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, 2009

¨	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: 001-33193

ATLAS ENERGY RESOURCES, LLC

(Exact name of registrant as specified in its charter)


Delaware		51-0404430
(State or other jurisdiction or incorporation or organization)		(I.R.S. Employer Identification No.)

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

Registrant’s telephone number, including area code: 412-262-2830

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

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 ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ 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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ 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. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “small reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer x Smaller reporting company ¨

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

Atlas Energy Resources, LLC meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format. Items 1, 2 and 6 have been reduced and Items 5, 9, 10, 11, and 12 have been omitted in accordance with Instruction I.

DOCUMENTS INCORPORATED BY REFERENCE: None

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K

TABLE OF CONTENTS


			Page
PART I	Item 1:	Business	6

	Item 1A:	Risk Factors	8

	Item 1B:	Unresolved Staff Comments	20

	Item 2:	Properties	20

	Item 3:	Legal Proceedings	21

PART II	Item 4:	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	22

	Item 5:	Selected Financial Data	22

	Item 6:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22

	Item 6A:	Quantitative and Qualitative Disclosures about Market Risk	32

	Item 7:	Financial Statements and Supplementary Data	35

	Item 8:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	78

	Item 8A:	Controls and Procedures	78

	Item 8B:	Other Information	80

PART III	Item 9:	Directors, Executive Officers and Corporate Governance	81

	Item 10:	Executive Compensation	81

	Item 11:	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	81

	Item 12:	Certain Relationships and Related Transactions, and Director Independence Matters	81

	Item 13:	Principal Accounting Fees and Services	81

PART IV	Item 14:	Exhibits and Financial Statement Schedules	82

SIGNATURES			84

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. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

Extension well. A well drilled to extend the limits of a known reservoir.

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. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

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.

MBbl. 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.

Mcfd. One thousand cubic feet per day.

MMBl. 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.

MMcfed. 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.

Oil. Crude oil, condensate and natural gas liquids.

PV-10. Present value of future net revenues. See “Standardized Measure”.

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 or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

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 directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. Estimates for undeveloped reserves cannot be attributable 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 projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

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

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

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.

Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

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 or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Standardized measure differs from PV-10 because standardized measure includes the effect of future 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.

FORWARD-LOOKING STATEMENTS

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.

Other 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 an independent developer and producer of natural gas and oil, with operations in the Appalachian Basin, the Michigan Basin and the Illinois Basin. Within these basins, we believe we are one of the leading natural gas producers in four established shale plays, namely the Marcellus Shale of western Pennsylvania, the Antrim Shale of northern Michigan, and the Chattanooga Shale of northeastern Tennessee and the New Albany Shale of west central Indiana. Our focus is to increase our own reserves, production, and cash flows through development drilling and the sponsorship of investment partnerships.

On September 29, 2009, we completed our merger, pursuant to the definitive merger agreement previously executed between us and Atlas America on April 27, 2009, whereby we survived as a wholly-owned subsidiary of Atlas America, Inc. (“Atlas America”) (NASDAQ: ATLS) (the “Merger”). In the Merger, 33.4 million of our Class B common units not previously held by Atlas America were exchanged for 38.8 million shares of Atlas America common stock (a ratio of 1.16 shares of Atlas America common stock for each Class B common unit) and 30.0 million Class B common units held by Atlas America were cancelled. Additionally, Atlas America changed its name to “Atlas Energy, Inc.” (“ATLS”). Prior to the Merger, we had 63,381,249 Class B common units and 1,293,496 Class A units outstanding, with ATLS and its affiliates owning 29,952,996 of our Class B common units and all of the Class A units outstanding, representing a 48.3% ownership interest in us. The Class A units (which continue to remain outstanding after the Merger) were entitled to 2% of all quarterly cash distributions by us without any requirement for future capital contributions by the holder of such Class A units. Our Class B common units are no longer listed on the NYSE and have been deregistered under the Exchange Act.

We have been active in the Appalachian Basin for over 40 years and, with 7,930 operated wells as of December 31, 2009, we believe we are currently one of its largest operators. As of December 31, 2009, our Appalachian Basin proved reserves were approximately 498 billion cubic feet equivalents (“Bcfe”), of which 348 Bcfe were proved undeveloped reserves. Historically we had targeted the numerous shallow sandstone formations in the Appalachian Basin. However, we are currently directing most of our drilling activity in the Appalachian Basin toward the development of our position in the Marcellus Shale, where we control approximately 584,000 gross acres in Pennsylvania, West Virginia and New York. With 226 Marcellus Shale wells drilled as of December 31, 2009, we are one of the most active operators in the play. Of these Marcellus wells, 210 were funded through either our direct investment partnerships or industry partnerships and 16 were funded 100% on our own account. All but two of these 226 Marcellus Shale wells were drilled in our focus area of southwestern Pennsylvania, where we control approximately 270,000 acres. In this region, we have delineated a majority of our acreage primarily through vertical well drilling. Going forward, we intend to develop our Marcellus Shale acreage primarily through horizontal drilling techniques, which we believe enhance our rates of return due to a lateral well’s increased exposure to the producing reservoir and the ability to cost-effectively drill multiple wells on a single well site location. During the year ended December 31, 2009, we successfully drilled 17 horizontal Marcellus Shale wells, 14 of which were drilled through our direct investment partnerships and industry joint ventures, and 3 for our own account. Of these Marcellus Shale wells, 9 are online and 8 are yet to be fractured as of December 31, 2009. Our last 4 horizontal Marcellus Shale wells that were turned online during

the year ended December 31, 2009 in southwestern Pennsylvania had an average peak 24-hour rate of production of 4.1 million cubic feet equivalents per day (“Mmcfed”). We have scheduled 9 horizontal well completions for the first quarter 2010, which will include 7 for our own account and 2 for our direct investment partnerships. We expect to drill approximately 25 horizontal Marcellus Shale wells for our own account during the year ended December 31, 2010.

We currently fund a significant portion of our drilling activity through the sponsorship of investment drilling partnerships. With approximately $351.9 million of investor funds raised during 2009, we believe we are the largest sponsor of such partnerships in the United States. 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. We also receive an additional equity interest (carried interest) in each partnership, for which we do not make any additional capital contribution, for a total interest in our partnerships ranging from 27% to 41%. The fees and carried interests that we earn serve to reduce our net capital at risk and enhance our rates of returns.

We are the largest producer in Michigan’s Antrim Shale, as reported by the January 2010 Michigan Public Service Commission’s Monthly Gas Production Summary, and as of December 31, 2009, we operated 1,938 Antrim Shale wells. Our technical and operating team in Michigan has a long operating track record in the Antrim Shale which we believe has resulted in our strong operating discipline and our position as one of the lowest-cost producers in the region. Antrim Shale reserves are long-lived and have historically stable production rates. In Michigan, as of December 31, 2009, we had proved reserves of approximately 522 Bcfe, of which 137 Bcfe were proved undeveloped reserves. We entered the Antrim Shale through our acquisition of DTE Gas & Oil, LLC from DTE Energy Company in June 2007. Since July 1, 2007, we have drilled 326 gross wells in the Antrim Shale. During the year ended December 31, 2009, we drilled 55 Antrim Shale wells, of which 4 were for our own account and 51 were funded through our investment partnerships.

Using our experience in the Antrim Shale, we entered the biogenic portion of the New Albany Shale in west central Indiana in July 2008 through several lease acquisitions and a farmout agreement. Today we control approximately 250,000 gross acres in this region. During the year ended December 31, 2009, we drilled 42 horizontal wells, all of which were funded through our investment partnerships. As of December 31, 2009, 21 of these wells were online with the remainder expected to be turned online during the first half of 2010.

In the southern part of the Appalachian Basin, we are also developing the Chattanooga Shale. With 480 operated wells as of December 31, 2009, we believe that we are the largest operator in Tennessee. Since March 2008, we have drilled 28 horizontal wells in the Chattanooga Shale, where previously we had predominately employed vertical drilling techniques. During the year ended December 31, 2009, we drilled 13 horizontal wells in the Chattanooga Shale. Going forward, we intend to pursue a horizontal drilling program funded by our investment partnerships. We have leased 180,545 gross acres in the play, all of which are undeveloped. In addition to the Chattanooga Shale, we are also pursuing a vertical well development of the shallower Monteagle and Fort Payne limestone formations.

ITEM 1A:

RISK FACTORS

Risks Relating to Our Business

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:

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the level of the domestic and foreign supply and demand;

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the price and level of foreign imports;

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the level of consumer product demand;

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weather conditions and fluctuating and seasonal demand;

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overall domestic and global economic conditions;

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

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

•

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

•

technological advances affecting energy consumption;

•

domestic and foreign governmental relations, regulations and taxation;

•

the impact of energy conservation efforts;

•

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

•

the price and availability of alternative fuels.

In the past, the prices of natural gas and oil have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2009, the NYMEX Henry Hub natural gas index price ranged from a high of $6.10 per MMBtu to a low of $1.83 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $81.04 per Bbl to a low of $33.98 per Bbl.

Economic conditions and instability in the financial markets could negatively impact our business.

Our operations are affected by the continued financial crisis and related turmoil in the global financial system. The consequences of an economic recession and the current credit crisis include a lower level of economic activity and increased volatility in energy prices. This has resulted in a decline in energy consumption and lower market prices for oil and natural gas, and may result in a reduction in drilling activity in our service areas. This event may adversely affect our revenues and ability to fund capital expenditures and, in turn, may impact the cash that we have available to fund our operations and pay debt service.

Continuing instability in the financial markets, as a result of recession or otherwise, has increased the cost of capital while the availability of funds from those markets has diminished significantly. This may affect our ability to raise capital and reduce the amount of cash available to fund our operations. We rely on our cash flow from operations and our credit facilities to execute our growth strategy and to meet our financial commitments and other short-term liquidity needs. We cannot be certain that additional capital will be available to us to the extent required and on acceptable terms. Disruptions in the capital and credit markets could negatively impact our access to liquidity needed for our business and impact our flexibility to react to changing economic and business conditions. Any disruption could require us to take measures to conserve cash until the markets stabilize or until we can arrange alternative credit arrangements or other funding for our business needs. Such measures could include reducing or delaying business activities, reducing our operations to lower expenses, and reducing other discretionary uses of cash.

The current economic situation could have an adverse impact on our producers, key suppliers or other customers, or on our lenders, causing them to fail to meet their obligations to us. Market conditions could also impact our derivative instruments. If a counterparty is unable to perform its obligations and the derivative instrument is terminated, our cash flow could be impacted. The uncertainty and volatility of the global financial crisis may have further impacts on our business and financial condition that we currently cannot predict or anticipate.

Unless we replace our reserves, our reserves and production will decline, which would reduce our cash flow from operations and income.

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, 2009 reserve report, our average annual decline rate for proved developed producing reserves is approximately 7.8% during the first five years, approximately 5.5% in the next five years and less than 5.7% thereafter. Because our total estimated proved reserves include proved undeveloped reserves at December 31, 2009, production will decline at this rate even if those proved undeveloped reserves are developed, and the wells produce as expected. This rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances. Thus, our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. Our ability to find and acquire additional recoverable reserves to replace current and future production at acceptable costs depends on our generating sufficient cash flow from operations and other sources of capital, principally our sponsored investment partnerships, all of which are subject to the risks discussed elsewhere in this section.

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Underground accumulations of natural gas and oil cannot be measured in an exact way. Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Our independent petroleum engineers prepare estimates of our proved reserves. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we make certain assumptions regarding future natural gas prices, production levels and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas and

oil attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Our PV-10 and standardized measure are 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 historical prices and costs. However, actual future net cash flows from our natural gas properties also will be affected by factors such as:

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actual prices we receive for natural gas;

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the amount and timing of actual production;

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the amount and timing of our capital expenditures;

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supply of and demand for natural gas; and

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changes in governmental regulations or taxation.

The timing of both our production and 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 and standardized measure, and our financial condition and results of operations. In addition, our reserves or PV-10 and standardized measure 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 and standardized measure.

A decrease in natural gas prices could subject our oil and gas properties to a non-cash impairment loss under generally accepted accounting principles.

Generally accepted accounting principles require oil and gas properties and other long-lived assets to be reviewed for impairment whenever events or changes in circumstances indicated 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. We test our oil and gas properties on a field-by-field basis, by determining if the historical cost of proved properties less the applicable 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 our own economic interests and our 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. We estimate prices based on current contracts in place at the impairment testing date, adjusted for basis differentials and market related information, including published future 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. Accordingly, futher declines in the price of natural gas may cause the carrying value of our oil and gas properties to exceed the expected future cash flows, and a non-cash impairment loss would be required to be recognized in the financial statements for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

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 crude 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. We also have exposure to interest rate fluctuations as a result of variable rate debt under our credit facility. We have entered into interest rate swap agreements to convert a portion of the variable rate debt to a fixed rate obligation, thereby reducing our exposure to market rate fluctuations.

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, crude oil and NGL production, we have reduced, but not eliminated, the potential effects of changing commodity prices on our cash flow from operations for those periods. Furthermore, while intended to help reduce the effects of volatile commodity prices, such transactions, depending on the hedging instrument used, may limit our potential gains if commodity 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 commodity prices, we may be exposed to the risk of financial loss. In addition, it is not always possible for us to engage in a derivative transaction that completely mitigates our exposure to commodity prices and interest rates. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices and interest rates for which we are unable to enter into a completely effective hedge transaction.

Due to the accounting treatment for derivative contracts, increases in prices for natural gas and crude oil could result in non-cash balance sheet reductions.

The accounting standards regarding hedge accounting are complex, and even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our financial statements may reflect volatility due to these derivatives, even when there is no underlying economic impact at that point. Due to the mark-to-market accounting treatment for these contracts, we could recognize incremental hedge liabilities between reporting periods resulting from increases in reference prices for natural gas and crude oil, which could result in our recognizing a non-cash loss in our accumulated other comprehensive income and a consequently non-cash decrease in our owner’s equity between reporting periods. Any such decrease could be substantial.

Our operations require substantial capital expenditures to increase our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, our revenues will decline.

The natural gas and oil industry is capital intensive. We intend to finance our future capital expenditures with capital raised through debt offerings, cash flow from operations, bank borrowings and our investment partnerships. If we are unable to obtain sufficient capital funds on satisfactory terms, we may be unable to increase or maintain our inventory of properties and reserve base, or be forced to curtail drilling or other activities. As a result, our revenues will decline and our ability to service debt may be diminished. If we do not make sufficient or effective expansion capital expenditures, including with funds from third-party sources, we will be unable to expand our business operations.

The scope and costs of the risks involved in making business acquisitions may prove greater than estimated at the time of the acquisition.

Any business acquisition involves potential risks, including, among other things:

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mistaken assumptions about revenues and costs, including synergies;

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significant increases in our indebtedness and working capital requirements;

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

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the assumption of unknown liabilities;

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limitations on rights to indemnity from the seller;

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

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increased demands on existing personnel;

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customer or key employee losses at the acquired businesses; and

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the failure to realize expected growth or profitability.

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

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 have an active, on-going program to identify potential acquisitions. The integration of previously independent operations 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, 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.

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.

We have limited experience in drilling wells in 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 in 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 in the Marcellus Shale. As of February 15, 2010, we have drilled 239 wells in the Marcellus Shale, 202 of which have been turned on-line, but those wells have been producing for only a short period of time. Other operators in the Appalachian Basin also have limited experience in drilling wells in 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 our other primary areas, which make 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.

Our drilling and production operations require adequate sources of water to facilitate the fracturing process and the disposal of that water. If we are unable to dispose of the water we use or remove from the strata at a reasonable cost and within applicable environmental rules, our ability to produce gas commercially and in commercial quantities could be impaired.

Much of our natural gas extraction activity utilizes a process called hydraulic fracturing, which results in water discharges that must be treated and disposed of in accordance with applicable regulatory requirements. Environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse affect on our operations and financial performance. Our ability to remove and dispose of water will affect our production and the cost of water treatment and disposal may affect our profitability. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct hydraulic fracturing or disposal of produced water, drilling fluids and other substances associated with the exploration, development and production of gas and oil.

We have a substantial amount of indebtedness which could adversely affect our financial position.

We currently have a substantial amount of indebtedness. As of February 1, 2010, we had total debt of approximately $768.4 million, consisting of $602.4 million of senior notes and $166.0 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 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 or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness. 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 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.

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. However, President Obama’s administration has proposed, among other tax changes, the repeal on January 1, 2011 of certain oil and gas tax benefits, including the repeal of the percentage depletion allowance, the election to expense intangible drilling costs, the passive activity exception for working interests and the marginal production tax credit. These proposals may or may not be adopted. The repeal of these oil and gas tax benefits, if adopted, would result in a substantial decrease in tax benefits associated with an investment in our investment partnerships. Also, President Obama’s administration proposes to raise the top federal income tax rate of 35% to 38.6% beginning with the 2011 taxable year which would increase limited partners’ potential federal income tax liability from their share of the partnership’s net taxable income, if any. These or other changes to federal tax law 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 2009, charges for severance taxes in the states in which we operate, other than Pennsylvania, were approximately $5.8 million. While Pennsylvania has historically not imposed a severance tax, with a focus on its budget deficit and the increasing exploration of the Marcellus Shale, legislation was proposed in 2008 to implement a tax of 5% of the value of natural gas at the wellhead plus $0.047 per Mcf. Though that proposal was not adopted, lawmakers may propose similar taxes in the future. 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 recent levels.

