—		$	1,039,336

See accompanying notes to combined and consolidated financial statements

73

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Years Ended December 31,
	2008			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	142,779		$	117,504		$	58,182
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of deferred finance costs		2,823			3,040			—
Depreciation, depletion and amortization		95,434			56,942			22,491
Non-cash compensation expense		5,485			4,684			337
Loss (gain) on asset sales and dispositions		(32	)		111			(39	)
Cumulative effect of accounting change		—			—			(6,355	)
Non-cash loss (gain) on derivative value		12,430			(14,000	)		—
Equity (income) loss of unconsolidated subsidiary		(233	)		158			—
Minority interest		(55	)		32			—
Changes in operating assets and liabilities, net of effects of acquisition
Accounts receivable, prepaid expenses and other		(16,461	)		3,239			(8,862	)
Accounts payable		19,211			6			(3,229	)
Liabilities associated with drilling contracts		(35,817	)		45,752			16,251
Other operating assets and liabilities		24,359			13,514			1,760
Net cash provided by operating activities		249,923			230,982			80,536
CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash paid for acquisition		—			(1,272,518	)		—
Capital expenditures		(340,975	)		(196,735	)		(75,635	)
Proceeds from sale of assets		62			1,092			47
Other		(195	)		(273	)		—
Net cash used in investing activities		(341,108	)		(1,468,434	)		(75,588	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility		493,000			951,891			—
Repayments under credit facility		(766,030	)		(211,929	)		(88	)
Net proceeds from issuance of debt		407,125			—
Distributions paid to members		(151,126	)		(69,282	)		—
Distributions net of capital contributions to Atlas America		—			—			(139,944	)
Net proceeds from issuance of Class B members units		107,697			597,495			139,944
Advances to affiliates, net of repayments		(6,984	)		(3,806	)		(16,748	)
Other		(12,100	)		(10,492	)		(197	)
Net cash provided by (used in) financing activities		71,582			1,253,877			(17,033	)
Net change in cash and cash equivalents		(19,603	)		16,425			(12,085	)
Cash and cash equivalents, beginning of year		25,258			8,833			20,918
Cash and cash equivalents, end of year	$	5,655		$	25,258		$	8,833

See accompanying notes to combined and consolidated financial statements

74

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - NATURE OF OPERATIONS

Atlas Energy Resources, LLC (“the Company”) is a publicly-traded Delaware limited liability company (NYSE: ATN) and an independent developer and producer of natural gas and, to a lesser extent, oil in Northern Michigan's Antrim Shale, Indiana’s New Albany 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”).

On December 18, 2006, Atlas America, Inc. and its affiliates (“Atlas America”), a publicly-traded company (NASDAQ: ATLS), 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 Class B common units and 748,456 Class A units.  Concurrent with this transaction, the Company completed an initial public offering of 7,273,750 units of its Class B common units, representing a 19.4% interest at that moment, at a price of $21.00 per common unit.  The net proceeds from the offering of $139.9 million, after deducting underwriting discounts and costs, were distributed to Atlas America Class A units. The Class A units are entitled to 2% of all quarterly cash distributions by the Company, without any requirement for future capital contributions by the holder of such Class A units, even if the Company issues additional Class B common units or other equity securities in the future.  The Company is managed by Atlas Energy Management, Inc. (the “Managing Member”), a wholly-owned subsidiary of Atlas America. At December 31, 2008, the Company has 63,380,749 Class B common units and 1,293,486 Class A units outstanding.  At December 31, 2008, Atlas America owns 49.4% of the Company.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Combination and Consolidation

The consolidated financial statements subsequent to the Company’s initial public offering on December 18, 2006 include the accounts of the Company and its subsidiaries.  Prior to the Company’s initial public offering, at which date Atlas America contributed its ownership interests in its natural gas and oil development and production assets to the Company, the combined financial statements have been prepared from the separate records maintained by Atlas America 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 that comprised the assets contributed by Atlas America to the Company, Atlas America’s net investment in these entities was shown as combined equity in the combined financial statements. Transactions between the Company and other Atlas America 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, income and lease operating and general and administrative costs and expenses of the investment partnerships in which it has an interest.  Such interests typically range from 15% to 35%. The Company’s financial statements do not include proportional consolidation of the depletion or impairment expenses of the Partnerships. Rather, the Company calculates these items specific to its own economics as further explained under the heading “Oil and Gas Properties” below.  All material intercompany transactions have been eliminated.

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. The Company’s consolidated financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, depreciation and amortization, fair value of derivative instruments, the probability of forecasted transactions, and the allocation of purchase price to the fair value of assets acquired.  Actual results could differ from these estimates.

75

Reclassifications

Certain amounts in the prior year’s combined and consolidated financial statements have been reclassified to conform to the current year presentation.

Cash Equivalents

The Company considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.  These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.

Stock-Based Compensation

The Company applies the provisions of SFAS No. 123(R), “Share-Based Payment,” as revised (“SFAS No. 123(R)”), to its share-based payments.  Generally, the approach to accounting for SFAS No. 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.

Net Income Per Common Unit

Basic net income per unit for Class B common units is computed by dividing net income attributable to the Class B members, which is determined after the deduction of the Class A member’s interests, by the weighted average number of Class B common units outstanding during the period.  The Class A management incentive interests (“MIIs” – see Note 13) in net income is calculated on a quarterly basis based upon its 2% ownership interest, represented by its 1,293,486 Class A units, and its member’s incentive interests, with a priority allocation of net income to the Class A member’s MIIs in accordance with the Company’s limited liability agreement, and the remaining net income or loss allocated with respect to the Class A’s and Class B’s ownership interests.  Diluted net income per unit for Class B common units is calculated by dividing net income or loss attributable to the Class B members by the sum of the weighted average number of Class B common units outstanding and 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 Class B 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 net income attributable to Class B common units is only presented for the years ended December 31, 2008 and 2007 and the period from December 18, 2006 to December 31, 2006.

In March 2004, the FASB ratified the Emerging Issue Task Force (“EITF”) consensus on EITF Issue No. 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128” (“EITF No. 03-6”), which addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitles the holder of those securities to participate in dividends and earnings of the entity when, and if, the entity declares dividends on its common stock.  In quarterly accounting periods where net income does not exceed the Company’s aggregate cash distributions to its members, EITF No. 03-6 does not have any impact on the Company’s net income per Class B common unit calculation as net income is allocated to its members with a priority allocation to actual MIIs paid to the Class A member for the quarterly period, with the remaining net income allocated with respect to relative ownership interests.  However, EITF No. 03-6 provides that if the Company has net income which exceeds the aggregate cash distributions to its members during a quarterly period, it is required to present net income per Class B common unit as if all of the earnings for the quarterly period were distributed in a manner consistent with the Company’s limited liability agreement, regardless of whether those earnings would actually be distributed during a quarterly period from an economic probability standpoint.  The allocation of net income for net income per Class B common unit purposes under EITF No. 3-06 will result in an increased allocation of net income to the Class A member’s MIIs and a reduction of net income allocated to Class B members.   On January 1, 2009, the Company will adopt EITF No. 07-4, “Application of the Two-Class Method Under FASB Statement No. 128, Earnings Per Share, to Master Limited Partnerships” (see “Recently Issued Accounting Standards”).

