ATLAS ENERGY, INC. - FORM 10-K

ATLAS ENERGY, INC. - FORM 10-K - February 26, 2010

Attached files

Attached files

file	filename
EX-31.2 - SECTION 302 CFO CERTIFICATION - ATLAS ENERGY, INC.	dex312.htm
EX-99.1 - SUMMARY RESERVE REPORT - ATLAS ENERGY, INC.	dex991.htm
EX-23.1 - CONSENT OF GRANT THORNTON LLP - ATLAS ENERGY, INC.	dex231.htm
EX-23.2 - CONSENT OF WRIGHT & COMPANY, INC. - ATLAS ENERGY, INC.	dex232.htm
EX-32.1 - SECTION 906 CEO CERTIFICATION - ATLAS ENERGY, INC.	dex321.htm
EX-21.1 - SUBSIDIARIES OF ALTAS ENERGY, INC. - ATLAS ENERGY, INC.	dex211.htm
EX-32.2 - SECTION 906 CFO CERTIFICATION - ATLAS ENERGY, INC.	dex322.htm
EX-10.34 - FORM OF RESTRICTED STOCK UNIT AGREEMENT - ATLAS ENERGY, INC.	dex1034.htm
EX-10.33 - FORM OF INCENTIVE STOCK OPTION GRANT AGREEMENT - ATLAS ENERGY, INC.	dex1033.htm
EX-10.32 - FORM OF NON-QUALIFIED STOCK OPTION GRANT AGREEMENT - ATLAS ENERGY, INC.	dex1032.htm
EX-31.1 - SECTION 302 CEO CERTIFICATION - ATLAS ENERGY, INC.	dex311.htm

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: 001-32169

ATLAS ENERGY, INC.

(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:


Title of each class		Name of each exchange on which registered
None		None

Securities registered pursuant to Section 12(g) of the Act:

Common stock, par value $.01 per share

Title of class

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

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 x Accelerated filer ¨ Non-accelerated filer ¨ 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

The aggregate market value of the voting common stock held by non-affiliates of the registrant, based on the closing price of such stock on the last business day of the registrant’s most recently completed second quarter, June 30, 2009, was approximately $0.7 billion.

The number of outstanding shares of the registrant’s common stock on February 25, 2010 was 78,226,206 shares.

DOCUMENTS INCORPORATED BY REFERENCE: None

ATLAS ENERGY, INC. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K

TABLE OF CONTENTS


			Page
PART I	Item 1:	Business	6

	Item 1A:	Risk Factors	26

	Item 1B:	Unresolved Staff Comments	41

	Item 2:	Properties	42

	Item 3:	Legal Proceedings	49

PART II	Item 4:	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	50

	Item 5:	Selected Financial Data	50

	Item 6:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	54

	Item 6A:	Quantitative and Qualitative Disclosures about Market Risk	80

	Item 7:	Financial Statements and Supplementary Data	84

	Item 8:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	164

	Item 8A:	Controls and Procedures	164

	Item 8B:	Other Information	166

PART III	Item 9:	Directors, Executive Officers and Corporate Governance	166

	Item 10:	Executive Compensation	172

	Item 11:	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	192

	Item 12:	Certain Relationships and Related Transactions, and Director Independence Matters	194

	Item 13:	Principal Accounting Fees and Services	198

PART IV	Item 14:	Exhibits and Financial Statement Schedules	198

SIGNATURES			202

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 a publicly traded Delaware corporation whose common shares are listed on the NASDAQ Stock Market under the symbol “ATLS”. 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, 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 with Atlas Energy Resources, LLC (“ATN”), our formerly publicly-traded subsidiary and a Delaware limited liability company, pursuant to the definitive merger agreement previously executed, with ATN surviving as our wholly-owned subsidiary (the “Merger”). Additionally, we changed our name to Atlas Energy, Inc. upon completion of the Merger. As such, the discussion of our business in Item 1 focuses on our development and production of natural gas and oil and our related activities, which is our core business.

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.

In addition to our natural gas development and production operations, we maintain ownership interests in other entities, including Atlas Pipeline Partners, L.P. (“APL”) and Atlas Pipeline Holdings, L.P (“AHD”). Please see our further discussion of these ownership interests under “Other Ownership Interests.”

Business Strategy

Our objective is to achieve capital appreciation and increase shareholder value through growth of our natural gas production and reserves and ongoing fee generation through our investment partnerships on a cost-efficient basis. The key elements of our business strategy are further explained below.

Continue to increase our reserves, production and cash flow through the development of our position in the Marcellus Shale. We will continue to develop our Marcellus Shale acreage position through horizontal drilling and, where not practical to drill horizontally, through vertical drilling. We intend to fund horizontal drilling of Marcellus Shale wells primarily through available cash flow generated from operations. We will fund our vertical Marcellus Shale program and a small portion of our horizontal Marcellus Shale wells through our investment partnerships. Due to the general high degree of development success to date, we believe an active Marcellus Shale drilling program should result in increased proved reserves, production and cash flow.

Continue to increase our reserves, production and cash flow through the development of the Antrim, Chattanooga, and New Albany Shale as well as other conventional shallow formations. We will continue to develop our significant acreage positions in other shale formations and conventional sandstones through both horizontal and vertical drilling. We intend to primarily fund the development drilling of these formations through our investment partnerships.

Continue to grow our fee-based revenue and funds to support and develop drilling through our sponsorship of investment partnerships. For the year ended December 31, 2009, we generated approximately $83.0 million of gross margin from fees paid by the investment partnerships to us for partnership management. As we continue to sponsor investment partnerships, we expect that the fee revenue we generate will continue to add stability to our revenue and cash flows. Furthermore, the carried interests and fees we earn reduce our net investment in our drilling programs and therefore enhance our rates of return on investment.

Continue to manage our exposure to commodity price risk. We actively manage our exposure to commodity price fluctuations by hedging a significant portion of our forecasted production. We use fixed price swaps, collars and puts as mechanisms for the financial hedging of our commodity price risks. We believe that engaging in a systematic hedging program allows us to more easily forecast our projected results, while reducing our exposure to movements in commodity prices, and provides more stability to our operations for our investors.

Continue to maintain control of operations and costs. We believe it is important to be the operator of wells in which we or our investment partnerships have an interest because it allows us to achieve operating efficiencies and control costs. As operator, we are better positioned to control the timing and plans for future enhancement and exploitation efforts, costs of enhancing, drilling, completing and producing the well, and marketing negotiations for our natural gas and oil production to maximize both volumes and wellhead price. As of December 31, 2009, we operated approximately 89% of the properties in which we or our investment partnerships had a working interest in Appalachia and approximately 77% of the properties in which we had a working interest in Michigan/Indiana.

Continue to evaluate strategic acquisitions. We continually evaluate acquisition opportunities in order to increase our reserve base and undeveloped drilling opportunities. We will continue to seek strategic opportunities in our core areas of operation, as well as in other regions that complement our existing asset portfolio or further geographically diversify our reserve base. We will continue our disciplined approach to evaluating acquisitions, focusing on long reserve lives with minimal technical risks and sustainable cash flow accretion.

Subsequent Events

Monetization of Certain Derivative Positions. In January 2010, we received approximately $20.1 million in proceeds from the early settlement of natural gas derivative positions for production periods from 2011 through 2013. In conjunction with the early termination of these derivatives, we 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 ATN’s revolving credit facility.

APL Unit Issuance. In January 2010, APL executed amendments to warrants to purchase 2,689,765 of its common units. The warrants were originally issued along with its common units in connection with a private placement to institutional investors that closed on August 20, 2009. The amendments to the warrants provided

that, for the period January 8 through January 12, 2010, the warrant exercise price was lowered to $6.00 from $6.35 per unit. In connection with the amendments, the holders of the warrants agreed to exercise all of the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan and credit facility.

Recent Developments

Merger Agreement with ATN. On September 29, 2009, we completed our merger with ATN pursuant to the definitive merger agreement, with ATN surviving as our wholly-owned subsidiary. In the Merger, the 33.4 million Class B common units of ATN not previously held by us were exchanged for 38.8 million shares of our common stock (a ratio of 1.16 shares of our common stock for each Class B common unit of ATN). We also changed our name from Atlas America, Inc. to Atlas Energy, Inc. Concurrent with the Merger, the Compensation Committee of our Board of Directors approved the Atlas Energy, Inc. 2009 Stock Incentive Plan, which created a new stock incentive plan for the combined entity. We also have the legacy Atlas America stock incentive plan and assumed the legacy ATN Long-Term Incentive Plan.

Issuance of ATN Senior Unsecured Notes. On July 13, 2009, ATN issued $200.0 million of 12.125% senior unsecured notes (“ATN 12.125% Senior Notes”) due 2017 at 98.116% of par value to yield 12.5% at maturity. We used the net proceeds of $191.7 million, net underwriting fees of $4.5 million, to repay outstanding borrowings under ATN’s revolving credit facility. Interest on the ATN 12.125% Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year. The ATN 12.125% Senior Notes are redeemable on or after August 1, 2013 at certain redemption prices, together with accrued interest at the date of redemption. In addition, before August 1, 2012, we may redeem up to 35% of the aggregate principal amount of the ATN 12.125% Senior Notes with the proceeds of certain equity offerings at a stated redemption price of 112.125% of the principal, plus accrued interest. The ATN 12.125% Senior Notes are junior in right of payment to ATN’s secured debt, including its obligations under the revolving credit facility. The indenture governing the ATN 12.125% Senior Notes contains covenants, including limitations of ATN’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 ATN’s assets. We are not guarantors of ATN’s senior notes, including the ATN 12.125% Senior Notes, or its credit facility.

Amendment of ATN’s Senior Secured Credit Facility. On July 10, 2009, ATN’s credit agreement was amended to, among other things, permit the Merger and to allow ATN to distribute to us (a) amounts equal to our income tax liability attributable to ATN’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, may carry an amount up to $20.0 million for use in the next year.

Monetization of Certain Derivative Positions. In May 2009, we received approximately $28.5 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, we 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 ATN’s revolving credit facility.

northern Appalachian assets, excluding its northern Tennessee operations, of which we will be the largest customer. We used the net proceeds to reduce borrowings under ATN’s revolving credit facility.

Upon completion of the transaction with Laurel Mountain, we entered into new gas gathering agreements with Laurel Mountain which superseded the existing master natural gas gathering agreement and omnibus agreement between us and APL. Under the new gas gathering agreement, we are obligated to pay Laurel Mountain all of the gathering fees we collect from the partnerships, which generally ranges from $0.35 per thousand cubic feet (“Mcf”) to the amount of the competitive gathering fee (which is currently defined as 13% of the gross sales price received for the partnerships gas) plus any excess amount of the gathering fees collected up to an amount equal to approximately 16% of the natural gas sales price. 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.

Geographic and Geologic Overview

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

Marcellus Shale Overview. The Marcellus Shale is a black, organic rich shale formation located at depths between 6,000 and 8,500 feet and ranges in thickness from 75 to 150 feet on our acreage in western Pennsylvania. As of December 31, 2009, we control approximately 584,000 Marcellus Shale gross acres in Pennsylvania, New York and West Virginia, and we continue to expand our position. As of December 31, 2009, we have drilled 226 wells, consisting of 206 vertical wells and 20 horizontal wells, and are currently producing 179 wells into a pipeline. An additional 26 wells are scheduled to be completed and turned online during the first quarter of 2010. Our drilling efforts are currently focused on approximately 270,000 of our existing Marcellus Shale acres in southwestern Pennsylvania, where we have drilled all but two of our Marcellus wells and have now largely delineated our acreage. Almost all of this acreage in southwestern Pennsylvania has or is expected to have ample pipeline capacity using our or Laurel Mountain’s gas gathering infrastructure.

We have made great strides in optimizing our completion practices for vertical Marcellus Shale wells. We have initiated a multiple stage completion process that isolates various portions of the Marcellus package, giving a more effective stimulation of the reservoir. This technique has been used on over 75 wells to date and has consistently illustrated better-than-average peak 24-hour, 30-day, and 60-day cumulative production results. It is anticipated that, where applicable, all future vertical wells will be stimulated in this fashion.

Appalachian Basin Overview. The Appalachian Basin includes the states of Kentucky, Maryland, New York, Ohio, Pennsylvania, Virginia, West Virginia and Tennessee. It is the most mature oil and gas producing region in the United States, having established the first oil production in 1860. Because the Appalachian Basin is located near the energy-consuming regions of the mid-Atlantic and northeastern United States, Appalachian producers have historically sold their natural gas at a premium to the benchmark price for natural gas on the NYMEX. For the twelve months ended December 31, 2009, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin was $0.40 per million British thermal units (“MMBtu”). In addition, our Appalachian gas production also has the advantage of a high energy content, ranging from 1.00 to 1.11 dekatherms (“Dth”) per Mcf. Historically, our gas sales contracts yield upward adjustments from index based pricing for throughput with an energy content above 1.0 Dth per Mcf. This higher energy content resulted in realized premiums averaging 1.05% over normal pipeline quality gas for the twelve months ended December 31, 2009.

Historically, producers in the Appalachian Basin developed oil and natural gas from shallow sandstones with low permeability which are prevalent in the region. These shallow wells are characterized by modest initial volumes, low pressures, and high initial decline rates followed by low annual decline rates. Almost all of these wells were drilled vertically and usually produce for 30 years or more. Shallow sandstone formations in the Appalachian Basin are typically homogenous and have a high degree of step-out development success. The

primary shallow pay zones are shallow sandstones in the Upper Devonian Shale formation. As the step-out development progresses, reserves from newly completed wells are reclassified from the proved undeveloped to the proved developed category and additional adjacent locations are added to proved undeveloped reserves. As a result, the cumulative amount of total proved reserves tends to increase as development progresses. Traditional shallow wells in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. In addition, most wells produce dry natural gas, which does not require processing.

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

Antrim Shale wells produce substantial volumes of water, especially during the early production stages, which must be removed from the formation to initiate gas production. Each well’s gas is transported to a centrally located separation, compression and dehydration facility, where water is separated from it and disposed of, usually in a dedicated salt water disposal well, to minimize water disposal costs. From there gas is compressed and sent via high pressure sales lines to regional treating plants for CO2 removal. Gas is then sent to market via MichCon’s gas distribution network.

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

Horizontal Drilling Overview

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

Gas and Oil Production

Production Volumes. We increased our production volumes for the year ended December 31, 2009 by 6.0% over prior year levels to a record 37.0 Bcfe. Our production for the fourth quarter 2009 was 9.5 Bcfe, reflecting volumetric growth of 4.6% compared with the prior year comparable period and 2.9% compared with the third quarter 2009. The following table shows our total net gas and oil production volumes and production per day for the three year period ended December 31, 2009 (in thousands, except for production per day):


	Years Ended December 31,
	2009		2008	2007
Production:⁽¹⁾⁽²⁾
Appalachia:⁽³⁾
Natural gas (MMcf)	14,568		12,086	9,912
Oil (000’s Bbls)	194		155	153

Total (MMcfe)	15,734		13,014	10,828

Michigan/Indiana:
Natural gas (MMcf)	21,190		21,816	11,051	⁽⁵⁾
Oil (000’s Bbls)	5		4	1	⁽⁵⁾

Total (MMcfe)	21,221		21,839	11,056	⁽⁵⁾

Total:
Natural gas (MMcf)	35,758		33,902	20,963	⁽⁵⁾
Oil (000’s Bbls)	199		159	154	⁽⁵⁾

Total (MMcfe)	36,955		34,853	21,884	⁽⁵⁾


Production per day:⁽¹⁾⁽²⁾
Appalachia:⁽³⁾
Natural gas (Mcfd)	39,912		33,023	27,156
Oil (Bpd)	532	⁽⁴⁾	423	418

Total (Mcfed)	43,106		35,558	29,664

Michigan/Indiana:
Natural gas (Mcfd)	58,056		59,606	59,737	⁽⁵⁾
Oil (Bpd)	14	⁽⁴⁾	11	4	⁽⁵⁾

Total (Mcfed)	58,140		59,672	59,761	⁽⁵⁾

Total:
Natural gas (Mcfd)	97,968		92,629	86,893	⁽⁵⁾
Oil (bpd)	546	⁽⁴⁾	434	422	⁽⁵⁾

Total (Mcfed)	101,246		95,230	89,425	⁽⁵⁾

⁽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.

⁽⁵⁾	Amounts represent production volumes related to our Michigan acquisition from the acquisition date (June 29, 2007).

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 shows our production revenues and our average sales prices for our oil and gas production for the three year period ended December 31, 2009, along with our average production costs, taxes, and transmission and compression costs in each of the reported periods:


	Years Ended December 31,
	2009		2008		2007
Production revenues (in thousands):
Appalachia:⁽¹⁾
Natural gas revenue	$	105,642	$	113,595	$	88,269
Oil revenue		12,518		14,340		10,747

Total revenues	$	118,160	$	127,935	$	99,016

Michigan/Indiana:
Natural gas revenue	$	159,832	$	183,550	$	81,045
Oil revenue		192		365		64

Total revenues	$	160,024	$	183,915	$	81,109

Total:
Natural gas revenue	$	265,474	$	297,145	$	169,314
Oil revenue		12,710		14,705		10,811

Total revenues	$	278,184	$	311,850	$	180,125

Average sales price:⁽²⁾
Natural gas (per Mcf):
Total realized price, after hedge⁽³^{) (}⁴⁾	$	7.67	$	9.13	$	8.66	⁽⁶⁾
Total realized price, before hedge⁽³^{) (}⁴⁾	$	4.07	$	9.23	$	7.22	⁽⁶⁾
Oil (per Bbl):
Total realized price, after hedge	$	70.81	$	92.35	$	70.16	⁽⁶⁾
Total realized price, before hedge	$	57.26	$	91.79	$	70.16	⁽⁶⁾

Production costs (per Mcfe):⁽²⁾
Appalachia:⁽¹⁾
Lease operating expenses⁽⁵⁾	$	1.06	$	1.03	$	0.86
Production taxes		0.03		0.03		0.03
Transportation and compression		0.70		0.87		0.74

	$	1.79	$	1.93	$	1.63

Michigan/Indiana:
Lease operating expenses	$	0.72	$	0.75	$	0.68	⁽⁶⁾
Production taxes		0.25		0.54		0.26	⁽⁶⁾
Transportation and compression		0.25		0.29		0.38	⁽⁶⁾

	$	1.22	$	1.58	$	1.32	⁽⁶⁾

Total:
Lease operating expenses⁽⁵⁾	$	0.86	$	0.85	$	0.77	⁽⁶⁾
Production taxes		0.16		0.35		0.21	⁽⁶⁾
Transportation and compression		0.44		0.51		0.49	⁽⁶⁾

	$	1.46	$	1.71	$	1.47	⁽⁶⁾

⁽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 years ended December 31, 2008 and 2007. 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, $12.4 million and $12.3 million for the years ended December 31, 2009, 2008 and 2007, respectively, received from the settlement of ineffective derivative gains associated with the acquisition of our Michigan operations. Also excludes non-cash derivative gains of $26.3 million associated with the Michigan acquisition for the year ended December 31, 2007.

⁽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 years ended December 31, 2008 and 2007. 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).

⁽⁶⁾	Amounts include data related to our Michigan acquisition from the acquisition date (June 29, 2007).

Investment Partnerships

We generally fund our drilling activities through sponsorship of tax-advantaged investment partnerships. Accordingly, the amount of development activities we undertake depends in part upon our ability to obtain investor subscriptions to the partnerships. We 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 the investment partnerships proportionate to the amount of capital and the value of the leasehold acreage we contribute, typically 20% to 31% of the overall capitalization in a particular partnership. We also receive an additional interest in each partnership for operating the wells and managing the general partner, typically 7% to 10%, for which we do not make any additional capital contribution. This brings our total interest in the partnerships in a range from 27% to 41%.

Over the last three years, we raised over $1.2 billion from outside investors for participation in our drilling partnerships. Net proceeds from these partnerships are used to fund the investors’ share of drilling and completion costs under our drilling contracts with the partnerships. We recognize revenues from drilling operations on the percentage-of-completion method as the wells are drilled, rather than when funds are received. Our fund raising activities for sponsored drilling partnerships during the last three years are summarized in the following table (amounts in millions):


	Drilling Program Capital
Years Ended December 31,	Investor Contributions		Our Contributions		Total Capital
2009	$	351.9	$	97.5	$	449.4
2008		438.4		146.3		584.7
2007		363.3		137.6		500.9

Total	$	1,153.6	$	381.4	$	1,535.0

Drilling Operations

The number of wells we drill will vary depending on the amount of money we raise through our investment partnerships, the cost of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table shows the number of gross and net development wells we drilled for ourselves and our investment partnerships during the last three years. We did not drill any exploratory wells during the three year period ended December 31, 2009:


	Years Ended December 31,
	2009	2008	2007
Gross wells drilled:
Appalachia	187	830	1,106
Michigan/Indiana	97	173	115

Total	284	1,003	1,221


Net wells drilled:
Appalachia	170	786	1,021
Michigan/Indiana	85	143	92

Total	255	929	1,113


Our share of net wells drilled⁽¹⁾:
Appalachia	56	279	378
Michigan/Indiana	25	140	92

Total	81	419	470


Gross dry wells drilled:
Appalachia	—	8	11
Michigan/Indiana	4	—	—

Total	4	8	11


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

Total	4	3	4

⁽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.

We do not operate any of the rigs or related equipment used in our drilling operations, relying instead on specialized subcontractors or joint venture partners for all drilling and completion work. This enables us to streamline our operations and conserve capital for investments in new wells, infrastructure and property acquisitions, while generally retaining control over all geological, drilling, engineering and operating decisions. We perform regular inspection, testing and monitoring functions on our operated wells and Laurel Mountain’s gathering systems with our own personnel.

As managing general partner of the investment partnerships, we receive the following fees:

•

Well construction and completion. For each well that is drilled by an investment partnership, we receive an 18% mark-up on those costs incurred to drill and complete the well. For our investment partnerships that were formed prior to November 2008, the mark-up was 15%.

•

Administration and oversight. For each well drilled by an investment partnership, we receive a fixed fee of approximately $249,000 for horizontal Marcellus Shale wells and a range of $15,700 to $62,200 for all other well types. For our investment partnerships that were formed prior to April 2009, the fixed fee for wells ranged from was $15,700 to $62,000, including horizontal Marcellus Shale wells. Additionally, the partnership pays us a monthly per well administrative fee of $75 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

•

Well services. Each partnership pays us a monthly per well operating fee, currently $100 to $1,500, for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

•

Gathering. Each royalty owner, partnership and certain other working interest owners pay us a gathering fee, which generally ranges from $0.35 per Mcf to the amount of the competitive gathering fee, currently defined as 16% of the gross sales price. Under our new gas gathering agreements with Laurel Mountain, which were entered into upon its formation on May 31, 2009 (see further discussion under “Recent Developments”), we are obligated to pay to Laurel Mountain all of the gathering fees we collect from the various owners. Prior to the gas gathering agreements with Laurel Mountain, we were required to remit these gas gathering fees 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%. We also recognize our proportionate share of gathering fees based on our percentage interest in the well, which is included in gas and oil production expense.

We generally agree to subordinate up to 50% of our share of net production revenues to specified returns to the investor partners, typically 10% per year for the first five years of distributions. We subordinated $3.9 million of our revenues, net of corresponding production costs, for the year ended December 31, 2009, which reduced our cash distributions received from the investment partnerships for the year. We did not subordinate our share of revenues from any of our investment partnerships during the years ended December 31, 2008 and 2007.

Our investment partnerships provide tax advantages to our investors because an investor’s share of the partnership’s intangible drilling cost deduction may be used to offset ordinary income. Intangible drilling costs include items that do not have salvage value, such as labor, fuel, repairs, supplies and hauling. For our investment partnerships that were formed after October 2008, approximately 85% of the subscription proceeds received have been used to pay 100% of the partnership’s intangible drilling costs. For example, an investment of $10,000 generally permits the investor to deduct from taxable ordinary income approximately $8,500 in the year in which the investor invests. For our investment partnerships that were formed prior to October 2008, approximately 90% of the subscription proceeds received were used to pay 100% of the partnership’s intangible drilling costs.

Natural Gas and Oil Leases

The typical natural gas and oil lease agreement provides for the payment of royalties to the mineral owner for all natural gas and oil produced from any well(s) drilled on the leased premises. In the Appalachian Basin, this amount is typically 1/8^th(12.5%) resulting in a 87.5% net revenue interest to us, and, in Michigan, this amount is typically 1/6^th (16.67%) resulting in an 83.3% net revenue interest to us. In certain instances, this royalty amount may increase to 1/6^thin the Appalachian Basin and to 3/16^th (18.75%) in Michigan when leases are taken from larger landowners or mineral owners such as coal and timber companies.

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

Because the acquisition of natural gas and oil leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are often held by other natural gas and oil operators. In order to gain the right to drill these leases, we may elect to farm-in leases and/or purchase leases from other natural gas and oil operators. Typically the assignor of such leases will reserve an overriding royalty interest, ranging in the Appalachian Basin from 1/32^ndto 1/16^th(3.125% to 6.25%), which further reduces the net revenue interest available to us to between 84.375% and 81.25%, and in Michigan from 3.33% to 5.33%, which further reduces the net revenue interest available to us to between 80.0% and 78.0%.