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. We have raised $351.9 million, $438.4 million and $363.3 million in calendar years 2009, 2008 and 2007, respectively. In the future, we may not be successful in raising funds through these investment partnerships at the same levels we have recently experienced, and we also may not be successful in increasing the amount of funds we raise. 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 maintaining or increasing the level of funds we have recently raised through our partnerships. In this event, we may need to obtain financing for our drilling activities on a less attractive basis than the financing we realized through these partnerships or we may determine to reduce drilling activity.

Our fee-based revenues may decline if we are unsuccessful in sponsoring investment partnerships.

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.

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, net of corresponding production costs, 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 we do not achieve the specified minimum return. We subordinated $3.9 million of our share of the revenues, net of corresponding production costs, from our investment partnerships for the year ended December 31, 2009. We did not subordinate our share of net revenues from March 2005 through December 31, 2008, but did subordinate $0.1 million in 2005 and $0.3 million 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 partnerships than we do. All of these challenges could make it more difficult for us to execute our growth strategy. We may not be able to compete successfully in the future in acquiring leasehold acreage or prospective reserves or in raising additional capital.

Furthermore, competition arises not only from numerous domestic and foreign sources of natural gas and oil but also from other industries that supply alternative sources of energy. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. Product availability and price are the principal means of competition in selling natural gas and oil. Many of our competitors possess greater financial and other resources than we do, 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 could decline.

In Appalachia, our natural gas is sold under contracts with various purchasers. During the year ended December 31, 2009, natural gas sales to Hess Corporation and Equitable Gas Company accounted for approximately 15% and 11% of our total Appalachian oil and gas revenues, respectively. In Michigan, during year ended December 31, 2009, gas under contracts to a former affiliate of Atlas Gas & Oil, which expire at various dates through 2012, accounted for approximately 42% 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 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 Laurel Mountain Midstream, LLC (“Laurel Mountain”). 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 flows.

Laurel Mountain gathers more than 71% of our current Appalachia production and approximately 35% 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 Laurel Mountain 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.

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

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

Because we handle natural gas and oil, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.

The operations of our wells and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:

•

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

•

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

•

Resource Conservation and Recovery Act (“RCRA”) and comparable state laws that impose requirements for the handling and disposal of waste, including produced waters, from our facilities; and

•

Comprehensive Environmental Response, Compensation, and Liability Act (“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 Marcellus Shale 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 Marcellus Shale acreage. As of December 31, 2009, we had identified over 4,564 potential drilling locations in the Marcellus Shale. 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 4,564 potential Marcellus Shale drilling locations, our independent petroleum engineering consultants have assigned proved reserves to the 226 proved undeveloped locations. Of the remaining Marcellus Shale 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 our Marcellus Shale 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 Marcellus Shale 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 Marcellus Shale drilling activities may materially differ from our anticipated drilling activities in that region.

Some of our undeveloped leasehold acreage is subject to leases that may expire in the near future.

As of December 31, 2009, leases covering approximately 52,505 of our 555,931 net undeveloped acres, or 9%, are scheduled to expire on or before December 31, 2010. An additional 14% and 16% are scheduled to expire in the years 2011 and 2012, respectively. If we are unable to renew these leases or any leases scheduled for expiration beyond December 31, 2010, 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.

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 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.

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 96 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 the partnerships to the extent that partnership assets or insurance proceeds are insufficient. We have agreed to indemnify each investor partner in the 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 us 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.

Lawsuits have been filed against us, certain officers and members of our board of directors and ATLS challenging the Merger, and any adverse judgment for monetary damages could have a material adverse effect on the operations of the combined company.

We, ATLS, and certain officers and directors of both companies are named as defendants in a consolidated purported class action lawsuit brought by our unitholders in Delaware Chancery Court generally alleging claims of breach of fiduciary duty in connection with the Merger. The complaint alleges inadequate disclosures in connection with our unitholder vote on the Merger. Plaintiffs filed a Verified Consolidated Class Action Complaint on July 1, 2009. The lawsuit originally sought monetary damages or injunctive relief, or both. However, on August 7, 2009, plaintiffs advised the Chancery Court by letter that they were not pursuing their motion for a preliminary injunction, and requested that the preliminary injunction hearing date be removed from the Court’s calendar. Around that time, plaintiffs advised counsel for the defendants that plaintiffs intended to continue to pursue the action for monetary damages after the Merger was completed. The Chancery Court approved the briefing schedule in mid-September and defendants filed a brief in support of their motion to dismiss on October 16, 2009. On December 15, 2009, plaintiffs filed an amended complaint alleging that the defendants breached their purported fiduciary duties to our public unitholders in connection with the negotiation of the Merger. In particular, the amended complaint alleged that the Merger was not entirely fair to our public unitholders, and that defendants conducted the Merger process in bad faith. On January 6, 2010, the Chancery Court granted the parties’ Scheduling Stipulation and Order, providing that defendants would have until February 18, 2010, to file a motion to dismiss the amended complaint; that plaintiffs’ answering brief in opposition would be due on or before May 3, 2010; and that defendants’ reply papers would be due on or before June 4, 2010. Defendants filed their opening brief in support of their motion to dismiss on February 18, 2010. Predicting the outcome of this lawsuit is difficult. An adverse judgment for monetary damages could have a material adverse effect on the operations of the combined company.

ITEM 1B:

UNRESOLVED STAFF COMMENTS

None.

ITEM 2:

PROPERTIES

A description of our properties has been included in Item 1.

ITEM 3:

LEGAL PROCEEDINGS

Following announcement of the Merger on April 27, 2009, five purported class actions were filed in Delaware Chancery Court and were later consolidated into a single complaint, In re Atlas Energy Resources, LLC Unitholder Litigation, C.A. No. 4589-VCN (the “Consolidated Action”) filed on July 1, 2009 (the “Consolidated Complaint”). The Consolidated Complaint named ATLS and our various officers and directors as defendants (the “Defendants”), alleged violations of fiduciary duties in connection with the Merger, and requested injunctive relief and damages. On August 7, 2009, plaintiffs advised the Delaware Chancery Court by letter that they would not pursue their motion for a preliminary injunction, which had been scheduled for a hearing on September 4, 2009, and requested that the September 4 hearing date be removed from the Court’s calendar. On October 16, 2009, Defendants filed a motion to dismiss the Consolidated Complaint. On December 15, 2009, plaintiffs filed an Amended Complaint (the “Amended Complaint”). On January 6, 2010, the Delaware Chancery Court granted the parties’ Scheduling Stipulation and Order, providing that Defendants would have until February 18, 2010, to file a motion to dismiss the Amended Complaint; that plaintiffs’ answering brief in opposition would be due on or before May 3, 2010; and that Defendants’ reply papers would be due on or before June 4, 2010. Defendants filed their opening brief in support of their motion to dismiss on February 18, 2010. The Amended Complaint alleges that Defendants breached their purported fiduciary duties to our public unitholders in connection with the negotiation of the Merger. In particular, plaintiffs allege that the Merger was not entirely fair to our public unitholders, and that Defendants conducted the Merger process in bad faith.

Predicting the outcome of this lawsuit is difficult. An adverse judgment for monetary damages could have a material adverse effect on our operations. Based on the facts known to date, Defendants believe that the claims asserted against them in this lawsuit are without merit, and will continue to defend themselves vigorously against the claims.

In June 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 alleges that Miller breached a contract to assign to CNX certain leasehold rights (“Leases”) representing approximately 30,000 acres in Campbell County, Tennessee and that Atlas America, LLC 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, LLC could not have tortuously interfered with the contract. The Chancery Court dismissed all claims against Atlas America, LLC; however, CNX has appealed this decision.

We are also 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 operations.

PART II

ITEM 4:

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Prior to the delisting of our common units on September 30, 2009 in connection with the Merger, our common units were 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 for the prior two years through September 29, 2009, when the Merger was consummated.


	High		Low		Distributions Declared⁽¹⁾
Year ended December 31, 2009
Fourth quarter	$	–	$	–	$	–
Third quarter	$	30.19	$	18.42	$	–
Second quarter	$	22.78	$	10.88	$	–
First quarter	$	16.50	$	8.32	$	–

Year ended December 31, 2008
Fourth quarter	$	26.50	$	10.23	$	0.61
Third quarter	$	40.25	$	22.41	$	0.61
Second quarter	$	45.40	$	31.76	$	0.61
First quarter	$	34.87	$	23.65	$	0.59

⁽¹⁾

Effective April 1, 2009, we suspended further distributions due to the announcement of our intent to merge with ATLS.

As of February 26, 2010, there are no Class B common units outstanding and there are 1,293,496 Class A common units solely held by ATLS.

Our credit facility limits the amount of cash dividends we may pay ATLS to (a) amounts equal to ATLS’s income tax liability attributable to our net income at the highest marginal rate and (b) up to $40 million each fiscal year, assuming there has been no default under the credit facility, provided that up to $20 million may be carried over from one fiscal year to the next fiscal year.

For information concerning the securities authorized for issuance under our incentive plan, see Note 14 under “Item 7: Financial Statements and Supplementary Data”.

ITEM 5.

SELECTED FINANCIAL DATA

Since we, a registrant and wholly-owned subsidiary of another registrant, have met the requirements within General Instruction I(1) of Form 10-K, Item 5, Selected Financial Data, has been omitted from this report.

ITEM 6:

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this report. Since we, a registrant and wholly-owned subsidiary of another registrant, have met the requirements within General Instruction I(1) of Form 10-K, Item 6 has been presented in a reduced disclosure format pursuant to the guidelines within General Instruction I(1).

RESULTS OF OPERATIONS

GAS AND OIL PRODUCTION

Production Profile. Currently, we have focused our natural gas production operations in various shale plays in the northeastern and Midwestern United States. Notably, we are one of the leading producers in the Marcellus Shale, a rich, organic shale located in the Appalachia basin. The portion of the Marcellus Shale in southwestern Pennsylvania in which we focus our drilling is high-pressured and generally contains dry, pipeline-quality natural gas. In addition, we also are a leading natural gas producer in Michigan through our activity in the Antrim Shale, a biogenic shale play with a long-lived and shallow decline profile. We have also established a position in the New Albany Shale in southwestern Indiana, where we produce out of the biogenic region of the shale similar to the Antrim Shale. We also produce from the Chattanooga Shale in northeastern Tennessee, which enables us to access other formations in that region such as the Monteagle and Ft. Payne Limestone.

Production Volumes. The following table presents our total net gas and oil production volumes and production per day during the years ended December 31, 2009 and 2008:


	Years Ended December 31,
	2009		2008
Production:⁽¹⁾⁽²⁾
Appalachia:⁽³⁾
Natural gas (MMcf)	14,568		12,086
Oil (000’s Bbls)	194		155

Total (MMcfe)	15,734		13,014

Michigan/Indiana:
Natural gas (MMcf)	21,190		21,816
Oil (000’s Bbls)	5		4

Total (MMcfe)	21,221		21,839

Total:
Natural gas (MMcf)	35,758		33,902
Oil (000’s Bbls)	199		159

Total (MMcfe)	36,955		34,853


Production per day:⁽¹⁾⁽²⁾
Appalachia:⁽³⁾
Natural gas (Mcfd)	39,912		33,023
Oil (Bpd)	532	⁽⁴⁾	423

Total (Mcfed)	43,106		35,558

Michigan/Indiana:
Natural gas (Mcfd)	58,056		59,606
Oil (Bpd)	14	⁽⁴⁾	11

Total (Mcfed)	58,140		59,672

Total:
Natural gas (Mcfd)	97,968		92,629
Oil (bpd)	546	⁽⁴⁾	434

Total (Mcfed)	101,246		95,230

⁽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⁾	“MMcf” represents million cubic feet; “MMcfe” represent million cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day.

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

⁽⁴⁾	Includes NGL production volume of 101 bpd for the year ended December 31, 2009.

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 December 31, 2009. The following table presents our production revenues and average sales prices for our natural gas and oil production for the years ended December 31, 2009 and 2008, along with our average production costs, taxes, and transmission and compression costs in each of the reported periods:


	Years Ended December 31,
	2009		2008
Production revenues (in thousands):
Appalachia:⁽¹⁾
Natural gas revenue	$	105,642	$	113,595
Oil revenue		12,518		14,340

Total revenues	$	118,160	$	127,935

Michigan/Indiana:
Natural gas revenue	$	159,832	$	183,550
Oil revenue		192		365

Total revenues	$	160,024	$	183,915

Total:
Natural gas revenue	$	265,474	$	297,145
Oil revenue		12,710		14,705

Total revenues	$	278,184	$	311,850


Average sales price:⁽²⁾
Natural gas (per Mcf):
Total realized price, after hedge⁽³^{) (}⁴⁾	$	7.67	$	9.13
Total realized price, before hedge⁽³^{) (}⁴⁾	$	4.07	$	9.23
Oil (per Bbl):
Total realized price, after hedge	$	70.81	$	92.35
Total realized price, before hedge	$	57.26	$	91.79

Production costs (per Mcfe):⁽²⁾
Appalachia:⁽¹⁾
Lease operating expenses⁽⁵⁾	$	1.06	$	1.03
Production taxes		0.03		0.03
Transportation and compression		0.70		0.87

	$	1.79	$	1.93

Michigan/Indiana:
Lease operating expenses	$	0.72	$	0.75
Production taxes		0.25		0.54
Transportation and compression		0.25		0.29

	$	1.22	$	1.58

Total:
Lease operating expenses⁽⁵⁾	$	0.86	$	0.85
Production taxes		0.16		0.35
Transportation and compression		0.44		0.51

	$	1.46	$	1.71

⁽¹⁾

Appalachia includes our operations located in Pennsylvania, Ohio, New York, West Virginia and Tennessee.

⁽²⁾

“Mcf” represents thousand cubic feet; “Mcfe” represents thousand cubic feet equivalents; and “Bbl” represents barrels.

⁽³⁾

Excludes the impact of certain allocations of production revenue to investor partners within our investment partnerships for the year ended December 31, 2009. There were no allocations of production revenue to investor partners within our investment partnerships for the year ended December 31, 2008. Including the effect of these allocations, the average realized gas sales price for the year ended December 31, 2009 was $7.50 per Mcf ($3.91 per Mcf before the effects of financial hedging).

⁽⁴⁾

Includes cash proceeds of $2.8 million and $12.4 million for the years ended December 31, 2009 and 2008, respectively, received from the settlement of ineffective derivative gains associated with the acquisition of our Michigan operations, but not reflected in the consolidated statement of operations for the respective periods.

⁽⁵⁾

Excludes the effects of our proportionate share of lease operating expenses associated with certain allocations of production revenue to investor partners within our investment partnerships for the year ended December 31, 2009. There were no allocations of production revenue to investor partners within our investment partnerships for the year ended December 31, 2008. Including the effects of these costs, lease operating expenses per Mcfe for the year ended December 31, 2009 for Appalachia were $0.94 per Mcfe (total production costs per Mcfe were $1.67) and in total they were $0.81 per Mcfe (total production costs per Mcfe were $1.41).

Year Ended December 31, 2009 Compared with the Year Ended December 31, 2008. Total natural gas revenues were $265.5 million for the year ended December 31, 2009, a decrease of $31.6 million from $297.1 million for the year ended December 31, 2008. This decrease consisted of a $39.9 million decrease attributable to lower realized natural gas prices and $5.9 million of gas revenues subordinated to the investor partners within our investment partnerships, partially offset by a $14.2 million increase attributable to a higher natural gas production volumes. Appalachian production volumes increased 6.9 MMcfd to 39.9 MMcfd for the year ended December 31, 2009 when compared to the prior year, which was principally attributable to the increase in production we received from our Marcellus Shale wells and other wells drilled during 2009 as they were connected to gas gathering facilities and transportation pipelines. Total oil revenues were $12.7 million for the year ended December 31, 2009, a decrease of $2.0 million from $14.7 million for the prior year. This decrease resulted primarily from a $4.3 million decrease associated with lower average realized oil prices, partially offset by a $2.3 million increase associated with higher production volumes.

Appalachia production costs were $26.2 million for the year ended December 31, 2009, an increase of $1.1 million from $25.1 million for the year ended December 31, 2008. This increase was principally due to a $2.7 million increase in water hauling and disposal costs, partially offset by a decrease of $2.0 million associated with our proportionate share of lease operating expenses associated with our revenue that was subordinated to the investor partners within our investment partnerships. Michigan/Indiana production costs were $25.8 million for the year ended December 31, 2009, a decrease of $8.7 million from $34.5 million for the prior year. This decrease was primarily attributable to a $6.5 million decrease in production taxes due to a state reduction in the production tax rate on January 1, 2009 and a $1.5 million decrease in transportation costs attributable to production.