76

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

					Period from
					December 18, 2006
	Years Ended December 31,				to December 31,
	2008		2007		2006
Weighted average number of Class B units – basic		62,409		48,909		36,627
Add effect of dilutive unit incentive awards		614		540		11
Weighted average number of Class B units – diluted		63,023		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 that, under accounting principles generally accepted in the United States, have not been recognized in the calculation of net income.  These changes, other than net income, are referred to as “other comprehensive income (loss)” and for the Company include only changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.

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

	December 31,
	2008			2007
Unrealized gain (loss) on commodity derivatives	$	106,117		$	(5,102	)
Unrealized loss on interest rate derivatives		(5,842	)		—
	$	100,275		$	(5,102	)

Accounts Receivable and Allowance for Possible Losses

In evaluating its allowance for possible losses, the Company performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by the Company’s review of its customer’s credit information. The Company extends credit on an unsecured basis to many of its customers. At December 31, 2008 and 2007, 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 are stated at cost. Depreciation, depletion and amortization are based on cost less estimated salvage value primarily using the units-of-production or straight line method over the assets estimated useful lives. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.

The estimated service lives of property, plant and equipment excluding natural gas and oil properties are as follows:

Pipelines, processing and compression facilities	15-40 years
Rights-of-way – Appalachia	20-40 years
Buildings and improvements	10-40 years
Furniture and equipment	3-7 years
Other	3-10 years

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

	December 31,
	2008			2007
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,214,991		$	1,043,687
Wells and related equipment		872,128			752,184
		2,087,119			1,795,871
Unproved properties		43,749			16,380
Support equipment		9,527			6,936
		2,140,395			1,819,187
Pipelines, processing and compression facilities		22,541			—
Rights-of-way		149			—
Land, buildings and improvements		6,484			5,881
Other		7,827			9,653
		2,177,396			1,834,721
Accumulated depreciation, depletion and amortization:		(232,277	)		(141,254	)
	$	1,945,119		$	1,693,467

Oil and Gas Properties

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

Depletion depreciation and amortization expense is determined on a field-by-field basis using the units-of-production method, with depletion, depreciation and amortization rates for leasehold acquisition costs based on estimated proved reserves and depletion, depreciation and amortization rates for well and related equipment costs based on proved developed reserves associated with each field.    Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties.  Capitalized costs of developed producing properties in each field are aggregated to include the Company’s costs of property interests in uncontrolled but proportionately consolidated from investment partnerships, wells drilled solely by the Company, properties purchased and working interests with other outside operators.

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

Goodwill

The Company has  recorded goodwill of $35.2 million in connection with several acquisitions of assets.  Goodwill and intangibles with infinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. Under the principles of SFAS No. 142, an impairment loss should be recognized if the carrying value of an entity’s reporting units exceeds its estimated fair value.  Because quoted market prices for the Company’s reporting units are not available, the Company must apply judgment in determining the estimated fair value of these reporting units.  The Company uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets.  A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to our market capitalization.  The principles of SFAS No. 142 and its interpretations acknowledge that the observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole.  Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity.  Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity’s individual equity securities.  In most industries, including the Company’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest.  Therefore, once the above fair value calculations have been determined, the Company also considers a control premium to the calculations.  This control premium is judgmental and is based on, among other items, observed acquisitions in our industry.  The resultant fair values calculated for the reporting units are then compared to observable metrics on large mergers and acquisitions in the Company’s industry to determine whether those valuations appear reasonable in the Company’s judgment.  The Company’s evaluation of goodwill at December 31, 2008, 2007 and 2006, respectively, indicated there was no impairment loss.

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Impairment of Oil and Gas Properties and Long-Lived Assets

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

The review of the Company’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place at December 31, 2008, 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.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.  In particular, the Company’s reserve estimates for its investment in its limited partnerships are based on its own assumptions rather than its proportionate share of the limited partnership’s reserves.  These assumptions include the Company’s actual capital contributions, an additional carried interest (generally 7% to 10%), a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

The Company’s lower operating and administrative costs result from the limited partners paying to the Company their proportionate share of these expenses plus a profit margin. These assumptions could result in the Company’s calculation of depletion and impairment being different than its proportionate share of the limited partnership calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production.   Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified.  The Company cannot predict what reserve revisions may be required in future periods.

The Company’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the investment partnerships which the Company sponsors and owns an interest in but does not control. The Company’s reserve quantities include reserves in excess of its proportionate share of reserves in a partnership which the Company may be unable to recover due to the partnership legal structure. The Company may have to pay additional consideration in the future as a well or investment partnership becomes uneconomic under the terms of the partnership agreement in order for the Company to recover these excess reserves and to acquire any additional residual interests in the wells held by other partnership investors. The acquisition of any well interest from the partnership by the Company is governed under the partnership agreement and must be at fair market value supported by an appraisal of an independent expert selected by the Company.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value.  There were no impairments of oil and gas properties or unproved properties recorded by the Company for the years ended December 31, 2008, 2007, or 2006, respectively.

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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 7.3% and 6.7% for the years ended December 31, 2008 and 2007, respectively, which resulted in interest capitalized of $5.0 million and $2.7 million, respectively.  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 No. 143”). SFAS No. 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 No. 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 SFAS 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.

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 a $6.4 million cumulative effect of an accounting change during the year ended December 31, 2006 and a $8.0 million increase in its asset retirement obligation and a $14.4 million increase in property, plant and equipment as of December 31, 2006.

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):

	December 31,
	2006
Net income as reported	$	51,827
Proforma asset retirement obligation adjustment		1,414
Proforma net income as adjusted		53,241
Proforma asset retirement obligation	$	26,726

Fair Value of Financial Instruments

The carrying amount of the Company’s financial instruments, including cash and cash equivalents, accounts receivables and accounts payables approximate fair values because of their short maturities and are represented in the Company’s consolidated balance sheets.  For further information with regard to the Company’s financial instruments, see “Recently Adopted Accounting Standards” and Note 7, “Fair Value of Financial Instruments” and Note 9 “Long-Term Debt”.

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Derivative Instruments

The Company enters into certain financial contracts to manage its exposure to movement in commodity prices and interest rate movements.  The Company applies the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No.133”). SFAS No. 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 the Company’s consolidated statements of income 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, 2008 and 2007, the Company had $25.1 million and $41.8 million, respectively, in deposits at various banks, of which $23.6 million and $40.9 million, respectively, was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date.