The interests in some of our operated properties and of natural gas and oil leases retain the option to participate in the drilling of wells on leases farmed out or assigned to us for a retained working interest of up to 50% of the wells drilled on the covered acreage. In this event, our working interest ownership will be reduced by the amount retained by the third party. In all other instances, we anticipate owning a 100% working interest in newly drilled wells.

Contractual Revenue Arrangements and Major Customers

Appalachia Natural Gas. We market the majority of our natural gas production in the Appalachian Basin to Hess Corporation, Colonial Energy, Inc., Atmos Energy, UGI Energy Services, Equitable Gas Co., EQT Energy, Sequent Energy and South Jersey Resources Group. The remainder of our natural gas production in the Appalachian Basin has been primarily supplied to gas marketers, local distribution companies, industrial or other end-users, and companies generating electricity. The sales price of natural gas produced in the Appalachian Basin has been primarily based upon the NYMEX spot market price. For the year ended December 31, 2009, Hess Corporation and Equitable Gas Company accounted for approximately 15% and 11% of our total Appalachian natural gas and oil production revenues, respectively, with no other single customer accounting for more than 10% of our Appalachian natural gas and oil production revenues for this period.

Michigan/Indiana Natural Gas. In Michigan, we have natural gas sales agreements with DTE Energy Company (“DTE”) through December 31, 2012. DTE has the obligation to purchase all of the natural gas produced and delivered by us and our affiliates from specific projects at certain delivery points. For the year ended December 31, 2009, DTE accounted for approximately 42% of our Michigan and Indiana natural gas and oil production revenues under these sales agreements, in most instances at NYMEX spot market pricing. Three additional customers accounted for more than 32% of our Michigan and Indiana natural gas and oil production revenues. The remainder of our natural gas production in Michigan and Indiana has been primarily supplied to gas marketers, local distribution companies, industrial or other end-users, and companies generating electricity. The sales price of natural gas produced in Michigan has been primarily based upon the NYMEX spot market price and Indiana has been primarily based upon Texas Gas Zone SL and Chicago spot market prices.

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

Investment Partnerships. We generally fund our drilling activities through sponsorship of tax-advantaged investment partnerships. 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. See “Drilling Operations” for further discussion.

Natural Gas Hedging

We seek to provide greater stability in our cash flows through our use of financial derivatives and physical hedges. The financial derivatives 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 and oil at future dates and generally cover one-month periods for up to six years in the future. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, we have a risk management committee to assure that all financial trading is done in compliance with our hedging policies and procedures. We do not intend to contract for positions that we cannot offset with actual production.

Third-party marketers to which we sell natural gas also use NYMEX-based financial instruments to hedge their pricing exposure and make price hedging opportunities available to us through physical hedge transactions. These transactions are not deemed hedges for accounting purposes because they require firm delivery of natural gas and are considered normal sales of natural gas. We generally limit these arrangements to much smaller quantities than those projected to be available at any delivery point. The price paid by these third-party marketers for volumes of natural gas sold under these sales agreements may be significantly different from the underlying monthly spot market value.

Natural Gas Gathering Agreements

Upon completion of the contribution of APL’s Appalachia gathering systems to Laurel Mountain, on May 31, 2009, we entered into natural gas gathering agreements with Laurel Mountain which superseded the master natural gas gathering agreement and omnibus agreement, both dated February 2, 2000, between us and APL: (1) a Gas Gathering Agreement for Natural Gas on the Legacy Appalachian System with respect to the existing gathering systems and expansions to it (the “Legacy Agreement”) and (2) a Gas Gathering Agreement for Natural Gas on the Expansion Gathering System with respect to other gathering systems constructed within the specified area of mutual interest (the “Expansion Agreement” and, collectively with the Legacy Agreement, the “Gathering Agreements”). Under the Gathering Agreements, we will dedicate our natural gas production in the Appalachian Basin to Laurel Mountain for transportation to interstate pipeline systems, local distribution companies, and/or end users in the area, subject to certain exceptions. In return, Laurel Mountain is required to accept and transport our dedicated natural gas in the Appalachian Basin subject to certain conditions.

Under the Gathering Agreements, we are required to pay a gathering fee to Laurel Mountain that is the generally the same as the gathering fee required under the terminated agreements, the greater of $0.35 per mcf or 16% of the gross sales price except that a lower fee applies with respect to specific wells subject to existing contracts calling for lower minimum gathering fees and if Laurel Mountain fails to perform specified obligations. In addition, if an investment partnership pays a lesser competitive gathering fee for the natural gas it transports using Laurel Mountain’s gathering system, which currently is 13% of the gross sales price, then we, and not the partnership, will have to pay the difference to Laurel Mountain.

The provisions in the Gathering Agreements regarding the allocation of responsibility for constructing additional flowline are substantially the same as the provisions in the terminated agreements. To the extent that we own wells or propose wells that are within 2,500 feet of Laurel Mountain’s gathering system, we must at our cost construct up to 2,500 feet of flowline as necessary to connect the wells to the gathering system. For wells more than 2,500 feet from Laurel Mountain’s gathering system, if we construct a flow line to within 1,000 feet of Laurel Mountain’s gathering system, then Laurel Mountain must, at its own cost, extend its gathering system to connect to such flowline.

The Gathering Agreements remain in effect so long as gas from our wells is produced in economic quantities without lapse of more than 90 days.

Competition

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

Many of our competitors possess greater financial and other resources which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than we do. Moreover, we also compete with a number of other companies that offer interests in investment partnerships. As a result, competition for investment capital to fund investment partnerships is intense.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas of the Appalachian region and Michigan/Indiana. These seasonal anomalies may pose challenges for meeting our well construction objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay our operations. In the past, we have drilled a greater number of wells during the winter months, because we have typically received the majority of funds from our investment partnerships during the fourth calendar quarter. Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

Environmental Matters and Regulation

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

•

require the acquisition of various permits before drilling commences;

•

require the installation of expensive pollution control equipment and water treatment facilities;

•

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

•

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

•

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

•

impose substantial liabilities for pollution resulting from our operations; and

•

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

These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently enact new, and revise existing, environmental laws and regulations, and any new laws or changes to existing laws that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs. We believe that our operations substantially comply with all currently applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict how environmental laws and regulations that may take effect in the future may impact our properties or operations. For the three year period ended December 31, 2009, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. We are not aware of any environmental issues or claims that will require material capital expenditures during 2010, or that will otherwise have a material impact on our financial position or results of operations.

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

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

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

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

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

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

Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state. These permits may require pretreatment of produced waters before discharge. Compliance with such permits and requirements may be costly. Further, 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. Recently, this subject has received much regulatory and legislative attention at both the federal and state level and we anticipate that the permitting and compliance requirements applicable to hydraulic fracturing activity are likely to become more stringent and could have a material adverse impact on our business and operations.

The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The Clean Water Act also requires specified facilities to maintain and implement spill prevention, control and countermeasure plans and to take measures to minimize the risks of petroleum spills. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for failure to obtain or non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe our operations are in substantial compliance with the requirements of the Clean Water Act.

Air Emissions. The Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through permits and other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic and other air pollutants at specified sources. Some of

our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new emission limitations. These regulations may increase the costs of compliance for some facilities, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance. These laws and regulations also apply to entities that use natural gas as fuel, and may increase the costs of compliance of our customers to the point where demand for natural gas is affected. We believe that our operations are in substantial compliance with the requirements of the Clean Air Act.

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

Greenhouse Gas Regulation and Climate Change. Natural gas contains methane, which is considered to be a greenhouse gas. Additionally, the burning of natural gas produces carbon dioxide, which is also a greenhouse gas. Published studies have suggested that the emission of greenhouse gases may be contributing to global warming, although that conclusion is the subject of ongoing debate within the scientific community. To date, legislative and regulatory initiatives relating to greenhouse gas emissions have not had a material impact on our business. However, both Congress and the EPA are actively considering imposing enhanced regulatory and reporting requirements applicable to greenhouse gas emissions. One significant development in this regard is that in December 2009, the EPA issued a determination that greenhouse gases cause or contribute to air pollution and pose a risk of endangerment to public health. This determination allows the EPA to promulgate regulations relating to greenhouse gases under the Clean Air Act. Similarly, some of the states in which we conduct business are giving consideration to these same issues. The timing and outcome of these ongoing legislative and regulatory efforts is currently uncertain, and we cannot predict what specific impact such efforts could have on our business in the future. However, it would appear that the trend is toward increased regulation, and that the regulatory environment with respect to emissions of greenhouse gases will be more stringent in the future than it is today. Any such enhanced regulation could result in increased compliance costs, possible restrictions on our operations and possible impact on demand of our products. We would expect that any such new regulations would impact our competitors in the natural gas industry in much the same manner as it would impact us.

There are also ongoing legislative and regulatory efforts to encourage the use of cleaner energy technologies. While natural gas is a fossil fuel, it is considered to be more benign, from a greenhouse gas standpoint, than other carbon-based fuels, such as coal or oil. Thus future regulatory developments could have a positive impact on our business to the extent that they either decrease the demand for other carbon-based fuels or position natural gas as a favored fuel.

In addition to domestic regulatory developments, the United States is a participant in multi-national discussion intended to deal with the greenhouse gas issue on a global basis. To date, those discussions have not resulted in the imposition of any specific regulatory system, but such talks are continuing and may result in treaties or other multi-national agreements that could have an impact on our business.

Finally, as noted above, the scientific community continues to engage in a healthy debate as to the impact of greenhouse gas emissions on planetary conditions. For example, such emissions may be responsible for increasing global temperatures, and/or enhancing the frequency and severity of storms, flooding and other similar adverse weather conditions. We do not believe that these conditions are having any material current adverse impact on our business, and we are unable to predict at this time what if any long-term impact such climate effects would have.

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

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

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

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the location of wells;

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the manner in which water necessary to develop wells is managed;

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the method of drilling and casing wells;

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

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the plugging and abandoning of wells; and

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notice to surface owners and other third parties.

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

State Regulation. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Michigan imposes a 4.9% severance tax on natural gas and a 7.3% severance tax on oil, Tennessee imposes a 3% severance tax on natural gas and oil production and Ohio imposes a severance tax of $0.25 per Mcf of natural gas and $0.10 per Bbl of oil. While Pennsylvania has historically not imposed a severance tax, there has been legislation proposed to initiate the concept of a severance tax on oil and gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead

prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.

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

Other Ownership Interests

In addition to our production operations, we also maintain ownership interests in the following entities at December 31, 2009:

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1,112,000 common units, representing a 2.2% ownership interest, in Atlas Pipeline Partners, L.P. (“Atlas Pipeline Partners” or “APL”), a publicly traded Delaware limited partnership (NYSE: APL) and midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions;

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17,808,109 common units, representing a 64.3% ownership interest, in Atlas Pipeline Holdings, L.P. (“Atlas Pipeline Holdings” or “AHD”), a publicly traded Delaware limited partnership (NYSE: AHD) and owner of the general partner of APL. We manage AHD through our ownership of its general partner; and

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Lightfoot Capital Partners LP (“Lightfoot LP”) and Lightfoot Capital Partners GP LLC (“Lightfoot GP”), the general partner of Lightfoot (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. We have an approximate direct and indirect 18% ownership interest in Lightfoot GP and a commitment to invest a total of $19.7 million in Lightfoot. We also have a direct and indirect ownership interests in Lightfoot LP.

AHD, which owns APL’s general partner and manages APL, had the following ownership interests in APL at December 31, 2009:

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a 2.0% general partner interest, which entitles it to receive 2% of the cash distributed by APL;

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all of the incentive distribution rights (“IDRs”), which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per APL common unit in any quarter. Commencing July 1, 2009, AHD agreed to allocate up to $3.75 million of its incentive distribution rights per quarter back to APL (“the IDR Adjustment Agreement”) after AHD receives the initial $7.0 million per quarter of incentive distribution rights;

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5,754,253 common units, representing approximately 11.4% of the outstanding common units, or an 11.2% ownership interest in APL; and

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15,000 $1,000 par value 12.0% cumulative preferred limited partner units.

Our consolidated financial statements contain the financial statements of AHD, which we control, and APL, which is controlled by AHD.

AHD’s cash generating assets currently consist solely of its interests in APL. APL is a leading provider of natural gas gathering services in the Anadarko and Permian Basins in the southwestern and mid-continent United

States and the Appalachian Basin in the eastern United States. In addition, APL is a leading provider of natural gas processing and treatment services in Oklahoma and Texas. APL’s business is conducted in the midstream segment of the natural gas industry through two reportable segments: its Mid-Continent operations and its Appalachian operations.

As of December 31, 2009, through its Mid-Continent operations, APL owns and operates:

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eight active natural gas processing plants with aggregate capacity of approximately 900 MMcfd and one treating facility with a capacity of approximately 200 MMcfd, located in Oklahoma and Texas; and

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9,100 miles of active natural gas gathering systems located in Oklahoma, Kansas and Texas, which transport gas from wells and central delivery points in the Mid-Continent region to APL’s natural gas processing and treating plants or third party pipelines.

As of December 31, 2009, APL’s Appalachia operations are conducted principally through its 49% ownership interest in Laurel Mountain, a joint venture which owns and operates a 1,800-mile natural gas gathering system in the Appalachia Basin located in eastern Ohio, western New York, and western Pennsylvania. APL also owns an 80-mile natural gas gathering system in northeastern Tennessee. Laurel Mountain gathers the majority of our natural gas production in the Appalachia Basin.

APL’s credit facility permits it to pay distributions only if, pro forma for such payment, its senior secured leverage ratio, as defined in the credit agreement, is less than or equal to 2.75 to 1.00 and its minimum liquidity, as defined in the credit agreement, is at least $50 million. If APL does not meet these financial thresholds, we will not receive distributions on our APL common units nor will AHD receive distributions with respect to the IDRs and common units held by it. Furthermore, AHD’s credit facility prohibits it from paying any distributions to its unitholders until the credit facility has been terminated, which is scheduled to occur in April 2010.

Employees

As of December 31, 2009, we employed 872 persons.

Available Information

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

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;

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

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technological advances affecting energy consumption;

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domestic and foreign governmental relations, regulations and taxation;

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the impact of energy conservation efforts;

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

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the price and availability of alternative fuels.

In the past, the prices of natural gas and oil have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 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 or in wells currently connected to APL’s pipeline system being shut in by their operators until prices improve. Any of these events 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 ATN’s and APL’s 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 APL’s, and consequently AHD’s, business and financial condition that AHD and APL 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, further 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, ATN and APL use financial and physical hedges for their natural gas, crude oil and NGL 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. ATN, APL and AHD also have exposure to interest rate fluctuations as a result of variable rate debt under their credit facilities. ATN, APL and AHD have entered into interest rate swap agreements to convert a portion of this variable rate debt to a fixed rate obligation, thereby reducing their 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 shareholders’ 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 equity and 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 acquisitions may prove greater than estimated at the time of the acquisition.

Any 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:

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operating a significantly larger combined entity;

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

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integrating personnel with diverse business backgrounds and organizational cultures;

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consolidating operational and administrative functions;

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

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

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customer or key employee loss from the acquired businesses;

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a significant increase in its indebtedness; and

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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.

We may pay a limited dividend or no dividend to our shareholders.

We may pay a limited dividend or no dividend, to our shareholders. The determination of the amount of dividends on our common stock, if any, will be determined solely by our board of directors, based upon its analysis of factors that it deems relevant. Generally, these factors include our results of operations, financial condition, capital requirements and investment opportunities.

We may issue additional shares of common stock without the approval of our shareholders, which may dilute our common shareholders’ existing ownership interests and could depress the market price of our common stock.

Our charter authorizes us to issue 114,000,000 shares of common stock, of which approximately 78,000,000 shares are currently outstanding. We may issue shares of our common stock or other securities from time to time as consideration for acquisitions and investments. If any such acquisition or investment is significant, the number of shares of common stock, or the number or aggregate principal amount, as the case may be, of other securities that we may issue may in turn be substantial. The issuance of additional shares of our common stock or other securities may have the following effects:

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the proportionate ownership of our existing common shareholders’ interest may decrease;

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the relative voting strength of each previously outstanding share of common stock may be diminished; and

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the market price of our common stock may decline.

We may issue shares of preferred stock in the future, which could make it difficult for another company to acquire us or could otherwise adversely affect holders of our common stock, which could depress the price of our common stock.

Our charter authorizes us to issue up to 1,000,000 shares of one or more series of preferred stock. Our board of directors has the authority to determine the preferences, limitations and relative rights of shares of preferred stock and to fix the number of shares constituting any series and the designation of such series, without any further vote or action by our shareholders. Our preferred stock could be issued with voting, liquidation, dividend and other rights superior to the rights of our common stock. The potential issuance of preferred stock may delay or prevent a change in control, discouraging bids for our common stock at a premium over the market price, and materially and adversely affect the market price and the voting and other rights of the holders of our common stock.

ATN has a substantial amount of indebtedness which could adversely affect our financial position.

ATN currently has a substantial amount of indebtedness. As of February 1, 2010, it had total debt of approximately $768.4 million, consisting of $602.4 million of senior notes and $166.0 million of borrowings under its credit facility. ATN may also incur significant additional indebtedness in the future. Its substantial indebtedness may:

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

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limit ATN’s ability to borrow additional funds for working capital, capital expenditures, acquisitions or other general business purposes;

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

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require ATN to use a substantial portion of its cash flow from operations to make debt service payments;

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

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

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

ATN’s ability to service its 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 ATN’s 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 ATN’s indebtedness. We may not be able to affect any of these remedies on satisfactory terms or at all.

Covenants in ATN’s debt agreements restrict its business in many ways.

The indenture governing ATN’s senior notes and its credit facility contain various covenants that limit its ability and/or its subsidiaries’ ability to, among other things:

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

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issue redeemable stock and preferred stock;

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pay dividends or distributions or redeem or repurchase capital stock;

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prepay, redeem or repurchase debt;

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make loans, investments and capital expenditures;

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enter into agreements that restrict distributions from its subsidiaries;

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sell assets and capital stock of its subsidiaries;

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enter into certain transactions with affiliates; and

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

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

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.

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, the 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 us.

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. See Item 1: Business “—Environmental Matters and Regulation” for a description of these laws and regulations. These include, for example:

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

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

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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

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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 5,900 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 5,900 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:

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

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unexpected operational events and drilling conditions;

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adverse weather conditions;

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facility or equipment malfunctions;

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title problems;

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pipeline ruptures or spills;

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compliance with environmental and other governmental requirements;

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unusual or unexpected geological formations;

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formations with abnormal pressures;

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injury or loss of life;

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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;

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fires, blowouts, craterings and explosions; and

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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.

The combined company resulting from the Merger may fail to realize the anticipated cost savings, growth opportunities and synergies and other benefits anticipated from the merger, which could adversely affect the value of our common stock.

The success of the Merger will depend, in part, on our ability to realize the anticipated synergies and growth opportunities from combining the businesses, as well as the projected stand-alone cost savings and revenue growth trends identified by each company. In addition, on a combined basis, we expect to benefit from operational synergies resulting from the consolidation of capabilities and elimination of redundancies as well as greater efficiencies from increased scale. Management also intends to focus on revenue synergies for the combined entity. However, management must successfully combine our businesses in a manner that permits these cost savings and synergies to be realized. In addition, it must achieve the anticipated savings without adversely affecting current revenues and our investments in future growth. If we are not able to successfully achieve these objectives, the anticipated cost savings, revenue growth and synergies may not be realized fully or at all, or may take longer to realize than expected.

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

We, ATN, 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 the ATN’s 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 ATN’s public unitholders in connection with the negotiation of the Merger. In particular, the amended complaint alleged that the Merger was not entirely fair to ATN’s 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.

The credit facilities of ATN, APL and AHD restrict their payment of distributions.

ATN’s credit facility limits the amount of cash dividends it may pay us to (a) amounts equal to our income tax liability attributable to ATN’s 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.

We have risk through our ownership interests in APL and AHD.

Because we consolidate our operations with those of APL and AHD, we share in their results of operations. Accordingly, there may be fluctuations in the results reported in our financial statements based on the performance of APL and AHD. We are also subject to the risks associated with their business and operations, including:

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changes in general economic conditions;

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fluctuations in natural gas and NGL prices;

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failure or delays in us and third parties achieving expected production from natural gas projects;

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competitive conditions in the midstream industry;

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actions taken on non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers;

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changes in the availability and cost of capital;

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operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

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construction costs or capital expenditures exceeding estimated or budgeted amounts;

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the effects of existing and future laws and governmental regulations;

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the effects of future litigation; and

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other factors discussed in APL’s and AHD’s Annual Reports on Form 10-K and as are or may be detailed from time to time in their public announcements and other filings with the SEC.

We have guaranteed certain debt of AHD and therefore will be liable for this debt if AHD is unable to meet its obligations. In addition, we hold two promissory notes from AHD, and we may not be paid if AHD defaults.

On June 1, 2009, AHD entered into an amendment to its revolving credit facility, dated as of July 26, 2006, with Wachovia Bank, National Association, as administrative agent, and the lenders thereunder. In connection with the execution of the amendment, AHD agreed to immediately repay $30 million of the

approximately $46 million outstanding indebtedness under the credit facility, such that approximately $16 million remained outstanding. AHD agreed to repay $4 million of the remaining $16 million on each of July 13, 2009, October 13, 2009 and January 13, 2010, with the balance of indebtedness being due on the original maturity date of April 13, 2010. In connection with the execution of this amendment, we agreed to guarantee the remaining debt outstanding under the credit facility up to $17.5 million. Accordingly, if AHD is unable to make such payments, we, as guarantor, will be responsible for such payment. Pursuant to this guaranty, we paid $8 million in respect of payments due on July 13, 2009 and October 13, 2009 under the AHD credit agreement.

AHD’s $30 million repayment was funded from the proceeds of (i) a loan from us in the amount of $15 million, with an interest rate of 12% per annum and a maturity date the day following the day AHD pays all outstanding indebtedness due under the credit facility, and (ii) the purchase by APL of $15 million of preferred equity in a newly formed subsidiary of AHD. Moreover, in consideration of our guaranty, AHD issued a guaranty note to us whose principal amount is increased on the first day of each fiscal quarter by an amount equal to 3.75% per annum multiplied by the outstanding principal amount of indebtedness under AHD’s credit facility plus a $1.0 million guaranty fee. The maturity date on this note is the day following the day AHD pays all outstanding indebtedness due under the credit facility. Both promissory notes issued by AHD to us are payable-in-kind until their maturity date. If AHD defaults on either note, we may not receive any of the principal or interest due under such notes.

If our share price declines, the common shareholders could lose a significant part of their investment.

The market price of our common shares could be subject to wide fluctuations in response to a number of factors, most of which we cannot control including:

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

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

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

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Changes in market valuations of similar companies;

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Departures of key personnel;

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Commencement of or involvement in litigation;

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

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Variations in the amount of our quarterly cash distributions;

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Future issuances and sales of our shares; and

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

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

ITEM 1B:

UNRESOLVED STAFF COMMENTS

None.

ITEM 2:

PROPERTIES

Natural Gas and Oil Reserves

In December 2008, the Securities and Exchange Commission (“SEC”) approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of Regulation S-X and Items 201, 801, and 802 of Regulation S-K effective for fiscal years ending on or after December 31, 2009. These new disclosure requirements are referred to as “Modernization of Oil and Gas Reporting” and include provisions that:

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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.

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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.

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

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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”.

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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.

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Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures are required related 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.

We have complied with these disclosure requirements for the year ended December 31, 2009.

The following tables summarize information regarding our estimated proved natural gas and oil reserves as of the dates indicated. Proved reserves are the estimated quantities of crude oil and natural gas, which, by an analysis of geological and engineering data, can be estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic conditions, operating methods and government regulations (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The estimated reserves include reserves attributable to our direct ownership interests in oil and gas properties as well as the reserves attributable to our percentage interests in the oil and gas properties owned by investment partnerships in which we own partnership interests. All of the reserves are generally located in the Appalachian Basin, in Michigan’s Lower Peninsula and in the southwestern corner of Indiana. For the year ended December 31, 2009, we based our estimates of proved reserves on the 12-month unweighted average price of the first-day-of-the-month price for each calendar month 2009 and then applied any basis and British Thermal Units (“btu”) differentials specifically applicable to each oil and gas property based on location and pricing details. For the years ended December 31, 2008 and 2007, we based our estimates of proved reserves using the natural gas

and oil prices as of December 31 of the respective year. The following table summarizes the natural gas and oil prices used in the estimation of proved reserves:


	December 31,
	2009		2008		2007
Natural gas (per Mmbtu)	$	3.87	$	5.71	$	6.93
Oil (per Bbl)	$	61.18	$	44.80	$	90.30

Fluctuations in the price used in the estimation of proved reserves can cause significant variations in the resulting reserve calculation. The following table represents our PV-10 reserve amounts as of December 31, 2009 under three different pricing scenarios:


	Sensitivity of Reserves to Prices As of December 31, 2009
Proved reserves:	SEC Modernization Methodology⁽¹⁾		Previous SEC Methodology⁽²⁾		NYMEX Calculation Methodology⁽³⁾
Natural gas reserves (Mmcf)		1,008,064		1,067,254		1,086,113
Oil (Mbbls)		1,871		1,975		2,017
PV-10	$	436,484	$	1,128,114	$	1,436,861

⁽¹⁾

Amounts determined based on the recently adopted SEC “Modernization of Gas and Oil Accounting”. The pricing used in this calculation represents a 12-month unweighted average price of the first-of-the-month price for each calendar month during the year ended December 31, 2009. The average base price for natural gas was $3.87 per Mmbtu and the average base price for crude oil was $61.18 per bbl.