PARTNERSHIP MANAGEMENT

Well Construction and Completion

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 presents the number of gross and net development wells we drilled for us and our investment partnerships during the years ended December 31, 2009 and 2008. We did not drill any exploratory wells during the years ended December 31, 2009 and 2008:


	Years Ended December 31,
	2009	2008
Gross wells drilled:
Appalachia	187	830
Michigan/Indiana	97	173

Total	284	1,003


Net wells drilled:
Appalachia	170	786
Michigan/Indiana	85	143

Total	255	929


Our share of net wells drilled⁽¹⁾:
Appalachia	56	279
Michigan/Indiana	25	140

Total	81	419

Gross dry wells drilled:
Appalachia	—	8
Michigan/Indiana	4	—

Total	4	8


Net dry wells drilled:
Appalachia	—	3
Michigan/Indiana	4	—

Total	4	3

⁽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.

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,
	2009			2008
Average construction and completion per well:
Revenue	$	1,531		$	535
Costs		(1,299	)		(463	)

Gross profit	$	232		$	72


Gross profit margin	$	56,499		$	55,427


Net wells drilled within investment partnerships:⁽¹⁾
Marcellus Shale		94			81
Chattanooga Shale		15			11
Michigan/Indiana		77			3
Other - shallow		57			681

		243			776

⁽¹⁾

Includes wells drilled for which revenue is recognized on a percentage of completion basis.

Well construction and completion segment margin was $56.5 million for the year ended December 31, 2009, an increase of $1.1 million from $55.4 million for the year ended December 31, 2008. This increase was due to a $39.2 million increase associated with an increase in the gross profit per well, partially offset by a $38.1 million decrease associated with a reduction in the number of wells drilled within the investment partnerships. Since our drilling contracts with the investment partnerships are on a “cost-plus” basis (typically cost-plus 18%), an increase in our average cost per well also results in a proportionate increase in our average revenue per well, which directly affects the number of wells we drill. Average cost and revenue per well have increased due to a shift from drilling less expensive shallow wells to more expensive deep or horizontal shale wells in both Appalachia and Michigan/Indiana during the year ended December 31, 2009 in comparison to the prior year.

Our consolidated balance sheet at December 31, 2009 includes $122.5 million of “liabilities associated with drilling contracts” for funds raised by our investment partnerships that have not been applied to the completion of wells due to the timing of drilling operations, and thus had not been recognized as well construction and completion revenue on our consolidated statements of operations. We expect to recognize this amount as revenue during the first quarter of 2010. During the year ended December 31, 2009, we raised $351.9 million from investors in our investment partnerships.

Administration and Oversight

Administration and oversight fee revenues represents supervision and administrative fees earned for the drilling and subsequent ongoing management of wells for our investment partnerships. Administration and oversight fee revenues were $15.6 million for the year ended December 31, 2009, a decrease of $3.8 million from $19.4 million for the year ended December 31, 2008. This decrease was primarily the result of fewer wells drilled during 2009 in comparison to the prior year, partially offset by an increase in the number of Marcellus Shale wells drilled, for which we earn higher fees from our partnership management activities in comparison to conventional wells.

Well Services

Well service revenue and expenses represent the monthly operating fees we charge and the work our service company performs for our investment partnership wells during the drilling and completing phase as well as ongoing maintenance of these wells and other wells in which we serve as operator.

Well services revenues were $20.2 million for the year ended December 31, 2009, a decrease of $0.3 million from $20.5 million for the year ended December 31, 2008. This decrease was primarily attributable to the slowdown in drilling of shallow wells for our investment partnerships, partially offset by an increase in well operating revenues for the investment partnership wells put into operation during 2009. Well services expenses were $9.3 million for year ended December 31, 2009, a decrease of $1.4 million from $10.7 million for the year ended December 31, 2008. This decrease was primarily attributable to a decrease in labor costs associated with drilling fewer, but more productive, wells for our investment partnerships during the current period.

Gathering

We charge gathering fees to our investment partnership wells that are connected to Laurel Mountain’s Appalachian gathering systems. On May 31, 2009, Atlas Pipeline Partners L.P. (“APL”), our affiliate, contributed its Appalachian gathering systems to Laurel Mountain, a joint venture in which APL retained a 49% ownership interest. Under new gas gathering agreements with Laurel Mountain entered into upon formation of the joint venture, we are obligated to pay to Laurel Mountain all of the gathering fees we collect from the investment partnerships. During the period from January 1, 2009 to June 1, 2009, we were required to remit these gathering fees to ATLS, who in turn remitted them to APL.

Pursuant to these gas gathering agreements with Laurel Mountain, we generally pay a gathering fee equal to 16% of the realized natural gas sales price (adjusted for the settlement of natural gas derivative instruments). However, in most of our direct investment partnerships, we collect a gathering fee of 13% of the realized natural gas sales price per the respective partnership agreement. As a result, our Appalachian gathering expenses within our partnership management segment will generally exceed the revenues collected from the investment partnerships by approximately 3%.

For the years ended December 31, 2009 and 2008, we received $21.0 million and $20.7 million, respectively, in gathering fees collected from our investment partnerships and were obligated to remit $26.8 million and $19.5 million, respectively, in gathering expense. The increase in net gathering expense between periods was principally due to the new gathering agreement we entered into with Laurel Mountain on June 1, 2009, whereby we agreed to pay an additional amount equal to the excess of the gathering fees collected from the investment partnerships up to an amount equal to approximately 16% of the natural gas sales price. Prior to June 1, 2009, ATLS was responsible for this amount.

OTHER COSTS AND EXPENSES

General and Administrative

Total general and administrative expenses, including amounts reimbursed to affiliates, increased to $58.6 million for the year ended December 31, 2009 compared with $44.7 million for the year ended December 31, 2008. The $13.9 million increase was principally attributable to $7.8 million of professional fees incurred related to the Merger and a $4.4 million increase in expenses related to wages and other corporate activities due to the growth of our business.

Depreciation, Depletion and Amortization

Total depreciation, depletion and amortization increased to $108.3 million for the year ended December 31, 2009 compared with $95.4 million for the prior year, due primarily to an increase in our depletable basis and production volumes.

The following table presents our depletion expense per Mcfe for our Appalachia and Michigan/Indiana regions for the years ended December 31, 2009 and 2008:


	Years Ended December 31,
	2009		2008
Depletion expense (in thousands):
Appalachia	$	46,265	$	37,181
Michigan/Indiana		57,723		54,810

Total	$	103,988	$	91,991

Depletion expense as a percentage of gas and oil production		37%		29%

Depletion per Mcfe:
Appalachia	$	2.94	$	2.86
Michigan/Indiana	$	2.72	$	2.51
Total	$	2.81	$	2.64

Depletion expense varies from period to period and is directly affected by 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. Increases in our depletable basis and production volumes caused depletion expense to increase $12.0 million to $104.0 million for the year ended December 31, 2009 compared with $92.0 million for the year ended December 31, 2008. Our depletion expense of oil and gas properties as a percentage of oil and gas revenues was 37% for the year ended December 31, 2009, compared with 29% for the year ended December 31, 2008. Depletion expense per Mcfe was $2.81 for the year ended December 31, 2009, an increase of $0.17 per Mcfe from $2.64 for year ended December 31, 2008.

Interest Expense

Total interest expense increased to $65.0 million for the year ended December 31, 2009 as compared with $56.3 million for the year ended December 31, 2008. Our $8.7 million increase was principally attributable to a $17.5 million increase associated with the issuances of our senior unsecured notes in July 2009, May 2008 and January 2008, partially offset by a $7.1 million decrease associated with borrowings under our credit facility and a $3.9 million increase in capitalized interest. The increase in interest expense related to our senior notes was due to the issuance of $200.0 million of 12.125% senior notes in July 2009. Proceeds from the issuance of senior notes were used to repay outstanding borrowings under our credit facility, which principally resulted in the $7.1 million reduction in related interest expense.

Asset Impairment

During the year ended December 31, 2009, we recognized a $156.4 million asset impairment related to oil and gas properties within property, plant and equipment on our consolidated balance sheet for our shallow natural gas wells in the Upper Devonian shale. This impairment related to the carrying amount of these oil and gas properties being in excess of our estimate of their fair value at December 31, 2009. The estimate of fair value of these oil and gas properties was impacted by, among other factors, the deterioration of natural gas prices.

Loss on Asset Sales

Loss on asset sales of $6.4 million for the year ended December 31, 2009 represented the loss recognized on our sale of assets totaling $10.0 million to Laurel Mountain in May 2009.

LIQUIDITY AND CAPITAL RESOURCES

General

Our primary sources of liquidity are cash generated from operations, capital raised through investment partnerships and borrowings under our credit facility. Our primary cash requirements, in addition to normal operating expenses, are for debt service and capital expenditures. In general, we expect to fund:

•

capital expenditures and working capital deficits through the retention of cash, additional borrowings and capital raised through investment partnerships; and

•

debt principal payments through additional borrowings as they become due.

Recent instability in the financial markets, as a result of recession or otherwise, has increased the cost of capital while the availability of funds has diminished significantly. This may affect our ability to raise capital and reduce the amount of cash available to fund our operations. We rely on cash flow from operations and our credit facility to execute our growth strategy and to meet our financial commitments and other short-term liquidity needs. We cannot be certain that additional capital will be available to us to the extent required and on acceptable terms. We believe that we will have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve month period. However, we are subject to business, operational and other risks that could adversely affect our cash flow. We may supplement our cash generation with proceeds from financing activities, including borrowings under our credit facility and other borrowings, the sale of assets and other transactions.

Revolving Credit Facility

At December 31, 2009, we had a credit facility with a syndicate of banks with a borrowing base of $575.0 million that matures in June 2012. The borrowing base is redetermined semiannually on April 1 and October 1 subject to changes in oil and gas reserves and is automatically reduced by 25% of the stated principal of any senior unsecured notes we issue. Up to $50.0 million of the credit facility may be in the form of standby letters of credit, of which $1.2 million was outstanding at December 31, 2009. The facility is secured by substantially all of our assets and is guaranteed by each of our subsidiaries. In July 2009, the credit agreement was amended to, among other things, permit the Merger and to allow us to distribute to us (a) amounts equal to ATLS’s income tax liability attributable to our net income at the highest marginal rate and (b) up to $40.0 million per year and, to the extent that we distribute less than that amount in any year, it may carry over up to $20.0 million for use in the next year.

The events which constitute an event of default for our credit facility are customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against us 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. We are in compliance with these covenants as of December 31, 2009. The credit facility also 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 less than or equal to 3.75 to 1.0 commencing January 1, 2009, 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 1.7 to 1.0 and our ratio of total debt to EBITDA was 2.7 to 1.0 at December 31, 2009.

ITEM 6A:

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 natural 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 the market risk sensitive instruments were entered into for purposes other than trading.

General

All of our assets and liabilities are denominated in U.S. dollars, and as a result, we do not have exposure to currency exchange risks.

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 periodical use of derivative financial instruments such as forward contracts and interest rate cap and swap agreements. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on December 31, 2009. Only the potential impact of hypothetical assumptions is analyzed. The analysis does not consider other possible effects that could impact our business.

Current market conditions elevate our concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us, if any. The counterparties related to our commodity and interest-rate derivative contracts are banking institutions, who 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 their contracts and believe our exposure to non-performance is remote.

Interest Rate Risk. At December 31, 2009, we had an outstanding balance of $184.0 million on our senior secured revolving credit facility with a borrowing base of $575.0 million. At December 31, 2009, 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 3.1% 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 agreement is effective as of December 31, 2009 and expires on January 31, 2011.

Holding all other variables constant, including the effect of interest rate derivatives, a hypothetical 100 basis-point or 1% change in variable interest rates would change our interest expense by $0.3 million.

Commodity Price Risk. Our market risk exposure to commodities is due to the fluctuations in the price of natural gas and oil and the impact those price movements have on our financial results. To limit our exposure to changing natural gas and oil prices, we use financial derivative instruments for a portion of our future natural gas and oil production.

Holding all other variables constant, including the effect of commodity derivatives, a 10% change in the average price of natural gas and oil would result in a change to our operating income for the twelve-month period ending December 31, 2010 of approximately $9.5 million.

Realized pricing of our oil and natural gas production is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production. Pricing for natural

gas and oil production has been volatile and unpredictable for many years. To limit our exposure to changing natural gas prices, we enter into natural gas and oil swap and costless collar option contracts. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index.

At December 31, 2009, we had the following interest rate and commodity derivatives:

Interest Fixed Rate Swap


Term	Notional Amount		Option Type	Contract Period Ended December 31,
January 2008 – January 2011	$	150,000,000	Pay 3.1% - Receive LIBOR	2010
				2011

Natural Gas Fixed Price Swaps


Production Period Ending December 31,		Volumes	Average Fixed Price
		(mmbtu)⁽¹⁾	(per mmbtu)⁽¹⁾
2010		41,360,004	$	7.337
2011		24,140,004	$	6.982
2012		19,680,000	$	7.223
2013		13,260,000	$	7.082
Natural Gas Costless Collars
Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap
		(mmbtu)⁽¹⁾	(per mmbtu)⁽¹⁾
2010	Puts purchased	3,360,000	$	7.839
2010	Calls sold	3,360,000	$	9.007
2011	Puts purchased	12,840,000	$	6.449
2011	Calls sold	12,840,000	$	7.630
2012	Puts purchased	9,780,000	$	6.512
2012	Calls sold	9,780,000	$	7.714
2013	Puts purchased	10,740,000	$	6.584
2013	Calls sold	10,740,000	$	7.792
Crude Oil Fixed Price Swaps
Production Period Ending December 31,		Volumes	Average Fixed Price
		(Bbl)⁽¹⁾	(per Bbl)⁽¹⁾
2010		48,900	$	97.400
2011		42,600	$	77.460
2012		33,500	$	76.855
2013		10,000	$	77.360

Crude Oil Costless Collars


Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap
		(Bbl)⁽¹⁾	(per Bbl)⁽¹⁾
2010	Puts purchased	31,000	$	85.000
2010	Calls sold	31,000	$	112.918
2011	Puts purchased	27,000	$	67.223
2011	Calls sold	27,000	$	89.436
2012	Puts purchased	21,500	$	65.506
2012	Calls sold	21,500	$	91.448
2013	Puts purchased	6,000	$	65.358
2013	Calls sold	6,000	$	93.442

⁽¹⁾	“Mmbtu” represents million British Thermal Units; “Bbl” represents barrels.

ITEM 7:

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholder

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, 2009 and 2008, and the related consolidated statements of operations, comprehensive income, owner’s/members’ equity, and cash flows for each of the three years in the period ended December 31, 2009. 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 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 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, 2009, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 26, 2010 expressed an unqualified opinion on the effectiveness of internal control over financial reporting.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

February 26, 2010

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)


	December 31,
	2009		2008
ASSETS
Current assets:
Cash and cash equivalents	$	3,640	$	5,655
Accounts receivable		71,058		69,411
Current portion of derivative receivable from Partnerships		270		3,022
Current portion of derivative asset		73,066		107,766
Subscriptions receivable from Partnerships		47,275		44,250
Prepaid expenses and other		15,621		14,714

Total current assets		210,930		244,818
Property, plant and equipment, net		1,871,418		1,963,891
Intangible assets, net		2,873		3,838
Goodwill, net		35,166		35,166
Long-term derivative asset		58,930		69,451
Advances to affiliates		5,689		—
Other assets, net		23,747		18,403

	$	2,208,753	$	2,335,567

LIABILITIES AND OWNER’S/MEMBERS’ EQUITY
Current liabilities:
Accounts payable		76,993		74,262
Accrued interest		29,245		19,878
Accrued liabilities		14,308		5,872
Liabilities associated with drilling contracts		122,532		141,133
Accrued well drilling and completion costs		89,261		43,946
Current portion of derivative payable to Partnerships		22,382		34,932
Current portion of derivative liability		4,652		12,829

Total current liabilities		359,373		332,852
Long-term debt, less current portion		786,390		873,655
Long-term derivative payable to Partnerships		22,380		22,581
Asset retirement obligation		51,813		48,136
Long-term derivative liability		14,315		10,771
Other long-term liabilities		—		6,337
Advances from affiliates		—		1,712
Commitments and contingencies

Owner’s/members’ equity:
Class B members’ interests		—		932,804
Class A member’s interest		—		6,257
Owner’s equity		873,170		—
Accumulated other comprehensive income		101,143		100,275

		974,313		1,039,336
Non-controlling interests		169		187

Total owner’s/members’ equity		974,482		1,039,523

	$	2,208,753	$	2,335,567

See accompanying notes to consolidated financial statements

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)


	Years Ended December 31,
	2009			2008			2007
Revenues:
Gas and oil production	$	278,184		$	311,850		$	180,125
Well construction and completion		372,045			415,036			321,471
Gathering		21,008			20,670			14,314
Administration and oversight		15,613			19,362			18,138
Well services		20,191			20,482			17,592
Gain on mark-to-market derivatives		—			—			26,257
Other, net		592			1,255			770

Total revenues		707,633			788,655			578,667

Costs and expenses:
Gas and oil production		51,941			59,579			32,193
Well construction and completion		315,546			359,609			279,540
Gathering		26,810			19,539			13,995
Well services		9,330			10,654			9,062
General and administrative		58,570			44,658			39,414
Depreciation, depletion and amortization		108,293			95,434			56,942
Asset impairment		156,359			—			—
(Gain) loss on asset sales		6,435			32			(111	)

Total costs and expenses		733,284			589,505			431,035

Operating income (loss)		(25,651	)		199,150			147,632

Interest expense		(64,951	)		(56,306	)		(30,096	)