Environmental Matters

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. 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. At December 31, 2008 and 2007, 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  sponsored investment partnerships. The Company contracts with the investment partnerships to drill partnership wells. The contracts require that the investment partnerships 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 titled “Liabilities Associated with Drilling Contracts” on its consolidated balance sheets. The Company recognizes gathering revenues at the time the natural gas is delivered, and. recognizes well services revenues at the time the services are performed. The Company is also 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.

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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, 2008 and 2007 of $43.7 million and $44.9 million, respectively, which are included in accounts receivable on its consolidated balance sheets.

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 years ended December 31, 2008 and 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. 

Recently Issued Financial Accounting Standards

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

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

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Policies” (“SFAS No. 162”).  SFAS No. 162 identifies sources of accounting principles and the framework for selecting such principles used in the preparation of financial statements of nongovernmental entities presented in conformity with U.S. generally accepted accounting principles.  SFAS No. 162 is effective beginning November 15, 2008.  The Company adopted the provisions of SFAS No. 162 on November 15, 2008 and it had no impact on its financial position and results of operations.

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

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

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”), an amendment of FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). SFAS No. 161 requires entities to provide qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in their hedged positions. The standard is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged but not required. SFAS No. 161 also requires entities to disclose more information about the location and amounts of derivative instruments in financial statements; how derivatives and related hedges are accounted for under SFAS No. 133, and how the hedges affect the entity’s financial position, financial performance, and cash flows. The Company will apply the requirements of SFAS No. 161 on its adoption on January 1, 2009 and does not expect it to have an impact on its financial position or results of operations.

In January 2008, the FASB issued Statement 133 Implementation Issue No. E23, “Hedging – General Issues Involving the Application of the Shortcut Method under Paragraph 68” (“Implementation Issue E23”).  Implementation Issue E23 is effective for hedging relationships designated on or after January 1, 2008, and amends SFAS No. 133 to explicitly permit use of the “shortcut” method for those hedging relationships in which:  the interest rate swap has a nonzero fair value at the inception of the hedging relationship attributable solely to differing prices within the bid-ask spread; or the hedged item has a trade date that differs from its settlement date because of generally established conventions in the marketplace in which the transaction to acquire or issue the hedging item is executed.  The Company uses the “long-haul” method by applying the change in variable cash flow method (See Note 7) to measure ineffectiveness on its interest rate swaps under SFAS No. 133 and therefore Implementation Issue E23 did not have a significant impact on its financial position or results of operations.

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

In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141(R), “Business Combinations” (“SFAS 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.  Early adoption is not permitted. 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) does not expect the adoption to have a significant impact on its financial position and results of operations.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. By electing the fair value option in conjunction with a derivative, an entity can achieve an accounting result similar to a fair value hedge without having to comply with complex hedge accounting rules. The statement was effective for the Company as of January 1, 2008. The Company adopted SFAS No. 159 at January 1, 2008, and has elected not to apply the fair value option to any of its financial instruments not already carried at fair value in accordance with other accounting standards, and therefore the adoption of SFAS No. 159 did not impact the Company’s consolidated financial statements for the year ended December 31, 2008.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurement” (“SFAS No. 157”). SFAS No. 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements. In February 2008, the FASB issued FSP FAS 157-2, “Effective Date of FASB Statement No. 157”, (“FSP FAS 157-2”).  FSP FAS 157-2, which was effective upon issuance, delays the effective date of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value at least once a year, to fiscal years beginning after November 15, 2008. On January 1, 2009, the Company will adopt SFAS No. 157 for nonfinancial assets and liabilities that are not measured at fair value on a recurring basis.  For the Company, the nonfinancial assets and liabilities will be limited to the initial recognition of asset retirement obligations. FSP FAS 157-2 also covers interim periods within the fiscal years for items within its scope. The delay is intended to allow the FASB and its constituents the time to consider the various implementation issues associated with SFAS No. 157. The Company adopted SFAS No. 157 as of January 1, 2008 with respect to its commodity and interest rate swap derivative instruments which are measured at fair value within its consolidated financial statements.  See Note 7 and Note 9 for disclosures pertaining to the provisions of SFAS No. 157 with regard to the Company’s fair value measurements.

NOTE 3 —- ACQUISITION OF DTE GAS & OIL COMPANY

In June 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.  Subsequently, the Company changed DGO’s name to Atlas Gas and Oil Company, LLC (“AGO”).

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To fund the acquisition, the Company borrowed $713.9 million on its 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) of which $52.5 million was 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):

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

AGO’s operations are included within the Company’s combined and consolidated financial statements from the date of the acquisition.

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

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.

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NOTE 4 – OTHER ASSETS AND INTANGIBLE ASSETS

Other Assets

The following is a summary of other assets (in thousands):

	At December 31,
	2008		2007
Long-term derivative receivable from partnerships	$	2,719	$	13,542
Deferred finance costs, net of accumulated amortization of $5,531 and $2,708 at December 31, 2008 and 2007, respectively		15,018		7,650
Other		666		238
	$	18,403	$	21,430

Long-term hedge receivable from Partnerships represents the portion of the long-term unrealized derivative liability on contracts that has been allocated to them based on their share of total production volumes sold.  Deferred finance costs related to the Company’s credit facility and senior unsecured notes (see Note 9) are recorded at cost and amortized over their respective lives (5 to 10 years).

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, the Company entered into a two-year non-compete agreement in connection with the acquisition of AGO during the year ended December 31, 2007.  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, 2008, 2007, and 2006 was $1.2 million, $1.0 million and $1.0 million, 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: 2009—$964,000; 2010—$710,000; 2011─$664,000; 2012—$180,000 and 2013—$158,000.

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

	At December 31,
	2008			2007
Management and operating contracts	$	14,343		$	14,343
Non-compete agreement		890			890
Total costs		15,233			15,233
Accumulated amortization		(11,395	)		(10,172	)
	$	3,838		$	5,061

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 and related facilities. Under SFAS No. 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 No. 143 requires the Company to consider estimated salvage value in the calculation of depreciation, depletion and amortization.

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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 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):

	Years Ended December 31,
	2008			2007			2006
Asset retirement obligations, beginning of period	$	42,358		$	26,726		$	18,499
Cumulative effect of adoption of FIN 47		—			—			8,042
Liabilities acquired		—			11,109			─
Liabilities incurred		3,305			2,582			1,570
Liabilities settled		(253	)		(91	)		(194	)
Revision in estimates		—			—			(2,411	)
Accretion expense		2,726			2,032			1,220
Asset retirement obligations, end of period	$	48,136		$	42,358		$	26,726

The 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 Atlas America.  Atlas America 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. The employees supporting these Company operations are employees of Atlas America.  The compensation costs of these employees, and rent for the offices out of which they operate, are allocated to the Company based on estimates of the time spent by such employees in performing services for the Company.  This allocation of costs may fluctuate from period to period based upon the level of activity by the Company of any acquisitions, equity or debt offerings, or other non-recurring transactions, which requires additional management time.  Management believes the method used to allocate these expenses is reasonable.