⁽²⁾

Amounts determined based on the reserve calculation methodology utilized prior to the issuance and adoption of the SEC’s “Modernization of Gas and Oil Accounting”. The pricing used in this calculation represents the closing price on December 31, 2009. The base price for natural gas was $5.79 per Mmbtu and the base price for crude oil was $79.39 per bbl.

⁽³⁾

Amounts determined based on the 12-month unweighted average price per year from the publicly traded NYMEX 2010 to 2015 natural gas and oil forward curve. The five year average base price for natural gas was $6.43 per Mmbtu and the five year average base price for crude oil was $87.50 per bbl.

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

The preparation of our natural gas and oil reserve estimates were completed in accordance with our prescribed internal control procedures, which include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. For the year ended December 31, 2009, we retained Wright & Company, Inc. (“Wright & Company”), a third-party, independent petroleum engineering firm, 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, including the qualifications of the chief technical person responsible for the report, was prepared in accordance with generally accepted petroleum engineering and evaluation principles and is attached as Exhibit 99.1 to this Annual Report on Form 10-K.

Results of drilling, testing and production subsequent to the date of the estimate may justify revision of this estimate. Future prices received from the sale of natural gas and oil may be different from those estimated by our independent petroleum engineering firm in preparing their reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced and the proved undeveloped reserves may not be developed within the periods anticipated. Please read “Item 1A: Risk Factors”. You should not construe the estimated PV-10 and standardized measure values as representative of the current or future fair market value of our proved natural gas and oil properties. PV-10 and standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas and oil prices or for the escalation of expenses and capital costs. The meaningfulness of these estimates depends upon the accuracy of the assumptions upon which they were based.

We evaluate natural gas reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas reserves. We deduct operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows. The following table presents our reserve information for the previous three years. We base the estimates on operating methods and conditions prevailing as of the dates indicated:


	Proved natural gas and oil reserves at December 31,
	2009	2008	2007
Proved reserves:
Appalachia:
Natural gas reserves (Mmcf):
Proved developed reserves	139,064	139,659	131,100
Proved undeveloped reserves⁽¹⁾	347,625	223,930	86,976

Total proved reserves of natural gas	486,689	363,589	218,076

Oil reserves (Mbbl):
Proved developed reserves	1,800	1,678	1,966
Proved undeveloped reserves	64	48	6

Total proved reserves of oil	1,864	1,726	1,972

Total proved reserves (Mmcfe):
Proved developed reserves	149,864	149,727	142,896
Proved undeveloped reserves	348,009	224,218	87,012

Total proved reserves	497,873	373,945	229,908

Michigan/Indiana:
Natural gas reserves (Mmcf):
Proved developed reserves	385,157	446,996	463,609
Proved undeveloped reserves⁽¹⁾	136,899	180,220	203,074

Total proved reserves of natural gas	522,056	627,216	666,683

Oil reserves (Mbbl):
Proved developed reserves	7	8	11
Proved undeveloped reserves	—	—	—

Total proved reserves of oil	7	8	11

Total proved reserves (Mmcfe):
Proved developed reserves	385,199	447,044	463,675
Proved undeveloped reserves	136,899	180,220	203,074

Total proved reserves	522,098	627,264	666,749


	Proved natural gas and oil reserves at December 31,
	2009			2008			2007
Total:
Natural gas reserves (Mmcf):
Proved developed reserves		524,221			586,655			594,709
Proved undeveloped reserves⁽¹⁾		484,524			404,150			290,050

Total proved reserves of natural gas		1,008,745			990,805			884,759

Oil reserves (Mbbl):
Proved developed reserves		1,807			1,686			1,977
Proved undeveloped reserves		64			48			6

Total proved reserves of oil		1,871			1,734			1,983

Total proved reserves (Mmcfe)		1,019,971			1,001,209			896,657

Standardized measurement estimate of cash flows of proved reserves (in thousands):⁽²⁾
Appalachia:
Proved developed reserves	$	197,080		$	288,637		$	394,999
Proved undeveloped reserves		(123,762	)		(34,180	)⁽³⁾		8,813

Total standardized measure estimate	$	73,318		$	254,457		$	403,812

Michigan/Indiana:
Proved developed reserves	$	374,663		$	728,245		$	869,310
Proved undeveloped reserves		(11,497	)		149,239			208,056

Total standardized measure estimate	$	363,166		$	877,484		$	1,077,366

Total:
Proved developed reserves	$	571,743		$	1,016,882		$	1,264,309
Proved undeveloped reserves		(135,259	)		115,059			216,869

Total standardized measurement estimate	$	436,484		$	1,131,941		$	1,481,178

Standardized measure of discounted future cash flows (in thousands)⁽²⁾	$	404,524		$	924,741		$	1,144,990

⁽¹⁾

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

⁽²⁾	The following reconciles the PV-10 value to the standardized measure:


	Proved natural gas and oil reserves at December 31,
	2009			2008			2007
PV-10 value	$	436,484		$	1,131,941		$	1,481,178
Income tax effect		(31,960	)		(207,200	)		(336,188	)

Standardized measure	$	404,524		$	924,741		$	1,144,990

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

At December 31, 2009, the PV-10 of proved natural gas and oil reserves, before taxes, was $436.5 million, a decrease of $695.4 million compared with the PV-10 of $1,131.9 million at December 31, 2008. The decrease in PV-10 was largely the result of a change in the price calculation based on amendments to the SEC’s oil and gas disclosure requirements. Under the previous SEC unweighted price calculation method, the PV-10 of proved reserves at December 31, 2009 would have been $1,128.1 million, based on the year-end natural gas price of $5.79 per mmbtu and the year-end oil price of $79.39 per bbl.

Proved Undeveloped Reserves (“PUDS”)

PUD Locations. As of December 31, 2009, we had 965 PUD locations totaling approximately 484.9 Bcfe’s of natural gas and oil. Approximately 73 of these PUDs have been assigned to horizontal drilling locations associated with our major development area of the Marcellus Shale in Fayette, Greene, Washington, and Westmoreland counties, Pennsylvania. The new SEC rules expanded the technologies that a company can use to establish reserves. The SEC currently allows the use of techniques that have been proven effective through documented evidence, such as actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies that has been field-tested and has been demonstrated to provide results with reasonable certainty, consistency and repeatability within the formation being evaluated, or in an analogous formation. As a result, 66 of the 73 Marcellus horizontal drilling locations are included as PUDs because of the expanded SEC definition of technologies that may be applied to reserve estimation.

We also have an additional 153 Marcellus vertical PUD locations and 129 shallow well locations in Appalachia. In our Michigan/Indiana region, we have 576 Antrim and 34 New Albany PUD locations.

Changes in PUDs. Changes in PUDS that occurred during the year ended December 31, 2009 were due to the following:

•

New PUDS of approximately 296.6 Bcfe were acquired;

•

Conversion of approximately 11.6 Bcfe from PUDs to proved developed reserves; and

•

Negative revisions of approximately 203.0 Bcfe in PUDs primarily due to changes in commodity prices.

Development Costs. Costs incurred related to the development of PUDs were approximately $134.7 million, $229.7 million, and $168.3 million for the years ended December 31, 2009, 2008 and 2007, respectively.

Drilling Plans. For the year ending December 31, 2010, our primary drilling activities will be focused on the development of our Marcellus Shale vertical and horizontal PUD locations, as well as the continued development of our Tennessee, Michigan and Indiana acreage.

Productive Wells

The following table sets forth information regarding productive natural gas and oil wells in which we have a working interest as of December 31, 2009. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, directly or through our ownership interests in investment partnerships, and net wells are the sum of our fractional working interests in gross wells, based on the percentage interest we own in the investment partnership that owns the well:


	Number of productive wells⁽¹⁾
	Gross	Net
Appalachia:
Oil wells	444	296
Gas wells	7,704	3,192

Total	8,148	3,488

Michigan/Indiana:
Oil wells	—	—
Gas wells	2,583	1,992

Total	2,583	1,992

Total:
Oil wells	444	296
Gas wells	10,287	5,184

Total	10,731	5,480

⁽¹⁾

Includes our proportionate interest in wells owned by 96 investment partnerships for which we serve as managing general partner and various joint ventures. This does not include royalty or overriding interests in 518 wells.

Developed and Undeveloped Acreage

The following table sets forth information about our developed and undeveloped natural gas and oil acreage as of December 31, 2009. The information in this table includes the proportionate interest in acreage owned by our investment partnerships:


	Developed acreage⁽¹⁾		Undeveloped acreage⁽²⁾
	Gross⁽³⁾	Net⁽⁴⁾	Gross⁽³⁾	Net⁽⁴⁾
Arkansas	2,560	403	—	—
Indiana	8,608	6,895	242,021	116,499
Kansas	160	20	—	—
Kentucky	924	462	9,060	4,530
Louisiana	1,819	206	—	—
Michigan	318,275	247,993	25,756	22,783
Mississippi	40	3	—	—
Montana	—	—	2,650	2,650
New York	20,501	14,973	42,207	42,207
North Dakota	639	96	—	—
Ohio	112,740	94,619	31,064	31,064
Oklahoma	4,323	468	—	—
Pennsylvania	144,310	144,310	382,172	382,172
Tennessee	20,040	18,522	121,491	121,491
Texas	4,520	329	—	—
West Virginia	1,078	539	14,632	11,948
Wyoming	—	—	80	80

	640,537	529,838	871,133	735,424

⁽¹⁾

Developed acres are acres spaced or assigned to productive wells.

⁽²⁾

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

⁽³⁾

A gross acre is an acre in which we and our investment partnerships own an interest. The number of gross acres is the total number of acres in which we and our investment partnerships own an interest.

⁽⁴⁾

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

The leases for our developed acreage generally have terms that extend for the life of the wells, while the leases on our undeveloped acreage have terms that vary from less than one year to five years. We paid rentals of approximately $4.8 million during the year ended December 31, 2009 to maintain leases on our undeveloped acreage.

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

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

A description of all other properties can be found 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 us and ATN’s 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 ATN’s public unitholders in connection with the negotiation of the Merger. In particular, plaintiffs allege that the Merger was not entirely fair to ATN’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 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. ATN 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

Our common stock trades on the NASDAQ Stock Market under the symbol “ATLS.” At the close of business on February 24, 2010, there were 235 holders of record of our common stock. The following table sets forth the high and low sale prices per share of our common stock as reported by the NASDAQ Stock Market and the cash dividends declared:


	High⁽¹⁾		Low⁽¹⁾		Cash Dividends Declared⁽²⁾
Year ended December 31, 2009:
Fourth quarter	$	32.30	$	24.32	$	–
Third quarter	$	27.55	$	15.05	$	–
Second quarter	$	20.12	$	8.48	$	–
First quarter	$	18.79	$	6.98	$	–

Year ended December 31, 2008:
Fourth quarter	$	34.58	$	11.00	$	0.05
Third quarter	$	46.25	$	30.32	$	0.05
Second quarter	$	50.06	$	40.06	$	0.03
First quarter	$	42.41	$	30.63	$	0.03

⁽¹⁾

Quarterly share prices have been adjusted to reflect the 3-for-2 stock split on May 30, 2008.

⁽²⁾

The determination of the amount of future cash dividends declared, if any, is at the sole discretion of our Board of Directors and will depend on various factors affecting our financial conditions and other matters the Board of Directors deems relevant.

On April 22, 2008, our Board of Directors approved a three-for-two stock split affected in the form of a 50% stock dividend. Shareholders of record as of May 21, 2008, received one additional share of common stock for each two shares of common stock they owned on that date. The shares were distributed on May 30, 2008, and the adjusted per share stock price was reported by the NASDAQ Stock Market, effective June 2, 2008.

APL’s credit facility permits it to pay distributions only if, pro forma for such payment, its senior secured leverage ratio, as defined in the credit agreement, is less than or equal to 2.75 to 1.00 and its minimum liquidity, as defined in the credit agreement, is at least $50 million. If APL does not meet these financial thresholds, we will not receive distributions on our APL common units nor will AHD receive distributions with respect to the incentive distribution rights and common units held by it. Furthermore, AHD’s credit facility prohibits it from paying any distributions to its unitholders until the credit facility has been terminated, which is scheduled to occur in April 2010.

For information concerning common stock authorized for issuance under our stock incentive plans, see Item 11, “Security Ownership of Certain Beneficial Owners and Management – Equity Compensation Plan Information”.

ITEM 5.

SELECTED FINANCIAL DATA

In June 2006, we changed our fiscal year end to December 31 from September 30. As such, the following information within the table includes data for the years ended December 31, 2009, 2008, 2007 and 2006, the three months ended December 31, 2005, our transition period and the fiscal year ended September 30, 2005. We

have derived the selected financial data set forth in the table for each of the years ended December 31, 2009, 2008 and 2007 and at December 31, 2009 and 2008 from our consolidated financial statements appearing elsewhere in this report, which have been audited by Grant Thornton LLP, independent registered public accounting firm. We derived the financial data for the year ended December 31, 2006, the three months ended December 31, 2005 and the fiscal year ended September 30, 2005 and at December 31, 2007, 2006 and 2005 and September 30, 2005 from our consolidated financial statements which are not included in this report.

Our consolidated financial statements contain our accounts and those of our subsidiaries, including:

•

Atlas Energy Resources, LLC (“Atlas Energy Resources” or “ATN”), our former publicly-traded subsidiary which completed its initial public offering on December 18, 2006. On September 29, 2009, we completed our Merger, with ATN surviving as our wholly-owned subsidiary (the “Merger”);

•

Atlas Pipeline Holdings, L.P. (“Atlas Pipeline Holdings” or “AHD”), our publicly-traded subsidiary which completed its initial public offering on July 26, 2006. At December 31, 2009, we had a 64.3% ownership interest in AHD and a 100% ownership interest in its general partner, through which we control AHD; and

•

Atlas Pipeline Partners, L.P. (“Atlas Pipeline Partners” or “APL”), our publicly-traded subsidiary which AHD controls through its 100% ownership of APL’s general partner. At December 31, 2009, we had a 2.2% direct ownership interest in APL and AHD had a 13.2% ownership interest in APL.

Due to the structure of our ownership interests in ATN, AHD and APL, in accordance with generally accepted accounting principles, we consolidate the financial statements of these subsidiaries into our financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in ATN prior to the Merger, AHD and APL are reflected as income (loss) attributable to non-controlling interests in our consolidated statements of operations and as a component of shareholders’ equity on our consolidated balance sheets. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us and our wholly-owned subsidiaries and the consolidated results of AHD, including APL’s financial results, adjusted for non-controlling interests in ATN’s net income (loss) prior to the Merger on September 29, 2009 and AHD’s and APL’s net income (loss).

The selected financial data set forth in the table include our historical consolidated financial statements, which have been adjusted to reflect the following:

•

In May 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system (“NOARK”). In accordance with prevailing accounting literature, we retrospectively adjusted our prior period consolidated financial statements to reflect the amounts related to the operations of NOARK as discontinued operations; and

•

The adoption of Statement of 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. ASC 810-10-65-1 also requires consolidated net income to be reported and disclosed on the face of the consolidated statements of operations at amounts that include the amounts attributable to both the parent and the non-controlling interest. We adopted the requirements of ASC 810-10-65-1 on January 1, 2009, and have reflected the retrospective application for all periods presented.

The following table should be read together with our consolidated financial statements and notes thereto included within Item 7, “Financial Statements and Supplementary Data” and Item 6, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report.


	Years Ended December 31,												Three Months Ended December 31, 2005			Year Ended September 30, 2005
	2009			2008			2007			2006			Three Months Ended December 31, 2005			Year Ended September 30, 2005
	(in thousands, except per share data)
Statement of operations data:
Revenues:
Gas and oil production	$	278,184		$	311,850		$	180,125		$	88,449		$	24,086		$	63,499
Well construction and completion		372,045			415,036			321,471			198,567			42,145			134,338
Transmission, gathering and processing		815,755			1,384,212			767,085			367,551			108,708			262,829
Administration and oversight		15,613			19,362			18,138			11,762			2,964			9,875
Well services		20,191			20,482			17,592			12,953			2,561			9,552
Gain (loss) on asset sales		105,005			(32	)		916			2,748			2			104
Gain (loss) on mark-to-market derivatives		(37,005	)		(63,480	)		(153,325	)		2,316			(138	)		1,887
Other, net		17,814			11,415			9,780			5,428			316			4,415

Total revenues		1,587,602			2,098,845			1,161,782			689,774			180,644			486,499


Costs and expenses:
Gas and oil production		45,737			48,194			24,184			8,499			1,721			6,044
Well construction and completion		315,546			359,609			279,540			172,666			36,648			116,816
Transmission, gathering and processing		680,099			1,153,555			617,629			315,081			96,406			229,816
Well services		9,330			10,654			9,062			7,337			1,487			5,167
General and administrative		108,421			57,787			111,180			44,312			9,614			24,563
Depreciation, depletion and amortization		200,725			178,269			100,838			39,408			9,346			24,895
Goodwill and other asset impairment		166,683			676,860			—			—			—			—

Total costs and expenses		1,526,541			2,484,928			1,142,433			587,303			155,222			407,301

Operating income (loss)		61,061			(386,083	)		19,349			102,471			25,422			79,198
Interest expense		(169,983	)		(144,065	)		(93,677	)		(26,439	)		(5,420	)		(11,467	)
Gain on early extinguishment of debt		—			19,867			—			—			—			—

Income (loss) from continuing operations before income taxes		(108,922	)		(510,281	)		(74,328	)		76,032			20,002			67,731
Income tax provision (benefit)		(49,069	)		(5,021	)		13,283			26,713			6,577			20,018

Income (loss) from continuing operations		(59,853	)		(505,260	)		(87,611	)		49,319			13,425			47,713
Income from discontinued operations, net of income tax provision		59,769			19,671			29,471			10,986			5,044			—

Income (loss) before cumulative effect of accounting change		(84	)		(485,589	)		(58,140	)		60,305			18,469			47,713
Cumulative effect of accounting change, net of income tax provision		—			—			—			3,825			—			—

Net income (loss).		(84	)		(485,589	)		(58,140	)		64,130			18,469			47,713
(Income) loss attributable to non-controlling interests		(71,902	)		479,431			93,476			(18,283	)		(6,745	)		(14,773	)

Net income (loss) attributable to common shareholders.	$	(71,986	)	$	(6,158	)	$	35,336		$	45,847		$	11,724		$	32,940


	Years Ended December 31,												Three Months Ended December 31, 2005			Year Ended September 30, 2005
	2009			2008			2007			2006			Three Months Ended December 31, 2005			Year Ended September 30, 2005
	(in thousands, except per share data)
Net income (loss) attributable to common shareholders per share ⁽¹⁾:
Basic:
Income (loss) from continuing operations attributable to common shareholders	$	(1.55	)	$	(0.19	)	$	0.82		$	1.01		$	0.24		$	0.73
Income from discontinued operations attributable to common shareholders		0.09			0.04			0.05			0.02			0.02			—

Net income (loss) attributable to common shareholders	$	(1.46	)	$	(0.15	)	$	0.87		$	1.03		$	0.26		$	0.73


Diluted⁽²⁾:
Income (loss) from continuing operations attributable to common shareholders	$	(1.55	)	$	(0.19	)	$	0.78		$	0.99		$	0.24		$	0.73
Income from discontinued operations attributable to common shareholders		0.09			0.04			0.05			0.02			0.02			—

Net income (loss) attributable to common shareholders	$	(1.46	)	$	(0.15	)	$	0.83		$	1.01		$	0.26		$	0.73

Cash dividends declared per share	$	—		$	0.17		$	0.11		$	—		$	—		$	—

Balance sheet data (at period end):
Property, plant and equipment, net⁽³⁾	$	3,555,802		$	3,744,815		$	3,210,785		$	884,812		$	535,933		$	508,822
Total assets⁽³⁾		4,406,163			4,890,131			4,919,052			1,379,838			1,059,751			762,566
Total debt, including current portion		2,048,572			2,413,082			1,994,456			324,151			298,781			191,727
Total shareholders’ equity		1,703,516			1,529,568			2,008,944			677,728			456,147			310,473

Cash flow data:
Net cash provided by (used in) operating activities⁽⁴⁾	$	241,229		$	(47,416	)	$	195,085		$	62,186		$	53,485		$	113,409
Net cash provided by (used in) investing activities⁽⁴⁾		77,197			(643,893	)		(3,508,157	)		(184,157	)		(195,567	)		(296,255	)
Net cash provided by (used in) financing activities		(402,295	)		649,909			3,273,881			268,108			179,046			171,935

⁽¹⁾

Amounts have been adjusted to reflect Atlas Energy’s 3-for-2 splits on May 30, 2008, May 25, 2007 and March 10, 2006.

⁽²⁾

For the year ended December 31, 2008, approximately 1,735,000 stock awards were excluded from the computation of diluted net income (loss) per common share because the inclusion of such shares would have been anti-dilutive.

⁽³⁾

Certain pre-development costs and joint venture receivables previously netted with “Liabilities associated with drilling contracts” of $3.6 million, $3.6 million and $1.5 million as of December 31, 2005 and September 30, 2005, respectively, have been reclassified from “Liabilities associated with drilling contracts” to oil and gas properties within “Property, plant and equipment” and accounts receivable to conform to the presentation of “Total assets” for all other periods presented.

⁽⁴⁾

Net cash flows provided by operating activities and net cash flows used in investing activities have been restated for the three months ended December 31, 2005 and the fiscal year ended September 30, 2005 to conform to the current presentation for all other periods presented (see note 2 above). As a result, net cash flows provided by operating activities have been increased by $0.7 million and $1.4 million for the three months ended December 31, 2005 and the fiscal year ended September 30, 2005, respectively, and net cash flows used in investing activities has been decreased by the same amount for the respective periods.

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 Item 5, “Selected Financial Data” and our consolidated financial statements and related notes appearing elsewhere in this report.

BUSINESS OVERVIEW

We are a publicly traded Delaware corporation whose common units are listed on the NASDAQ Stock Market under the symbol “ATLS”. On September 29, 2009, we completed our merger with Atlas Energy Resources, LLC (“ATN”), our formerly publicly traded subsidiary and a Delaware limited liability company, pursuant to the definitive merger agreement previously executed between us and ATN, with ATN surviving as our wholly-owned subsidiary (the “Merger”).

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: the Marcellus Shale of western Pennsylvania, the Antrim Shale of northern Michigan, the Chattanooga Shale of northeastern Tennessee and the New Albany Shale of west central Indiana. We specialize in development of these natural gas basins, because they provide repeatable, low-risk drilling opportunities. We are also a leading sponsor and manager of tax-advantaged direct investment natural gas and oil partnerships in the United States. We fund the drilling of natural gas and oil wells on our acreage by sponsoring and managing tax advantaged investment partnerships. We generally structure our investment partnerships so that, upon formation of a partnership, we co-invest in and contribute leasehold acreage to it, enter into drilling and well operating agreements with it and become its managing general partner.

The following is a summary of our key operating measures as of and for the year ended December 31, 2009:


	Appalachia		Michigan/ Indiana		Total
Proved reserves (Mmcfe)		497,873		522,098		1,008,745

Standardized measure estimate of cash flows of proved reserves (in thousands)	$	34,914	$	369,610	$	404,524

Acreage:
Gross developed acreage		313,654		326,883		640,537
Gross undeveloped acreage – Marcellus Shale		383,551		—		383,551
Gross undeveloped acreage – Other		219,805		267,777		487,582

Total gross acreage		917,010		594,660		1,511,670

Net developed acreage		274,950		254,888		529,838
Net undeveloped acreage – Marcellus Shale		383,551		—		383,551
Net undeveloped acreage – Other		212,591		139,282		351,873

Total net acreage		871,092		394,170		1,265,262

Net core Marcellus Shale acreage (included above)						269,902

Production per day (Mcfed)		43,106		58,140		101,246

Investor contributions to drilling investment partnerships (in millions)					$	351.9

Direct and indirect gross well working interests		9,296		2,543		11,839
Gross wells drilled		187		97		284
Marcellus Shale wells drilled (included above)						126

OTHER OWNERSHIP INTERESTS

In addition to our production operations, we also maintain ownership interests in the following entities at December 31, 2009:

•

Atlas Pipeline Holdings, L.P. (“Atlas Pipeline Holdings” or “AHD”), our publicly-traded subsidiary (NYSE: AHD). At December 31, 2009, we had a 64.3% ownership interest in AHD and a 100% ownership interest in its general partner, through which we control AHD;

•

Lightfoot Capital Partners LP (“Lightfoot LP”) and Lightfoot Capital Partners GP LLC (“Lightfoot GP”), the general partner of Lightfoot (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. We have an approximate direct and indirect 18% ownership interest in Lightfoot GP and a commitment to invest a total of $19.7 million in Lightfoot. We also have direct and indirect ownership interests in Lightfoot LP.