Net income (loss)		(90,602	)		142,844			117,536
Income attributable to non-controlling interests		(63	)		(64	)		(32	)

Net income (loss) attributable to owner’s/members’ interests	$	(90,665	)	$	142,780		$	117,504

Allocation of net income (loss) attributable to owner’s/members’ interests:
Portion allocable to members’ interests (period prior to merger on September 29, 2009)	$	42,340		$	142,780		$	117,504
Portion allocable to owner’s interest (period subsequent to merger on September 29, 2009)		(133,005	)		—			—

Net income (loss) attributable to owner’s/members’ interests	$	(90,665	)	$	142,780		$	117,504

Allocation of net income attributable to members’ interests:
Class A member’s units	$	(7,109	)	$	9,062		$	4,099
Class B members’ units		49,449			133,718			113,405

Net income attributable to members’ interests	$	42,340		$	142,780		$	117,504

Net income attributable to Class B members per unit:
Basic	$	0.77		$	2.12		$	2.30
Diluted	$	0.77		$	2.11		$	2.28

Weighted average Class B members’ units outstanding:
Basic		63,381			62,409			48,844
Diluted		63,405			62,767			49,152

See accompanying notes to consolidated financial statements

ATLAS ENERGY RESOURCES, LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)


	Years Ended December 31,
	2009			2008			2007
Net income (loss)	$	(90,602	)	$	142,844		$	117,536
Income attributable to non-controlling interests		(63	)		(64	)		(32	)

Net income (loss) attributable to owner’s/members’ interests		(90,665	)		142,780			117,504
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges		116,360			79,478			(8,582	)
Less: reclassification adjustment for realized losses (gains) in net income		(115,492	)		25,899			(17,608	)

Total other comprehensive income (loss)		868			105,377			(26,190	)

Comprehensive income (loss)	$	(89,797	)	$	248,157		$	91,314

See accompanying notes to consolidated financial statements

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OWNER’S/MEMBERS’ EQUITY

(in thousands, except share data)


	Owner’s Equity			Class A Units					Class B Common Units					Class D Units					Accumulated Other Comprehensive Income (Loss)			Non- Controlling Interests			Total Owner’s / Members’ Equity


				Shares		Amount			Shares		Amount			Shares		Amounts
Balance, January 1, 2007	$	—		748,456		$	3,825		36,626,746		$	187,769		—		$	—		$	21,088		$	—		$	212,682
Units issued		—		490,530			—		7,380,801			181,179		16,702,827			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	)
Unit-based compensation		—		—			—		—			4,684		—			—			—			—			4,684
Other comprehensive loss		—		—			—		—			—		—			—			(26,190	)		—			(26,190	)
Conversion of Class D units		—		—			—		16,702,827			415,845		(16,702,827	)		(415,845	)		—			—			—
Non-controlling interests’ capital contributions		—		—			—		—			—		—			—			—			210			210
Net income		—		—			4,099		—			104,689		—			8,716			—			32			117,536

Balance, December 31, 2007		—		1,238,986			5,770		60,710,374			835,447		—			—			(5,102	)		242			836,357
Units issued		—		54,500			—		2,670,375			107,697		—			—			—			—			107,697
Distributions to members		—		—			(8,576	)	—			(148,104	)	—			—			—			—			(156,680	)
Distributions paid on unissued units under incentive plan		—		—			—		—			(1,438	)	—			—			—			—			(1,438	)
Unit-based compensation		—		—			—		—			5,485		—			—			—			—			5,485
Other comprehensive income		—		—			—		—			—		—			—			105,377			—			105,377
Distributions to non-controlling interests		—		—			—		—			—		—			—			—			(119	)		(119	)
Net income		—		—			9,063		—			133,717		—			—			—			64			142,844

Balance at December 31, 2008		—		1,293,486			6,257		63,380,749			932,804		—			—			100,275			187			1,039,523
Units issued		—		10			—		500			(54	)	—			—			—			—			(54	)
Distributions to members		—		—			(2,476	)	—			(38,663	)	—			—			—			—			(41,139	)
Distributions paid on unissued units under incentive plan		—		—			—		—			(443	)	—			—			—			—			(443	)
Distributions to non-controlling interests		—		—			—		—			—		—			—			—			(81	)		(81	)
Unit-based compensation		—		—			—		—			3,386		—			—			—			—			3,386
Other comprehensive income		—		—			—		—			—		—			—			868			—			868
Reversal of management incentive distribution payable		—		—			8,024		—			—		—			—			—			—			8,024
Net income (loss) attributable to members’ interests prior to September 29, 2009		—		—			(7,109	)	—			49,449		—			—			—			44			42,384
Merger with Atlas Energy, Inc.		951,175		(1,293,496	)		(4,696	)	(63,381,249	)		(946,479	)	—			—			—			—			—
Contribution from owner		55,000		—			—		—			—		—			—			—			—			55,000
Net income (loss) attributable to owner subsequent to merger on September 29, 2009		(133,005	)	—			—		—			—		—			—			—			19			(132,986	)

Balance at December 31, 2009	$	873,170		—		$	—		—		$	—		—		$	—		$	101,143		$	169		$	974,482

See accompanying notes to consolidated financial statements

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Years Ended December 31,
	2009			2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(90,602	)	$	142,844		$	117,536
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		108,293			95,434			56,942
Asset impairment		156,359			—			—
Amortization of deferred finance costs		4,187			2,823			3,040
Adjustment to reflect cash impact of derivatives		31,334			12,430			(14,000	)
Non-cash compensation expense		3,386			5,485			4,684
(Gain) loss on asset sales and dispositions		6,435			(32	)		111
Equity (income) loss in unconsolidated company		(553	)		(233	)		158
Distributions paid to non-controlling interests		(81	)		(119	)		—
Changes in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable and prepaid expenses and other		(11,060	)		(15,716	)		1,956
Accounts payable and accrued liabilities		4,094			37,910			(1,514	)
Liabilities associated with drilling contracts		(18,601	)		(21,134	)		38,697
Liabilities associated with well drilling and completion costs		45,315			(3,088	)		27,806

Net cash provided by operating activities		238,506			256,604			235,416

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(168,060	)		(347,656	)		(201,169	)
Net cash paid for acquisitions		—			—			(1,272,518	)
Net proceeds from asset sales		10,320			62			1,092
Other		(6	)		(195	)		(273	)

Net cash used in investing activities		(157,746	)		(347,789	)		(1,472,868	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility		353,000			493,000			951,891
Repayments under credit facility		(636,000	)		(766,030	)		(211,929	)
Net proceeds from issuance of debt		196,232			407,125			—
Capital contribution from owner		55,000			—			—
Net proceeds from issuance of Class B members units		—			107,697			597,495
Distributions paid to members		(39,452	)		(151,126	)		(69,282	)
Advances to affiliates		(1,712	)		(6,984	)		(3,806	)
Deferred financing costs and other		(9,843	)		(12,100	)		(10,492	)

Net cash provided by (used in) financing activities		(82,775	)		71,582			1,253,877

Net change in cash and cash equivalents		(2,015	)		(19,603	)		16,425
Cash and cash equivalents, beginning of year		5,655			25,258			8,833

Cash and cash equivalents, end of year	$	3,640		$	5,655		$	25,258

See accompanying notes to consolidated financial statements

ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 — BASIS OF PRESENTATION

Atlas Energy Resources, LLC (the “Company”) is a single-member Delaware limited liability company and an independent developer and producer of natural gas and oil, with operations in the Appalachian, Michigan and Illinois Basins.

On September 29, 2009, the Company completed its merger with Atlas America, Inc. (“Atlas America”) pursuant to the definitive merger agreement previously executed on April 27, 2009, with the Company surviving as a wholly-owned subsidiary of Atlas America (the “Merger”). In the Merger, 33.4 million Class B common units of the Company not previously held by Atlas America were exchanged for 38.8 million shares of Atlas America common stock (a ratio of 1.16 shares of Atlas America common stock for each Class B common unit of the Company) and 30.0 million Class B common units held by Atlas America were cancelled. Additionally, Atlas America changed its name to “Atlas Energy, Inc.” (“Atlas Energy” or “ATLS”) (NASDAQ: ATLS). Prior to the Merger, the Company had 63,381,249 Class B common units and 1,293,496 Class A units outstanding, with Atlas Energy and its affiliates owning 29,952,996 of the Company’s Class B common units and all of the Class A units outstanding, representing a 48.3% ownership interest in the Company. The Class A units (which continue to remain outstanding after the Merger) were 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. Subsequent to the Merger, the Class A units and management incentive interests owned by Atlas Energy Management, Inc. are combined with and shown as “owner’s equity” on the consolidated balance sheet. The Company’s Class B common units are no longer listed on the NYSE and have been deregistered under the Exchange Act.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Non-Controlling Interest

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Transactions between the Company and ATLS and its affiliates have been identified in the consolidated financial statements as transactions between affiliates (see Note 11). The non-controlling ownership interest in net income of the Company is reflected as non-controlling interest on the Company’s consolidated statements of operations, and the non-controlling interests in the assets and liabilities of the Company are reflected as a separate component of owner’s/members’ equity on the Company’s consolidated balance sheets.

In accordance with established practice in the oil and gas industry, the Company’s financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the energy partnerships in which the Company has an interest (“the Partnerships”). 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 “Property, Plant and Equipment” below. All material intercompany transactions have been eliminated.

Use of Estimates

The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Company’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Company’s consolidated financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, depreciation and

amortization, asset impairments, 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 those estimates.

Reclassifications

Certain amounts in the prior year’s consolidated financial statements have also been reclassified to conform to the current year presentation, including $18.8 million of pre-development costs shown as a component of “Property, plant, and equipment, net” and $44.3 million of “Subscriptions receivable from Partnerships”, both of which were previously combined with “Liabilities associated with drilling contracts” on the Company’s consolidated balance sheet at December 31, 2008. In addition, the Company’s consolidated financial statements and related footnotes contained within this Form 10-K have been restated to reflect the principles within the Financial Accounting Standards Board’s Accounting Standard Concept 810-10-65-1, “Non-controlling interests in Consolidated Financial Statements” (see “Recently Adopted Accounting Standards”).

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.

Receivables

Accounts receivable on the consolidated balance sheets consists solely of the trade accounts receivable associated with the Company’s operations. In evaluating the realizability of accounts receivable, the Company’s management performs ongoing credit evaluations of their customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the Company’s customers’ credit information. The Company extends credit on an unsecured basis to many of their customers. At December 31, 2009 and 2008, the Company had recorded no allowance for uncollectible accounts receivable on their consolidated balance sheets.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired (see Note 5). Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.

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

The Company’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves and depletion rates for well and related equipment costs are 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 investment partnerships, wells drilled solely by the Company for its interests, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the Company eliminates the cost from the property accounts, and the resultant gain or loss is reclassified to the Company’s consolidated statements of operations. Upon the sale of an individual well, the Company credits the proceeds to accumulated depreciation and depletion within its consolidated balance sheets. Upon the Company’s 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 Company’s consolidated statements of operations. 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.

Impairment of Long-Lived Assets

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

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, 2009, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future 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 the Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ 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 in the Partnerships 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 Partnerships’ 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 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 Partnership becomes uneconomic under the terms of the partnership agreement in order 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.

During the year ended December 31, 2009, the Company recognized a $156.4 million asset impairment related to oil and gas properties within property, plant and equipment on its consolidated balance sheet for its shallow natural gas wells in the Upper Devonian shale. This impairment related to the carrying amount of these oil and gas properties being in excess of the Company’s estimate of their fair value at December 31, 2009. The estimate of fair value of these oil and gas properties was impacted by, among other factors, the deterioration of natural gas prices. There were no impairments of unproved oil and gas properties recorded by the Company for the years ended December 31, 2009, 2008 and 2007.

Capitalized Interest

The Company capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds by the Company was 7.9%, 7.3% and 6.7% for the years ended December 31, 2009, 2008 and 2007, respectively. The amount of interest capitalized by the Company was $8.9 million, $5.0 million and $2.7 million for the years ended December 31, 2009, 2008 and 2007, respectively.

Intangible Assets

The Company has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through consummated acquisitions. The Company amortizes contracts acquired on a declining balance and straight-line method over their respective estimated useful lives. The following table reflects the components of intangible assets being amortized at December 31, 2009 and 2008 (in thousands):


	December 31,						Estimated Useful Lives In Years
	2009			2008			Estimated Useful Lives In Years
Gross Carrying Amount:
Partnership management and operating contracts		14,343			14,343		2 – 13
Non-compete agreement		890			890

	$	15,233		$	15,233

Accumulated Amortization:
Partnership management and operating contracts		(11,470	)		(10,728	)
Non-compete agreement		(890	)		(667	)

	$	(12,360	)	$	(11,395	)

Net Carrying Amount:
Partnership management and operating contracts		2,873			3,615
Non-compete agreement		—			223

	$	2,873		$	3,838

Amortization expense on intangible assets was $1.0 million, $1.2 million and $1.0 million for the years ended December 31, 2009, 2008 and 2007, respectively. Estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2010-$0.7 million; 2011-$0.7 million; 2012-$0.2 million; 2013-$0.2 million; and 2014-$0.1 million.

Goodwill

At December 31, 2009 and 2008, the Company had $35.2 million of goodwill recorded in connection with consummated acquisitions. There have been no changes in the carrying amount of goodwill for the years ended December 31, 2009, 2008 and 2007.

The Company tests its goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for its reporting units are not available, the Company’s management must apply judgment in determining the estimated fair value of these reporting units. The Company’s 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 the Company’s market capitalization. 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 on a stand-alone basis. 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’s management also considers the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in the Company’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in the Company’s industry to determine whether those valuations appear reasonable in management’s judgment. The Company will continue to evaluate goodwill at least annually or when impairment indicators arise.

There were no goodwill impairments recognized by the Company during the years ended December 31, 2009, 2008 and 2007.

Derivative Instruments

The Company enters into certain financial contracts to manage its exposure to movement in commodity prices and interest rates (see Note 9). The Company records each derivative instrument in the consolidated 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 operations unless specific hedge accounting criteria are met.

Asset Retirement Obligations

Pursuant to prevailing accounting literature, the Company recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities or asset retirement obligations (see Note 6). The Company recognizes a liability for future asset retirement obligations in the current period 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. The Company is required to consider estimated salvage value in the calculation of depreciation, depletion and amortization.

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 members 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 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 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 consolidated financial statements.

The Company recognizes the financial statement benefit of a tax position after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting a more-likely-than-not threshold, the amount recognized in the consolidated financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. The Company had applied this methodology to all tax positions for which the statute of limitation remains open and determined the methodology had no impact in the accompanying consolidated financial statements of the Company for the years ended December 31, 2009 and 2008. 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.

Stock-Based Compensation

The Company recognizes all share-based payments to employees, including grants of employee stock options, in the consolidated financial statements based on their fair values. As of the Merger, the Company’s Long-Term Incentive Plan was assumed by ATLS. Subsequent to September 29, 2009, no additional stock compensation expense was recorded by the Company within its consolidated statement of operations.

Net Income Per Unit

As a result of the Merger on September 29, 2009, there are no Class B member common units outstanding. Net income attributable to Class B member units is only presented through September 29, 2009. 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 and participating securities, by the weighted average number of Class B common units outstanding during the period. The Class A management incentive interests in net income is calculated on a quarterly basis based upon its 2% ownership interest, represented by its 1,293,496 Class A units, and its Member’s Incentive Interests (“MII”), with a priority allocation of net income to the Class A member’s MIIs in accordance with the Company’s original limited liability company agreement, and the remaining net income or loss allocated with respect to the Class A’s and Class B’s ownership interests.

On April 27, 2009, the Company and ATLS executed a definitive merger agreement. In anticipation of the Merger on September 29, 2009, the Company suspended distributions to the Class A and Class B members’ interests on April 1, 2009. Due to the suspension of distributions and in accordance with the limited liability company agreement, the Company determined that previously accrued distributions to MII’s of $8.0 million are no longer payable to ATLS.

The Company presents net income per unit by applying the Two-Class Method for Master Limited Partnerships in the calculation of earnings per share. Under this method, the Company must consider whether the incentive distributions represent a participating security when considered in the calculation of earnings per unit. The Company must also consider whether its limited liability company agreement contains any contractual limitations concerning distributions to the MIIs that would impact the amount of earnings to allocate to the MIIs

for each reporting period. If distributions are contractually limited to the MIIs’ share of currently designated available cash for distributions as defined under the Company’s limited liability company agreement, undistributed earnings in excess of available cash should not be allocated to the MIIs. The Company believes that its limited liability agreement contractually limits cash distributions to available cash and, therefore, undistributed earnings will not be allocated to the MIIs.

Effective January 1, 2009, the Company was required to determine if any of its share-based payment awards with rights to dividends or dividend equivalents qualify as participating securities. 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. Prior to the Merger, the Company had a Long-Term Incentive Plan that contained previously awarded phantom units, which consisted of Class B units (see Note 14) and contained nonforfeitable rights to distribution equivalents of the Company. These participation rights resulted in a non-contingent transfer of value each time the Company declared a distribution or distribution equivalent during the award’s vesting period. As such, the net income utilized in the calculation of net income per unit must be after the allocation of income to the phantom units on a pro-rata basis. The Company’s earnings per unit computations in its consolidated statement of operations prior to January 1, 2009 have been retroactively adjusted to conform to the current year presentation.