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

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

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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 Atlas America, the Company remits this amount to Atlas America.  Therefore, after the closing of its initial public offering, the gathering revenues and costs within the partnership management segment net to $0.

NOTE 7—DERIVATIVE AND FINANCIAL INSTRUMENTS

Commodity Risk Hedging Program

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

The Company has a $106.1 million unrealized net asset related to financial derivatives on its gas and oil production shown as a component of accumulated other comprehensive loss at December 31, 2008, compared to a net unrealized liability of $5.1 million at December 31, 2007. If the fair values of the instruments remain at current market values, the Company will reclassify $63.7 million of unrealized gains to its consolidated statements of income over the next twelve-month period as these contracts settle and $42.4 million of unrealized gains will be reclassified in later periods.

The Company recognized a loss of $25.1 million and gains of $17.6 million and $7.1 million on settled contracts covering natural gas production for the years ended December 31, 2008, 2007 and 2006, respectively. The Company recognized a loss of $312,000 on settled oil production for the year ended December 31, 2008, and there were no gains or (losses) on oil settlements for the years ended December 31, 2007 and 2006. These gains and losses are included with gas and oil production in the Company’s combined and consolidated statements of income.  As the underlying prices and terms in the Company’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the years ended December 31, 2008, 2007 and 2006 for derivative ineffectiveness or as a result of the discontinuance of any cash flow hedges.

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

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As of December 31, 2008, the Company had the following natural gas volumes hedged:

Natural Gas Fixed Price Swaps

Twelve Month
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset
	(MMBtu)		(per MMBtu)		(in thousands) (1)
2009		38,120,000	$	8.55	$	93,246
2010		26,360,000	$	8.11		25,537
2011		18,680,000	$	7.84		9,670
2012		13,800,000	$	8.05		10,851
2013		1,500,000	$	8.73		2,098
					$	141,402

Natural Gas Costless Collars

Twelve Month
Period Ending				Average		Fair Value
December 31,	Option Type	Volumes		Floor and Cap		Asset
		(MMBtu)		(per MMBtu)		(in thousands) (1)
2009	Puts purchased		240,000	$	11.00	$	1,182
2009	Calls sold		240,000	$	15.35		—
2010	Puts purchased		3,360,000	$	7.84		3,340
2010	Calls sold		3,360,000	$	9.01		—
2011	Puts purchased		7,500,000	$	7.48		3,708
2011	Calls sold		7,500,000	$	8.44		—
2012	Puts purchased		1,020,000	$	7.00		223
2012	Calls sold		1,020,000	$	8.32		—
2013	Puts purchased		300,000	$	7.00		72
2013	Calls sold		300,000	$	8.25		—
						$	8,525

Crude Oil Fixed Price Swaps

Twelve Month
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset
	(Bbl)		(per Bbl)		(in thousands) (2)
2009		59,900	$	100.14	$	2,790
2010		48,900	$	97.40		1,624
2011		42,600	$	96.44		1,141
2012		33,500	$	96.00		785
2013		10,000	$	96.06		221
					$	6,561

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Crude Oil Costless Collars

Twelve Month
Period Ending				Average		Fair Value
December 31,	Option Type	Volumes		Floor and Cap		Asset
		(Bbl)		(per Bbl)		(in thousands) (2)
2009	Puts purchased		36,500	$	85.00	$	1,200
2009	Calls sold		36,500	$	118.63		—
2010	Puts purchased		31,000	$	85.00		754
2010	Calls sold		31,000	$	112.92		—
2011	Puts purchased		27,000	$	85.00		538
2011	Calls sold		27,000	$	110.81		—
2012	Puts purchased		21,500	$	85.00		379
2012	Calls sold		21,500	$	110.06		—
2013	Puts purchased		6,000	$	85.00		100
2013	Calls sold		6,000	$	110.09		—
							2,971
				Total Net Asset		$	159,459

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

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

The fair value of the derivatives related to commodities included in the consolidated balance sheets are as follows (in thousands):

	December 31,
	2008			2007
Current portion of derivative asset	$	107,766		$	38,181
Long-term derivative asset		69,451			6,882
Current portion of derivative liability		(9,348	)		(356	)
Long-term derivative liability		(8,410	)		(39,204	)
	$	159,459		$	5,503

In addition, an unrealized derivative liability of $(51.8) million and an unrealized derivative asset of $3.4 million have been allocated to the limited partners in the Partnerships at December 31, 2008 and 2007, respectively, based on the Partnerships’ share of estimated future gas and oil production related to the hedges not yet settled and are included in the consolidated balance sheets as follows (in thousands):

	December 31,
	2008			2007
Unrealized derivative loss – short-term	$	3,022		$	213
Other assets – long-term		2,719			13,542
Accrued liabilities – short-term		(34,932	)		(9,013	)
Unrealized derivative gain – long-term		(22,581	)		(1,348	)
	$	(51,772	)	$	3,394

Interest Rate Risk Hedging Program

At December 31, 2008, the Company had debt outstanding of $467.0 million under its revolving credit facility. During the year ended December 31, 2008, the Company entered into derivative contracts in the form of interest rate swaps to reduce the impact of volatility of changes in the London interbank offered rate (“LIBOR”).  The Company has LIBOR interest rate swaps at a three-year fixed swap rate of 3.11% on $150.0 million of outstanding debt through January 2011. The swaps have been designated as cash flow hedges to minimize the risk associated with changes in the designated benchmark interest rate (in this case, LIBOR) related to forecasted payments associated with interest on the credit facility. The Company has accounted for the interest rate swaps under the “long-haul” method to measure ineffectiveness under SFAS No. 133. Using the change in variable cash flow method, no hedge ineffectiveness was identified. The value of the Company’s cash flow derivatives related to interest rate swaps included in accumulated other comprehensive income was a net unrecognized loss of approximately $5.8 million at December 31, 2008. The Company recognized a loss on settled swaps of $520,000 for the year ended December 31, 2008. The fair value of the derivatives related to interest rate swaps are included in the consolidated balance sheet as follows:

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	December 31,
	2008			2007
Current portion of derivative liability	$	(3,481	)	$	—
Long-term derivative liability		(2,361	)		—
	$	(5,842	)	$	—

Fair Value of Financial Instruments

Derivative Instruments

The Company adopted the provisions of SFAS No. 157 at January 1, 2008. SFAS No. 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS No. 157’s hierarchy defines three levels of inputs that may be used to measure fair value:

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

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

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

The Company uses the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities for its outstanding derivative contracts. All of the Company’s derivative contracts are defined as Level 2. The Company’s natural gas and crude oil derivative contracts are valued based on prices quoted on the NYMEX or WTI and adjusted by the respective counterparty using various assumptions including quoted forward prices, time value, volatility factors, and contractual prices for the underlying instruments. The Company’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model.  In accordance with SFAS No. 157, the following table represents the Company’s fair value hierarchy for its financial instruments at December 31, 2008 (in thousands):

	Level 2			Total
Commodity-based derivatives	$	159,459		$	159,459
Interest rate swap-based derivatives		(5,842	)		(5,842	)
Total	$	153,617		$	153,617

Other Financial Instruments

The estimated fair value of the Company’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies.  However, these estimates may not necessarily be indicative of the amounts that the Company could realize upon the sale or refinancing of such financial instruments.  The Company’s other current assets and liabilities on its consolidated balance sheets are financial instruments and their estimated fair values  approximate their carrying amounts due to their short-term nature.   The estimated fair values of the Company’s long-term debt at December 31, 2008 and 2007, which consists principally of the Company’s senior unsecured notes and borrowings under its credit facilities, were $712.2 million and $740.0 million, respectively, compared with the carrying amounts of $873.7 million and $740.0 million, respectively.  The senior unsecured notes were valued based upon recent trading activity.  The carrying value of outstanding borrowings under the credit facility, which bears interest at a variable interest rate, approximates their estimated fair value.

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NOTE 8—COMMITMENTS AND CONTINGENCIES

General Commitments

The Company leases office space and equipment under leases with varying expiration dates through 2014. Rental expense was approximately $1.6 million, $1.0 million and $670,000, for the years ended December 31, 2008, 2007 and 2006, respectively. Future minimum rental commitments for the next five annual periods are as follows (in thousands):

Years Ended December 31,
2009	$	3,178
2010		2,770
2011		2,071
2012		1,427
2013		1,069
Thereafter		3,853
	$	14,368

The Company is the managing general partner of the Partnerships, and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Partnership assets. Subject to certain conditions, investor partners in certain Partnerships have the right to present their interests for purchase by the Company, as managing general partner. The Company is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on past experience, the Company believes that any liability incurred would not be material.  The Company may be required to subordinate a part of its net partnership revenues from the Partnerships to the receipt by investor partners of cash distributions from the investment partnerships equal to at least 10% of their subscriptions determined on a cumulative basis, in accordance with the terms of the partnership agreements.

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

Legal Proceedings

On June 20, 2008, the Company’s wholly-owned subsidiary, Atlas America, LLC, was named as a co-defendant in the matter captioned CNX Gas Company, LLC (“CNX”) v. Miller Petroleum, Inc. (“Miller”), et al. (Chancery Court, Campbell County, Tennessee).   In its complaint, CNX alleged that Miller breached a contract to assign to CNX certain leasehold rights (“Leases”) representing approximately 30,000 acres in Campbell County, Tennessee and that the Company and another defendant, Wind City Oil & Gas, LLC, interfered with the closing of this assignment on June 6, 2008.  The Company purchased the Leases from Miller for approximately $19.1 million.  On December 15, 2008, the Chancery Court dismissed the matter in its entirety, holding that there had been no breach of the contract by Miller and, therefore, that Atlas America could not have tortuously interfered with the contract.  The Chancery Court dismissed all claims against Atlas America, LLC; however, CNX has appealed this decision.

One of the Company’s subsidiaries, Resource Energy, LLC, together with Resource America, Inc., (the former parent of Atlas America), 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 Atlas America 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.

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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,
	2008		2007
Revolving credit facility	$	467,000	$	740,000
10.75% senior unsecured notes – due 2018		400,000		—
Unamortized notes premium		6,655		—
Other debt		—		30
	$	873,655	$	740,030
Less current maturities		—		(30	)
	$	873,655	$	740,000

Revolving Credit Facility.  At December 31, 2008, the Company had a credit facility with a syndicate of banks with a borrowing base of $697.5 million that matures in June 2012.  The borrowing base will be redetermined semiannually on April 1 and October 1 subject to changes in the Company’s oil and gas reserves.  Up to $50.0 million of the facility may be in the form of standby letters of credit, of which $1.2 million was outstanding at December 31, 2008, which are not reflected as borrowings on the Company’s consolidated balance sheets.   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, 2008 and 2007, the weighted average interest rate on outstanding borrowings was 2.8% and 7.2%, respectively.  The base rate for any day equals the higher of the federal funds rate plus 0.50% or the J.P. Morgan prime rate.  Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for  determining the reserve requirement for Eurocurrency liabilities.  The applicable margin ranges from 0.0% to 0.75% for base rate loans and 1.00% to 1.75% for LIBOR loans.

The events which constitute an event of default for the Company’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against the Company in excess of a specified amount, and a change of control.  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 was in compliance with these covenants as of December 31, 2008 and 2007.  The credit facility also requires the Company to maintain ratios of current assets (as defined in the credit facility) to current liabilities (as defined in the credit facility) of not less than 1.0 to 1.0 and a ratio of total debt (as defined in the credit facility) to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”, as defined in the credit facility) of 4.0 to 1.0, decreasing to 3.75 to 1.0 commencing January 1, 2009, and decreasing to 3.5 to 1.0 commencing January 1, 2010 and thereafter.  According to the definitions contained in the Company’s credit facility,  the Company’s ratio of current assets to current liabilities was 1.60 to 1.0 and its ratio of total debt to EBITDA was 2.89 to 1.0 at December 31, 2008.

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Senior Unsecured Notes.  In January 2008, the Company completed a private placement of $250.0 million of its 10.75% senior unsecured notes (“Senior Notes”) due 2018 to institutional buyers pursuant to rule 144A under the Securities Act of 1933. In May 2008, the Company issued an additional $150.0 million of Senior Notes at 104.75% to par to yield 9.85% to the par call on February 1, 2016.  The Company intends to treat these issuances as a single class of debt securities which were subsequently registered for resale on September 19, 2008.  The Company received proceeds of approximately $398.0 million from these offerings, including a $7.1 million premium and net of $9.2 million in underwriting fees.  In addition, the Company received approximately $4.7 million related to accrued interest.  The Company used the net proceeds to reduce the balance outstanding on its revolving credit facility.  Interest on the Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year.  The Senior Notes are redeemable at any time at specified redemption prices, together with accrued and unpaid interest to the date of redemption.  In addition, before February 1, 2011, the Company may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of equity offerings at a stated redemption price.  The Senior Notes are also subject to repurchase by the Company at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if the Company does not reinvest the net proceeds within 360 days.  The Senior Notes are junior in right of payment to the Company’s secured debt, including its obligations under its credit facility.  The indenture governing the Senior Notes contains covenants, including limitations of the Company’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets.  The Company is in compliance with the covenants as of December 31, 2008.