FINANCIAL PRESENTATION

Our consolidated financial statements contain our accounts and those of our subsidiaries, including ATN, AHD and APL. Due to the structure of our ownership interests in ATN, AHD and APL, in accordance with generally accepted accounting principles, we consolidate the financial statements of these subsidiaries into our financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in ATN prior to the Merger, AHD and APL are reflected as income (loss) attributable to non-controlling interests in our consolidated statements of operations and as a component of shareholders’ equity on our consolidated balance sheets. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us and our wholly-owned subsidiaries and the consolidated results of AHD, including APL’s financial results, adjusted for non-controlling interests in ATN’s net income (loss) prior to the Merger on September 29, 2009 and AHD’s and APL’s net income (loss).

On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system (“NOARK”). As such, we have adjusted the prior year consolidated financial information presented to reflect the amounts related to the operations of the NOARK as discontinued operations.

SUBSEQUENT EVENTS

Monetization of Certain Derivative Positions. In January 2010, we 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, we 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 ATN’s revolving credit facility.

APL Unit Issuance. In January, 2010, APL executed amendments to warrants to purchase 2,689,765 of its common units. The warrants were originally issued along with its common units in connection with a private placement to institutional investors that closed on August 20, 2009. The amendments to the warrants provided that, for the period January 8 through January 12, 2010, the warrant exercise price was lowered to $6.00 from $6.35 per unit. In connection with the amendments, the holders of the warrants agreed to exercise all of the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan and credit facility.

RECENT DEVELOPMENTS

Merger Agreement with Atlas Energy Resources, LLC. On September 29, 2009, we completed our merger with ATN pursuant to the definitive merger agreement previously executed, with ATN surviving as our wholly-owned subsidiary. In the Merger, the 33.4 million Class B common units of ATN not previously held by us were exchanged for 38.8 million shares of our common stock (a ratio of 1.16 shares of our common stock for each Class B common unit of ATN). We also changed our name from Atlas America, Inc. to Atlas Energy, Inc. Concurrent with the Merger, the Compensation Committee of the Board of Directors approved the Atlas Energy, Inc. 2009 Stock Incentive Plan, which created a new stock incentive plan for the combined entity. We also have the legacy Atlas America stock incentive plan and assumed the legacy ATN Long-Term Incentive Plan.

Issuance of ATN Senior Unsecured Notes. On July 13, 2009, ATN issued $200.0 million of 12.125% senior unsecured notes (“ATN 12.125% Senior Notes”) due 2017 at 98.116% of par value to yield 12.5% at maturity. We used the net proceeds of $191.7 million, net underwriting fees of $4.5 million, to repay outstanding borrowings under ATN’s revolving credit facility (see “ATN Credit Facility”). Interest on the ATN 12.125% Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year. The ATN 12.125% Senior Notes are redeemable on or after August 1, 2013 at certain redemption prices, together with accrued interest at the date of redemption. In addition, before August 1, 2012, we may redeem up to 35% of the aggregate principal amount of the ATN 12.125% Senior Notes with the proceeds of certain equity offerings at a stated redemption price of 112.125% of the principal, plus accrued interest. The ATN 12.125% Senior Notes are junior in right of payment to ATN’s secured debt, including its obligations under the revolving credit facility. The indenture governing the ATN 12.125% Senior Notes contains covenants, including limitations of ATN’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 ATN’s assets. We are not guarantors of ATN’s senior notes, including the ATN 12.125% Senior Notes, or its credit facility.

Amendment of ATN’s Senior Secured Credit Facility. On July 10, 2009, ATN’s credit agreement was amended to, among other things, permit the Merger and to allow ATN to distribute (a) amounts equal to our income tax liability attributable to ATN’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, may carry an amount up to $20.0 million for use in the next year.

Sale of Natural Gas Gathering and Processing Assets. On May 31, 2009, we completed the sale of two natural gas processing plants and associated pipelines located in southwestern Pennsylvania for cash of approximately $10.0 million to Laurel Mountain Midstream, LLC (“Laurel Mountain”), a newly-formed joint venture between 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. Laurel Mountain owns and operates all of APL’s previously owned northern Appalachian assets, excluding its northern Tennessee operations, of which we will be the largest customer. We recorded a loss on the sale of the two natural gas processing plants and associated pipelines of $4.3 million which is recorded on our consolidated statements of operations for the year ended December 31, 2009. We used the net proceeds to reduce borrowings under ATN’s revolving credit facility.

Upon completion of the transaction with Laurel Mountain, we entered into new gas gathering agreements with Laurel Mountain which superseded the existing master natural gas gathering agreement and omnibus agreement between us and APL. Under the new gas gathering agreement, we are obligated to pay Laurel Mountain all of the gathering fees we collect from the partnerships, which generally ranges from $0.35 per thousand cubic feet (“Mcf”) to the amount of the competitive gathering fee (which is currently defined as 13% of the gross sales price received for the partnerships gas) plus any excess amount of the gathering fees collected up to an amount equal to approximately 16% of the natural gas sales price. The new gathering agreement contains additional provisions which define certain obligations and options of each party to build and connect newly drilled wells to any Laurel Mountain gathering system.

CONTRACTUAL REVENUE ARRANGMENT

Michigan/Indiana Natural Gas. In Michigan, we have natural gas sales agreements with DTE Energy Company (“DTE”) through December 31, 2012. DTE has the obligation to purchase all of the natural gas produced and delivered by us and our affiliates from specific projects at certain delivery points. For the year ended December 31, 2009, DTE accounted for approximately 42% of our Michigan and Indiana natural gas and oil production revenues under these sales agreements, in most instances at NYMEX spot market pricing. No other single customer accounted for more than 10% of our Michigan and Indiana natural gas and oil production revenues. The remainder of our natural gas production in Michigan and Indiana has been primarily supplied to gas marketers, local distribution companies, industrial or other end-users, and companies generating electricity. The sales price of natural gas produced in Michigan has been primarily based upon the NYMEX spot market price and Indiana has been primarily based upon the Texas Gas Zone SL and Chicago spot market prices.

Investment Partnerships. We generally fund our drilling activities through sponsorship of tax-advantaged investment partnerships. 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. As managing general partner of the investment partnerships, we receive the following fees:

•

the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well; and

•

GENERAL TRENDS AND OUTLOOK

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

Natural Gas Supply and Outlook. While commodity prices for natural gas were at lower levels during the year ended December 31, 2009 when compared with the prior year, we believe that the current development of the Marcellus Shale and new horizontal drilling techniques will likely cause relatively high levels of natural gas-related drilling in these geological areas as producers seek to increase their level of natural gas production. The areas in which we operate are experiencing a decline in the development of shallow wells, but a significant increase in drilling activity related to new and increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques, including horizontal and multiple fracturing techniques. While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas reserves. Drilling activity generally decreases as natural gas prices decrease. We have no control over the level of drilling activity in the areas of our operations.

Reserve Outlook. Our future oil and gas reserves, production, cash flow and our ability to make payments on ATN’s debt depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. We face the challenge of natural production declines and volatile natural gas and oil prices. As initial reservoir pressures are depleted, natural gas production from particular wells decrease. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce.

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, 2008 and 2007:


	Years Ended December 31,
	2009		2008	2007
Production:⁽¹⁾⁽²⁾
Appalachia:⁽³⁾
Natural gas (MMcf)	14,568		12,086	9,912
Oil (000’s Bbls)	194		155	153

Total (MMcfe)	15,734		13,014	10,828

Michigan/Indiana:
Natural gas (MMcf)	21,190		21,816	11,051	⁽⁵⁾
Oil (000’s Bbls)	5		4	1	⁽⁵⁾

Total (MMcfe)	21,221		21,839	11,056	⁽⁵⁾

Total:
Natural gas (MMcf)	35,758		33,902	20,963	⁽⁵⁾
Oil (000’s Bbls)	199		159	154	⁽⁵⁾

Total (MMcfe)	36,955		34,853	21,884	⁽⁵⁾


Production per day:⁽¹⁾⁽²⁾
Appalachia:⁽³⁾
Natural gas (Mcfd)	39,912		33,023	27,156
Oil (Bpd)	532	⁽⁴⁾	423	418

Total (Mcfed)	43,106		35,558	29,664

Michigan/Indiana:
Natural gas (Mcfd)	58,056		59,606	59,737	⁽⁵⁾
Oil (Bpd)	14	⁽⁴⁾	11	4	⁽⁵⁾

Total (Mcfed)	58,140		59,672	59,761	⁽⁵⁾

Total:
Natural gas (Mcfd)	97,968		92,629	86,893	⁽⁵⁾
Oil (bpd)	546	⁽⁴⁾	434	422	⁽⁵⁾

Total (Mcfed)	101,246		95,230	89,425	⁽⁵⁾

⁽¹⁾

⁽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.

⁽⁵⁾	Amounts represent production volumes related to our Michigan acquisition from the acquisition date (June 29, 2007).

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, 2008 and 2007, along with our average production costs, taxes, and transmission and compression costs in each of the reported periods:


	Years Ended December 31,
	2009		2008		2007
Production revenues (in thousands):
Appalachia:⁽¹⁾
Natural gas revenue	$	105,642	$	113,595	$	88,269
Oil revenue		12,518		14,340		10,747

Total revenues	$	118,160	$	127,935	$	99,016

Michigan/Indiana:
Natural gas revenue	$	159,832	$	183,550	$	81,045
Oil revenue		192		365		64

Total revenues	$	160,024	$	183,915	$	81,109

Total:
Natural gas revenue	$	265,474	$	297,145	$	169,314
Oil revenue		12,710		14,705		10,811

Total revenues	$	278,184	$	311,850	$	180,125


Average sales price:⁽²⁾
Natural gas (per Mcf):
Total realized price, after hedge^{(3) (4)}	$	7.67	$	9.13	$	8.66	⁽⁶⁾
Total realized price, before hedge^{(3) (4)}	$	4.07	$	9.23	$	7.22	⁽⁶⁾
Oil (per Bbl):
Total realized price, after hedge	$	70.81	$	92.35	$	70.16	⁽⁶⁾
Total realized price, before hedge	$	57.26	$	91.79	$	70.16	⁽⁶⁾

Production costs (per Mcfe):⁽²⁾
Appalachia:⁽¹⁾
Lease operating expenses⁽⁵⁾	$	1.06	$	1.03	$	0.86
Production taxes		0.03		0.03		0.03
Transportation and compression		0.70		0.87		0.74

	$	1.79	$	1.93	$	1.63

Michigan/Indiana:
Lease operating expenses	$	0.72	$	0.75	$	0.68	⁽⁶⁾
Production taxes		0.25		0.54		0.26	⁽⁶⁾
Transportation and compression		0.25		0.29		0.38	⁽⁶⁾

	$	1.22	$	1.58	$	1.32	⁽⁶⁾

Total:
Lease operating expenses⁽⁵⁾	$	0.86	$	0.85	$	0.77	⁽⁶⁾
Production taxes		0.16		0.35		0.21	⁽⁶⁾
Transportation and compression		0.44		0.51		0.49	⁽⁶⁾

	$	1.46	$	1.71	$	1.47	⁽⁶⁾

⁽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⁾

⁽⁴⁾

Includes cash proceeds of $2.8 million, $12.4 million and $12.3 million for the years ended December 31, 2009, 2008 and 2007, 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. Also excludes non-cash derivative gains of $26.3 million associated with the Michigan acquisition for the year ended December 31, 2007.

⁽⁵⁾

⁽⁶⁾	Amounts include data related to our Michigan acquisition from the acquisition date (June 29, 2007).

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 $19.9 million for the year ended December 31, 2009, an increase of $6.2 million from $13.7 million for the year ended December 31, 2008. This increase was principally due to a $5.1 million decrease in the elimination of intercompany transportation costs subsequent to the formation of the Laurel Mountain joint venture. Prior to the formation of Laurel Mountain, the transportation costs included within Appalachia production costs were eliminated within our consolidated financial statements against APL’s corresponding transportation revenue for performing such transportation services. Subsequent to the formation of Laurel Mountain, APL no longer recognizes transportation revenue for these transportation services, but rather recognizes its equity in the net income of Laurel Mountain. The remaining $1.1 million increase in Appalachia production costs 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.

Year Ended December 31, 2008 Compared with the Year Ended December 31, 2007. Total natural gas revenues were $297.1 million for the year ended December 31, 2008, an increase of $127.8 million from $169.3 million for the year ended December 31, 2007. The increase was principally attributable to a $113.4 million increase from higher production volumes and a $14.4 million increase from higher realized natural gas prices. The increase in production volumes resulted principally from a $102.4 million increase associated with a full year of production from our Michigan operations, which we acquired on June 29, 2007, and a 22% increase in Appalachian production volumes. Total oil revenues were $14.7 million for the year ended December 31, 2008, an increase of $3.9 million from $10.8 million for the year ended December 31, 2007. This increase resulted primarily from a $3.4 million increase associated with a 33% increase in average oil sales prices.

Appalachia production costs were $13.8 million for the year ended December 31, 2008, an increase of $4.2 million from $9.6 million for the year ended December 31, 2007. This increase was attributable to a $4.2 million increase in transportation charges, water hauling and labor and maintenance costs associated with an increase in the number of wells we own in Appalachia from the prior year. Michigan/Indiana production costs were $34.4 million for the year ended December 31, 2008, an increase of $19.8 million from $14.6 million for the year ended December 31, 2007. This increase was principally attributable to a full year of production from our Michigan operations, which we acquired on June 29, 2007.

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, 2008 and 2007. We did not drill any exploratory wells during the years ended December 31, 2009, 2008 and 2007:


	Years Ended December 31,
	2009	2008	2007
Gross wells drilled:
Appalachia	187	830	1,106
Michigan/Indiana	97	173	115

Total	284	1,003	1,221


Net wells drilled:
Appalachia	170	786	1,021
Michigan/Indiana	85	143	92

Total	255	929	1,113


Our share of net wells drilled:⁽¹⁾
Appalachia	56	279	378
Michigan/Indiana	25	140	92

Total	81	419	470


Gross dry wells drilled:
Appalachia	—	8	11
Michigan/Indiana	4	—	—

Total	4	8	11


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

Total	4	3	4

⁽¹⁾

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			2007
Average construction and completion per well:
Revenue	$	1,531		$	535		$	317
Costs		(1,299	)		(463	)		(276	)

Gross profit	$	232		$	72		$	41


Gross profit margin	$	56,499		$	55,427		$	41,931


Net wells drilled within investment partnerships:⁽¹⁾
Marcellus Shale		94			81			18
Chattanooga Shale		15			11			—
Michigan/Indiana		77			3			—
Other - shallow		57			681			996

		243			776			1,014

⁽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.

Well construction and completion segment margin was $55.4 million for the year ended December 31, 2008, an increase of $13.5 million from $41.9 million for the year ended December 31, 2007. The increase in margin was primarily due to the increase in the number of Marcellus Shale wells drilled within the partnerships in 2008 when compared with the prior year, which are drilled at a higher cost than Appalachian shallow wells.

Our consolidated balance sheet at December 31, 2009 includes $122.1 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.

Administration and oversight fee revenues were $19.4 million for the year ended December 31, 2008 compared with $18.1 million for the year ended December 31, 2007, an increase of $1.3 million. The increase was principally due to 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, partially offset by a decrease in other wells drilled.

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.

Well services revenues were $20.5 million for the year ended December 31, 2008 compared with $17.6 million for the prior year, an increase of $2.9 million. The increase in well services revenue was due to investment partnerships wells put into operation during 2008. Well services expenses were $10.7 million for year ended December 31, 2008, an increase of $1.6 million from $9.1 million for the year ended December 31, 2007. This increase was attributable to an increase in employees due to the increase in the number of wells we operate for our investment partnerships.

Transmission, Gathering and Processing

Transmission, gathering and processing revenue includes gathering fees we charge to our investment partnership wells that are connected to Laurel Mountain’s Appalachian gathering systems and the operating revenues and expenses of APL. On May 31, 2009, APL 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 APL, which were eliminated when we consolidated APL’s financial statements.

The gathering fees charged to our investment partnership wells generally ranges from $0.35 per Mcf to the amount of the competitive gathering fee, currently defined as 13% of the gross sales price of the natural gas. Pursuant to our new agreements with Laurel Mountain, we must also 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. As a result of our agreements with Laurel Mountain, our Appalachian gathering expenses within our partnership management segment will generally exceed the revenues collected from the investment partnerships by approximately 3%. We recognize a proportionate share of gathering fees paid to Laurel Mountain based on our percentage interest in the investment partnership wells, which is included in gas and oil production expense. The net effect of the elimination amounts is eliminated against our pro-rata portion of production costs from our investment partnerships in our consolidated statements of operations.

The following table presents our gathering revenues and expenses and those attributable to APL for each of the respective periods:


	Years Ended December 31,
Transmission, Gathering and Processing:	2009			2008⁽¹⁾			2007⁽¹⁾
Atlas Energy:
Revenue	$	21,008		$	20,670		$	14,314
Expense		(32,064	)		(32,875	)		(25,873	)

Gross Margin	$	(11,056	)	$	(12,205	)	$	(11,559	)


Atlas Pipeline:
Revenue	$	811,513		$	1,407,268		$	786,342
Expense		(659,872	)		(1,153,022	)		(617,317	)

Gross Margin	$	151,641		$	254,246		$	169,025


Eliminations:
Revenue	$	(16,766	)	$	(43,726	)	$	(33,571	)
Expense		11,837			32,342			25,561

Gross Margin	$	(4,929	)	$	(11,384	)	$	(8,010	)


Total:
Revenue	$	815,755		$	1,384,212		$	767,085
Expense		(680,099	)		(1,153,555	)		(617,629	)

Gross Margin	$	135,656		$	230,657		$	149,456

⁽¹⁾

Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system.

Our net gathering fee expense for the year ended December 31, 2009 was $11.1 million compared with $12.2 million for the year ended December 31, 2008. This favorable decrease was principally due to lower average gas sales prices between periods, partially offset by higher Appalachia production volume. Our net gathering fee expense for the year ended December 31, 2008 was $12.2 million compared with $11.6 million for the year ended December 31, 2007. This unfavorable increase was principally due to higher average gas sales prices between periods and higher Appalachia production volume.

Transmission, gathering and processing margin for APL was $151.6 million for the year ended December 31, 2009 compared with $254.2 million for the year ended December 31, 2008. This decrease was due principally to lower average commodity prices between periods. Transmission, gathering and processing margin for APL was $254.2 million for the year ended December 31, 2008 compared with $169.0 million for the year ended December 31, 2007. This increase was due principally to higher average commodity prices between periods.

Gain on Asset Sales

Gain on asset sales of $105.0 million for the year ended December 31, 2009 principally represents the gain recognized on APL’s sale of a 51% ownership interest in its Appalachia natural gas gathering system to the Laurel Mountain joint venture.

Loss on Mark-to-Market Derivatives

Loss on mark-to-market derivatives was $37.0 million for the year ended December 31, 2009 compared with $63.5 million for the year ended December 31, 2008. This favorable movement was due primarily to the absence in the current year of APL’s $200.0 million net cash derivative expense related to the early termination of a portion of its derivative contracts, an $84.1 million favorable movement in APL’s non-cash derivative gains related to the early termination of a portion of its derivative contracts, partially offset by an unfavorable movement of $215.5 million in APL’s non-cash mark-to-market adjustments on derivatives and a $37.0 million unfavorable movement related to APL’s cash settlements on derivatives that were not designated as hedges.

Loss on mark-to-market derivatives was $63.5 million for the year ended December 31, 2008 compared with $153.3 million for the year ended December 31, 2007. This favorable movement was due to a $356.8 million favorable movement in APL’s non-cash mark-to-market adjustments on derivatives, partially offset by a net cash derivative expense of $200.0 million and a non-cash derivative loss of $39.2 million related to the early termination of a portion of APL’s derivative contracts, and an unfavorable movement of $1.5 million related to APL’s cash settlements on derivatives that were not designated as hedges. The $356.8 million favorable movement in non-cash mark-to-market adjustments on derivatives was due principally to a decrease in forward crude oil market prices from December 31, 2007 to December 31, 2008 and their favorable mark-to-market impact on certain non-hedge derivative contracts APL has for production volumes in future periods. For example, average forward crude oil market prices, which are the basis for adjusting the fair value of APL’s crude oil derivative contracts, at December 31, 2008 were $56.94 per barrel, a decrease of $32.95 per barrel from average forward crude oil market prices at December 31, 2007 of $89.89 per barrel. APL enters into derivative instruments principally to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under Item 6A, “Quantitative and Qualitative Disclosures About Market Risk” and under Item 7, “Financial Statements and Supplementary Data”.

OTHER COSTS AND EXPENSES

General and Administrative

The following table presents our general and administrative expenses and those attributable to APL and AHD for each of the respective periods:


	Years Ended December 31,
	2009		2008⁽¹⁾		2007⁽¹⁾
General and Administrative expenses:
Atlas Energy	$	69,341	$	56,060	$	48,005
Atlas Pipeline and Atlas Pipeline Holdings		39,080		1,727		63,175

Total	$	108,421	$	57,787	$	111,180

⁽¹⁾

Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system.

Total general and administrative expenses, including amounts reimbursed to affiliates, increased to $108.4 million for the year ended December 31, 2009 compared with $57.8 million for the year ended December 31, 2008. This $50.6 million increase was due to our $13.3 million increase and a $37.3 million increase related to APL and AHD. The $13.3 million increase was principally attributable to $8.1 million of professional fees incurred related to the Merger and a $4.1 million increase in expenses related to wages and other corporate activities due to the growth of our business. The $37.3 million increase for APL and AHD was due principally to a $36.3 million mark-to-market gain recognized during the year ended December 31, 2008 for certain APL common unit awards and a $2.8 million increase in salaries and wages, partially offset by a $1.4 million decrease in consulting and other outside services.

Total general and administrative expenses decreased $53.4 million to $57.8 million for the year ended December 31, 2008 compared with $111.2 million for the year ended December 31, 2007. This decrease was related to a $61.5 million decrease related to APL and AHD, partially offset by our $8.1 million increase. Our $8.1 million increase was due principally to $4.5 million of higher wages and other corporate activities due to the growth of our business and a $3.6 million increase in non-cash stock compensation. The $61.5 million decrease for APL and AHD was due principally to a $70.3 million decrease in non-cash compensation expense, partially offset by $8.8 million of higher costs incurred in managing their operations. The decrease in their non-cash compensation expense was principally attributable to a $69.7 million gain recognized during the year ended December 31, 2008 for certain APL common unit awards for which the ultimate amount to be issued was determined after the completion of its 2008 fiscal year and was based upon the financial performance of APL’s acquired assets. The gain was the result of a significant change in APL’s common unit market price at December 31, 2008 when compared with the December 31, 2007 price, which was utilized in the calculation of the non-cash compensation expense for these awards. The $8.8 million increase in other APL and AHD general and administrative costs between periods was principally related to an increase in wages and corporate activities.

Depreciation, Depletion and Amortization

The following table presents our depreciation, depletion and amortization expense and that which is attributable to APL and AHD for each of the respective periods:


	Years Ended December 31,
	2009		2008⁽¹⁾		2007⁽¹⁾
Depreciation, depletion and amortization:
Atlas Energy	$	108,290	$	95,427	$	56,935
Atlas Pipeline and Atlas Pipeline Holdings		92,435		82,842		43,903

Total	$	200,725	$	178,269	$	100,838

⁽¹⁾

Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system.

Total depreciation, depletion and amortization increased to $200.7 million for the year ended December 31, 2009 compared with $178.3 million for the prior year, due primarily to an increase in our depletable basis and production volumes and APL’s expansion capital expenditures incurred subsequent to December 31, 2008. Depreciation, depletion and amortization increased to $178.3 million for the year ended December 31, 2008 compared with $100.8 million for the prior year due primarily to the depreciation and depletion associated with our acquired Michigan assets and APL’s acquired Chaney Dell and Midkiff/Benedum system assets, an increase in our depletable basis and production volumes, and APL’s expansion capital expenditures incurred between the periods.

The following table presents our depletion expense, excluding amounts attributable to APL and AHD, per Mcfe for our Appalachia and Michigan/Indiana regions for the years ended December 31, 2009, 2008 and 2007:


	Years Ended December 31,
	2009		2008		2007
Depletion expense (in thousands):
Appalachia	$	46,265	$	37,181	$	26,083
Michigan/Indiana		57,723		54,810		28,300

Total	$	103,988	$	91,991	$	54,383

Depletion expense as a percentage of gas and oil production		37%		29%		30%

Depletion per Mcfe:
Appalachia	$	2.94	$	2.86	$	2.41
Michigan/Indiana	$	2.72	$	2.51	$	2.56
Total	$	2.81	$	2.64	$	2.49

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.