The following table is a reconciliation of net income allocated to the Class A member units and Class B members’ units for purposes of calculating net income per Class B member unit (in thousands):


	Years Ended December 31,
	2009⁽¹⁾			2008			2007
Net income attributable to members’ interests	$	42,340		$	142,780		$	117,504
Income allocable to Class A member’s actual cash incentive distributions reserved⁽²⁾		(8,024	)		6,274			1,749
Income allocable to Class A member’s 2% ownership interest		915			2,788			2,350

Net income attributable to Class A member’s ownership interest		(7,109	)		9,062			4,099

Net income attributable to Class B members’ ownership interests		49,449			133,718			113,405
Less: Net income attributable to participating securities – phantom units⁽³⁾		(558	)		(1,373	)		(1,193	)

Net income utilized in the calculation of net income attributable to Class B members per unit	$	48,891		$	132,345		$	112,212

⁽¹⁾	Relates to the period prior to the Merger from January 1, 2009 through September 29, 2009.

⁽²⁾	In connection with the Merger, the Company discontinued distributions in April 2009. Accordingly, the previously recorded amounts relating to the MII were reversed.

⁽³⁾	Net income attributable to Class B members’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of weighted average phantom units and Class B members’ units outstanding).

Dilutive potential units of Class B members’ units consisted of the excess of shares issuable under the terms of the Company’s stock incentive plan over the number of such units that could have been reacquired (at the weighted average market price of units during the period) with the proceeds received from the exercise of the stock options (see Note 14). The following table sets forth the reconciliation of the Company’s weighted average number of Class B member units used to compute basic net income attributable to Class B members per unit with those used to compute diluted net income attributable to Class B members per unit (in thousands):


	Years Ended December 31,
	2009⁽¹⁾	2008	2007
Weighted average number of Class B members’ units – basic	63,381	62,409	48,844
Add: effect of dilutive unit options	24	358	308

Weighted average number of Class B members’ units diluted	63,405	62,767	49,152

⁽¹⁾	The weighted average units for 2009 were as of September 29, 2009 prior to the Merger.

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. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities 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 environmental expenditures. At December 31, 2009 and 2008, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

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, 2009, the Company had $20.2 million in deposits at various banks, of which $16.9 million were over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date.

Revenue Recognition

Certain energy activities are conducted by the Company through, and a portion of its revenues are attributable to, sponsored investment partnerships. The Company contracts with the Partnerships to drill partnership wells. The contracts require that the Partnerships must pay the Company the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed between 60 and 180 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 the Company’s consolidated balance sheets. The Company recognizes well services revenues at the time the services are performed. The Company is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned and includes them in administration and oversight revenues.

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 and/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.

The Company accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management estimates of the related commodity sales which are, in turn, based upon applicable product prices (see “–Use of Estimates” accounting policy for further description). The Company had unbilled revenues at December 31, 2009 and 2008 of $29.6 million and $43.7 million, respectively, which are included in accounts receivable within the Company’s consolidated balance sheets.

Comprehensive Income

Comprehensive income includes net income and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources 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” and for the Company includes changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges. The following table sets forth the components of accumulated other comprehensive income in our consolidated balance sheets (in thousands):


	December 31,
	2009			2008
Unrealized gain on commodity derivative contracts	$	105,118		$	106,117
Unrealized loss on interest rate contracts		(3,975	)		(5,842	)

Accumulated other comprehensive income	$	101,143		$	100,275

Recently Adopted Accounting Standards

In February 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-09 “Amendments to Certain Recognition and Disclosure Requirements” (“Update 2010-09”). Update 2010-09 amends Accounting Standards Codification (“ASC”) 855-10-50-1 to clarify that all entities other than SEC filers must disclose (1) the date through, which subsequent events have been evaluated and (2) whether that date is the date the financial statements were issued or available to be issued. However, the date-disclosure exemption for SEC filers does not relieve management from its responsibility to evaluate subsequent events through the date on which financial statements are issued. The Company adopted the requirements of Update 2010-09 on December 31, 2009, and it did not have a material impact on its financial position, results of operations or related disclosures.

In January 2010, the Financial Accounting Standards Board (“FASB”) Issued Accounting Standards Update 2010-01, “Equity (Topic 505) - Accounting for Distributions to Shareholders with Components of Stock and Cash” (“Update 2010-01”). Update 2010-01 includes amendments to Subtopic 505-20 “Equity – Stock Dividends and Stock Splits” and relates specifically to entities that declare dividends to shareholders that may be paid either in cash or shares at the election of the shareholders with a potential limitation on the total amount of cash that all shareholders can elect to receive in the aggregate. The amendment clarifies that the stock portion of a distribution to shareholders in this circumstance is considered a share issuance that is reflected in earnings per share prospectively and is not a stock dividend for purposes of applying Topics 505 and 260 (Equity and Earnings Per Share). Update 2010-01 is intended to eliminate the diversity in practice by reporting entities. The Company adopted the requirements of Update 2010-01 on December 31, 2009, and it did not have a material impact on its financial position, results of operations or related disclosures.

In January 2010, the FASB Issued Accounting Standards Update 2010-03, “Extractive Activities Oil and Gas (Topic 932) - Oil and Gas Reserve Estimation and Disclosures” (“Update 2010-03”). Update 2010-03 includes amendments to Accounting Standards Codification (“ASC”) Topic 932 “Extractive Activities – Oil and Gas”, to include within the ASC the reporting requirements covered in the Securities and Exchange Commission’s (“SEC”) final rule, Modernization of Oil and Gas Reporting issued on December 31, 2008. The Company adopted the requirements of Update 2010-03 on December 31, 2009. These new disclosure requirements include provisions that:

•

Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations;

•

Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end pricing. This should maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date;

•

Permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves;

•

Update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty”;

•

Permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes; and

•

Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures are required with regard to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a company’s reserves preparer or auditor based on Society of Petroleum Engineers criteria.

The Company has complied with the disclosure requirements for the year ended December 31, 2009.

In August 2009, the FASB issued Accounting Standards Update 2009-05, “Fair Value Measurements and Disclosures (Topic 820) – Measuring Liabilities at Fair Value” (“Update 2009-05”). Update 2009-05 amends Subtopic 820-10, “Fair Value Measurements and Disclosures - Overall” and provides clarification for the fair value measurement of liabilities in circumstances where quoted prices for an identical liability in an active market are not available. The amendments also provide clarification for not requiring the reporting entity to include separate inputs or adjustments to other inputs relating to the existence of a restriction that prevents the transfer of a liability when estimating the fair value of a liability. Additionally, these amendments clarify that both the quoted price in an active market for an identical liability at the measurement date and the quoted price for an identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are considered Level 1 fair value measurements. These requirements are effective for financial statements issued after the release of Update 2009-05. The Company adopted the requirements of Update 2009-05 on September 30, 2009, and it did not have a material impact on its financial position, results of operations or related disclosures.

In August 2009, the FASB issued Accounting Standards Update 2009-04, “Accounting for Redeemable Equity Instruments – Amendment to Section 480-10-S99” (“Update 2009-04”). Update 2009-04 updates Section 480-10-S99, “Distinguishing Liabilities from Equity”, to reflect the SEC staff’s views regarding the

application of Accounting Series Release No. 268, “Presentation in Financial Statements of ‘Redeemable Preferred Stocks’” (“ASR No. 268”). ASR No. 268 requires preferred securities that are redeemable for cash or other assets to be classified outside of permanent equity if they are redeemable (1) at a fixed or determinable price on a fixed or determinable date, (2) at the option of the holder, or (3) upon the occurrence of an event that is not solely within the control of the issuer. The Company adopted the requirements of Update 2009-04 on August 1, 2009, and it did not have a material impact on its financial position, results of operations or related disclosures.

In June 2009, the FASB issued Accounting Standards Update 2009-01, “Topic 105 – Generally Acceptable Accounting Principles Amendments Based on Statement of Financial Accounting Standards No. 168 - The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“Update 2009-01”). Update 2009-01 establishes the FASB ASC as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The ASC supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following the ASC, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting Standards Updates, which will serve only to update the ASC. The ASC is effective for financial statements issued for interim and annual periods ending after September 15, 2009. All required references to non-SEC accounting standards have been modified by the Company. The Company adopted the requirements of Update 2009-01 for its financial statements on September 30, 2009, and it did not have a material impact on its financial statement disclosures.

In May 2009, the FASB issued ASC 855-10, “Subsequent Events” (“ASC 855-10”). ASC 855-10 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The provisions require management of a reporting entity to evaluate events or transactions that may occur after the balance sheet date for potential recognition or disclosure in the financial statements and provides guidance for disclosures that an entity should make about those events. ASC 855-10 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. The Company adopted the requirements of this standard on June 30, 2009, and it did not have a material impact on its financial position or results of operations or related disclosures. The adoption of these provisions does not change the Company’s current practices with respect to evaluating, recording and disclosing subsequent events.

In April 2009, the FASB issued ASC 820-10-65-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“ASC 820-10-65-4”). ASC 820-10-65-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. ASC 820-10-65-4 also require an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. ASC 820-10-65-4 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted the requirements of ASC 820-10-65-4 on April 1, 2009, and its adoption did not have a material impact on its financial position and results of operations.

In April 2009, the FASB issued ASC 320-10-65-1, “Recognition and Presentation of Other-Than-Temporary Impairments” (“ASC 320-10-65-1”), which changes previously existing guidance for determining whether an impairment is other than temporary for debt securities. ASC 320-10-65-1 replaces the previously existing requirement that an entity’s management assess if it has both the intent and ability to hold an impaired security until recovery with a requirement that management assess that it does not have the intent to sell the security and that it is more likely than not that it will not have to sell the security before recovery of its cost basis. ASC 320-10-65-1 also requires that an entity recognize noncredit losses on held-to-maturity debt securities in other comprehensive income and amortize that amount over the remaining life of the security and for the entity to present the total other-than-temporary impairment in the statement of operations with an offset for the amount recognized in other comprehensive income. ASC 320-10-65-1 is effective for interim and annual periods ending

after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted these requirements on April 1, 2009, and its adoption did not have a material impact on its financial position and results of operations.

In April 2009, the FASB issued ASC 825-10-65-1, “Interim Disclosures about Fair Value of Financial Instruments” (“ASC 825-10-65-1”), which requires an entity to provide disclosures about fair value of financial instruments in interim financial information. In addition, an entity shall disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position. ASC 825-10-65-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted these requirements on April 1, 2009, and its adoption did not have a material impact on its financial position and results of operations.

In April 2009, the FASB issued ASC 805-20-30-23, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“ASC 805-20-30-23”), which requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be recognized at fair value if fair value can be reasonably estimated. If fair value of such an asset or liability cannot be reasonably estimated, the asset or liability would generally be recognized in accordance with previous requirements. ASC 805-20-30-23 eliminates the requirement to disclose an estimate of the range of outcomes of recognized contingencies at the acquisition date. ASC 805-20-30-23 is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for the Company). The Company adopted the requirements on January 1, 2009, and its adoption did not have a material impact on its financial position and results of operations.

In June 2008, the FASB issued ASC 260-10-45-61A, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“ASC 260-10-45-61A”). ASC 260-10-45-61A applies to the calculation of earnings per share (“EPS”) described in previous guidance, for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain non-forfeitable 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. ASC 260-10-45-61A is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption was prohibited. The Company adopted the requirements on January 1, 2009, and its adoption did not have a material impact on its financial position and results of operations.

In April 2008, the FASB issued ASC 350-30-65-1, “Determination of Useful Life of Intangible Assets” (“ASC 350-30-65-1”). ASC 350-30-65-1 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 previous guidance. The intent of ASC 350-30-65-1 is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset. The Company adopted the requirements of ASC 350-30-65-1 on January 1, 2009, and its adoption did not have a material impact on its financial position and results of operations.

In March 2008, the FASB issued ASC 260-10-55-103 through 55-110, “Application of the Two-Class Method” (“ASC 260-10-55-103”), which considers whether the incentive distributions of a master limited partnership represent a participating security when considered in the calculation of earnings per unit under the two-class method. ASC 260-10-55-103 considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under

the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. The Company adopted the requirements of ASC 260-10-55-103 on January 1, 2009, and its adoption did not have a material impact on its financial position and results of operations.

In March 2008, the FASB issued ASC 815-10-50-1, “Disclosures about Derivative Instruments and Hedging Activities” (“ASC 815-10-50-1”), to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The Company adopted the requirements of this section of ASC 815-10-50-1 on January 1, 2009, and it did not have a material impact on its financial position or results of operations (see Note 9).

In December 2007, the FASB issued ASC 810-10-65-1, “Non-controlling Interests in Consolidated Financial Statements” (“ASC 810-10-65-1”). ASC 810-10-65-1 establishes accounting and reporting standards for the non-controlling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It also requires consolidated net income to be reported and disclosed on the face of the consolidated statement of operations at amounts that include the amounts attributable to both the parent and the non-controlling interest. Additionally, ASC 810-10-65-1 establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated and adjust its remaining investment, if any, at fair value. The Company adopted the requirements of ASC 810-10-65-1 on January 1, 2009 and adjusted the presentation of its financial position and results of operations. Prior period financial position and results of operations have been adjusted retrospectively to conform to these provisions.

In December 2007, the FASB issued ASC 805, “Business Combinations” (“ASC 805”). ASC 805 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. ASC 805 requires an acquirer to recognize the assets acquired, liabilities assumed, and any non-controlling interest in the acquiree at the acquisition date, at their fair values as of that date, with specified limited exceptions. Additionally, it 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 non-controlling interests in the acquiree, at the full amounts of their fair values. The Company adopted these requirements on January 1, 2009 and it did not have a material impact on its financial position and results of operations.

Recently Issued Accounting Standards

In January 2010, the FASB Issued Accounting Standards Update 2010-02, “Consolidation (Topic (810) - Accounting and Reporting for Decreases in Ownership of a Subsidiary – A Scope Clarification” (“Update 2010-02”). Subtopic 810-10 previously applied to decrease-in-ownership provisions when an entity either deconsolidates or realizes a decrease in ownership in which the entity retains control. When an entity deconsolidates a subsidiary, it is required to record any remaining interest at fair value and recognize a gain or loss. Update 2010-02 amends Subtopic 810-10 “Consolidation – Overall” and provides clarification on the entities and activities required to follow more specific guidance already included in the ASC. Update 2010-02 includes in the scope of decrease-in-ownership provisions of ASC 810-10 a subsidiary or groups of assets that is a business or nonprofit activity, a subsidiary or group of assets transferred to an equity method investee or joint venture, or an exchange of a group of assets that constitutes a business or nonprofit activity for a noncontrolling interest in an entity. Excluded from the scope of Subtopic 810-10 are sales of in-substance real estate and conveyances of oil and gas mineral rights. The requirements of Update 2010-02 are effective at the start of a reporting entity’s first fiscal year beginning after December 15, 2009 (January 1, 2010 for the Company). The Company will apply the requirements of Update 2010-02 upon its adoption on January 1, 2010 and does not expect it to have a material impact on its financial position, results of operations or related disclosures.

In October 2009, the FASB issued Accounting Standards Update 2009-15, “Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing” (“Update 2009-15”). Update 2009-15 includes amendments to Topic 470, “Debt”, and Topic 260, “Earnings per Share”, to provide guidance on share-lending arrangements entered into on an entity’s own shares in contemplation of a convertible debt offering or other financing. These requirements are effective for existing arrangements for fiscal years beginning on or after December 15, 2009 (January 1, 2010 for the Company), and interim periods within those fiscal years for arrangements outstanding as of the beginning of those years, with retrospective application required for such arrangements that meet the criteria. These requirements are also effective for arrangements entered into on (not outstanding) or after the beginning of the first reporting period that begins on or after June 15, 2009. The Company will apply the requirements of Update 2009-15 upon its adoption on January 1, 2010 and does not expect it to have a material impact on its financial position, results of operations or related disclosures.

In June 2009, the FASB issued ASC 810-10-25-20 through 25-59, “Consolidation of Variable Interest Entities” (“ASC 810-10-25-20”), which changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. ASC 820-10-25-20 requires a reporting entity to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. A reporting entity will be required to disclose how its involvement with a variable interest entity affects the reporting entity’s financial statements. The requirements of ASC 820-10-25-20 are effective at the start of a reporting entity’s first fiscal year beginning after November 15, 2009 (January 1, 2010 for the Company). The Company will apply the requirements of ASC 810-10-25-20 upon its adoption on January 1, 2010 and does not expect it to have a material impact on its financial position, results of operations or related disclosures.

NOTE 3 – COMMON EQUITY OFFERINGS

In May 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, as both joint book-running managers and underwriters, yielding net proceeds of approximately $82.5 million after underwriting expenses of $3.4 million. The net proceeds were used to repay a portion of its outstanding balance under its revolving credit facility.