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

2009	$	—
2010		—
2011		—
2012		467,000
2013		—
Thereafter		406,655
	$	873,655

Cash payments for interest related to debt were $42.4 million and $23.2 million for the years ended December 31, 2008 and 2007, respectively.  There were no cash payments for interest related to debt for the year ended December 31, 2006.

NOTE 10—OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS

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/Indiana segment represents the Company’s well interests in the Antrim Shale, located in Michigan’s northern, lower peninsula and the New Albany shale located in southwestern Indiana.

Operating segment data (in thousands):

	Years Ended December 31,
	2008		2007		2006
Gas and oil production
Appalachia:
Revenues	$	127,935	$	99,015	$	88,449
Costs and expenses		25,176		17,638		13,881
Segment profit	$	102,759	$	81,377	$	74,568
Michigan/Indiana:
Revenues(1)	$	183,915	$	107,367	$	—
Costs and expenses		34,403		14,555		—
Segment profit	$	149,512	$	92,812	$	—
Partnership management:
Revenues	$	472,008	$	370,053	$	232,533
Costs and expenses		389,361		302,382		209,548
Segment profit	$	82,647	$	67,671	$	22,985

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	Years Ended December 31,
	2008			2007			2006
Reconciliation of segment profit to net income
Segment profit
Gas and oil production-Appalachia	$	102,759		$	81,377		$	74,568
Gas and oil production-Michigan/Indiana		149,512			92,812			—
Partnership management		82,647			67,671			22,985
Total segment profit		334,918			241,860			97,553
General and administrative expense		(44,659	)		(39,414	)		(23,367	)
Compensation reimbursement – affiliate		—			—			(1,237	)
Depreciation, depletion and amortization		(95,434	)		(56,942	)		(22,491	)
Interest expense		(56,306	)		(30,096	)		—
Other − net (2)		4,260			2,096			1,369
Net income before cumulative effect of accounting change	$	142,779		$	117,504		$	51,827

	Years Ended December 31,
	2008		2007		2006
Capital expenditures
Gas and oil production
Appalachia	$	258,941	$	146,605	$	74,075
Michigan/Indiana		77,884		40,878		—
Partnership management		2,890		4,499		1,042
Corporate		1,260		4,753		518
	$	340,975	$	196,735	$	75,635

(1) Revenues for the twelve months ended December 31, 2007 include non-cash gains of $26.3 million related to non-qualifying hedges associated with the acquisition of AGO.

(2)  Includes revenues of $3.5 million and $1.5 million and expenses of $441,000 and $214,000 for the years ended December 31, 2008 and 2007, respectively for AGO well services and transportation.  These amounts do not meet the quantitative threshold for reporting segment information.  The following table reconciles revenue shown for each operating segment to total revenues shown on the combined and consolidated statements of income:

	Years Ended December 31,
	2008		2007		2006
Revenues:
Gas and oil production – Appalachia	$	127,935	$	99,015	$	88,449
Gas and oil production – Michigan/Indiana		183,915		107,367		—
Partnership Management		472,008		370,053		232,533
Other		3,542		1,462		—
	$	787,400	$	577,897	$	320,982

	December 31,
	2008		2007
Balance sheets
Goodwill
Gas and oil production - Appalachia	$	21,527	$	21,527
Partnership management		13,639		13,639
	$	35,166	$	35,166
Total assets
Gas and oil production
Appalachia	$	773,889	$	491,199
Michigan/Indiana		1,416,042		1,330,432
Partnership management		53,031		30,359
Corporate		27,723		39,244
	$	2,270,685	$	1,891,234

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Segment profit per segment represents total revenues less costs and expenses attributable thereto.  Amounts for interest, provision for possible losses and depreciation, depletion and amortization and general corporate expenses are shown in the aggregate because these measures are not significant drivers in deciding how to allocate resources and assessing performance of each defined segment.

Major Customer Information:

For the year ended December 31, 2008, gas sales to DTE Gas & Oil Company accounted for 12% of total revenues.  No other fiscal period or operating segment had revenues from a single customer which exceeded 10% of total revenues.

NOTE 11 - BENEFIT PLANS

Unit Incentive Plan.In December 2006, the Company adopted a Long-Term Incentive Plan (“LTIP”), which provides performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners.  The LTIP is administered by the Company’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 2008 and 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 the Company’s compensation committee, cash equivalent to the then fair market value of a common unit of the Company.  In tandem with phantom unit grants, the Company’s compensation committee may grant a distribution equivalent right (“DER”), which is the right to receive cash per phantom 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 LTIP, 156,793, 590,950 and 47,619 units of restricted stock and phantom units were awarded in 2008, 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.

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
Granted		156,793		$	21.43
Vested		(12,279	)	$	21.06
Forfeited		(350	)	$	26.47
Non-vested shares outstanding at December 31, 2008		768,829		$	23.86

Unit Options.  For the years ended December 31, 2008, 2007 and 2006, 14,000, 1,532,000 and 373,752 unit options, respectively, were awarded under the 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:

96

	Years Ended December 31,
	2008			2007			2006
Expected life (years)		6.25			6.25			6.25
Expected volatility		27-34	%		25	%		25	%
Risk-free interest rate		2.8-4.0	%		4.7	%		4.4	%
Expected dividend yield		6.2-7.0	%		5.1-8.0	%		8.0	%
Weighted average fair value of stock options granted	$	5.69		$	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
Granted		14,000		$	35.36
Exercised		—			—
Forfeited or expired		(6,150	)	$	25.97
Outstanding at December 31, 2008		1,902,902		$	24.17		7.9	$	—
Options exercisable at December 31, 2008		186,876		$	21.00		7.25
Available for grant at December 31, 2008		1,046,086

The following tables summarize information about stock options outstanding and exercisable at December 31, 2008:

 

	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		1,654,802		7.9	$	22.59		186,876	$	21.00
$30.24 - 35.00		240,600		8.5	$	34.53		—		—
$39.00 & above		7,500		9.0	$	39.79		—		—
		1,902,902		7.9	$	24.17		186,876	$	21.00

The Company recognized $5.5 million, $4.7 million and $337,000 in compensation expense related to restricted stock units, phantom units and unit options for the years ended December 31, 2008, 2007 and 2006, respectively.  The Company paid $1.4 million with respect to its LTIP DERs for the year ended December 31, 2008.  This amount was recorded as a reduction of members’ equity on the Company’s consolidated balance sheet.   At December 31, 2008, the Company had approximately $13.7 million of unrecognized compensation expense related to the unvested portion of the restricted stock units, phantom units and options.