Our depletion expense of oil and gas properties as a percentage of oil and gas revenues was 29% for the year ended December 31, 2008, compared with 30% for the year ended December 31, 2007. Depletion expense per Mcfe was $2.64 for the year ended December 31, 2008, an increase of $0.15 per Mcfe from $2.49 for year ended December 31, 2007. Increases in our depletable basis associated with the AGO acquisition and wells drilled for our investment partnerships and associated production volumes caused depletion expense to increase $37.6 million to $92.0 million for the year ended December 31, 2008 compared with $54.4 million in the year ended December 31, 2007. Depletion expense associated with our Michigan asset base was $54.8 million for the year ended December 31, 2008, compared with $28.3 million for the year ended December 31, 2007.

Goodwill and Other Asset Impairment

Goodwill and other asset impairment was $166.7 million for the year ended December 31, 2009, as compared with $676.9 million for the year ended December 31, 2008. 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. In addition, during the year ended December 31, 2009, APL evaluated its long-lived assets for impairment and recognized a $10.3 million impairment related to inactive pipelines and a reduction in estimated useful lives. The loss for the year ended December 31, 2008 was the result of an impairment charge to APL’s goodwill as a result of its annual goodwill impairment test. The goodwill impairment resulted from the reduction of APL’s estimate of the fair value of its goodwill in comparison to its carrying amount at December 31, 2008. The estimate of fair value of goodwill was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008. APL’s estimates were subjective and based upon numerous assumptions about future operations and market conditions.

Interest Expense

The following table presents our interest expense and that which is attributable to APL and AHD for each of the respective periods:


	Years Ended December 31,
	2009			2008⁽¹⁾		2007⁽¹⁾
Interest Expense:
Atlas Energy	$	64,951		$	56,213	$	29,982
Atlas Pipeline and Atlas Pipeline Holdings		106,373			87,852		63,695
Eliminations		(1,341	)		—		—

Total	$	169,983		$	144,065	$	93,677

⁽¹⁾

Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system.

Total interest expense increased to $170.0 million for the year ended December 31, 2009 as compared with $144.1 million for the year ended December 31, 2008. This $25.9 million increase was primarily due to our $8.7 million increase and an $18.5 million increase related to APL and AHD, partially offset by a $1.3 million elimination of intercompany interest related to AHD’s promissory note. Our $8.7 million increase was principally attributable to a $17.5 million increase associated with the issuances of ATN’s senior unsecured notes in July 2009 and May 2008, partially offset by a $7.1 million decrease associated with borrowings under ATN’s credit facility and a $3.9 million increase in capitalized interest. The $7.1 million decrease associated with ATN’s credit facility was primarily due to the repayment of amounts from the net proceeds of the issuances of senior notes and lower average interest rates and borrowings outstanding. The $18.5 million increase in interest expense for APL and AHD was due principally to a $9.1 million increase associated with higher borrowings under APL’s credit facility, an $8.5 million increase associated with the issuances of APL senior notes in June 2008, a $2.0 million increase in amortization of deferred finance costs and a $1.3 million increase in interest expense associated with AHD’s subordinated loan with us, which is eliminated in consolidation. These increases were partially offset by a $5.9 million decrease associated with the repayment of certain amounts of APL’s senior secured term loan.

Interest expense increased to $144.1 million for the year ended December 31, 2008 as compared with $93.7 million for the year ended December 31, 2007. This $50.4 million increase was primarily due to our $26.2 million increase and a $24.2 million increase related to APL and AHD. Our $26.2 million increase was principally attributable to a full year’s interest expense on ATN’s borrowings to partially finance the acquisition of our Michigan assets in June 2007, partially offset by lower variable interest rates between periods. The $24.2 million increase in interest expense for APL and AHD was due principally to higher APL borrowings to partially finance the acquisition of its Chaney Dell and Midkiff/Benedum systems during July 2007, partially offset by lower variable interest rates between periods.

Gain on Early Extinguishment of Debt

Gain on early extinguishment of debt of $19.9 million for the year ended December 31, 2008 resulted from APL’s repurchase of approximately $60.0 million in face amount of its senior unsecured notes for an aggregate purchase price of approximately $40.1 million plus accrued interest of approximately $2.0 million. The notes repurchased were comprised of $33.0 million in face amount of APL’s 8.125% senior unsecured notes and approximately $27.0 million in face amount of its 8.75% senior unsecured notes. All of APL’s senior unsecured notes repurchased have been retired and are not available for re-issue.

Income Taxes

The income tax benefit related to net income (loss) from continuing operations of attributable to common shareholders was $49.1 million and $5.0 million for the years ended December 31, 2009 and 2008, respectively, compared with an income tax provision of $13.3 million for the year ended December 31, 2007. Our effective income tax rate related to net income (loss) from continuing operations attributable to common shareholders was 39%, 40% and 29% for the years ended December 31, 2009, 2008 and 2007 respectively. Our effective tax rate fluctuates as a result of the impact of state income taxes and permanent differences between our accounting for certain revenue or expense items and their corresponding treatment for income tax purposes. We expect our effective income tax rate to be 39% in 2010.

Income from Discontinued Operations

Income from discontinued operations, net of income taxes, which consists of amounts associated with APL’s NOARK gas gathering and interstate pipeline system that was sold in May 2009, increased to $59.8 million for the year ended December 31, 2009 compared with $19.7 million for the year ended December 31, 2008. The increase was due to the $48.9 million gain, net of income tax expense of $2.2 million, APL recognized on the sale of its NOARK system, partially offset by an $8.8 million decrease in the operating results of the system, net of income taxes, due to a partial year of operating results in 2009.

Income from discontinued operations, net of income taxes, decreased to $19.7 million for the year ended December 31, 2008 compared with $29.5 million for the year ended December 31, 2007. The decrease was due to a $9.8 million decrease in the operating results of the system, net of income taxes.

Income (Loss) Attributable to Non-Controlling Interests

Income (loss) attributable to non-controlling interests was an expense of $71.9 million for the year ended December 31, 2009 compared with a benefit of $479.4 million for the prior year. Income (loss) attributable to non-controlling interests includes an allocation of APL’s and AHD’s net income (loss) to non-controlling interest holders, as well as an allocation of ATN’s net income prior to the Merger on September 29, 2009 to its non-controlling interest holders. This change was primarily due to an increase in ATN’s and APL’s net earnings between periods.

Income (loss) attributable to non-controlling interests was a benefit of $479.4 million for the year ended December 31, 2008 compared with a benefit of $93.5 million for the year ended December 31, 2007. The change between periods is principally due to a $464.3 million increase in APL’s net loss, a $25.3 million increase in ATN’s net income, a decrease in our ownership interest in AHD to 64% for the year ended December 31, 2008 compared with 83% for the first half of the prior year, and a decrease in our ownership interest in ATN to 51% for the year ended December 31, 2008 compared with 80% for the first half of the prior year. The increase in APL’s net loss was the result of a $676.9 goodwill impairment loss during the year ended December 31, 2008, offset by a favorable movement of $115.9 million from the impact of certain net losses recognized on derivatives from the prior year, a full year’s operating results from the Chaney Dell and Midkiff/Benedum systems which were acquired in July 2007, and a $19.9 million gain APL recognized in 2008 for the early extinguishment of debt. ATN’s increase in net income between periods was principally due to a full year’s operating results from its Michigan assets which were acquired in June 2007 and higher Appalachia production volumes and prices. The decrease in our ownership interest in AHD was due to its private placement of common units to third parties to partially finance its capital contribution to APL to maintain its 2% general partner interest in relation to APL’s private placement of common units to third parties to partially finance its acquisition of the Chaney Dell and Midkiff/Benedum systems in 2007. The decrease in our ownership interest in ATN was due to its private placement of common units to third parties to partially finance its acquisition of its Michigan assets in 2007.

LIQUIDITY AND CAPITAL RESOURCES

General

Our primary sources of liquidity are cash generated from operations, capital raised through investment partnerships and borrowings under ATN’s 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 or by the issuance of additional common shares.

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 ATN’s 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 ATN’s credit facility and other borrowings, the issuance of additional common shares, the sale of assets and other transactions.

ATN Revolving Credit Facility

At December 31, 2009, ATN 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 ATN. 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 ATN’s assets and is guaranteed by each of its subsidiaries. In July 2009, ATN’s credit agreement was amended to, among other things, permit the Merger and to allow ATN to distribute to us (a) amounts equal to our income tax liability attributable to ATN’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 ATN’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 ATN 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. ATN is in compliance with these covenants as of December 31, 2009. The credit facility also requires ATN 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 ATN’s credit facility, ATN’s 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.

Cash Flows – Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Net cash provided by operating activities of $241.2 million for the year ended December 31, 2009 represented a favorable movement of $288.6 million from net cash used in operating activities of $47.4 million for the prior year. The increase was derived principally from a $168.0 million increase in net income excluding non-cash items, a $195.4 million favorable movement in distributions paid to non-controlling interest holders and a $20.6 million favorable movement in working capital changes, partially offset by a $64.9 million unfavorable movement in deferred taxes and a $30.5 million unfavorable movement in cash provided by discontinued operations. The non-cash charges which impacted net income include favorable movements in income from continuing operations of $445.4 million and favorable increases in non-cash loss on derivatives of $263.4 million, partially offset by a $105.0 million gain on asset sales and a $510.2 million non-cash favorable movement in goodwill and other asset impairment. The movement in cash distributions to non-controlling interest holders is due mainly to decreases in the cash distributions of our consolidated subsidiaries, including ATN prior to the Merger. The movement in working capital was principally due to a $72.2 million favorable movement in accounts payable and accrued liabilities, partially offset by a $51.6 million unfavorable movement in accounts receivable and other current assets. The movement in non-cash derivative losses resulted from decreases in commodity prices during the year ended December 31, 2009 and their favorable impact on the fair value of derivative contracts we and APL have for future periods.

Net cash provided by investing activities of $77.2 million for the year ended December 31, 2009 represented a favorable movement of $721.1 million from $643.9 million of net cash used in investing activities for the prior year. This favorable movement was principally due to a $315.8 million favorable movement in cash provided by discontinued operations, a $122.3 million increase in proceeds from assets sales due primarily to the sale of APL’s Appalachia segment assets to the Laurel Mountain joint venture, and a decrease in our and APL’s capital expenditures of $325.4 million, partially offset by a prior year receipt of $31.4 million of cash proceeds from acquisition purchase price adjustments. The $315.8 million favorable movement in cash provided by discontinued operations was principally the result of $294.5 million of net cash proceeds from the sale of APL’s NOARK system assets. See further discussion of capital expenditures under “—Capital Requirements”.

Net cash used in financing activities of $402.3 million for the year ended December 31, 2009 represented an unfavorable movement of $1,052.2 million from $649.9 million of net cash provided by financing activities for the prior year. This unfavorable movement was principally due to a $455.7 million reduction in net proceeds from APL and ATN’s issuance of debt, a $278.3 million reduction in net proceeds from APL and ATN’s issuance of equity and a $352.7 million favorable movement in subsidiary borrowings under their respective credit facilities.

Cash Flows – Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Net cash used in operating activities of $47.4 million for the year ended December 31, 2008 represented a decrease of $242.5 million from $195.1 million of net cash provided by operating activities for the prior year. The decrease was derived principally from a $136.7 million increase in cash distributions paid to non-controlling interests and a $104.4 million decrease in net income excluding non-cash items. The decrease due to cash distributions to non-controlling interests is due mainly to increases in ATN’s, AHD’s and APL’s common units outstanding and their cash distribution amount per common unit. The non-cash charges which impacted net income include unfavorable increases in non-cash loss on derivatives of $351.8 million, gain on early extinguishment of debt of $19.9 million and non-cash compensation related to long-term incentive plans of $66.8 million, partially offset by favorable increases of $676.9 for goodwill impairment and $77.4 million for depreciation, depletion and amortization. The movement in net non-cash loss on derivative value between periods resulted from commodity price movements during the year ended December 31, 2008 and the unfavorable non-cash impact it had on our net income, which was due to the mark-to-market of derivative contracts APL has for future periods. The increase in depreciation, depletion and amortization resulted from our acquisition of Michigan assets in June 2007 and APL’s acquisition of its Chaney Dell and Midkiff/Benedum systems in July 2007.

Net cash used in investing activities of $643.9 million for the year ended December 31, 2008 represented a decrease of $2,864.3 million from $3,508.2 million used in investing activities for the prior year. This decrease was principally due to a $3,157.0 million reduction in net cash paid for acquisitions related to the acquisition of our Michigan assets in June 2007 and APL’s acquisition of its Chaney Dell and Midkiff/Benedum systems in July 2007, the $31.4 million post-closing purchase price adjustment of APL’s acquisition of its Chaney Dell and Midkiff/Benedum systems during the year ended December 31, 2008 and a $9.4 million decrease in cash paid for investments in Lightfoot. These decreases were partially offset by a $326.4 million increase in our and APL’s capital expenditures. See further discussion of capital expenditures under “—Capital Requirements”.

Net cash provided by financing activities of $649.9 million for the year ended December 31, 2008 represented a decrease of $2,624.0 million from $3,273.9 million of net cash provided by financing activities for the prior year. This decrease was principally due to a $1,712.6 million net reduction in APL, ATN, and AHD credit facility borrowings and a $1,431.5 million decrease in net proceeds from APL, ATN and AHD equity offerings. These amounts were partially offset by a $489.0 million net increase in issuances of APL and ATN long-term debt and a $40.4 million decrease in purchases of our outstanding common stock.

Capital Requirements

Our capital requirements consist primarily of:

•

capital expenditures we make to expand our capital asset base for longer than the short-term and include new leasehold interests and the development and exploitation of existing leasehold interests through acquisitions and investments in our drilling partnerships; and

•

our commitment to invest a maximum of $19.7 million in Lightfoot, of which we had invested $13.4 million at December 31, 2009.

The following table presents our capital expenditures and those attributable to APL, excluding amounts paid for acquisitions, for the periods presented (in thousands):


	Years Ended December 31,
	2009		2008⁽¹⁾		2007⁽¹⁾
Atlas Energy	$	168,060	$	347,656	$	201,169
Atlas Pipeline		154,916		300,723		120,833

Total	$	322,976	$	648,379	$	322,002

⁽¹⁾

Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system.

During the year ended December 31, 2009, our capital expenditures related primarily to $97.5 million of investments in our investment partnerships, a decrease of $48.8 million compared with the prior year, $19.1 million in wells drilled exclusively for our own account, a decrease of $75.1 million compared with the prior year, $24.8 million incurred for leasehold acquisition costs, a decrease of $65.4 million compared with the prior year, and $9.4 million in construction costs related to gas processing plants in Tennessee, an increase of $3.6 million compared with the prior year.

During the year ended December 31, 2008, our capital expenditures related primarily to $146.3 million of investments in our investment partnerships, an increase of $8.7 million compared with the prior year, $94.2 million in wells drilled exclusively for our own account, an increase of $65.7 million compared with the prior year, $90.2 million incurred for leasehold acquisition costs, an increase of $80.6 million compared with the prior year, and $5.8 million in construction costs related to gas processing plants in Tennessee, which began operations in May 2008.

The level of capital expenditures we devote to our exploration and production operations depends upon any acquisitions made and the level of funds raised through our investment partnerships. We believe cash flows from operations and amounts available under ATN’s credit facility will be adequate to fund our capital expenditures. However, the amount of funds we raise and the level of our capital expenditures will vary in the future depending on market conditions for natural gas and other factors. We expect to fund our capital expenditures with cash flow from our operations, borrowings under ATN’s credit facility, and with the temporary use of funds raised in our investment partnerships in the period before we invest the funds. We may also consider other transactions, which may supplement our cash generation activities and provide liquidity to fund capital expenditures.

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

Atlas Pipeline Partners. APL’s capital expenditures decreased to $154.9 million for the year ended December 31, 2009, compared with $300.7 million for the prior year. The decrease was due principally to costs incurred in the prior year for APL’s construction of a 60 MMcfd expansion of its Sweetwater processing plant and its Madill to Velma pipeline and a decrease related to the sale of a 51% ownership interest in the Appalachia system in June 2009.

APL’s expansion capital expenditures increased to $300.7 million for the year ended December 31, 2008 due principally to the expansion of APL’s gathering systems and upgrades to processing facilities and compressors to accommodate new wells drilled in its service areas, including the construction of a 60 MMcfd expansion of APL’s Sweetwater processing plant and its Madill to Velma pipeline.

As of December 31, 2009, APL is committed to expend approximately $12.8 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

OFF BALANCE SHEET ARRANGEMENTS

As of December 31, 2009, our off balance sheet arrangements are limited to our guarantee of Crown Drilling of Pennsylvania, LLC’s $11.5 million credit agreement, ATN’s and APL’s letters of credit outstanding of $1.2 million and $10.1 million, respectively, our estimated capital contribution for drilling and completion expenditures related to Atlas Resources Public #18-2008 Program of approximately $12.4 million, and APL’s commitments to expend approximately $12.8 million on capital projects. In addition, we are committed to invest a total of $19.7 million in Lightfoot, of which $13.5 million has been invested as of December 31, 2009.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The following table summarizes our contractual obligations at December 31, 2009 (in thousands):


			Payments Due By Period
Contractual cash obligations:	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
Total debt	$	2,050,034	$	8,000	$	510,000	$	708,984	$	823,050
Interest on total debt⁽¹⁾		925,884		151,886		298,105		237,445		238,448
Operating leases		24,046		6,703		10,479		3,202		3,662

Total contractual cash obligations	$	2,999,964	$	166,589	$	818,584	$	949,631	$	1,065,160

⁽¹⁾	Based on the interest rates of ATN’s, APL’s and AHD’s respective debt components as of December 31, 2009.


			Amount of Commitment Expiration Per Period
Other commercial commitments:	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
Standby letters of credit	$	11,239	$	11,239	$	—	$	—	$	—
Other commercial commitments⁽¹⁾		36,669		27,388		4,800		4,481		—

Total commercial commitments	$	47,908	$	38,627	$	4,800	$	4,481	$	—

⁽¹⁾

Other commercial commitments relate to a guarantee for one half of a bank loan related to ATN’s 50% ownership in Crown Drilling of Pennsylvania, LLC, estimated capital contributions for drilling and completion expenditures related to Atlas Resources Public #18-2008 Program and commitments for pipeline extensions, compressor station upgrades and processing facility upgrades.

DIVIDENDS

We paid cash dividends of $2.0 million, $6.7 million and $3.6 million in the years ended December 31, 2009, 2008 and 2007, respectively. The determination of the amount of future cash dividends, if any, is at the sole discretion of our board of directors and will depend on the various factors affecting our financial condition and other matters the board of directors deems relevant.

ENVIRONMENTAL REGULATION

Our and our subsidiaries’ operations are subject to federal, state and local laws and regulations governing the release of regulated materials into the environment or otherwise relating to environmental protection or human health or safety (see Item 1: Business “—Environmental Matters and Regulations”). We believe that our and our subsidiaries’ operations and facilities are in substantial compliance with applicable environmental laws and regulations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of remedial requirements and issuance of injunctions as to future compliance or other mandatory or consensual measures. We and our subsidiaries have ongoing environmental compliance programs. However, risks of accidental leaks or spills are associated with our and their operations. There can be no assurance that we and our subsidiaries will not incur significant costs and liabilities relating to claims for damages to property, the environment, natural resources, or persons resulting from the operation of our and our subsidiaries’ business. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies hereunder, could result in increased costs and liabilities to us and our subsidiaries.

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

CHANGES IN PRICES AND INFLATION

Our revenues, the value of our assets, our and our subsidiaries’ ability to obtain bank loans or additional capital on attractive terms, and our ability to finance our drilling activities through drilling investment partnerships have been and will continue to be affected by changes in oil and natural gas market prices. Natural gas and oil prices are subject to significant fluctuations that are beyond our ability to control or predict.

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

ISSUANCE OF SUBSIDIARY COMMON UNITS

We have adopted a policy to recognize gains on our subsidiaries’ equity transactions as a credit to equity rather than as income. These gains represent our portion of the excess net offering price per unit of each of our subsidiaries’ units to the book carrying amount per unit.

Atlas Pipeline Partners and Atlas Pipeline Holdings

On January 7, 2010, APL executed amendments to warrants to purchase 2,689,765 of its common units. The warrants were originally issued along with its common units in connection with a private placement to institutional investors that closed on August 20, 2009. The amendments to the warrants provided that, for the period January 8 through January 12, 2010, the warrant exercise price was lowered to $6.00 from $6.35 per unit. In connection with the amendments, the holders of the warrants agreed to exercise all of the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan and credit facility.

In August 2009, APL sold 2,689,765 common units in a private placement at an offering price of $6.35 per unit, yielding net proceeds of approximately $16.1 million. APL also received a capital contribution from AHD of $0.4 million for AHD to maintain its 2.0% general partner interest in APL. In addition, APL issued warrants granting investors in our private placement the right to purchase an additional 2,689,765 common units at a price of $6.35 per unit for a period of two years following the issuance of the original common units. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan.

The common units and warrants sold by APL in the August 2009 private placement are subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement required APL to (a) file a registration statement with the Securities and Exchange Commission for the privately placed common units and those underlying the warrants by September 21, 2009 and (b) cause the registration statement to be declared effective by the Securities and Exchange Commission by November 18, 2009. APL filed a registration statement with the Securities and Exchange Commission in satisfaction of the registration requirements of the registration rights agreement on September 3, 2009, and the registration statement was declared effective on October 14, 2009.

In June 2008, APL sold 5,750,000 common units in a public offering at a price of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, we purchased 308,109 AHD common units and 1,112,000 APL common limited partner units through a private placement transaction at a price of $32.50 and $36.02 per unit, respectively, for net proceeds of approximately $10.0 million and $40.1 million, respectively. APL also received a capital contribution from AHD of $5.4 million for AHD to maintain its 2.0% general partner interest in it. APL utilized the net proceeds from both the sales of common units and the capital contribution from AHD to fund the early termination of certain derivative agreements.

In July 2007, APL sold 25,568,175 common units through a private placement to investors at a negotiated purchase price of $44.0 per unit, yielding net proceeds of approximately $1,125 billion. Of the 25,568,175 common units sold by APL, 3,835,227 common units were purchased by AHD for $168.8 million. APL also received a capital contribution from AHD of $23.1 million for AHD to maintain its 2.0% general partner interest

in APL. AHD funded this capital contribution and other transaction costs through borrowings under its revolving credit facility of $25.0 million. APL utilized the net proceeds from the sale to partially fund the acquisition of the Chaney Dell and Midkiff/Benedum systems.

In July 2007, AHD issued 6,249,995 common units for net proceeds of $167.0 million after offering costs in a private placement offering. AHD utilized the net proceeds from the sale to partially fund its purchase of 3,835,227 common units of APL. A gain of $53.0 million, net of an income tax provision of $34.3 million, was recorded as an increase to additional paid-in capital within the consolidated balance sheet as well as a corresponding adjustment of $87.3 million to minority interest, for the year ended December 31, 2007 in accordance with prevailing accounting literature upon completion of the offering.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include deferred tax assets and liabilities, depletion, depreciation and amortization, asset impairment, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. We summarize our significant accounting policies within our consolidated financial statements included in Item 7, “Financial Statements and Supplementary Data”. The critical accounting policies and estimates we have identified are discussed below.

Impairment of Long-Lived Assets and Goodwill

Long-Lived Assets. The cost of properties, plants and equipment, less estimated salvage value, is generally depreciated on a straight-line basis over the estimated useful lives of the assets. Useful lives are based on historical experience and are adjusted when changes in planned use, technological advances or other factors indicate that a different life would be more appropriate. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively.

Long-lived assets other than goodwill and intangibles with infinite lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. A long-lived asset other than goodwill and intangibles with infinite lives is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. Additional factors impacting the economic viability of long-lived assets are discussed under “Forward Looking Statements” in this document.

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. In addition, during the year ended December 31, 2009, APL evaluated its long-lived assets for impairment and

recognized a $10.3 million impairment related to inactive pipelines and a reduction in estimated useful lives. Also, as discussed below, APL recognized an impairment of goodwill at December 31, 2008. We believe this impairment of goodwill was an event that warranted assessment of APL’s long-lived assets for possible impairment. APL evaluated all of its long-lived assets, including intangible customer relationships, at December 31, 2008, and determined that the undiscounted estimated future net cash flows related to these assets continued to support the recorded values. We and our subsidiaries did not recognize an impairment of long-lived assets other than goodwill and intangibles with infinite lives for the year ended December 31, 2007.

Goodwill and Intangibles with Infinite Lives. Goodwill and intangibles with infinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment loss should be recognized if the carrying value of an entity’s reporting units exceeds its estimated fair value. Because quoted market prices for our reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units. Management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to market capitalization. Prevailing accounting principles acknowledge that the observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity’s individual equity securities. In most industries, including ours, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, we also consider a control premium to the calculations. This control premium is judgmental and is based, among other items, on observed acquisitions in our industry. The resultant fair values calculated for the reporting units are then compared to observable metrics on large mergers and acquisitions in our industry to determine whether those valuations appear reasonable in management’s judgment.