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

To partially fund the acquisition of equity interest in DTE Gas & Oil Company (“DGO”) 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 4 – ACQUISITIONS

DTE Gas and Oil Company Acquisition

On June 29, 2007, the Company acquired all of the outstanding equity interests of DTE Gas & Oil Company (“DGO”) from DTE Energy Company (NYSE: DTE) and MCN Energy Enterprises for $1.3 billion, including adjustments for working capital of $15.0 million and capital expenditures of $19.0 million. To fund the acquisition, the Company borrowed $713.9 million under its credit facility (see Note 8) and received net proceeds of $597.5 million from the private placement of its Class B common units. The acquisition was accounted for using the purchase method of accounting. The following table presents the purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed based on their estimated fair market value at the date of acquisition (in thousands):


Accounts receivable	$	33,764
Prepaid expenses		515
Other assets		890
Natural gas and oil properties		1,267,901

Total assets acquired		1,303,070
Accounts payable and accrued liabilities		(19,233	)
Other liabilities		(210	)
Asset retirement obligations		(11,109	)

Total liabilities assumed		(30,552	)

Net assets acquired	$	1,272,518

The results of DGO’s operations were included within the Company’s consolidated statements from the date of acquisition.

The following data presents pro forma revenue, net income and net income per share for the Company for the year ended December 31, 2007 as if the Company’s acquisition discussed above and related financing transactions had occurred on January 1, 2007. The Company prepared these unaudited pro forma financial results for comparative purposes only. These pro forma financial results may not be indicative of the results that would have occurred if the Company had completed these acquisitions and financing transactions at the beginning of the period shown below or the results that will be attained in the future (in thousands, except per share data; unaudited):


	Year Ended December 31, 2007
Revenue	$	594,635
Net income	$	59,627
Net income attributable to Class B unitholders	$	58,434
Net income per Class B common unit outstanding – basic	$	0.96
Weighted average Class B common units outstanding - basic		60,710
Net income per Class B common unit outstanding – diluted	$	0.95
Weighted average Class B common units outstanding – diluted		61,189

NOTE 5 – PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment (in thousands):


	December 31,						Estimated Useful Lives in Years
	2009			2008			Estimated Useful Lives in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,243,932		$	1,214,991
Pre-development costs		6,270			18,772
Wells and related equipment		1,017,370			872,128

Total proved properties		2,267,572			2,105,891
Unproved properties		41,816			43,749
Support equipment		8,930			9,527

Total natural gas and oil properties		2,318,318			2,159,167
Pipelines, processing and compression facilities		27,928			22,541		15 – 40
Rights of way		57			149		20 – 40
Land, buildings and improvements		8,768			6,484		10 – 40
Other		7,542			7,827		3 – 10

		2,362,613			2,196,168
Less – accumulated depreciation, depletion and amortization		(491,195	)		(232,277	)

	$	1,871,418		$	1,963,891

NOTE 6 – ASSET RETIREMENT OBLIGATIONS

The Company recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes 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. The Company also considers the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability is based on the Company’s 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 its oil and gas properties, 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,
	2009			2008			2007
Asset retirement obligations, beginning of year	$	48,136		$	42,358		$	26,726
Liabilities acquired (see Note 4)		—			—			11,109
Liabilities incurred		944			3,305			2,582
Liabilities settled		(270	)		(253	)		(91	)
Accretion expense		3,003			2,726			2,032

Asset retirement obligations, end of year	$	51,813		$	48,136		$	42,358

The above accretion expense was included in depreciation, depletion and amortization in the Company’s consolidated statements of operations and the asset retirement obligation liabilities were included in other long-term liabilities in the Company’s consolidated balance sheets.

NOTE 7 – OTHER ASSETS

The following is a summary of other assets at the dates indicated (in thousands):


	December 31,
	2009		2008
Deferred finance and organization costs, net of accumulated amortization of $9,718 and $5,531 at December 31, 2009 and 2008, respectively	$	19,743	$	15,053
Long-term derivative receivable from Partnerships		2,841		2,719
Other investments		900		331
Security deposits		263		300

	$	23,747	$	18,403

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 8). During the years ended December 31, 2009 and 2007, the Company recorded $1.0 million and 1.7 million of accelerated amortization of deferred financing costs, respectively, which is recorded within interest expense on the Company’s consolidated statement of operations. There was no accelerated amortization during the year ended December 31, 2008. During 2009, the Company accelerated amortization of its deferred finance costs due to changes in the borrowing base of its revolving credit facility in April and October 2009. During 2007, the Company accelerated amortization of its deferred finance costs due to the replacement of its revolving credit facility with a new facility.

Long-term derivative receivable from Partnerships represents a portion of the Company’s long-term unrealized derivative liability on contracts that have been allocated to the Partnerships based on their share of total production volumes sold.

NOTE 8 – DEBT

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


	December 31,
	2009		2008
Revolving credit facility	$	184,000	$	467,000
10.75% senior notes – due 2018		405,922		406,655
12.125% senior notes – due 2017		196,468		–

Total debt		786,390		873,655
Less current maturities		–		–

Total long-term debt	$	786,390	$	873,655

Revolving Credit Facility

At December 31, 2009, the Company had a credit facility with a syndicate of banks with a borrowing base of $575.0 million that matures in June 2012. The borrowing base is redetermined semiannually on April 1 and October 1 subject to changes in oil and gas reserves and is automatically reduced by 25% of the stated principal of any senior unsecured notes issued by the Company. Up to $50.0 million of the credit facility may be in the form of standby letters of credit, of which $1.2 million was outstanding at December 31, 2009, which was 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 its subsidiaries. At December 31, 2009 and 2008, the weighted average interest rate on outstanding borrowings was 2.9% and 2.8%, respectively. The base rate for any day equals the higher of the federal funds rate plus 0.50%, the J.P. Morgan prime rate or the adjusted LIBOR for a month interest period plus 1.0%. 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.

On July 10, 2009, the Company’s credit agreement was amended to, among other things, permit the Merger and to allow the Company to distribute to ATLS (a) amounts equal to ATLS’s income tax liability attributable to the Company’s net income at the highest marginal rate and (b) up to $40.0 million per year and, to the extent that it distributes less than that amount in any year, it may carry over up to $20.0 million for use in the next year.

The events which constitute an event of default for the Company’s credit facility are 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 Company is in compliance with these covenants as of December 31, 2009. The credit facility also requires the Company 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 less than or equal to 3.75 to 1.0 commencing January 1, 2009, decreasing to 3.5 to 1.0 commencing January 1, 2010. Based on the definitions contained in the Company’s credit facility, its ratio of current assets to current liabilities was 1.7 to 1.0 and its ratio of total debt to EBITDA was 2.7 to 1.0 at December 31, 2009.

Senior Notes

At December 31, 2009, the Company had $400.0 million principal amount outstanding of 10.75% senior unsecured notes (“10.75% Senior Notes”) due on February 1, 2018 and $200.0 million principal amount outstanding of 12.125% senior unsecured notes due August 1, 2017 (“12.125% Senior Notes”; collectively, the “Senior Notes”). The 12.125% Senior Notes, which are shown net of unamortized discount of $3.5 million, were

issued in July 2009 in a public offering at a price of 98.116% to par value for a yield of 12.5% at maturity. Net proceeds from the offering were used to reduce outstanding borrowings under the Company’s revolving credit facility. Interest on the Senior Notes in the aggregate is payable semi-annually in arrears on February 1 and August 1 of each year. The 10.75% Senior Notes, which are shown inclusive of unamortized premium of $5.9 million, are redeemable at any time on or after February 1, 2013, and the 12.125% Senior Notes are redeemable at any time on or after August 1, 2013, at specified redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, before February 1, 2011 for the 10.75% Notes and before August 1, 2012 for the 12.125% Senior Notes, 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 the principal amount of the 10.75% Senior Notes and 12.125% Senior Notes, 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 indentures governing the Senior Notes contain 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 these covenants as of December 31, 2009.

In January 2008, the Company completed a private placement of $250.0 million of the 10.75% Senior Notes 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 the 10.75% Senior Notes at 104.75% to par to yield 9.85% to the par call on February 1, 2016. The Company received proceeds of approximately $398.0 million from these private 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. All of the 10.75% Senior Notes were exchanged for registered securities with identical terms. The exchange offer was completed in December 2009, and the registration statement covering the Senior Notes were terminated in January 2010.

The aggregate amount of the Company’s debt maturities were as follows (in thousands):


Years Ended December 31:
2010	$	–
2011		–
2012		184,000
2013		–
2014		–
Thereafter		602,390

	$	786,390

Cash payments for interest related to debt were $59.4 million, $41.8 million and $25.6 million for the years ended December 31, 2009, 2008 and 2007, respectively.

NOTE 9 – DERIVATIVE INSTRUMENTS

The Company uses a number of different derivative instruments, principally swaps, collars and options, in connection with its commodity price and interest rate risk management activities. The Company enters into financial instruments to hedge its forecasted natural gas and crude oil sales against the variability in expected future cash flows attributable to changes in market prices. The Company also enters into financial swap instruments to hedge certain portions of its floating interest rate debt against the variability in market interest rates. Swap instruments are contractual agreements between counterparties to exchange obligations of money as

the underlying natural gas and crude oil is sold or interest payments on the underlying debt instrument are due. Under swap agreements, the Company receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas and crude oil at a fixed price for the relevant contract period.

The Company formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity and interest derivative contracts to the forecasted transactions. The Company assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Company will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the Company through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s consolidated statements of operations. For derivatives qualifying as hedges, the Company recognizes the effective portion of changes in fair value in owner’s/members’ equity as accumulated other comprehensive income and reclassifies the portion relating to commodity derivatives to gas and oil production revenues for the Company’s derivatives and the portion relating to interest rate derivatives to interest expense within the Company’s consolidated statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Company recognizes changes in fair value within gain (loss) on mark-to-market derivatives in its consolidated statements of operations as they occur.

Derivatives are recorded on the Company’s consolidated balance sheet as assets or liabilities at fair value. The Company reflected net derivative assets on its consolidated balance sheets of $113.0 million and $153.6 million at December 31, 2009 and 2008, respectively. Of the $101.1 million of net gain in accumulated other comprehensive income within owner’s/members’ equity on the Company’s consolidated balance sheet at December 31, 2009, if the fair values of the instruments remain at current market values, the Company will reclassify $50.1 million of gains to the Company’s consolidated statements of operations over the next twelve month period as these contracts expire, consisting of $52.1 million of gains to gas and oil production revenues and $2.0 million of losses to interest expense. Aggregate gains of $51.0 million will be reclassified to the Company’s consolidated statements of operations in later periods as these remaining contracts expire, consisting of $53.0 million of gains to gas and oil production revenues and $2.0 million of losses to interest expense. Actual amounts that will be reclassified will vary as a result of future price changes.

The following table summarizes the fair value of the Company’s derivative instruments as of December 31, 2009 and 2008, as well as the gain or loss recognized in the consolidated statements of operations for effective derivative instruments for the years ended December 31, 2009 and 2008:


Fair Value of Derivative Instruments:
	Asset Derivatives					Liability Derivatives
Derivatives in Cash Flow Hedging Relationships	Balance Sheet Location	Fair Value				Balance Sheet Location	Fair Value
		December 31,					December 31,
		2009		2008			2009			2008
		(in thousands)					(in thousands)
Commodity contracts:	Current assets	$	73,066	$	107,766	Current liabilities	$	(901	)	$	(9,348	)
	Long-term assets		58,930		69,451	Long-term liabilities		(14,091	)		(8,410	)

			131,996		177,217			(14,992	)		(17,758	)
Interest rate contracts:	Current assets		—		—	Current liabilities		(3,751	)		(3,481	)
	Long-term assets		—		—	Long-term liabilities		(224	)		(2,361	)

			—		—			(3,975	)		(5,842	)

Total derivatives		$	131,996	$	177,217		$	(18,967	)	$	(23,600	)


Effects of Derivative Instruments on Consolidated Statements of Operations for the Years ended December 31, 2009 and 2008 were as follows:
Derivatives in Cash Flow Hedging Relationships	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) For the Years Ended December 31,						Location of Gain/(Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) For the Years Ended December 31,
	2009			2008				2009			2008
	(in thousands)							(in thousands)
Commodity contracts	$	118,695		$	(26,447	)	Gas and oil production	$	119,695		$	(25,969	)
Interest rate contracts		(2,336	)		626		Interest expense		(4,203	)		(335	)

	$	116,359		$	(25,821	)		$	115,492		$	(26,304	)

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.

In May 2009, the Company received approximately $28.5 million in proceeds from the early termination of natural gas and oil derivative positions for production periods from 2011 through 2013. In conjunction with the early termination of these derivatives, the Company entered into new derivative positions at prevailing prices at the time of the transaction. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under the Company’s credit facility (see Note 8). The gain recognized upon the early termination of these derivative positions will continue to be reported in accumulated other comprehensive income and will be reclassified into the Company’s consolidated statements of operations in the same periods in which the hedged production revenues would have been recognized in earnings.

The Company recognized a gain of $119.7 million, a loss of $25.4 million and a gain of $17.6 million for years ended December 31, 2009, 2008 and 2007, respectively, on settled contracts covering natural gas and oil production. These gains and losses are included within gas and oil production revenue in the Company’s consolidated statements of operations. 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, 2009, 2008 and 2007 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

In May 2007, the Company signed a definitive agreement to acquire its Michigan assets (see Note 4). 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. The production volume of the assets to be acquired was not considered to be “probable forecasted production” under prevailing accounting literature 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 gain (loss) on mark-to-market derivatives in our consolidated statements of operations. The Company recognized a non-cash gain 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 prevailing accounting literature, and the Company evaluated these derivatives under the cash flow hedge criteria in accordance with prevailing accounting literature.

At December 31, 2009, the Company had $184.0 million of borrowings under its senior secured revolving credit facility (see Note 8). At December 31, 2009, the Company had interest rate derivative contracts having an

aggregate notional principal amount of $150.0 million through January 2011, which were designated as cash flow hedges. During the year ended December 31, 2008, the Company entered into hedging arrangements in the form of interest rate swaps to reduce the impact of volatility of changes in the London interbank offered rate (“LIBOR”). Under the terms of the contract, the Company will pay a three-year fixed swap interest rate of 3.1%, plus the applicable margin as defined under the terms of its revolving credit facility, and will receive LIBOR, plus the applicable margin, on the notional principal amounts. This derivative effectively converts $150.0 million of the Company’s floating rate debt under the revolving credit facility to fixed-rate debt. The Company has accounted for the interest rate derivative contracts as effective hedge instruments under prevailing accounting standards.

At December 31, 2009, the Company had the following interest rate and commodity derivatives:

Interest Fixed Rate Swap


Term	Notional Amount		Option Type	Contract Period Ended December 31,	Fair Value Liability
					(in thousands)
January 2008 – January 2011	$	150,000,000	Pay 3.1% - Receive LIBOR	2010	$	(3,751	)
				2011		(223	)

					$	(3,974	)

Natural Gas Fixed Price Swaps


Production Period Ending December 31,		Volumes	Average Fixed Price		Fair Value Asset
		(mmbtu)⁽¹⁾	(per mmbtu)⁽¹⁾		(in thousands)⁽²⁾
2010		41,360,004	$	7.337	$	64,015
2011		24,140,004	$	6.982		15,374
2012		19,680,000	$	7.223		13,126
2013		13,260,000	$	7.082		5,079

					$	97,594

Natural Gas Costless Collars
Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset
		(mmbtu)⁽¹⁾	(per mmbtu)⁽¹⁾		(in thousands)⁽² ⁾
2010	Puts purchased	3,360,000	$	7.839	$	7,131
2010	Calls sold	3,360,000	$	9.007		—
2011	Puts purchased	12,840,000	$	6.449		6,360
2011	Calls sold	12,840,000	$	7.630		—
2012	Puts purchased	9,780,000	$	6.512		3,410
2012	Calls sold	9,780,000	$	7.714		—
2013	Puts purchased	10,740,000	$	6.584		2,762
2013	Calls sold	10,740,000	$	7.792		—

					$	19,663

Crude Oil Fixed Price Swaps


Production Period Ending December 31,		Volumes	Average Fixed Price		Fair Value Asset/(Liability)
		(Bbl)⁽¹⁾	(per Bbl)⁽¹⁾		(in thousands) ⁽³⁾
2010		48,900	$	97.400	$	766
2011		42,600	$	77.460		(353	)
2012		33,500	$	76.855		(354	)
2013		10,000	$	77.360		(108	)

					$	(49	)

Crude Oil Costless Collars
Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset/(Liability)
		(Bbl)⁽¹⁾	(per Bbl)⁽¹ ⁾		(in thousands) ⁽³⁾
2010	Puts purchased	31,000	$	85.000	$	253
2010	Calls sold	31,000	$	112.918		—
2011	Puts purchased	27,000	$	67.223		—
2011	Calls sold	27,000	$	89.436		(201	)
2012	Puts purchased	21,500	$	65.506		—
2012	Calls sold	21,500	$	91.448		(200	)
2013	Puts purchased	6,000	$	65.358		—
2013	Calls sold	6,000	$	93.442		(57	)

					$	(205	)

				Total Company net asset	$	113,029

⁽¹⁾	“Mmbtu” represents million British Thermal Units; “Bbl” represents barrels.

⁽²⁾	Fair value based on forward NYMEX natural gas prices, as applicable.

⁽³⁾	Fair value based on forward WTI crude oil prices, as applicable.