97

NOTE 12 – COMMON EQUITY OFFERINGS

Public Common Unit Purchase

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

Atlas America Common Unit Purchase

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

Private Placement of Class B Common and Class D Units

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

NOTE 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 company agreement) for that quarter in accordance with their respective percentage interests.  If Class A and Class B common unit distributions in any quarter exceed specified target levels, the Managing Member will receive MIIs between 15% and 50% of such distributions in excess of the specified target levels as defined in our limited liability company agreement.  Distributions declared by the Company from inception are as follows:

			Cash
			Distribution			Total Cash		Total		Manager
Date Cash			Per			Distribution		Cash		Incentive
Distribution			Common			to Common		Distribution		Distribution
Paid or Payable		For Quarter Ended	Unit			Unit holders		to the Manager		Payable
						(in thousands)		(in thousands)		(in thousands)
February 14, 2007	��	December 31, 2006	$	0.06	(1)	$	2,198	$	45
May 15, 2007		March 31, 2007	$	0.43		$	15,770	$	322
August 14, 2007		June 30, 2007	$	0.43		$	15,770	$	322
November 14, 2007		September 30, 2007	$	0.55		$	33,391	$	681	$	784
February 14 , 2008		December 31, 2007	$	0.57		$	34,605	$	706	$	965
May 15, 2008		March 31, 2008	$	0.59		$	36,173	$	738	$	1,214
August 14, 2008		June 30, 2008	$	0.61		$	38,663	$	789	$	1,687
November 14, 2008		September 30, 2008	$	0.61		$	38,663	$	789	$	1,687
February 13, 2009(2)		December 31, 2008	$	0.61	(2)	$	38,663	$	789	$	1,687

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

98

(2) On January 28, 2009, the Company declared a quarterly cash distribution for the quarter ended December 31, 2008, of $0.61 per common unit.  The distribution is payable February 13, 2009 to holders of record as of February 9, 2009.

NOTE 14 – SUBSEQUENT EVENTS

On January 29, 2009, the Company declared a quarterly cash distribution for the quarter ended December 31, 2008, of $0.61 per common unit.  The distribution was paid on February 13, 2009 to unit holders of record as of February 9, 2009.

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):

	Years Ended December 31,
	2008			2007			2006
Revenues	$	311,850		$	206,382	(1)	$	88,449
Production costs		(59,579	)		(32,193	)		(13,881	)
Exploration expenses (2)		(6,029	)		(4,065	)		(3,016	)
Depreciation, depletion and amortization		(91,991	)		(54,383	)		(20,600	)
Results of operations from oil and gas producing activities		154,251		$	115,741		$	50,952

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

(2) Represents the Company’s land and leasing activities.

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,
	2008			2007
Natural gas and oil properties:
Proved properties	$	2,087,119		$	1,795,871
Unproved properties		43,749			16,380
Support equipment		9,527			6,936
		2,140,395			1,819,187
Accumulated depreciation, depletion and amortization(1)		(221,356	)		(136,603	)
Net capitalized costs	$	1,919,039		$	1,682,584

(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):

	Years Ended December 31,
	2008		2007		2006
Property acquisition costs:
Proved properties	$	63,146	$	1,243,877	$	5,153
Unproved properties		27,064		50,100		—
Exploration costs		6,029		4,065		3,016
Development costs		229,687		168,253		76,687
	$	325,926	$	1,466,295	$	84,856

(1) Represents the Company’s land and leasing activities.

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

Oil and Gas Reserve Information.  The estimates of the Company’s proved and unproved gas and oil reserves are based upon evaluations made by management and verified by an independent petroleum engineering firm. All reserves are generally located in the Appalachian Basin in Michigan’s Lower Peninsula and in southwestern Indiana. 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 & Oil Company on June 29, 2007.

100

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

	Gas			Oil
	(Mcf)			(Bbls)
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	)(3)		(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	(1)		23,358
Sales of reserves in-place		(62,699	)		(625	)
Purchase of reserves in-place		622,851,730	(2)		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
Extensions, discoveries and other additions		210,824,798	(1)		111,972
Sales of reserves in-place		(34,924	)		(161	)
Purchase of reserves in-place		3,461,987			794
Transfers to limited partnerships		(6,026,785	)		—
Revisions		(68,276,626	)(3)		(203,166	)
Production		(33,901,975	)		(158,529	)
Balance December 31, 2008		990,805,385			1,733,941
Proved developed reserves at:
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
December 31, 2008		586,655,301			1,685,771

(1) Includes a significant increase in proved undeveloped reserves due to the addition of proved undeveloped reserves for Marcellus wells.

(2) Represents the reserves purchased from the acquisition of AGO on June 29, 2007.

(3) Represents a decrease of the year-end price of natural gas and oil compared to the price of natural gas and oil at the beginning of the year.

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 December 31, 2006, 2007 and 2008 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.  Since the Company 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 calculation of standardized measure.

101

	Years Ended December 31,
	2008			2007			2006
	(in thousands)
Future cash inflows	$	6,333,935		$	6,408,367		$	1,262,161
Future production costs		(2,297,091	)		(1,804,199	)		(334,062	)
Future development costs		(618,604	)		(388,111	)		(149,610	)
Future income tax expense		—			—			—
Future net cash flows		3,418,240			4,216,057			778,489
Less 10% annual discount for estimating timing of cash flows		(2,286,299	)		(2,734,879	)		(495,048	)
Standardized measure of discounted future net cash flows	$	1,131,941		$	1,481,178		$	283,441

The future cash flows estimated to be spent to develop proved undeveloped properties in the years ended December 31, 2009, 2010, 2011 and 2012 are $200.7 million, $192.5 million, $192.0 million and $33.5 million, respectively.

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 for the years ended December 31, 2006, 2007 and 2008.  Since the Company allocates taxable income to unit holders, no recognition has been given to income taxes.

	Years Ended December 31,
	2008			2007			2006
Balance, beginning of year	$	1,481,178		$	283,441			$	597,137
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs		(252,270	)		(147,982	)			(74,567	)
Net changes in prices and production costs		(316,970	)		45,261				(273,631	)
Revisions of previous quantity estimates		(46,767	)		(1,208	)			(30,058	)
Development costs incurred		48,092			98,424				3,426
Changes in future development costs		(35,662	)		(14,128	)			(8,505	)
Transfers to limited partnerships		(615	)		(13,998	)			(8,449	)
Extensions, discoveries, and improved recovery less related costs		41,020			170,349				44,820
Purchases of reserves in place		5,170			957,137				660
Sales of reserves in place, net of tax effect		(97	)		(105	)			(572	)
Accretion of discount		147,781			74,685				59,714
Net changes in future income taxes		—			—				—
Estimated settlement of asset retirement obligations		(5,778	)		(4,523	)			(8,226	)
Estimated proceeds on disposals of well equipment		6,329			5,168				10,007
Changes in production rates (timing) and other		60,530			28,657				(28,315	)
Balance, end of year	$	1,131,941		$	1,481,178			$	283,441

102

NOTE 16 – QUARTERLY RESULTS (UNAUDITED)

	March 31,		June 30,		September 30,		December 31,
	(in thousands, except unit data)
Year ended December 31, 2008
Revenues	$	194,589	$	217,556	$	213,621	$	161,634
Net income	$	37,543	$	38,359	$	38,180	$	28,697
Net income per Class B common unit:
Basic	$	0.59	$	0.58	$	0.56	$	0.42
Diluted		0.58	$	0.57	$	0.56	$	0.42
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 Class B common unit:
Basic	$	0.53	$	1.10	$	0.50	$	0.38
Diluted		0.53	$	1.08	$	0.49	$	0.37
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 Class B members		—		—		—		2,751
Portion applicable to Class A members		—		—		—		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 Class B common unit – basic and diluted	$	—	$	—	$	—	$	0.08
Cumulative effect of accounting change		—		—		—		6,355
Net income	$	12,469	$	12,599	$	11,466	$	21,648

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, 2008, our disclosure controls and procedures were effective at the reasonable assurance level.