Our and our subsidiaries’ evaluation of goodwill at December 31, 2009 resulted in no impairment. As a result of our and our subsidiaries’ impairment evaluation at December 31, 2008, APL recognized a $676.9 million non-cash impairment charge within our consolidated statements of operations for the year ended December 31, 2008. The goodwill impairment resulted from the reduction in APL’s estimated fair value of reporting units in comparison to their carrying amounts at December 31, 2008. APL’s estimated fair value of the reporting units was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008. These estimates were subjective and based upon numerous assumptions about future operations and market conditions, which are subject to change. There were no goodwill impairments recognized by us and our subsidiaries during the year ended December 31, 2007. See “—Goodwill” in Note 2 under Item 7, “Financial Statements and Supplementary Data” for information regarding our impairment of goodwill and other assets.

Fair Value of Financial Instruments

We have established a hierarchy to measure our financial instruments at fair value which requires us 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.

We use a fair value methodology to value the assets and liabilities for our, AHD’s and APL’s outstanding derivative contracts and our Supplemental Employment Retirement Plan (“SERP”). Our and APL’s commodity hedges, with the exception of APL’s NGL fixed price swaps and NGL options, are calculated 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. Our, AHD’s and APL’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. Our SERP is calculated based on observable actuarial inputs developed by a third-party actuary and therefore is defined as a Level 2 fair value measurement, while the asset related to the funding of the SERP in a rabbi trust is based on publicly traded equity and debt securities and is therefore also defined as a Level 1 fair value measurement. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of natural gas, crude oil and propane prices and therefore are defined as Level 3 fair value measurements. Valuations for APL’s NGL options are based on forward price curves developed by the related financial institution and therefore are defined as Level 3 fair value measurements.

Liabilities that are required to be measured at fair value on a nonrecurring basis include our asset retirement obligations (“ARO’s”) that are defined as Level 3. Estimates of the fair value of ARO’s are based on discounted cash flows using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our credit-adjusted risk-free rate and inflation rates.

Reserve Estimates

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

Asset Retirement Obligations

On an annual basis, we and our subsidiaries estimate the costs of future dismantlement, restoration, reclamation and abandonment of our operating assets. We and our subsidiaries also estimate the salvage value of equipment recoverable upon abandonment. As of December 31, 2009 and 2008, the estimate of salvage values was greater than or equal to our estimate of the costs of future dismantlement, restoration, reclamation and abandonment. Projecting future retirement cost estimates is difficult as it involves the estimation of many variables such as economic recoveries of reserves, future labor and equipment rates, future inflation rates and our subsidiaries’ credit adjusted risk free rate. To the extent future revisions to these assumptions impact the fair value of our existing asset retirement obligation, a corresponding adjustment is made to our oil and gas properties and other property, plant and equipment. A decrease in salvage values or an increase in dismantlement, restoration, reclamation and abandonment costs from those we and our subsidiaries have estimated, or changes in their estimates or costs, could reduce our gross profit from operations.

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. As our assets currently consist principally of our ownership interests in our subsidiaries, the following information principally encompasses their exposure to market risks unless otherwise noted. 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 and our subsidiaries 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 and our subsidiaries 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 and our subsidiaries’ business.

Current market conditions elevate our and our subsidiaries’ 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 their revolving credit facilities. 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, ATN had an outstanding balance of $184.0 million on its 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 ATN’s revolving credit facility, and will receive LIBOR plus the applicable margin on the notional principal amounts. These derivatives effectively convert $150.0 million of ATN’s floating rate debt under its 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.

At December 31, 2009, AHD had a credit facility with $8.0 million outstanding. At December 31, 2009, AHD had an interest rate derivative contract having an aggregate notional principal amount of $25.0 million, which expires on May 28, 2010. Under the terms of agreement, AHD will pay an interest rate of 3.0%, plus the applicable margin as defined under the terms of its credit facility, and will receive LIBOR, plus the applicable margin, on the notional principal amounts.

At December 31, 2009, APL had $326.0 million of outstanding borrowings under its $380 million senior secured revolving credit facility and $433.5 million outstanding under its senior secured term loan. Borrowings under APL’s credit facility bear interest, at its option at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). On May 29, 2009, APL entered into an amendment to its senior secured credit facility

agreement, which, among other changes, set a floor for the LIBOR interest rate of 2.0% per annum. At December 31, 2009, APL had interest rate derivative contracts having aggregate notional principal amounts of $450.0 million. Under the terms of these agreements, APL will pay weighted average interest rates of 3.0%, 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. These derivatives effectively convert $450.0 million of APL’s floating rate debt under its term loan and revolving credit facility to fixed-rate debt. These derivatives are in effect as of December 31, 2009 and expire during periods ranging from January 30, 2010 through April 30, 2010.

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 consolidated interest expense by $0.4 million.

Commodity Price Risk. Our market risk exposure to commodities is due to the fluctuations in the price of natural gas, NGLs, condensate and oil and the impact those price movements have on the financial results of our subsidiaries. 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. APL is exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. APL enters into financial swap and option instruments to hedge forecasted sales against the variability in expected future cash flows attributable to changes in market prices. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate are sold. Under these swap agreements, APL receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas, NGLs and condensate at a fixed price for the relevant period.

Holding all other variables constant, including the effect of commodity derivatives, a 10% change in the average price of natural gas, NGLs, condensate and oil would result in a change to our consolidated operating income from continuing operations, excluding income tax effects, for the twelve-month period ending December 31, 2010 of approximately $36.7 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. These contracts have qualified and been designated as cash flow hedges and been recorded at their fair values.

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.

As of December 31, 2009, AHD had the following interest rate derivatives:

Interest Fixed-Rate Swap


Term	Notional Amount		Type	Contract Period Ended December 31,
May 2008-
May 2010	$	25,000,000	Pay 3.0%—Receive LIBOR	2010

(1)	Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace.

As of December 31, 2009, APL had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swap


Term	Amount		Type
January 2008-January 2010	$	200,000,000	Pay 2.9%—Receive LIBOR
April 2008-April 2010	$	250,000,000	Pay 3.1%—Receive LIBOR

Fixed Price Swaps


Production Period	Purchased/ Sold	Commodity	Volumes⁽¹⁾	Average Fixed Price
2010	Purchased	Natural Gas	4,380,000	$	8.635
2010	Sold	Natural Gas Basis	4,500,000		(0.638	)
2010	Purchased	Natural Gas Basis	8,880,000		(0.597	)
2011	Sold	Natural Gas Basis	1,920,000		(0.728	)
2011	Purchased	Natural Gas Basis	1,920,000		(0.758	)
2012	Sold	Natural Gas Basis	720,000		(0.685	)
2012	Purchased	Natural Gas Basis	720,000		(0.685	)

NGL Options


Production Period	Purchased/ Sold	Type	Commodity	Volumes⁽¹⁾	Average Strike Price
2010	Purchased	Put	Propane	35,910,000	$	1.022
2010	Purchased	Put	Normal Butane	3,654,000		1.205
2010	Purchased	Put	Natural Gasoline	3,906,000		1.545
Crude Oil Options
Production Period	Purchased/ Sold	Type	Commodity	Volumes⁽¹⁾	Average Strike Price
2010	Purchased	Put	Crude Oil	897,000		73.12
2010	Sold	Call	Crude Oil	3,361,500		81.23
2010	Purchased⁽²⁾	Call	Crude Oil	714,000		120.00
2011	Sold	Call	Crude Oil	678,000		94.68
2011	Purchased⁽²⁾	Call	Crude Oil	252,000		120.00
2012	Sold	Call	Crude Oil	498,000		95.83
2012	Purchased⁽²⁾	Call	Crude Oil	180,000		120.00

⁽¹⁾	Volumes for Natural Gas are stated in MMBTU’s. Volumes for NGLs are stated in gallons. Volumes for crude are stated in barrels.

⁽²⁾	Calls purchased for 2010 through 2012 represent offsetting positions for calls sold. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise.

ITEM 7:

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Atlas Energy, Inc.

We have audited the accompanying consolidated balance sheets of Atlas Energy, Inc. (a Delaware corporation) (formerly Atlas America, Inc.) and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2009. Our audits of the basic financial statements included the financial statement schedule listed in the Index appearing under Item 14(a)(2). These financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule 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, Inc. 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. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Atlas Energy, Inc.’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.

As discussed in Note 2 to the consolidated financial statements, the Company changed its method for accounting for non-controlling interests due to the adoption of Financial Accounting Standards Board’s Accounting Standard Codification 810-10-65-1, “Non-controlling Interests in Consolidated Financial Statements” on January 1, 2009.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

February 26, 2010

ATLAS ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)


	December 31,
	2009			2008
ASSETS
Current assets:
Cash and cash equivalents	$	20,627		$	104,496
Accounts receivable		172,848			172,427
Current portion of derivative asset		74,064			152,726
Subscriptions receivable from Partnerships		47,275			44,250
Prepaid expenses and other		31,010			25,464
Prepaid and deferred taxes		1,559			32,215
Current assets of discontinued operations		—			13,441

Total current assets		347,383			545,019
Property, plant and equipment, net		3,555,802			3,744,815
Intangible assets, net		170,964			197,485
Goodwill, net		35,166			35,166
Long-term derivative asset		59,291			69,451
Investment in joint venture		132,990			—
Other assets, net		74,833			56,030
Deferred tax asset		29,734			—
Long-term assets of discontinued operations		—			242,165

	$	4,406,163		$	4,890,131

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	8,000		$	—
Accounts payable		99,748			140,725
Liabilities associated with drilling contracts		122,532			141,133
Accrued producer liabilities		66,211			66,846
Current portion of derivative liability to Partnerships		22,382			34,933
Current portion of derivative liability		38,485			73,776
Accrued interest		38,898			22,321
Accrued well drilling and completion costs		89,261			43,946
Current portion of deferred tax liability		26,415			—
Accrued liabilities		45,969			37,116
Advances from affiliate		173			108
Current liabilities of discontinued operations		—			10,572

Total current liabilities		558,074			571,476
Long-term debt, less current portion		2,040,572			2,413,082
Deferred tax liability		—			242,058
Long-term derivative payable to Partnerships		22,380			22,581
Long-term derivative liability		25,441			59,103
Other long-term liabilities		56,180			52,263
Commitments and contingencies

Shareholders’ equity:
Preferred stock, $0.01 par value: 1,000,000 authorized shares		—			—
Common stock, $0.01 par value: 114,000,000 authorized shares		814			426
Additional paid-in capital		1,156,580			412,869
Treasury stock, at cost		(142,848	)		(147,621	)
Accumulated other comprehensive income		58,022			21,143
Retained earnings		50,744			124,698

		1,123,312			411,515
Non-controlling interests		580,204			1,118,053

Total shareholders’ equity		1,703,516			1,529,568

	$	4,406,163		$	4,890,131

See accompanying notes to consolidated financial statements

ATLAS ENERGY, INC. 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
Transmission, gathering and processing		815,755			1,384,212			767,085
Administration and oversight		15,613			19,362			18,138
Well services		20,191			20,482			17,592
Gain (loss) on asset sales		105,005			(32	)		916
Loss on mark-to-market derivatives		(37,005	)		(63,480	)		(153,325	)
Other, net		17,814			11,415			9,780

Total revenues		1,587,602			2,098,845			1,161,782

Costs and expenses:
Gas and oil production		45,737			48,194			24,184
Well construction and completion		315,546			359,609			279,540
Transmission, gathering and processing		680,099			1,153,555			617,629
Well services		9,330			10,654			9,062
General and administrative		107,320			56,836			110,250
Net expense reimbursement - affiliate		1,101			951			930
Depreciation, depletion and amortization		200,725			178,269			100,838
Goodwill and other asset impairment		166,683			676,860			—

Total costs and expenses		1,526,541			2,484,928			1,142,433

Operating income (loss)		61,061			(386,083	)		19,349

Interest expense		(169,983	)		(144,065	)		(93,677	)
Gain on early extinguishment of debt		—			19,867			—

Loss from continuing operations before income tax provision (benefit)		(108,922	)		(510,281	)		(74,328	)
Income tax provision (benefit)		(49,069	)		(5,021	)		13,283

Net loss from continuing operations		(59,853	)		(505,260	)		(87,611	)

Discontinued operations:
Gain on sale of discontinued operations (net of income tax provision of $2,228)		48,851			—			—
Income from discontinued operations (net of income tax provision of $498, $875 and $1,359 for the years ended December 31, 2009, 2008 and 2007, respectively)		10,918			19,671			29,471

Net loss		(84	)		(485,589	)		(58,140	)
(Income) loss attributable to non-controlling interests		(71,902	)		479,431			93,476

Net income (loss) attributable to common shareholders	$	(71,986	)	$	(6,158	)	$	35,336

ATLAS ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Continued)

(in thousands, except per share data)


	Years Ended December 31,
	2009			2008			2007
Net income (loss) attributable to common shareholders per share – basic:
Income (loss) from continuing operations attributable to common shareholders	$	(1.55	)	$	(0.19	)	$	0.82
Income from discontinued operations attributable to common shareholders		0.09			0.04			0.05

Net income (loss) attributable to common shareholders	$	(1.46	)	$	(0.15	)	$	0.87

Net income (loss) attributable to common shareholders per share – diluted:
Income (loss) from continuing operations attributable to common shareholders	$	(1.55	)	$	(0.19	)	$	0.78
Income from discontinued operations attributable to common shareholders		0.09			0.04			0.05

Net income (loss) attributable to common shareholders	$	(1.46	)	$	(0.15	)	$	0.83

Weighted average common shares outstanding:
Basic		49,208			39,999			40,840

Diluted		49,208			39,999			42,346

Income (loss) attributable to common shareholders:
Income (loss) from continuing operations (net of income tax provision (benefit) of ($49,069), ($5,021) and $13,283)	$	(76,239	)	$	(7,524	)	$	33,216
Income from discontinued operations (net of income tax provision of $2,726, $875 and $1,359)		4,253			1,366			2,120

Net income (loss) attributable to common shareholders	$	(71,986	)	$	(6,158	)	$	35,336

See accompanying notes to consolidated financial statements

ATLAS ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)


	Years Ended December 31,
	2009			2008			2007
Net loss	$	(84	)	$	(485,589	)	$	(58,140	)
(Income) loss attributable to non-controlling interests		(71,902	)		479,431			93,476

Net income (loss) attributable to common shareholders		(71,986	)		(6,158	)		35,336
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges, net of tax provision (benefit) of $58,398, ($9,874) and ($7,426) for the years ended December 31, 2009, 2008 and 2007, respectively		80,877			(24,721	)		(90,513	)
Less: reclassification adjustment for realized losses (gains) in net income (loss), net of tax provision (benefit) of ($34,688), $7,057 and $1,486 for the years ended December 31, 2009, 2008 and 2007, respectively		(47,307	)		69,553			33,271
Changes in non-controlling interest related to items in other comprehensive income (loss)		3,517			(17,999	)		42,931
Plus: amortization of additional post-retirement liability, net of tax provision (benefit) of ($63), $150 and ($7) for the years ended December 31, 2009, 2008 and 2007, respectively		(208	)		245			(50	)

Total other comprehensive income (loss)		36,879			27,078			(14,361	)

Comprehensive income (loss) attributable to common shareholders	$	(35,107	)	$	20,920		$	20,975

See accompanying notes to consolidated financial statements

ATLAS ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(in thousands, except share data)


	Common Stock				Additional Paid-In Capital			Treasury Stock					ESOP Loan Receivable			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Non- Controlling Interests			Total Shareholders’ Equity


	Shares		Amount					Shares		Amount
Balance, January 1, 2007	20,008,419		$	200	$	186,696		(659,135	)	$	(29,349	)	$	(490	)	$	8,426		$	105,858		$	406,387		$	677,728
Issuance of common stock	56,736			—		1,181		19,685			912			—			—			—			—			2,093
Other comprehensive loss	—			—		—		—			—			—			(14,361	)		—			(42,931	)		(57,292	)
Repayment of ESOP loan	—			—		—		—			—			73			—			—			—			73
Treasury stock purchase	—			—		—		(1,486,605	)		(80,449	)		—			—			—			—			(80,449	)
Stock option compensation	—			—		1,542		—			—			—			—			—			—			1,542
Three-for-two stock split	8,938,057			90		—		—			—			—			—			(90	)		—			—
Dividends paid	—			—		—		—			—			—			—			(3,584	)		—			(3,584	)
Tax benefits from employee stock options	—			—		276		—			—			—			—			—			—			276
Gain on sale of subsidiary units	—			—		200,896		—			—			—			—			—			—			200,896
Distributions to non-controlling interests	—			—		—		—			—			—			—			—			(104,344	)		(104,344	)
Non-controlling interests’ capital contributions	—			—		—		—			—			—			—			—			1,430,145			1,430,145

Net income (loss)	—			—		—		—			—			—			—			35,336			(93,476	)		(58,140	)

Balance, December 31, 2007	29,003,212			290		390,591		(2,126,055	)		(108,886	)		(417	)		(5,935	)		137,520			1,595,781			2,008,944
Issuance of common units	52,386			1		721		28,879			1,292			—			—			—			—			2,014
Other comprehensive income	—			—		—		—			—			—			27,078			—			17,999			45,077
Repayment of ESOP loan	—			—		—		—			—			417			—			—			—			417
Treasury stock purchase	—			—		—		(1,155,685	)		(40,027	)		—			—			—			—			(40,027	)
Stock option compensation expense	—			—		4,023		—			—			—			—			—			—			4,023
Three-for-two stock split	13,447,521			135		(135	)	—			—			—			—			—			—			—
Dividends paid	—			—		—		—			—			—			—			(6,664	)		—			(6,664	)
Gain on sale of subsidiary units	—			—		17,669		—			—			—			—			—			—			17,669
Distributions to non-controlling interests	—			—		—		—			—			—			—			—			(241,016	)		(241,016	)
Non-controlling interests’ capital contributions	—			—		—		—			—			—			—			—			224,720			224,720

Net loss	—			—		—		—			—			—			—			(6,158	)		(479,431	)		(485,589	)

Balance at December 31, 2008	42,503,119			426		412,869		(3,252,861	)		(147,621	)		—			21,143			124,698			1,118,053			1,529,568
Issuance of common units	51,205			—		(2,836	)	108,180			4,773			—			—			—			—			1,937
Other comprehensive income (loss)	—			—		—		—			—			—			36,879			—			(3,517	)		33,362
Stock option compensation expense	(40,600	)		—		4,790		—			—			—			—			—			—			4,790
Merger with Atlas Energy Resources LLC	38,776,768			388		741,757		—			—			—			—			—			(556,384	)		185,761
Dividends paid	—			—		—		—			—			—			—			(1,968	)		—			(1,968	)
Distributions to non-controlling interests	—			—		—		—			—			—			—			—			(45,589	)		(45,589	)
Non-controlling interests’ capital contributions	—			—		—		—			—			—			—			—			(4,261	)		(4,261	)

Net income (loss)	—			—		—		—			—			—			—			(71,986	)		71,902			(84	)

Balance at December 31, 2009	81,290,492		$	814	$	1,156,580		(3,144,681	)	$	(142,848	)	$	—		$	58,022		$	50,744		$	580,204		$	1,703,516

See accompanying notes to consolidated financial statements

ATLAS ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Years Ended December 31,
	2009			2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(84	)	$	(485,589	)	$	(58,140	)
Income from discontinued operations		59,769			19,671			29,471

Loss from continuing operations		(59,853	)		(505,260	)		(87,611	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		200,725			178,269			100,838
Goodwill and other asset impairment		166,683			676,860			—
Amortization of deferred finance costs		12,365			8,893			10,529
Non-cash loss (gain) on derivative value, net		67,024			(196,386	)		155,425
Non-cash compensation expense (income)		9,249			(20,373	)		46,394
(Gain) loss on asset sales and dispositions		(105,005	)		(32	)		916
Gain on early extinguishment of long-term debt		—			(19,867	)		—
Equity (income) loss in unconsolidated companies		(2,989	)		2,397			280
Distributions received from unconsolidated companies		4,310			—			—
Distributions paid to non-controlling interests		(45,589	)		(241,016	)		(104,344	)
Deferred income taxes		(66,749	)		(1,863	)		(127	)
Changes in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable and prepaid expenses and other		(15,463	)		36,142			(103,718	)
Accounts payable and accrued liabilities		62,312			(9,874	)		138,948

Net cash provided by (used in) continuing operating activities		227,020			(92,110	)		157,530
Net cash provided by discontinued operating activities		14,209			44,694			37,555

Net cash provided by (used in) operating activities		241,229			(47,416	)		195,085

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(322,976	)		(648,379	)		(322,002	)
Net cash paid for acquisitions		—			—			(3,156,976	)
Acquisition purchase price adjustment		—			31,429			—
Investment in unconsolidated companies		(4,480	)		(1,033	)		(10,447	)
Net proceeds from asset sales		122,355			62			1,645
Other		(8,296	)		(761	)		(1,498	)

Net cash used in continuing investing activities		(213,397	)		(618,682	)		(3,489,278	)
Net cash provided by (used in) discontinued investing activities		290,594			(25,211	)		(18,879	)

Net cash provided by (used in) investing activities		77,197			(643,893	)		(3,508,157	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under subsidiary credit facilities		1,009,000			1,301,400			2,123,046
Repayments under subsidiary credit facilities		(1,306,000	)		(1,356,430	)		(465,429	)
Net proceeds from issuance of subsidiary long-term debt		196,232			651,979			—
Repayments of subsidiary long-term debt		(273,675	)		(162,938	)		—
Costs related to Atlas Energy, Inc. and Atlas Energy Resources, LLC Merger		(11,661	)		—			—
Net proceeds from subsidiary equity offerings		16,074			279,357			1,710,878
Dividends paid		(1,968	)		(6,664	)		(3,584	)
Subsidiary preferred unit redemption		(15,000	)		—			—
Purchases of treasury stock		1,937			(40,027	)		(80,449	)
Deferred financing costs and other		(17,234	)		(16,768	)		(10,581	)

Net cash (used in) provided by financing activities		(402,295	)		649,909			3,273,881

Net change in cash and cash equivalents		(83,869	)		(41,400	)		(39,191	)
Cash and cash equivalents, beginning of year		104,496			145,896			185,087

Cash and cash equivalents, end of year	$	20,627		$	104,496		$	145,896

See accompanying notes to consolidated financial statements

ATLAS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 — BASIS OF PRESENTATION

Atlas Energy, Inc. (the “Company”) is a publicly traded Delaware corporation (NASDAQ: ATLS) which is 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 Energy Resources, LLC (“ATN”), the Company’s formerly publicly traded subsidiary and a Delaware limited liability company, pursuant to the definitive merger agreement previously executed, with ATN surviving as the Company’s wholly-owned subsidiary (the “Merger”) (see Note 3). Additionally, Atlas America, Inc. changed its name to Atlas Energy, Inc. upon completion of the Merger.

In addition to its natural gas development and production operations, the Company also maintains ownership interests in the following entities:

•

Atlas Pipeline Partners, L.P. (“Atlas Pipeline Partners” or “APL”), a publicly traded Delaware limited partnership (NYSE: APL) and midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions. At December 31, 2009, the Company had a 2.2% direct ownership interest in APL;

•

Atlas Pipeline Holdings, L.P. (“Atlas Pipeline Holdings” or “AHD”), a publicly traded Delaware limited partnership (NYSE: AHD) and owner of the general partner of APL. Through the Company’s ownership of AHD’s general partner, it manages AHD. AHD’s cash generating assets currently consist solely of its interests in APL. At December 31, 2009, the Company owned approximately 64.3% of the outstanding common units of AHD. At December 31, 2009, AHD owned a 2% general partner interest, all of the incentive distribution rights, an approximate 11.4% common limited partner interest, and 15,000 $1,000 par value 12.0% Class B cumulative preferred limited partner units in APL (representing an approximately 2.3% ownership); and

•

Lightfoot Capital Partners, LP (“Lightfoot LP”) and Lightfoot Capital Partners GP LLC, (“Lightfoot GP”), the general partner of Lightfoot (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. The Company has an approximate direct and indirect 18% ownership interest in Lightfoot GP and a commitment to invest a total of $19.7 million in Lightfoot L.P. The Company also has direct and indirect ownership interest in Lightfoot LP. As of December 31, 2009, the Company has invested $13.5 million in Lightfoot LP.

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 subsidiaries, all of which are wholly-owned at December 31, 2009 except for AHD, which is controlled by the Company, and APL, which is controlled by AHD. The financial statements of AHD include its accounts and the accounts of its subsidiaries, all of which are wholly-owned except for APL. Prior to ATN’s merger with the Company’s wholly-owned subsidiary on September 29, 2009, ATN was a controlled subsidiary of the Company but was not wholly-owned (see Note 3). The non-controlling ownership interests in the net income (loss) of ATN prior to the Merger, AHD and APL are reflected within non-controlling interests on the Company’s consolidated statements of operations. The non-controlling interests in the assets and liabilities of AHD and APL are reflected as a component of shareholders’ equity on the Company’s consolidated balance sheets. The non-controlling interests in the assets and liabilities of ATN are reflected as a component of shareholders’ equity on the Company’s December 31, 2008 consolidated balance sheet. All material intercompany transactions have been eliminated.