The Company’s commodity price risk management includes estimated future natural gas and crude oil production of the Partnerships. Therefore, a portion of any unrealized derivative gain or loss is allocable to the limited partners of the Partnerships based on their share of estimated gas and oil production related to the derivatives not yet settled. At December 31, 2009 and 2008, net unrealized derivative assets of $41.7 million and $51.8 million, respectively, are payable to the limited partners in the Partnerships and are included in the consolidated balance sheets, as follows (in thousands).


	December 31,
	2009			2008
Prepaid expenses and other	$	270		$	3,022
Other assets, net		2,841			2,719
Accrued liabilities		(22,382	)		(34,933	)
Long-term derivative liability		(22,380	)		(22,581	)

	$	(41,651	)	$	(51,773	)

NOTE 10 – FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1 – Unadjusted quoted prices in active markets for identical, unrestricted 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 assumption 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.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Company uses a fair value methodology to value the assets and liabilities for its derivative contracts (see Note 9). The Company’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. The Company’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model and are therefore defined as Level 2 fair value measurements. Information for assets and liabilities measured at fair value on a recurring basis at December 31, 2009 was as follows (in thousands):


	Level 1		Level 2			Level 3		Total
Commodity-based derivatives		–		117,003			–		117,003
Interest rate derivatives		–		(3,974	)		–		(3,974	)

Total	$	–	$	113,029		$	–	$	113,029

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. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature. The estimated fair values of the Company’s debt at December 31, 2009 and 2008, which consists principally of its Senior Notes and borrowings under its credit facility, were $853.0 million and $712.2 million, respectively, compared with the carrying amounts of $786.4 million and $873.7 million, respectively. The Senior Notes were valued based upon recent trading activity. The carrying value of outstanding borrowings under the credit facility, which bear interest at a variable interest rate, approximates their estimated fair value.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

The Company estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements; the credit-adjusted risk-free rate of the Company; and estimated inflation rates (see Note 6).

Information for assets that are measured at fair value on a nonrecurring basis for the year ended December 31, 2009 was as follows (in thousands):


	Year Ended December 31, 2009
	Level 3		Total
Asset retirement obligations	$	944	$	944

Total	$	944	$	944

NOTE 11 — 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 ATLS. ATLS 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 consolidated statements of operations. The employees supporting these Company operations are employees of ATLS. 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 ATLS’s cash management program. Any transaction performed by ATLS on behalf of the Company is not due on demand and has been recorded as a long-term liability in advances from affiliates on the Company’s consolidated balance sheets.

Relationship with the Company’s 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 general partner and operator of the Partnerships and assumes customary rights and obligations for the Partnerships. As the general partner, the Company is liable for the Partnerships’ liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Partnerships. The Company is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Partnerships’ revenue, and costs and expenses according to the respective Partnership agreements.

Relationship with Laurel Mountain. On May 31, 2009, the Company completed the sale of two natural gas processing plants and associated pipelines located in southwestern Pennsylvania for cash of $10.0 million to Laurel Mountain Midstream, LLC (“Laurel Mountain”), a newly-formed joint venture between the Company’s affiliate, Atlas Pipeline Partners, L.P. (NYSE: APL) (“APL”), and The Williams Companies, Inc. (NYSE: WMB). (“Williams”). Upon contribution of its Appalachia Basin natural gas gathering system to Laurel Mountain, APL received $87.8 million in cash, a preferred equity right to proceeds under a $25.5 million note issued to Laurel Mountain by Williams and a 49.0% ownership interest in Laurel Mountain. APL is a subsidiary of the Company’s parent company, ATLS. Laurel Mountain owns and operates all of APL’s previously owned northern Appalachian assets, excluding its northern Tennessee operations, of which the Company will be the largest customer. The Company recorded a loss on the sale the two natural gas processing plants and associated pipelines of $6.5 million, which is recorded as “Gain (loss) on asset sale” on its consolidated statements of operations for the year ended December 31, 2009. The Company used the net proceeds from the sale to repay outstanding borrowings under its revolving credit facility.

Upon completion of the transaction with Laurel Mountain, the Company entered into new gas gathering agreements with Laurel Mountain which superseded the existing master natural gas gathering agreement and omnibus agreement between the Company and APL. Pursuant to these gas gathering agreements with Laurel Mountain, the Company generally pays a gathering fee equal to 16% of the realized natural gas sales price (adjusted for the settlement of natural gas derivative instruments). However, in most of the Company’s direct investment partnerships, it collects a gathering fee of 13% of the realized natural gas sales price per the respective partnership agreement. As a result, the Company’s Appalachian gathering expenses within its partnership management segment will generally exceed the revenues collected from the investment partnerships by approximately 3%. The new gathering agreements contain additional provisions which define certain obligations and options of each party to build and connect newly drilled wells to any Laurel Mountain gathering system. Unlike the terminated agreements, ATLS will not assume or guarantee the Company’s obligation to pay gathering fees to Laurel Mountain.

Relationship with Crown Drilling of Pennsylvania, LLC. Since 2007, the Company has had an equity interest in Crown Drilling of Pennsylvania, LLC (“Crown”), a company that performs the drilling activities for certain of the Company’s investment partnerships. In addition to its equity ownership, the Company guarantees 50% of the outstanding balances of Crown’s credit agreement. As of December 31, 2009, the Company’s guarantee was limited to $11.5 million.

NOTE 12 — COMMITMENTS AND CONTINGENCIES

General Commitments

The Company leases office space and equipment under leases with varying expiration dates through 2020. Rental expense was $3.4 million, $2.4 million and $1.5 million for the years ended December 31, 2009, 2008 and 2007, respectively. Future minimum rental commitments for the next five years are as follows (in thousands):


Years Ended December 31:
2010		2,155
2011		1,614
2012		1,375
2013		1,175
2014		515
Thereafter		3,663

	$	10,497

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 management of 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 benefit of the investor partners for an amount equal to at least 10% of their subscriptions, determined on a cumulative basis, in accordance with the terms of the Partnership agreements. For the year ended December 31, 2009, $3.9 million of the Company’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the investment partnerships. No subordination of the Company’s net revenues was required for the years ended December 31, 2008 and 2007 with regard to the Partnerships.

The Company is party to employment agreements with certain executives that provide compensation and certain other benefits. The agreements also provide for severance payments under certain circumstances.

Legal Proceedings

Following announcement of the Merger on April 27, 2009, five purported class actions were filed in Delaware Chancery Court and were later consolidated into a single complaint, In re Atlas Energy Resources, LLC Unitholder Litigation, C.A. No. 4589-VCN (the “Consolidated Action”) filed on July 1, 2009 (the “Consolidated Complaint”). The Consolidated Complaint named ATLS and various officers and directors of the Company as defendants (the “Defendants”), alleged violations of fiduciary duties in connection with the Merger, and requested injunctive relief and damages. On August 7, 2009, plaintiffs advised the Delaware Chancery Court by letter that they would not pursue their motion for a preliminary injunction, which had been scheduled for a hearing on September 4, 2009, and requested that the September 4 hearing date be removed from the Court’s calendar. On October 16, 2009, the Company filed a motion to dismiss the Consolidated Complaint. On December 15, 2009, plaintiffs filed an Amended Complaint (the “Amended Complaint”). On January 6, 2010, the Delaware Chancery Court granted the parties’ Scheduling Stipulation and Order, providing that Defendants would have until February 18, 2010, to file a motion to dismiss the Amended Complaint; that plaintiffs’ answering brief in opposition would be due on or before May 3, 2010; and that Defendants’ reply papers would be due on or before June 4, 2010. Defendants filed their opening brief in support of their motion to dismiss on February 18, 2010. The Amended Complaint alleges that Defendants breached their purported fiduciary duties to the Company’s public unitholders in connection with their negotiation of the Merger. In particular, plaintiffs allege that the Merger was not entirely fair to the Company’s public unitholders, and that Defendants conducted the Merger process in bad faith.

Predicting the outcome of this lawsuit is difficult. An adverse judgment for monetary damages could have a material adverse effect on the operations of the Company. Based on the facts known to date, Defendants believe that the claims asserted against them in this lawsuit are without merit, and will continue to defend themselves vigorously against the claims.

In June 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 Atlas America, LLC 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, LLC could not have tortuously interfered with the contract. The Chancery Court dismissed all claims against Atlas America, LLC; however, CNX has appealed this decision.

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

NOTE 13 – CASH DISTRIBUTIONS

Prior to the Merger, the Company was 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 to its Class A and Class B common unitholders in accordance with their respective percentage interests. Effective April 1, 2009, the Company suspended further distributions due to the announcement of its intent to effectuate the Merger (see Note 1). Distributions declared by the Company from inception through December 31, 2008 were as follows:


Date Cash Distribution Paid or Payable	For Quarter Ended	Cash Distribution Per Common Unit			Total Cash Distribution to ATLS
					(in thousands)
February 14, 2007	December 31, 2006	$	0.06	⁽¹⁾	$	1,806

May 15, 2007	March 31, 2007	$	0.43		$	12,944
August 14, 2007	June 30, 2007	$	0.43		$	12,944
November 14, 2007	September 30, 2007	$	0.55		$	16,825
February 14, 2008	December 31, 2007	$	0.57		$	17,437

May 15, 2008	March 31, 2008	$	0.59		$	18,410
August 14, 2008	June 30, 2008	$	0.61		$	19,060
November 14, 2008	September 30, 2008	$	0.61		$	19,060
February 13, 2009	December 31, 2008	$	0.61		$	19,060

⁽¹⁾

Represents a pro-rated cash 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.

NOTE 14 — BENEFIT PLANS

Prior to the Merger on September 29, 2009, the Company had a Long-Term Incentive Plan (“LTIP”), which provided equity incentive awards to officers, employees and directors and employees of its affiliates, consultants and joint-venture partners. Subsequent to the Merger, ATLS assumed the Company’s LTIP and renamed the LTIP as the “Atlas Energy, Inc. Assumed Long-Term Incentive Plan” (“Assumed LTIP”) and each outstanding unit option, phantom unit and restricted unit granted under the LTIP was converted to an equivalent stock option, phantom share or restricted share of ATLS at a ratio of 1.0 unit to 1.16 common shares. No new grant awards will be issued under the Assumed LTIP.

Other than the conversion of the LTIP awards to ATLS options, restricted shares or phantom shares, the terms of the grants that had been awarded under the LTIP remain unchanged under the Assumed LTIP. Awards granted to all participants other than non-employee directors vest 25% upon the third anniversary of the grant date and 75% upon the fourth anniversary of the grant date. Awards to non-employee directors vest 25% per year over four years. Generally, upon termination of service by a grantee, all unvested awards will be forfeited. Upon vesting of a phantom stock award, a grantee is entitled to receive an equivalent number of common shares of ATLS. Non-employee directors have the right, upon the vesting of their phantom stock awards to receive an equivalent number of common shares or, the cash equivalent to the then fair market value of the Company’s common shares.

Restricted Unit and Phantom Units. The fair value of the grants under the Assumed LTIP was based on the closing unit price on the grant date, and was charged to operations over the requisite service periods using the straight-line method. The following table summarizes the pre-Merger unconverted restricted unit and phantom unit activity for the period from January 1, 2007 to September 29, 2009:


	Units		Weighted Average Grant Date Fair Value
Non-vested unit outstanding at January 1, 2007	47,619		$	21.00
Granted	590,950		$	24.63
Vested	(11,904	)	$	21.00
Forfeited	(2,000	)	$	23.06

Non-vested unit 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 unit outstanding at December 31, 2008	768,829		$	23.86
Granted	28,523		$	16.48
Vested	(13,073	)	$	21.70
Forfeited	(46,000	)	$	31.12

Non-vested unit outstanding at September 29, 2009	738,279		$	23.16

Unit Options. Option awards under the Assumed LTIP expire 10 years from the date of grant and were granted with an exercise price equal to the market price of the Company’s stock at the date of grant. For the period from January 1, 2007 to September 29, 2009, the following table summarizes the unconverted number of the Company’s Class B member units prior to the Merger on September 29, 2009 and weighted average exercise price. The following table sets forth the LTIP option activity for the periods indicated:


	Units		Weighted Average Exercise Price
Outstanding at January 1, 2007	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
Granted	5,000		$	25.78
Exercised	—			—
Forfeited or expired	(123,600	)	$	31.96

Outstanding at September 29, 2009	1,784,302		$	23.64

The Company used the Black-Scholes option pricing model to estimate the weighted average fair value per option granted under the Assumed LTIP with the following assumptions:


	Years Ended December 31,
	2009⁽¹⁾		2008⁽¹⁾		2007⁽¹⁾
Expected life (years)		6.25		6.25		6.25
Expected volatility		60%		27-34%		25%
Risk-free interest rate		3.0%		2.8-4.0%		4.7%
Expected dividend yield		0.0%		6.2-7.0%		5.1-8.0%
Weighted average fair value of stock options granted	$	15.18	$	5.69	$	2.96

⁽¹⁾

Based on pre-Merger unconverted original calculations.

The Company recognized $4.9 million, $5.5 million and $4.7 million in compensation expense related to the restricted stock units, phantom units and unit options for the years ended December 31, 2009, 2008 and 2007, respectively. The Company paid $0.4 million, $1.4 million and $0.8 million with respect to distribution equivalent rights (“DER”) for years ended December 31, 2009, 2008 and 2007, respectively. These amounts were recorded as a reduction of members’ equity on the Company’s consolidated balance sheets during the respective period. At December 31, 2009, the Company had no unrecognized compensation expense related to the unvested portion of the restricted shares, phantom shares and stock options.

NOTE 15 — 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. Operating segment data for the periods indicated are as follows (in thousands):


	Years Ended December 31,
	2009			2008			2007
Gas and oil production
Revenues⁽¹⁾	$	278,184		$	311,850		$	206,382
Costs and expenses		(51,941	)		(59,579	)		(32,193	)
Depreciation, depletion and amortization expense		(103,988	)		(91,991	)		(54,383	)
Asset Impairment		(156,359	)		—			—

Segment income (loss)	$	(34,104	)	$	160,280		$	119,806

Well construction and completion
Revenues	$	372,045		$	415,036		$	321,471
Costs and expenses		(315,546	)		(359,609	)		(279,540	)

Segment income	$	56,499		$	55,427		$	41,931

Other partnership management⁽²⁾
Revenues	$	57,404		$	61,769		$	50,814
Costs and expenses		(36,140	)		(30,193	)		(23,057	)
Depreciation, depletion and amortization expense		(4,305	)		(3,443	)		(2,559	)

Segment income	$	16,959		$	28,133		$	25,198

Reconciliation of segment income to net income (loss)
Segment income
Gas and oil production	$	(34,104	)	$	160,280		$	119,806
Well construction and completion		56,499			55,427			41,931
Other partnership management		16,959			28,133			25,198

Total segment income		39,354			243,840			186,935
General and administrative expenses		(58,570	)		(44,658	)		(39,414	)
Interest expense⁽³⁾		(64,951	)		(56,306	)		(30,096	)
Gain (loss) on sale of assets		(6,435	)		(32	)		111

Net income (loss)	$	(90,602	)	$	142,844		$	117,536

Capital expenditures
Gas and oil production	$	141,782		$	343,506		$	191,917
Well construction and completion		—			—			—
Other partnership management		24,858			2,890			4,499
Corporate		1,420			1,260			4,753

Total capital expenditures	$	168,060		$	347,656		$	201,169


	December 31,
	2009		2008
Balance sheet
Goodwill:
Gas and oil production	$	21,527	$	21,527
Well construction and completion		6,389		6,389
Other partnership management		7,250		7,250

	$	35,166	$	35,166

Total assets:
Gas and oil production	$	2,115,867	$	2,254,814
Well construction and completion		12,054		16,399
Other partnership management		44,311		36,632
Corporate		36,521		27,722

	$	2,208,753	$	2,335,567

⁽¹⁾

Revenues for the year ended December 31, 2007 include non-cash gains on mark-to-market derivatives of $26.3 million.

⁽²⁾

Includes revenues and expenses from well services, transportation and administration and oversight that do not meet the quantitative threshold for reporting segment information.

⁽³⁾

The Company notes that interest expense and general and administrative expenses have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.

For the years ended December 31, 2009 and 2007, no single customer exceeded ten percent of the Company’s revenues for its gas and oil production segment. For the year ended December 31, 2008, the Company’s gas and oil production segment had one customer that accounted for approximately 12% of the segment’s consolidated revenues.

NOTE 16 – SUBSEQUENT EVENTS

Monetization of Certain Derivative Positions. In January 2010, the Company received approximately $20.1 million in proceeds from the early settlement of natural gas and oil derivative positions for production periods from 2011 through 2013. In conjunction with the early termination of these derivatives, the Company entered into new derivative positions at prevailing prices at the time of the transaction. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under its revolving credit facility.

NOTE 17 — SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Results of Operations from Oil and Gas Producing Activities The results of operations related to the Company’s oil and gas producing activities during the periods indicated were as follows (in thousands):


	Years Ended December 31,
	2009			2008			2007
Revenues⁽¹⁾	$	278,184		$	311,850		$	206,382
Production costs		(51,941	)		(59,579	)		(32,193	)
Exploration expenses⁽²⁾		(6,522	)		(6,029	)		(4,065	)
Depreciation, depletion and amortization		(103,988	)		(91,991	)		(54,383	)
Asset impairment⁽³⁾		(156,359	)		—			—

	$	(40,626	)	$	154,251		$	115,741

(1)

Includes unrealized gains from mark-to-market derivatives of $26.3 million during the year ended December 31, 2007.