103

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.

Based on our evaluation under the COSO framework, management concluded that our internal control over financial reporting was effective at the reasonable assurance level as of December 31, 2008.  Grant Thornton, LLP, an independent registered public accounting firm and auditors of our consolidated financial statements, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2008, which is included herein.

There have been no changes in our internal control over financial reporting during the fourth quarter of 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

104

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Atlas Energy Resources, LLC

We have audited Atlas Energy Resources, LLC (a Delaware limited liability company) and subsidiaries internal control over financial reporting as of December 31, 2008, 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.

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, 2008, 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, (a Delaware limited liability company) and subsidiaries, as of December 31, 2008 and 2007, and the related combined and consolidated statements of income, comprehensive income, members' equity, and cash flows for each of the three years in the period ended December 31, 2008and our report dated March 2, 2009expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

March 2, 2009

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ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this item will be set forth in our definitive proxy statement with respect to our 2009 annual meeting of unitholders.

ITEM 11.  EXECUTIVE COMPENSATION

The information required by this item will be set forth in our definitive proxy statement with respect to our 2009 annual meeting of unitholders.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this item will be set forth in our definitive proxy statement with respect to our 2009 annual meeting of unitholders.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTORINDEPENDENCE

The information required by this item will be set forth in our definitive proxy statement with respect to our 2009 annual meeting of unitholders.

ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this item will be set forth in our definitive proxy statement with respect to our 2009 annual meeting of unitholders.

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PART IV

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)  The following documents are filed as part of this report:

(1)   Financial Statements

The financial statements required by this Item 15 (a)(1) are set forth in Item 8.

(2)  Financial Statement Schedules

No schedules are required to be presented.

(3)   Exhibits:

Exhibit No.	Description
3.1	Amended and Restated Limited Liability Company Agreement of Atlas Energy Resources, LLC(1)
3.2	Amendment No. 1 to Amended and Restated Operating Agreement of Atlas Energy Resources, LLC(2)
3.3	Certificate of Formation of Atlas Energy Resources, LLC(3)
4.1	Form of common unit certificate (included as Exhibit A to the Amended and Restated Limited Liability Company Agreement of Atlas Energy Resources, LLC) (1)
10.1(a)	Revolving Credit Agreement, dated as of June 29, 2007, among Atlas Energy Operating Company, LLC, its subsidiaries, J.P. Morgan Chase Bank, N.A., as Administrative Agent and the other lenders signatory thereto(2)
10.1(b)	First Amendment to Credit Agreement, dated as of October 25, 2007(4)
10.2	Contribution, Conveyance and Assumption Agreement, dated as of December 18, 2006, among Atlas America, Inc., Atlas Energy Resources, LLC and Atlas Energy Operating company, LLC)(1)
10.3	Omnibus Agreement, dated as of December 18, 2006, between Atlas America, Inc. and Atlas Energy Resources, LLC(1)
10.4	Management Agreement, dated as of December 18, 2006, among Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC and Atlas Energy Management, Inc (1)

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10.5(a)	Master Natural Gas Gathering Agreement, dated February 2, 2000, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc. and Viking Resources Corporation(3)
10.5(b)	Natural Gas Gathering Agreement, dated January 1, 2002, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas Resources, Inc., Atlas Energy Group, Inc., Atlas Noble Corporation, Resource Energy, Inc. and Viking Resources Corporation(3)
10.5(c)	Amendment to Master Natural Gas Gathering Agreement and Natural Gas Gathering Agreement, dated October 25, 2005, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc., Viking Resources Corporation, Atlas Noble Corp. and Atlas Resources, Inc. (3)
10.5(d)	Amendment and Joinder to Gas Gathering Agreements, dated as of December 18, 2006, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, LLC, Viking Resources, LLC, Atlas Noble, LLC, Atlas Resources, LLC, Atlas America, LLC, Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC(1)
10.6(a)	Omnibus Agreement, dated February 2, 2000, among Atlas America, Inc., Resource Energy, Inc., Viking Resources Corporation, Atlas Pipeline Partnership, L.P., and Atlas Pipeline Partners, L.P. (3)
10.6(b)	Amendment and Joinder to Omnibus Agreement, dated as of December 18, 2006 among Atlas Pipeline, Atlas America, Resource Energy, LLC, Viking Resources, LLC, Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC(1)
10.7	Agreement for Services among Atlas America, Inc. and Richard Weber, dated April 5, 2006(3)
10.8	Amended and Restated Long-Term Incentive Plan
12.1	Computation of Ratio of Earnings to Fixed Charges
21.1	Subsidiaries of Atlas Energy Resources, LLC
23.1	Consent of Independent Registered Accounting Firm
23.2	Consent of Independent Petroleum Consultants
31.1	Rule 13(a)-14(a)/15d-14(a) Certification
31.2	Rule 13(a)-14(a)/15d-14(a) Certification
32.1	Section 1350 Certification
32.2	Section 1350 Certification

(1)	Previously filed as an exhibit to our Form 8-K filed December 22, 2006.
(2)	Previously filed as an exhibit to our Form 8-K filed June 29, 2007.
(3)	Previously filed as an exhibit to our registration statement on Form S-1 (Reg. No. 333-136094).
(4)	Previously filed as an exhibit to our Form 8-K filed October 26, 2007.

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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 2, 2009	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 indicated as of March 2, 2009.

/s/ Edward E. Cohen	Chairman and Chief Executive Officer
Edward E. Cohen
/s/ Richard D. Weber	President and Chief Operating Officer
Richard D. Weber
/s/ Matthew A. Jones	Chief Financial Officer
Matthew A. Jones
/s/ Sean P. McGrath	Chief Accounting Officer
Sean P. McGrath
/s/ Jonathan Z. Cohen	Director
Jonathan Z. Cohen
/s/ Walter C. Jones	Director
Walter C. Jones
/s/ Ellen F. Warren	Director
Ellen F. Warren
/s/ Bruce M. Wolf	Director
Bruce M. Wolf

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