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.

The Company’s consolidated financial statements also include APL’s 95% ownership interest in joint ventures which individually own a 100% ownership interest in the Chaney Dell natural gas gathering system and processing plants and a 72.8% undivided interest in the Midkiff/Benedum natural gas gathering system and processing plants. APL consolidates 100% of these joint ventures. The Company reflects the non-controlling 5% ownership interest in the joint ventures as non-controlling interests on its statements of operations. The Company also reflects the 5% ownership interest in the net assets of the joint ventures as non-controlling interests as a component of shareholders’ equity on its consolidated balance sheets. The joint ventures have a $1.9 billion note receivable from the holder of the 5% ownership interest in the joint ventures, which is reflected within non-controlling interests on the Company’s consolidated balance sheets.

The Midkiff/Benedum joint venture has a 72.8% undivided joint venture interest in the Midkiff/Benedum system, of which the remaining 27.2% interest is owned by Pioneer Natural Resources Company (NYSE: PXD) (“Pioneer”). Due to the Midkiff/Benedum system’s status as an undivided joint venture, the Midkiff/Benedum joint venture proportionally consolidates its 72.8% ownership interest in the assets and liabilities and operating results of the Midkiff/Benedum system. On November 2, 2009, APL’s agreement with Pioneer, whereby Pioneer had an option to purchase additional interest in the Midkiff/Benedum system, expired without Pioneer exercising its option (see Note 4).

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, deferred tax assets and liabilities, 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. On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system (see Note 6). As such, the Company has adjusted its prior period consolidated financial statements and related footnote disclosures presented within this Form 10-K to reflect the amounts related to the operations of the NOARK gas gathering and interstate pipeline system as discontinued operations. 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 and APL’s operations. In evaluating the realizability of their accounts receivable, the Company’s and APL’s management perform ongoing credit evaluations of their customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the Company’s and APL customers’ credit information. The Company and APL extend credit on an unsecured basis to many of their customers. At December 31, 2009 and 2008, the Company and APL 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 7). 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. See “–Goodwill” accounting policy for information regarding APL’s impairment charge to its goodwill during the year ended December 31, 2008.

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. There were no impairments of unproved oil and gas properties recorded by the Company for the years ended December 31, 2009, 2008 and 2007.

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 its 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. In addition, during the year ended December 31, 2009, APL evaluated its long-lived assets for impairment and recognized a $10.3 million impairment related to inactive pipelines and a reduction in estimated useful lives.

Capitalized Interest

The Company and its subsidiaries capitalize 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 combined borrowed funds by the Company in the aggregate was 7.5%, 6.7% and 7.4% for the years ended December 31, 2009, 2008 and 2007, respectively. The aggregate amount of interest capitalized by the Company was $11.7 million, $12.7 million and $4.9 million for the years ended December 31, 2009, 2008 and 2007, respectively.

Intangible Assets

Customer contracts and relationships. APL amortizes intangible assets with finite lives in connection with natural gas gathering contracts and customer relationships assumed in certain consummated acquisitions, which APL amortizes over their estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At a minimum, APL will assess the useful lives of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for APL’s customer contract intangible assets is based upon the approximate average length of customer contracts in existence and expected renewals at the date of acquisition. The estimated useful life for APL’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition, adjusted for APL’s management’s estimate of whether the individual relationships will continue in excess or less than the average length.

Partnership management, operating contracts and non-compete agreement. 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:
Customer contracts and relationships	$	235,382		$	235,382		3 – 15
Partnership management and operating contracts		14,343			14,343		2 – 13
Non-compete agreement		890			890

	$	250,615		$	250,615


Accumulated Amortization:
Customer contracts and relationships	$	(67,291	)	$	(41,735	)
Partnership management and operating contracts		(11,470	)		(10,728	)
Non-compete agreement		(890	)		(667	)

	$	(79,651	)	$	(53,130	)


Net Carrying Amount:
Customer contracts and relationships	$	168,091		$	193,647
Partnership management and operating contracts		2,873			3,615
Non-compete agreement		–			223

	$	170,964		$	197,485

Amortization expense on intangible assets was $26.5 million, $26.8 million and $12.1 million for the years ended December 31, 2009, 2008 and 2007, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2010-$26.3 million; 2011-$26.2 million; 2012-$25.7 million; 2013-$24.6 million; and 2014-$20.6 million.

Goodwill

At December 31, 2009 and 2008, the Company had $35.2 million of goodwill recorded in connection with consummated acquisitions. The changes in the carrying amount of goodwill for the years ended December 31, 2009, 2008 and 2007 were as follows (in thousands):


	Years Ended December 31,
	2009		2008			2007
Balance, beginning of year	$	35,166	$	744,449		$	98,607
APL purchase price allocation adjustment – Chaney Dell and Midkiff/Benedum acquisition		–		–			645,842
APL post-closing purchase price adjustment with seller and purchase price allocation adjustment – Chaney Dell and Midkiff/Benedum systems acquisition		–		(2,217	)		–
APL recovery of state sales tax initially paid on transaction – Chaney Dell and Midkiff/Benedum systems acquisition		–		(30,206	)		–
Impairment		–		(676,860	)		–

Balance, end of year	$	35,166	$	35,166		$	744,449

The Company and its subsidiaries test their goodwill for impairment at each year end by comparing their reporting unit estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, the Company’s and subsidiaries’ management must apply judgment in determining the estimated fair value of these reporting units. The Company’s and subsidiaries’ 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 and subsidiaries’ 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 and its subsidiaries’, 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 and its subsidiaries’ management also consider 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 and its subsidiaries’ industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in the Company’s and its subsidiaries’ industry to determine whether those valuations appear reasonable in management’s judgment. The Company and its subsidiaries will continue to evaluate goodwill at least annually or when impairment indicators arise.

There were no goodwill impairments recognized by the Company and its subsidiaries during the years ended December 31, 2009 and 2007, and there were no goodwill impairments recognized by ATN during the year ended December 31, 2008. As a result of its impairment evaluation at December 31, 2008, APL recognized a $676.9 million non-cash impairment charge within the Company’s consolidated statements of operations for the year ended December 31, 2008. The goodwill impairment resulted from the reduction in APL’s estimated fair value of its reporting units in comparison to their carrying amounts at December 31, 2008. APL’s estimated fair value of its reporting units was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008. These estimates were subjective and based upon numerous assumptions about future operations and market conditions, which are subject to change.

During the year ended December 31, 2008, APL adjusted its preliminary purchase price allocation for the acquisition of its Chaney Dell and Midkiff/Benedum systems since its July 2007 acquisition date by increasing the estimated amounts allocated to goodwill and intangible assets and reducing amounts initially allocated to property, plant and equipment (see Notes 4). Also, in April 2008, APL received a $30.2 million cash reimbursement for sales tax initially paid on its transaction to acquire the Chaney Dell and Midkiff/Benedum systems in July 2007. The $30.2 million was initially capitalized as an acquisition cost and allocated to the assets acquired, including goodwill, based upon their estimated fair values at the date of acquisition. Based upon the reimbursement of the sales tax paid in April 2008, APL reduced goodwill recognized in connection with the acquisition.

Derivative Instruments

The Company and its subsidiaries enter into certain financial contracts to manage their exposure to movement in commodity prices and interest rates (see Note 11). 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 8). 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 accounts for income taxes under the asset and liability method pursuant to prevailing accounting literature (see Note 15). Deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value.

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 (see Note 18).

Net Income (Loss) Per Share

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of common stock outstanding during the period. Diluted net income (loss) per share is calculated by dividing net income (loss) by the sum of the weighted average number of common stock outstanding and the dilutive effect of potential shares issuable during the period, as calculated by the treasury stock method. Dilutive potential shares of common stock consist of the excess of shares issuable under the terms of the Company’s stock incentive plan over the number of such shares that could have been reacquired (at the weighted average market price of shares during the period) with the proceeds received from the exercise of the stock options (see Note 18). The following table sets forth the reconciliation of the Company’s weighted average number of common shares used to compute basic net income (loss) per share with those used to compute diluted net income (loss) per share (in thousands):


	Years Ended December 31,
	2009	2008⁽¹⁾	2007⁽²⁾
Weighted average number of shares – basic	49,208	39,999	40,840
Add: effect of dilutive incentive awards	–	–	1,506

Weighted average number of common shares – diluted	49,208	39,999	42,346

⁽¹⁾

For the years ended December 31, 2009 and 2008, approximately 1,076,000 and 1,736,000 shares, respectively, were excluded from the computation of diluted net income (loss) per share because the inclusion of such shares would have been anti-dilutive.

⁽²⁾

The shares for the years ended December 31, 2007 have been restated to reflect the three-for-two stock split on May 31, 2008.

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 $41.9 million in deposits at various banks, of which $37.0 million was 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.

Atlas Pipeline. APL’s revenue primarily consists of the fees earned from its transmission, gathering and processing operations. Under certain agreements, APL purchases natural gas from producers and moves it into receipt points on its pipeline systems, and then sells the natural gas, or produced natural gas liquids (“NGLs”), if any, off of delivery points on its systems. Under other agreements, APL transports natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. In connection with its gathering and processing operations, APL enters into the following types of contractual relationships with its producers and shippers:

•

Fee-Based Contracts. These contracts provide for a set fee for gathering and processing raw natural gas. APL’s revenue is a function of the volume of natural gas that it gathers and processes and is not directly dependent on the value of the natural gas.

•

POP Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this situation, APL and the producer are directly dependent on the volume of the commodity and its value; APL owns a percentage of that commodity and is directly subject to its market value.

•

Keep-Whole Contracts. These contracts require APL, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, APL bears the economic risk (the “processing margin risk”) that the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that it paid for the unprocessed natural gas. However, because the natural gas purchases contracted under keep-whole agreements are generally low in liquids content and meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants and delivered directly into downstream pipelines during periods of margin risk. Therefore, the processing margin risk associated with a portion of APL’s keep-whole contracts is minimized.

The Company accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s and APL’s records and management estimates of the related commodity sales and transportation and compression fees 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 $94.9 million and $87.4 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 and post-retirement plan liabilities (which are presented net of income taxes). 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 derivative contracts	$	58,482		$	21,398
Post retirement plan liability		(460	)		(255	)

Accumulated other comprehensive income	$	58,022		$	21,143

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.

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In January 2010, the 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 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:

•

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

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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

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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.

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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 11).

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.

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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 STOCK

Merger with Atlas Energy Resources, LLC

On September 29, 2009, the Company completed its Merger, with ATN surviving as the Company’s wholly-owned subsidiary. In the Merger, the 33.4 million Class B common units of ATN not previously held by the Company were exchanged for 38.8 million shares of the Company’s common stock (a ratio of 1.16 shares of the Company’s common stock for each Class B common unit of ATN). The Company also changed its name from Atlas America, Inc. to Atlas Energy, Inc. Concurrent with the Merger, the Compensation Committee of the Board of Directors approved the Atlas Energy, Inc. 2009 Stock Incentive Plan, which created a new stock

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incentive plan for the combined entity. The Company also has assumed the legacy Atlas America stock incentive plan and the legacy ATN Long-Term Incentive Plan (see Note 18). Due to the Merger, the Company recognized a reduction of $556.4 million in non-controlling interests, a decrease of $197.4 million in deferred tax liabilities, and a $741.8 million increase to additional paid-in-capital on the Company’s consolidated balance sheet. The Company accounted for the Merger transaction in accordance with prevailing accounting literature related to entities under common control and recognized the cost of the interests exchanged in the Merger, excluding transaction costs incurred, of $741.8 million as a non-cash item in its consolidated statement of cash flows for the year ended December 31, 2009.

The following data presents pro forma revenue, net income (loss), net income (loss) per share and basic and diluted weighted average shares outstanding for the Company for the years ended December 31, 2009, 2008 and 2007 as if the Merger discussed above had occurred on January 1, 2007. The Company has prepared these unaudited pro forma financial results for comparative purposes only. The pro forma adjustments reflect an adjustment to income previously allocated to non-controlling interest offset by the restated tax impact. These pro forma financial results may not be indicative of the results that would have occurred if the Merger had been completed at the beginning of the periods shown below or the results that will be attained in the future (in thousands, except per share data, unaudited):


	Years Ended December 31,
	2009			2008		2007
Revenue	$	1,587,602		$	2,098,845	$	1,162,782
Income (loss) attributable to common shareholders:
Income (loss) from continuing operations	$	(65,275	)	$	38,142	$	62,650
Discontinued operations		4,253			1,366		2,120

Net income (loss) attributable to common shareholders	$	(61,022	)	$	39,508	$	64,770

Net income (loss) attributable to common shareholders per share – basic:
Income (loss) from continuing operations attributable to common shareholders	$	(0.83	)	$	0.48	$	0.79
Discontinued operations attributable to common shareholders		0.05			0.02		0.02

Net income (loss) attributable to common shareholders	$	(0.78	)	$	0.50	$	0.81

Net income (loss) attributable to common shareholders per share – diluted:
Income (loss) from continuing operations attributable to common shareholders	$	(0.83	)	$	0.47	$	0.77
Discontinued operations attributable to common shareholders		0.05			0.02		0.03

Net income (loss) attributable to common shareholders	$	(0.78	)	$	0.49	$	0.80

Weighted average common shares outstanding:
Basic		78,210			78,775		79,616

Diluted		78,210			80,510		81,122

Authorized Shares

On July 13, 2009, the Company’s shareholders approved an increase to its authorized shares from 49,000,000 authorized shares to 114,000,000 authorized shares.

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Stock Repurchase Plan

In September 2008, the Company’s Board of Directors approved a stock repurchase program of up to $50.0 million at a price not to exceed $36.00 per share. The daily repurchase amount was limited to 50,000 shares. The Company purchased 595,292 of its shares during September and October 2008 for a total price of $20.0 million under this program. In addition, the Company utilized the remaining $20.0 million of availability under a stock repurchase program approved in September 2005 to purchase 560,291 shares in August and September 2008. The average price for the shares purchased during 2008 was $34.76 per share.

Stock Splits

On April 22, 2008, the Company’s Board of Directors approved a three-for-two stock split of the Company’s common stock affected in the form of a 50% stock dividend. All shareholders of record as of May 21, 2008 received one additional share of common stock for every two shares of common stock held on that date. The additional shares of common stock were distributed on May 30, 2008. Information pertaining to shares and earnings per share has been restated for the year ended December 31, 2007 in the accompanying consolidated financial statements and notes to the consolidated financial statements to reflect this split.

On April 27, 2007, the Company’s Board of Directors approved a three-for-two stock split of the Company’s common stock affected in the form of a 50% stock dividend. All shareholders of record as of May 15, 2007 received one additional share of common stock for every two shares of common stock held on that date. The additional shares of common stock were distributed on May 25, 2007.

Dutch Auction Tender Offer

In January 2007, the Company announced that the Board of Directors had authorized a “Dutch Auction” tender offer for up to 1,950,000 shares of the Company’s common stock at an anticipated offer range of between $52.00 and $54.00 per share. The tender offer commenced on February 8, 2007 and expired on March 9, 2007. In connection with this offering, the Company purchased 1,486,605 shares at a cost of $80.4 million, including expenses.

NOTE 4 – ACQUISITIONS

APL’s Chaney Dell and Midkiff/Benedum Acquisition

In July 2007, APL acquired control of Anadarko’s 100% interest in the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (the “Anadarko Assets”). The transaction was effected by the formation of two joint venture companies which own the respective systems, to which APL contributed $1.9 billion and Anadarko contributed the Anadarko Assets.

In connection with this acquisition, APL reached an agreement with Pioneer, which currently holds a 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer had an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system, which began on June 15, 2008 and ended on November 1, 2008, and an additional 7.4% interest which began on June 15, 2009 and ended on November 1, 2009 (the aggregate 22.0% additional interest could have been entirely purchased during the period from June 15, 2009 to November 1, 2009). If the option were fully exercised, Pioneer would have increased its interest in the system to approximately 49.2%. On November 2, 2009, the option Pioneer had to purchase additional interest in the Midkiff/Benedum system expired without Pioneer exercising it. Pioneer would have paid approximately $230 million, subject to certain adjustments, for the additional 22.0% interest if fully exercised.

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APL funded the purchase price in part from the private placement of $1.125 billion of its common units to investors at a negotiated purchase price of $44.00 per unit. Of the $1.125 billion, $168.8 million of these units were purchased by AHD. AHD funded this purchase through the private placement of $168.8 million of its common units to investors. APL also received a capital contribution from AHD of $23.1 million in order for AHD to maintain its 2.0% general partner interest in APL. AHD funded this capital contribution and the underwriting fees and other transaction costs related to its private placement of common units through borrowings under its revolving credit facility of $25.0 million (see Note 10). APL funded the remaining purchase price from $830.0 million of proceeds from a senior secured term loan which matures in July 2014 and borrowings from its senior secured revolving credit facility that matures in July 2013 (see Note 10). AHD, which holds all of the incentive distribution rights of APL as general partner, had also agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. AHD also agreed that the resulting allocation of incentive distribution rights back to APL would be after AHD receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter (see Note 17).

APL’s acquisition was accounted for using the purchase method of accounting under prevailing accounting literature. The following table presents the purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed in the acquisition, based on their fair values at the date of the acquisition (in thousands):


Accounts receivable	$	745
Prepaid expenses and other		4,587
Property, plant and equipment		1,030,464
Intangible assets – customer relationships		205,312
Goodwill		613,420

Total assets acquired		1,854,528
Accounts payable and accrued liabilities		(1,499	)

Net cash paid for acquisition	$	1,853,029

APL initially recorded goodwill in connection with this acquisition as a result of Chaney Dell’s and Midkiff/Benedum’s significant cash flow and strategic industry position. APL tested its goodwill for impairment at December 31, 2008 and recognized an impairment charge of $676.9 million during the year ended December 31, 2008, which included the amounts recognized in connection with its Chaney Dell and Midkiff/Benedum acquisitions (see “—Goodwill” in Note 2).

In April 2008, APL received a $30.2 million cash reimbursement for state sales tax initially paid on its transaction to acquire the Chaney Dell and Midkiff/Benedum systems. The $30.2 million was initially capitalized as an acquisition cost and allocated to the assets acquired, including goodwill, based upon their estimated fair values at the date of acquisition. Based upon the reimbursement of the sales tax paid in April 2008, APL reduced goodwill recognized in connection with the acquisition. The results of Chaney Dell’s and Midkiff/Benedum’s operations are included within the Company’s consolidated financial statements from the date of acquisition.

ATN’s DTE Gas and Oil Company Acquisition

On June 29, 2007, ATN 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, ATN borrowed $713.9 million under its credit facility (see Note 10) 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

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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 ATN and APL acquisitions 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 ATN and APL had completed these acquisitions and financing transactions at the beginning of the periods 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	$	1,498,902
Income attributable to common shareholders:
Income from continuing operations	$	13,165
Discontinued operations		2,120

Net income attributable to common shareholders	$	15,285


Net income attributable to common shareholders per share – basic:
Income from continuing operations attributable to common shareholders	$	0.32
Discontinued operations attributable to common shareholders		0.05

Net income attributable to common shareholders	$	0.37

Net income attributable to common shareholders per share – diluted:
Income from continuing operations attributable to common shareholders	$	0.31
Discontinued operations attributable to common shareholders		0.05

Net income attributable to common shareholders	$	0.36


Weighted average common shares outstanding:
Basic		40,840

Diluted		42,346

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NOTE 5 – APL INVESTMENT IN JOINT VENTURE

On May 31, 2009, APL and subsidiaries of The Williams Companies, Inc. (NYSE: WMB) (“Williams”) completed the formation of Laurel Mountain Midstream, LLC (“Laurel Mountain”), a joint venture which owns and operates APL’s Appalachia Basin natural gas gathering system, excluding APL’s Northern Tennessee operations. Williams contributed cash of $100.0 million to the joint venture (of which APL received approximately $87.8 million, net of working capital adjustments) and a note receivable of $25.5 million. APL contributed its Appalachia Basin natural gas gathering system and retained a 49% ownership interest. APL is also entitled to preferred distribution rights relating to all payments on the note receivable. Williams retained the remaining 51% ownership interest in Laurel Mountain. Upon completion of the transaction, APL recognized its 49% ownership interest in Laurel Mountain as an investment in joint venture on the Company’s consolidated balance sheet at fair value and recognized a gain on sale of $108.9 million, including $54.2 million associated with the re-measurement of APL’s investment in Laurel Mountain to fair value as determined by the purchase price of the assets. APL used the net proceeds from the transaction to reduce borrowings under its senior secured credit facility (see Note 10). In addition, the Company sold two natural gas processing plants and associated pipelines located in Southwestern Pennsylvania to Laurel Mountain for $10.0 million, resulting in a $6.5 million loss which is included in gain on asset sale on the Company’s consolidated statement of operations. Upon the completion of the contribution of APL’s Appalachia gathering systems to Laurel Mountain, Laurel Mountain entered into new gas gathering agreements with the Company which superseded the existing natural gas gathering agreements and omnibus agreement between APL and the Company. 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%. APL has accounted for its ownership interest in Laurel Mountain under the equity method of accounting, with recognition of its ownership interest in the income of Laurel Mountain other income (loss) on the Company’s consolidated statements of operations.

The following table provides summarized statement of operations and balance sheet data on a 100% basis for Laurel Mountain for the year ended December 31, 2009 and as of December 31, 2009 (in thousands):


	Year Ended December 31, 2009⁽¹⁾
	Year Ended December 31, 2009⁽¹⁾
Statement of Operations data:
Total revenue	$	23,334
Net income		5,855

	December 31, 2009
Balance Sheet data:
Current assets	$	12,193
Long-term assets		248,730
Current liabilities		19,724
Long-term liabilities		9,555
Net equity		231,644

⁽¹⁾

Represents the period from June 1, 2009 through December 31, 2009.

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NOTE 6 – DISCONTINUED OPERATIONS

On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system to Spectra Energy Partners OLP, LP (NYSE:SEP) (“Spectra”) for net proceeds of $292.0 million in cash, net of working capital adjustments. APL received an additional $2.5 million in cash in July 2009 upon the delivery of audited financial statements for the NOARK system assets to Spectra. APL used the net proceeds from the transaction to reduce borrowings under its senior secured term loan and revolving credit facility (see Note 10). The Company accounted for the sale of the NOARK system assets as discontinued operations within its consolidated financial statements and recorded a gain of $48.9 million (net of income taxes of $2.2 million) on the sale of APL’s NOARK assets within income from discontinued operations on its consolidated financial statement of operations for the year ended December 31, 2009. The following table summarizes the components included within income from discontinued operations on the Company’s consolidated statements of operations (amounts in thousands):


	Years Ended December 31,
	2009			2008			2007
Total revenues	$	21,274		$	62,423		$	56,587
Total costs and expenses		(9,858	)		(41,877	)		(25,757	)

Income before income tax expense		11,416			20,546			30,830
Income tax expense		(498	)		(875	)		(1,359	)

Income from discontinued operations	$	10,918		$	19,671		$	29,471

The following table summarizes the components included within total assets and liabilities of discontinued operations within the Company’s consolidated balance sheet for the period indicated (amounts in thousands):


	December 31,
	2008		2007
Cash and cash equivalents	$	75	$	(361	)
Accounts receivable		12,365		9,448
Prepaid expenses and other		1,001		248

Total current assets of discontinued operations		13,441		9,335
Property, plant and equipment, net		241,926		243,342
Other assets, net		239		207

Total assets of discontinued operations	$	255,606	$	252,884

Accounts payable	$	4,120	$	2,008
Accrued liabilities		5,892		4,993
Accrued producer liabilities		560		1,037

Total current liabilities of discontinued operations	$	10,572	$	8,038

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NOTE 7 – PROPERTY, PLANT AND EQUIPMENT

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


							Estimated Useful Lives in Years
	December 31,
	2009			2008⁽¹⁾
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		1,685,200			1,728,472		2 – 40
Rights of way		167,105			168,206		20 – 40
Land, buildings and improvements		26,697			24,385		3 – 40
Other		21,931			22,108		3 – 10

		4,219,251			4,102,338
Less – accumulated depreciation, depletion and amortization		(663,449	)		(357,523	)

	$	3,555,802		$	3,744,815

⁽¹⁾	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 6).

On July 13, 2009, APL sold a natural gas processing facility and a one-third undivided interest in other associated assets located in its Mid-Continent operating segment for approximately $22.6 million in cash. The facility was sold to Penn Virginia Resource Partners, L.P. (NYSE: PVR), who will provide natural gas volumes to the facility and reimburse APL for its proportionate share of the operating expenses. APL will continue to operate the facility. APL used the proceeds from this transaction to reduce outstanding borrowings under its senior secured credit facility. APL recognized a gain on sale of $2.5 million, which is recorded within gain on asset sales on the Company’s consolidated statements of operations.

NOTE 8 – 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.