(2)

Represents the Company’s land and leasing activities.

(3)

During the year ended December 31, 2009, the Company recognized a $156.4 million impairment related to its shallow natural gas wells in the Upper Devonian Shale.

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


	Years Ended December 31,
	2009			2008			2007
Natural gas and oil properties:
Proved properties	$	2,261,302		$	2,087,119		$	1,795,871

Unproved properties		41,816			43,749			16,380
Support equipment		8,930			9,527			6,936

		2,312,048			2,140,395			1,819,187
Accumulated depreciation, depletion and amortization⁽¹⁾		(478,912	)		(221,356	)		(136,603	)

	$	1,833,136		$	1,919,039		$	1,682,584

⁽¹⁾

During the year ended December 31, 2009, the company recognized a $156.4 million impairment related to its shallow natural gas wells in the Upper Devonian Shale. 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 during the periods indicated were as follows (in thousands):


	Years Ended December 31,
	2009		2008		2007
Property acquisition costs:
Proved properties	$	24,842	$	63,146	$	1,243,877
Unproved properties		—		27,064		50,100
Exploration costs⁽¹⁾		6,522		6,029		4,065
Development costs		134,708		229,687		168,253

	$	166,072	$	325,926	$	1,466,295

⁽¹⁾

Represents the Company’s land and leasing activities.

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

Oil and Gas Reserve Information. In accordance with the modernization of oil and gas accounting (see Note 2), the Company changed its calculation of proved reserves. Under the current accounting literature, the proved reserves quantities and future net cash flows are estimated using a 12-month average pricing at December 31, 2009 based on the prices on the first day of each month. Using this calculation resulted in the use of lower prices at December 31, 2009 than would have resulted using year-end prices as required by the previous rules. The impact of the new price methodology was negative reserve revisions of 59,133 Mcfe and a reduction in PV-10 standardized measure of $691.6 million.

The preparation of the Company’s natural gas and oil reserve estimates were completed in accordance with its prescribed internal control procedures, which include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. For the year ended December 31, 2009, the Company retained Wright & Company, independent, third-party reserves engineers, to prepare a report of proved reserves. The reserves report included a detailed review of our properties located in Arkansas, Indiana, Kansas, Kentucky, Louisiana, Michigan, New York, North Dakota, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, West Virginia, and Wyoming. Wright & Company’s evaluation was based on more than 35 years of experience

in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations applicable as of December 31, 2009. The Wright & Company report was prepared in accordance with generally accepted petroleum engineering and evaluation principles.

The reserve disclosures that follow reflect estimates of proved reserves consisting of proved developed and proved undeveloped reserves, net to the Company’s interests, of natural gas, crude oil, condensate and NGLs owned at year end and changes in proved reserves during the last three years. Proved oil and gas reserves are those quantities of oil and gas which can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. Proved developed reserves are those proved reserves, which can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from well locations on undrilled acreage or from existing wells where expenditure is required for completion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for undrilled units can be claimed only where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves can only be assigned to acreage for which improved recovery technology has been proven effective by actual tests in the area and in the same reservoir. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating they are scheduled to be drilled within five years, unless specific circumstances, justify a longer time.

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. In addition, the standardized measures 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 Company’s reconciliation of changes in proved reserve quantities is as follows (unaudited):


	Gas (Mcf)		Oil (Bbls)
Balance, January 1, 2007	168,541,574		2,067,646
Extensions, discoveries and other additions⁽¹⁾	126,613,549		23,358
Sales of reserves in-place	(62,699	)	(625	)
Purchase of reserves in-place⁽²⁾	622,851,730		48,634
Transfers to limited partnerships	(11,507,307	)	—
Revisions	(714,501	)	(2,517	)
Production	(20,963,436	)	(153,465	)

Balance, December 31, 2007	884,758,910		1,983,031
Extensions, discoveries and other additions⁽¹⁾	210,824,798		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⁽³⁾	(68,276,626	)	(203,166	)
Production	(33,901,975	)	(158,529	)

Balance, December 31, 2008	990,805,385		1,733,941
Extensions, discoveries and other additions⁽¹⁾	316,551,875		53,576
Sales of reserves in-place	(106,411	)	(1,944	)
Purchase of reserves in-place	110,953		302
Transfers to limited partnerships	(22,125,866	)	—
Revisions⁽⁴⁾	(240,732,396	)	283,672
Production	(35,758,287	)	(199,451	)

Balance, December 31, 2009	1,008,745,253		1,870,096


Proved developed reserves at:
January 1, 2007	107,683,343		2,064,276
December 31, 2007	594,708,965		1,977,446
December 31, 2008	586,655,301		1,685,771
December 31, 2009	524,221,194		1,806,124

Proved undeveloped reserves at:
January 1, 2007	60,858,231		3,370
December 31, 2007	290,049,945		5,585
December 31, 2008	404,150,084		48,170
December 31, 2009	484,524,059		63,971

⁽¹⁾

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

⁽²⁾

Represents the reserves purchased from the acquisition of DGO in June 2007.

⁽³⁾

Represents a decrease in the price of natural gas and oil compared from the year ended December 31, 2007 to the year ended December 31, 2008.

⁽⁴⁾

Represents a decrease in the price of natural gas and oil compared from the year ended December 31, 2008 to the year ended December 31, 2009, based on the change in pricing methodology to a 12-month unweighted average based on the first-day-of-the-month prices for the year ended December 31, 2009.

The following schedule presents the PV-10 standardized measure of estimated discounted future net cash flows relating to proved oil and gas reserves. The estimated future production is priced at a twelve month average for the year ended December 31, 2009, and at year-end prices for the years ended December 31, 2008 and 2007, 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 the dates presented 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 (in thousands):


	Years Ended December 31,
	2009			2008			2007
Future cash inflows	$	4,421,854		$	6,333,935		$	6,408,367
Future production costs		(1,780,244	)		(2,297,091	)		(1,804,199	)
Future development costs		(748,472	)		(618,604	)		(388,111	)

Future net cash flows	$	1,893,138		$	3,418,240		$	4,216,057

Less 10% annual discount for estimated timing of cash flows	$	(1,456,656	)	$	(2,286,299	)	$	(2,734,879	)

PV-10 standardized measure of discounted future net cash flows	$	436,482		$	1,131,941		$	1,481,178

The future cash flows estimated to be spent to develop proved undeveloped properties during the years ending December 31, 2010, 2011, 2012, 2013 and 2014 are $248.1 million, $224.5 million $212.3 million, $36.4 million and $27.1 million, respectively. The following table summarizes the changes in the PV-10 standardize measure of discounted future net cash flows from estimated production of proved oil and gas reserves (in thousands):


	Years Ended December 31,
	2009			2008			2007
Balance, beginning of year	$	1,131,941		$	1,481,178		$	283,441
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs		(226,243	)		(252,270	)		(147,982	)
Net changes in prices and production costs		(474,950	)		(316,970	)		45,261
Revisions of previous quantity estimates		(88,458	)		(46,767	)		(1,208	)
Development costs incurred		20,885			48,092			98,424
Changes in future development costs		(51,423	)		(35,662	)		(14,128	)
Transfers to limited partnerships		(9,834	)		(615	)		(13,998	)
Extensions, discoveries, and improved recovery less related costs		(11,373	)		41,020			170,349
Purchases of reserves in-place		141			5,170			957,137
Sales of reserves in-place, net of tax effect		(304	)		(97	)		(105	)
Accretion of discount		113,194			147,781			74,685
Estimated settlement of asset retirement obligations		(3,676	)		(5,778	)		(4,523	)
Estimated proceeds on disposals of well equipment		3,624			6,329			5,168
Changes in production rates (timing) and other		32,958			60,530			28,657

Outstanding, end of year	$	436,482		$	1,131,941		$	1,481,178

NOTE 18 — QUARTERLY RESULTS (Unaudited)


	Fourth Quarter⁽¹⁾			Third Quarter			Second Quarter			First Quarter
Year ended December 31, 2009:	(in thousands, except unit data)
Revenues	$	201,449		$	161,942		$	146,183		$	198,059
Net income (loss)	$	(133,037	)	$	4,583		$	12,249		$	25,603
Income attributable to non-controlling interests		(19	)		(14	)		(15	)		(15	)

Net income (loss) attributable to owner’s/members’ interests	$	(133,056	)	$	4,569		$	12,234		$	25,588

Net income attributable to Class B member per unit:
Basic	$	—		$	0.07		$	0.19		$	0.52
Diluted	$	—		$	0.07		$	0.19		$	0.52

⁽¹⁾	Upon completion of the Merger on September 29, 2009, the Class B common units of the Company were cancelled. As a result, no income was attributed to such unitholders for the period beginning September 30, 2009.


	Fourth Quarter			Third Quarter			Second Quarter			First Quarter
Year ended December 31, 2008:	(in thousands, except unit data)
Revenues	$	162,044		$	213,948		$	218,021		$	194,642
Net income	$	28,713		$	38,192		$	38,376		$	37,563
Income attributable to non-controlling interests		(16	)		(10	)		(18	)		(20	)

Net income attributable to owner’s/members’ interests	$	28,697		$	38,182		$	38,358		$	37,543

Net income attributable to Class B member per unit:
Basic	$	0.41		$	0.56		$	0.57		$	0.58
Diluted	$	0.41		$	0.55		$	0.57		$	0.58

ITEM 8.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 8A.

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 and with the participation of our disclosure committee appointed by such officers, 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, 2009, our disclosure controls and procedures were effective at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting

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

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

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, 2009. Grant Thornton LLP, an independent registered public accounting firm, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009, which is included herein.

There have been no changes in our internal control over financial reporting during the fourth quarter of 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholder

Atlas Energy Resources, LLC

We have audited Atlas Energy Resources, LLC’s (a Delaware limited liability company) internal control over financial reporting as of December 31, 2009, 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, 2009, based on criteria established in Internal Control – Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the accompanying consolidated balance sheets of Atlas Energy Resources, LLC and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, comprehensive income, owner’s/members’ equity, and cash flows for each of the three years in the period ended December 31, 2009 and our report dated February 26, 2010 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

February 26, 2010

ITEM 8B.

OTHER INFORMATION

None.

PART III

ITEM 9.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Item 9, Directors, Executive Officers and Corporate Governance, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 10.

EXECUTIVE COMPENSATION

Item 10, Executive Compensation, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 11.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS

Item 11, Security Ownership of Certain Beneficial Owners and Management, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 12.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Item 12, Certain Relationships and Related Transactions, and Director Independence, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 13.

PRINCIPAL ACCOUNTING FEES AND SERVICES

Our independent registered public accountants for the fiscal year ended December 31, 2009 was Grant Thornton LLP. Upon the recommendation of the audit committee, approved by the Board, Grant Thornton LLP served as our independent auditors during fiscal year 2009. Grant Thornton LLP has been re-appointed as our independent auditors for fiscal year 2010. For the years ended December 31, 2009 and 2008, Grant Thornton LLP’s accounting fees and services (in thousands) were as follows:


	Years Ended December 31,
	2009		2008
Audit fees⁽¹⁾	$	1,572	$	1,514
Audit-related fees		—		—
Tax fees⁽²⁾		73		110
All other fees		—		—

Total accounting fees and services	$	1,645	$	1,624

⁽¹⁾

Represents the aggregate fees recognized in each of the last two years for professional services rendered by Grant Thornton LLP principally for the audit of our annual financial statements and the review of financial statements included in Form 10-Q and also for services related to registration statements and comfort letters. The fees are for services that are normally provided by Grant Thornton LLP in connection with statutory or regulatory filings or engagements.

⁽²⁾	Represents the aggregate fees recognized in each of the last two years for professional services rendered by Grant Thornton for tax compliance, tax advice, and tax planning.

Audit Committee Pre-Approval Policies and Procedures

The audit committee, on at least an annual basis, reviews audit and non-audit services performed by Grant Thornton LLP as well as the fees charged by Grant Thornton LLP for such services. Our policy is that all audit and non-audit services must be pre-approved by the audit committee. All of such services and fees were pre-approved during 2009 and 2008.

PART IV

ITEM 14.

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 14(a)(1) are set forth in Item 7.

(2)

Financial Statement Schedules

No schedules are required to be presented.

(3)

Exhibits:


Exhibit No.		Description
2.1		Agreement and Plan of Merger dated as of April 27, 2009 among Atlas Energy Resources, LLC, Atlas America, Inc., Atlas Energy Management, Inc. and Merger Sub, as defined therein Schedules and exhibits to the Agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company agrees to furnish a copy of any omitted schedule or similar attachment to the SEC upon request ⁽⁵⁾
3.1		Second Amended and Restated Limited Liability Company Agreement of Atlas Energy Resources, LLC ⁽¹²⁾
3.2		Certificate of Formation of Atlas Energy Resources, LLC ⁽³⁾
4.1		Form of Common Unit Certificate (included as Exhibit A to the Second Amended and Restated Limited Liability Company Agreement of Atlas Energy Resources, LLC)⁽¹²⁾
4.2		Indenture dated as of January 23, 2008 among Atlas Energy Operating Company, LLC, Atlas Energy Finance Corp., as Issuers, the subsidiaries named therein, as Guarantors, and U.S. Bank National Association, as Trustee⁽⁹⁾
4.3		Form of 10.75% Senior Notes due 2018 (included as an exhibit to the Indenture filed as Exhibit 4.2 hereto)
4.4		Senior Indenture dated July 16, 2009 among Atlas Energy Operating Company, LLC, Atlas Energy Finance Corp., as Issuers, the subsidiaries named therein, as Guarantors, and U.S. Bank National Association, as Trustee⁽¹⁰⁾
4.5		First Supplemental Indenture dated July 16, 2009⁽¹⁰⁾
4.6		Form of 12.125% Senior Notes due 2017 (contained in Annex A to the First Supplemental Indenture filed as Exhibit 4.5 hereto)
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⁾
10.1(c)		Second Amendment to Credit Agreement, dated as of April 9, 2009⁽⁶⁾
10.1(d)		Third Amendment to Credit Agreement, dated as of July 10, 2009⁽¹¹⁾
10.2		Management Agreement, dated as of December 18, 2006, among Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, and Atlas Energy Management, Inc.⁽¹⁾
10.3		Agreement for Services among Atlas America, Inc., and Richard Weber, dated April 5, 2006⁽³⁾
10.4		Atlas Energy, Inc. Assumed Long-Term Incentive Plan⁽¹³⁾
10.5		ATN Option Agreement dated as of June 1, 2009, by and among APL Laurel Mountain, LLC, Atlas Pipeline Operating Partnership, L.P. and Atlas Energy Resources, LLC⁽⁸⁾


Exhibit No.		Description
10.6		Gas Gathering Agreement for Natural Gas on the Legacy Appalachian System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble, LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P.⁽¹⁴⁾ Specific terms in this exhibit have been redacted, as marked three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
10.7		Gas Gathering Agreement for Natural Gas on the Expansion Appalachian System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble, LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P.⁽¹⁴⁾ Specific terms in this exhibit have been redacted, as marked three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
12.1		Computation of Ratio of Earnings to Fixed Charges
31.1		Rule 13(a)-14(a)/15d-14(a) Certification
31.2		Rule 13(a)-14(a)/15d-14(a) Certification
32.1		Section 1350 Certification
32.2		Section 1350 Certification
99.1		Summary Reserve Report

⁽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.

⁽⁵⁾

Previously filed as an exhibit to our Form 8-K filed April 28, 2009.

⁽⁶⁾

Previously filed as an exhibit to our Form 8-K filed April 17, 2009.

⁽⁷⁾

[Intentionally omitted]

⁽⁸⁾

Previously filed as an exhibit to our Form 8-K filed June 5, 2009.

⁽⁹⁾

Previously filed as an exhibit to our Form 8-K filed January 24, 2008.

⁽¹⁰⁾

Previously filed as an exhibit to our Form 8-K filed July 17, 2009.

⁽¹¹⁾

Previously filed as an exhibit to our Form 8-K filed July 24, 2009.

⁽¹²⁾

Previously filed as an exhibit to our Form 8-K filed September 30, 2009.

⁽¹³⁾

Previously filed as an exhibit to Atlas Energy, Inc.’s Form S-8 filed on September 30, 2009.

⁽¹⁴⁾

Previously filed as an exhibit to our Form 10-Q for the quarter ended June 30, 2009.

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.

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 February 26, 2010.



/s/ EDWARD E. COHEN Edward E. Cohen		Chairman and Chief Executive Officer


/s/ JONATHAN Z. COHEN Jonathan Z. Cohen		Vice Chairman and Director


/s/ RICHARD D. WEBER Richard D. Weber		President, Chief Operating Officer and Director


/s/ MATTHEW A. JONES Matthew A. Jones		Chief Financial Officer


/s/ SEAN P. MCGRATH Sean P. McGrath		Chief Accounting Officer

ATLAS ENERGY RESOURCES, LLC

Date: February 26, 2010

/s/ EDWARD E. COHEN

Edward E. Cohen

Chairman and Chief Executive Officer

Atlas Energy Resources, LLC 10-K