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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 9 – OTHER ASSETS

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


	December 31,
	2009		2008⁽¹⁾
Deferred finance and organization costs, net of accumulated amortization of $35,470 and $23,105 at December 31, 2009 and 2008, respectively	$	47,147	$	38,871
Investment in Lightfoot LP, Lightfoot GP and Magnetar LP		11,528		10,779
Other investments		6,340		1,994
Long-term pipeline lease prepayment		3,168		–
Security deposits		3,809		1,667
Long-term derivative receivable from Partnerships		2,841		2,719

	$	74,833	$	56,030

⁽¹⁾

Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 6).

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 10). During the year ended December 31, 2009, the Company and APL recorded $1.0 million and $2.5 million of accelerated amortization of deferred financing costs, respectively, which is recorded within interest expense on the Company’s consolidated statement of operations. The Company accelerated $1.0 million of amortization expense because of changes in the borrowing base of its revolving credit facility in April and October 2009. During the year ended December 31, 2008, APL recorded $1.3 million for accelerated amortization of deferred financing costs associated with the repurchase of approximately $60.0 million in face

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amount of its senior unsecured notes and $1.2 million for accelerated amortization of deferred financing costs associated with the retirement of a portion of its term loan with a portion of the net proceeds from its issuance of senior unsecured notes. During the year ended December 31, 2007, ATN and APL recorded $1.7 million and $5.0 million, respectively, of accelerated amortization of deferred financing costs associated with the replacement of their respective credit facilities with new facilities.

Investments at December 31, 2009 included an aggregate $11.5 million invested in Lightfoot LP. The Company owns, directly and indirectly, approximately 13% of Lightfoot LP. In addition, the Company owns, directly and indirectly, approximately 18% of Lightfoot GP, the general partner of Lightfoot LP, an entity of which Jonathan Cohen, Vice Chairman of the Company’s Board of Directors, is the Chairman of the Board. The Company committed to invest a total of $19.7 million in Lightfoot LP. The Company has certain co-investment rights until such point as Lightfoot LP raises additional capital through a private offering to institutional investors or a public offering. Lightfoot LP has initial equity funding commitments of approximately $160.0 million and focuses its investments primarily on incubating new master limited partnerships and providing capital to existing MLPs in need of additional equity or structured debt. Lightfoot LP concentrates on assets that are MLP-qualified such as infrastructure, coal and other asset categories. The Company accounts for its investment in Lightfoot under the equity method of accounting. For the years ended December 31, 2009, 2008 and 2007, the Company recorded losses of $1.4 million, $0.6 million and $0.3 million, respectively.

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 10 – DEBT

At December 31, 2009, the Company’s debt consists entirely of instruments entered into by ATN, AHD and APL. The Company has not guaranteed any of its subsidiaries’ debt obligations, with the exception of the AHD credit facility. Total debt consists of the following at the date indicated (in thousands):


	December 31,
	2009			2008
ATN revolving credit facility	$	184,000		$	467,000
ATN 10.75 % senior notes – due 2018		405,922			406,655
ATN 12.125 % senior notes – due 2017		196,468			–
AHD credit facility		8,000			46,000
APL revolving credit facility		326,000			302,000
APL term loan		433,505			707,180
APL 8.125 % senior notes – due 2015		271,627			261,197
APL 8.75 % senior notes – due 2018		223,050			223,050

Total debt		2,048,572			2,413,082
Less current maturities		(8,000	)		–

Total long-term debt	$	2,040,572		$	2,413,082

ATN Revolving Credit Facility

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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 ATN’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, ATN’s credit agreement was amended to, among other things, permit the Merger and to allow ATN to distribute to the Company (a) amounts equal to the Company’s income tax liability attributable to ATN’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 ATN’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 ATN 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. ATN is in compliance with these covenants as of December 31, 2009. The credit facility also requires ATN 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 ATN’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.

ATN Senior Notes

At December 31, 2009, ATN had $400.0 million principal amount outstanding of 10.75% senior unsecured notes (“ATN 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 (“ATN 12.125% Senior Notes”; collectively, the “ATN Senior Notes”). The ATN 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 ATN’s revolving credit facility. Interest on the ATN Senior Notes in the aggregate is payable semi-annually in arrears on February 1 and August 1 of each year. The ATN 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 ATN 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 ATN 10.75% Notes and before August 1, 2012 for the ATN 12.125% Senior Notes, ATN 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 ATN Senior Notes are also subject to repurchase by ATN at a price equal to 101% of the principal amount of the ATN 10.75% Senior Notes and ATN 12.125% Senior Notes of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if ATN does not reinvest the net proceeds within 360 days. The ATN Senior Notes are junior in right of payment to ATN’s secured debt, including its obligations under its credit facility. The indentures governing the ATN Senior Notes contain covenants, including limitations of ATN’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. ATN is in compliance with these covenants as of December 31, 2009.

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In January 2008, ATN 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, ATN 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. ATN 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, ATN received approximately $4.7 million related to accrued interest. ATN 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 ATN Senior Notes was terminated in January 2010.

AHD Credit Facility

At December 31, 2009, AHD had $8.0 million outstanding under a credit facility with a syndicate of banks. In June 2009, AHD entered into an amendment to its credit facility agreement which, among other changes:

•

required AHD to immediately repay $30.0 million of then-outstanding $46.0 million of borrowings under the credit facility, $15.0 million of which was borrowed from the Company through a subordinate loan;

•

required AHD to repay $4.0 million of the then-remaining $16.0 million outstanding under the credit facility on each of July 13, 2009, October 13, 2009 and January 13, 2010, with the balance of the indebtedness being due on the original maturity date of the credit facility of April 13, 2010. The Company paid $4.0 million on October 13, 2009 and July 13, 2009 pursuant to its guaranty described below. AHD may not borrow additional amounts under the credit facility or issue letters of credit;

•

requires AHD to use any of its “excess cash flow”, which the amendment generally defines as cash in excess of $1.5 million as of the last business day of each month, to repay outstanding borrowings under the credit facility. In addition, the amendment requires AHD to repay borrowings under the credit facility with the net proceeds of any sales of its common units in APL;

•

eliminated all financial covenants in the credit agreement, including the leverage ratio, the combined leverage ratio with APL and the interest coverage ratio (all as defined within the credit facility agreement);

•

prohibits AHD from paying any cash distributions on or redeeming any of its equity while the credit facility is in effect and permits AHD to pay operating expenses only to the extent incurred or paid in the ordinary course of business; and

•

reduced the applicable margin above LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate to be 0.75% for LIBOR loans and 0.0% for federal funds rate or prime rate loans. The weighted average interest rates on the outstanding credit facility borrowings at December 31, 2009 and 2008 were 3.3% and 3.4%, respectively.

Borrowings under AHD’s credit facility are secured by a first-priority lien on a security interest in all of AHD’s assets, including the pledge of Atlas Pipeline GP’s interests in APL, and are guaranteed by Atlas Pipeline GP and AHD’s other subsidiaries (excluding APL and its subsidiaries). AHD’s credit facility contains customary covenants, including restrictions on its ability to incur additional indebtedness; make certain acquisitions, loans or investments; or enter into a merger or sale of substantially all of AHD’s property or assets, including the sale or transfer of interest in its subsidiaries. AHD is in compliance with these covenants as of December 31, 2009. The events which constitute an event of default under AHD’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements,

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adverse judgments against AHD in excess of a specified amount, a change of control of the Company, AHD’s general partner or any other obligor, and termination of a material agreement and occurrence of a material adverse effect.

AHD’s $30.0 million repayment in June 2009 was funded from the proceeds of (i) a loan from the Company in the amount of $15.0 million (originated on June 1, 2009) and (ii) the purchase by APL of $15.0 million of preferred equity in a newly-formed subsidiary of AHD. Under the subordinate loan, interest accrues quarterly on the outstanding principal amount at the rate of 12% per annum, but before the maturity date, interest is payable entirely by increasing the principal amount of the note, and the maturity date is generally the day following the day that AHD pays all indebtedness under the credit facility (“Termination Date”). The material terms of the preferred units purchased by APL in a newly-formed subsidiary of AHD are as follows: distributions are payable quarterly at the rate of 12% per annum, but before the Termination Date, distributions will be paid by increasing APL’s investment in the preferred units; upon the Termination Date, all preferred distributions will be paid in cash to APL; and AHD has the option, after the Termination Date, of redeeming all of the preferred units APL owns for an amount equal to the preferred unit capital.

In June 2009, in connection with AHD’s amendment of the credit facility, the Company guaranteed the then remaining balance outstanding under the credit facility under a guarantee agreement with the administrative agent of the credit facility. In consideration for this guarantee, AHD issued to the Company a promissory note which requires it to pay interest to the Company in an amount based upon the principal amount outstanding under the credit facility. The maturity date of the promissory note is the day following the date that AHD repays all outstanding borrowings under its credit facility. Interest on the promissory note, which is calculated on the outstanding balance under the credit facility plus a $1.0 million guaranty fee, accrues quarterly at the rate of 3.75% per annum. However, prior to the maturity date of the promissory note, interest under the promissory note will not be payable in cash, but instead the principal amount upon which interest is calculated will be increased by the interest amount payable.

APL Term Loan and Credit Facility

At December 31, 2009, APL had a senior secured credit facility with a syndicate of banks which consisted of a term loan which matures in July 2014 and a $380.0 million revolving credit facility which matures in July 2013. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding APL revolving credit facility and term loan borrowings at December 31, 2009 were both 6.8%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $10.1 million was outstanding at December 31, 2009. These outstanding letter of credit amounts were not reflected as borrowings on the Company’s consolidated balance sheet at December 31, 2009. At December 31, 2009, APL had $43.9 million of remaining capacity under its credit facility, subject to covenant limitations.

In May 2009, APL entered into an amendment to its credit facility agreement which, among other changes:

•

increased the applicable margin above adjusted LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank prime rate upon which borrowings under the credit facility bear interest;

•

for borrowings under the credit facility that bear interest at LIBOR plus the applicable margin, set a floor for the adjusted LIBOR interest rate of 2.0% per annum;

•

increased the maximum ratio of total funded debt (as defined in the credit agreement) to consolidated EBITDA (as defined in the credit agreement; the “leverage ratio”) and decreased the ratio of interest coverage (as defined in the credit agreement) that the credit facility requires APL to maintain;

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•

instituted a maximum ratio of senior secured funded debt (as defined in the credit agreement) to consolidated EBITDA (the “senior secured leverage ratio”) that the credit facility requires APL to maintain;

•

required that APL pay no cash distributions during the remainder of the year ended December 31, 2009 and allows it to pay cash distributions commencing with the quarter ending March 31, 2010 if its senior secured leverage ratio is less than 2.75x and it has minimum liquidity (as defined in the credit agreement) of at least $50.0 million;

•

generally limits APL’s annual capital expenditures to $95.0 million for the remainder of fiscal 2009 and $70.0 million each year thereafter;

•

permitted APL to retain (i) up to $135.0 million of net cash proceeds from dispositions completed in fiscal 2009 for reinvestment in similar replacement assets within 360 days, and (ii) up to $50.0 million of net cash proceeds from dispositions completed in any subsequent fiscal year subject to certain limitations as defined within the credit agreement; and

•

instituted a mandatory repayment requirement of the outstanding senior secured term loan from excess cash flow (as defined in the credit agreement) based upon APL’s leverage ratio.

In June 2008, APL entered into an amendment to the credit facility and term loan agreement to revise the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to its early termination of certain derivative contracts (see Note 11) in calculating Consolidated EBITDA. Pursuant to this amendment, in June 2008, APL repaid $122.8 million of its outstanding term loan and repaid $120.0 million of outstanding borrowings under the revolving credit facility with proceeds from its issuance of $250.0 million of 10-year 8.75% senior unsecured notes. Additionally, pursuant to this amendment, in June 2008 APL’s lenders increased their commitments for its revolving credit facility by $80.0 million to $380.0 million.

Borrowings under APL’s credit facility are secured by a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by Chaney Dell and Midkiff/Benedum joint ventures and the Laurel Mountain joint venture, and by the guaranty of each of APL’s consolidated subsidiaries other than the joint venture companies. The credit facility contains customary covenants, including restrictions on APL’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement. APL is in compliance with these covenants as of December 31, 2009.

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The events which constitute an event of default for the credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against APL in excess of a specified amount and a change of control of APL’s general partner. The credit facility requires APL to maintain the following ratios:


Fiscal quarter ending:	Maximum Leverage Ratio	Maximum Senior Secured Leverage Ratio	Minimum Interest Coverage Ratio

December 31, 2009	8.50x	5.25x	1.70x

March 31, 2010	9.25x	5.75x	1.40x

June 30, 2010	8.00x	5.00x	1.65x

September 30, 2010	7.00x	4.25x	1.90x

December 31, 2010	6.00x	3.75x	2.20x

Thereafter	5.00x	3.00x	2.75x

At December 31, 2009, APL’s leverage ratio was 5.1 to 1.0, its senior secured leverage ratio was 3.1 to 1.0 and its interest coverage ratio was 2.6 to 1.0.

APL Senior Notes

At December 31, 2009, APL had $223.1 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“APL 8.75% Senior Notes”) and $275.5 million principal amount outstanding of 8.125% senior unsecured notes due on December 15, 2015 (“APL 8.125% Senior Notes”; collectively, the “APL Senior Notes”). The APL 8.125% Senior Notes are presented combined with a net $3.9 million of unamortized discount as of December 31, 2009. Interest on the APL Senior Notes in the aggregate is payable semi-annually in arrears on June 15 and December 15. The APL 8.75% Senior Notes are redeemable at any time after June 15, 2013, and the APL 8.125% Senior Notes are redeemable at any time after December 15, 2010 at certain redemption prices, together with accrued and unpaid interest to the date of redemption. Prior to June 15, 2011, APL may redeem up to 35% of the aggregate principal amount of the APL 8.75% Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The APL Senior Notes in the aggregate are also subject to repurchase by APL at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if APL does not reinvest the net proceeds within 360 days. The APL Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility.

In January 2009, APL issued Sunlight Capital $15.0 million of its 8.125% Senior Notes to redeem 10,000 APL Class A Preferred Units. Management of APL estimated that the fair value of the $15.0 million 8.125% Senior Notes issued was approximately $10.0 million at the date of issuance based upon the market price of the publicly-traded Senior Notes. As such, APL recognized a $5.0 million discount on the issuance of the APL 8.125% Senior Notes, which is presented as a reduction of long-term debt on the Company’s consolidated balance sheets. The discount recognized upon issuance of the Senior Notes will be amortized to interest expense within the Company’s consolidated statements of operations over the term of the 8.125% Senior Notes based upon the effective interest rate method.

In December 2008, APL repurchased approximately $60.0 million in face amount of its APL Senior Notes for an aggregate purchase price of approximately $40.1 million plus accrued interest of approximately $2.0 million. The notes repurchased were comprised of $33.0 million in face amount of APL’s 8.125% Senior Notes and approximately $27.0 million in face amount of its 8.75% Senior Notes. All of the APL Senior Notes repurchased have been retired and are not available for re-issue.

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Indentures governing the APL Senior Notes in the aggregate contain covenants, including limitations of APL’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. APL is in compliance with these covenants as of December 31, 2009.

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


Years Ended December 31:
2010	$	8,000
2011		–
2012		184,000
2013		326,000
2014		433,505
Thereafter		1,097,067

	$	2,048,572

Cash payments for interest related to debt were $151.6 million, $129.6 million and $81.5 million for the years ended December 31, 2009, 2008 and 2007, respectively.

NOTE 11 – DERIVATIVE INSTRUMENTS

The Company and its subsidiaries use 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 and its subsidiaries enter into financial instruments to hedge its forecasted natural gas, NGL, crude oil and condensate sales against the variability in expected future cash flows attributable to changes in market prices. Its subsidiaries also enter 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, NGLs, crude oil and condensate is sold or interest payments on the underlying debt instrument are due. Under swap agreements, the Company and its subsidiaries receive or pay a fixed price and receive or remit 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, NGLs, crude oil and condensate at a fixed price for the relevant contract period.

The Company and its subsidiaries formally document 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 and its subsidiaries assess, 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 and its subsidiaries will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the Company and its subsidiaries 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 and its subsidiaries recognize the effective portion of changes in fair value in shareholders’ equity as accumulated other comprehensive income and reclassify the portion relating to commodity derivatives to gas and oil production revenues for the Company’s derivatives and gathering, transmission and processing revenues for APL 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

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portion of qualifying derivatives, the Company and its subsidiaries recognize 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 $69.4 million and $89.3 million at December 31, 2009 and 2008, respectively. Of the $58.5 million of net gain in accumulated other comprehensive income within shareholders’ equity on the Company’s consolidated balance sheet related to commodity and interest rate derivatives at December 31, 2009, if the fair values of the instruments remain at current market values, the Company will reclassify $28.7 million of gains to the Company’s consolidated statements of operations over the next twelve month period as these contracts expire, consisting of $31.8 million of gains to gas and oil production revenues, $1.8 million of losses to transmission, gathering and processing revenues and $1.3 million of losses to interest expense. Aggregate gains of $29.8 million will be reclassified to the Company’s consolidated statements of operations in later periods as these remaining contracts expire, consisting of $32.3 million of gains to gas and oil production revenues, $1.2 million of losses to gathering, transmission and processing revenues and $1.3 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:
	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,
Derivatives in Cash Flow Hedging Relationships

	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)

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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 ATN’s credit facility (see Note 10). 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. ATLS 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, ATN had $184.0 million of borrowings under its senior secured revolving credit facility (see Note 10). 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, ATLS 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 ATN’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.

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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	)

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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	)

Atlas Pipeline Holdings and Atlas Pipeline Partners

On July 1, 2008, APL discontinued hedge accounting for its existing commodity derivatives which were qualified as hedges under prevailing accounting literature. As such, subsequent changes in fair value of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s consolidated statements of operations. The fair value of these commodity derivative instruments at June 30, 2008, which was recognized in accumulated other comprehensive loss within shareholders’ equity on the Company’s consolidated balance sheet, will be reclassified to the Company’s consolidated statements of operations in the future at the time the originally hedged physical transactions affect earnings. 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.

At December 31, 2009, AHD had an interest rate derivative contract having an aggregate notional principal amount of $25.0 million. Under the terms of agreement, AHD will pay an interest rate of 3.0%, plus the applicable margin as defined under the terms of its revolving credit facility (see Note 10), and will receive

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LIBOR, plus the applicable margin, on the notional principal amounts. The interest rate swap agreement was effective at December 31, 2009 and expires on May 28, 2010. In June 2009, AHD repaid a portion of its borrowings under its credit facility with additional payments made in July and October 2009 with a resulting balance of $8.0 million outstanding under its credit facility at December 31, 2009. In addition, in accordance with the June 2009 amendment to its credit facility (see Note 10), AHD is prohibited from borrowing additional amounts under its credit facility once the amounts have been repaid. In accordance with prevailing accounting literature, the portion of any gain or loss in other comprehensive income (loss) related to forecasted hedge transactions that are no longer expected to occur are to be removed from other comprehensive income (loss) and recognized within the statements of operations. As a result of this reduction in borrowings under the credit facility below the notional amount of the interest rate derivative contract, the Company recognized an expense of $0.3 million within gain (loss) on mark-to-market derivatives in its consolidated statements of operations for the year ended December 31, 2009.

At December 31, 2009, APL had interest rate derivative contracts having aggregate notional principal amounts of $450.0 million. Under the terms of these agreements, APL will pay weighted average interest rates of 3.0%, plus the applicable margin as defined under the terms of its revolving credit facility (see Note 10), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The APL interest rate swap agreements were effective as of December 31, 2009 and expire during periods ranging from January 30, 2010 through April 30, 2010.

Beginning May 29, 2009, AHD and APL discontinued hedge accounting for their interest rate derivatives which were qualified as hedges under prevailing accounting literature. As such, subsequent changes in the fair value of these derivatives will be recognized immediately within loss on mark-to-market derivatives in the Company’s consolidated statements of operations. The fair value of these derivative instruments at May 29, 2009, which was recognized in accumulated other comprehensive loss within shareholders’ equity’ on the Company’s consolidated balance sheet, will be reclassified to the Company’s consolidated statements of operations in the future at the time the originally hedged physical transactions affect earnings. For non-qualifying derivatives, the Company recognizes changes in fair value within loss on mark-to-market derivatives in its consolidated statements of operations as they occur.

The following table summarizes AHD’s and APL’s gross fair values of cumulative derivative instruments for the period indicated (amounts in thousands):


	Asset Derivative Fair Value					Liability Derivative Fair Value
	Balance Sheet Location	December 31,				Balance Sheet Location	December 31,
	Balance Sheet Location	2009		2008		Balance Sheet Location	2009			2008
Interest rate contracts	N/A	$	–	$	–	Current portion of derivative liability	$	(2,533	)	$	(10,516	)
Interest rate contracts	N/A		–		–	Current portion of derivative asset		(593	)		–
Interest rate contracts	N/A		–		–	Long-term derivative liability		–			(1,936	)
Commodity contracts	Current portion of derivative asset		1,591		44,961	Current portion of derivative asset		–			–
Commodity contracts	Long-term derivative asset		361		–	Long-term derivative asset		–			–
Commodity contracts	Current portion of derivative liability		6,562		7,723	Current portion of derivative liability		(37,862	)		(58,154	)
Commodity contracts	Long-term derivative liability		3,435		3,505	Long-term derivative liability		(14,561	)		(49,902	)

		$	11,949	$	56,189		$	(55,549	)	$	(120,508	)

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As of December 31, 2009, AHD had the following interest rate derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swap


Term	Notional Amount	Type	Contract Period Ended December 31,	Fair Value Liability⁽¹⁾ (in thousands)
May 2008-
May 2010	$25,000,000	Pay 3.0% —Receive LIBOR	2010	$	(286	)

			Total AHD liability	$	(286	)

⁽¹⁾	Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace.

As of December 31, 2009, APL had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swap


Term	Amount		Type	Fair Value Liability (in thousands)
January 2008-January 2010	$	200,000,000	Pay 2.9% —Receive LIBOR	$	(438	)
April 2008-April 2010	$	250,000,000	Pay 3.1% —Receive LIBOR		(2,402	)

Total Interest Rate Swaps					(2,840	)

Fixed Price Swaps


Production Period	Purchased/ Sold	Commodity	Volumes⁽¹⁾	Average Fixed Price			Fair Value Asset/ (Liability) (in thousands)
2010	Purchased	Natural Gas	4,380,000	$	8.635		$	(13,306	)
2010	Sold	Natural Gas Basis	4,500,000		(0.638	)		(1,936	)
2010	Purchased	Natural Gas Basis	8,880,000		(0.597	)		3,369
2011	Sold	Natural Gas Basis	1,920,000		(0.728	)		(845	)
2011	Purchased	Natural Gas Basis	1,920,000		(0.758	)		903
2012	Sold	Natural Gas Basis	720,000		(0.685	)		(269	)
2012	Purchased	Natural Gas Basis	720,000		(0.685	)		269

Total Fixed Price Swaps								(11,815	)

NGL Options


Production Period	Purchased/ Sold	Type	Commodity	Volumes⁽¹⁾	Average Strike Price		Fair Value Asset (in thousands)
2010	Purchased	Put	Propane	35,910,000	$	1.022	$	1,137
2010	Purchased	Put	Normal Butane	3,654,000		1.205		29
2010	Purchased	Put	Natural Gasoline	3,906,000		1.545		102

								1,268

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Crude Oil Options


Production Period	Purchased/ Sold	Type	Commodity	Volumes⁽¹⁾	Average Strike Price	Fair Value Asset/ (Liability) (in thousands)
2010	Purchased	Put	Crude Oil	897,000	73.12		3,518
2010	Sold	Call	Crude Oil	3,361,500	81.23		(23,183	)
2010	Purchased⁽²⁾	Call	Crude Oil	714,000	120.00		430
2011	Sold	Call	Crude Oil	678,000	94.68		(6,687	)
2011	Purchased⁽²⁾	Call	Crude Oil	252,000	120.00		1,017
2012	Sold	Call	Crude Oil	498,000	95.83		(6,197	)
2012	Purchased⁽²⁾	Call	Crude Oil	180,000	120.00		1,175

							(29,927	)

				Total APL liability		$	(43,314	)

⁽¹⁾	Volumes for Natural Gas are stated in MMBTU’s. Volumes for NGLs are stated in gallons. Volumes for Crude are stated in barrels.

⁽²⁾	Calls purchased for 2010 through 2012 represent offsetting positions for calls sold. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise.

During the years ended December 31, 2009 and 2008, APL made net payments of $5.0 million and $274.0 million, respectively, related to the early termination of derivative contracts. The majority of these derivative contracts were put into place simultaneously with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 and related to production periods ranging from the end of the second quarter of 2008 through the fourth quarter of 2009. Additional terminated derivative contracts extend through the fourth quarter of 2012. During the years ended December 31, 2009, 2008 and 2007, the Company recognized the following derivative activity related to APL’s termination of these derivative instruments within its consolidated statement of operations (amounts in thousands):


Early termination of derivative contracts	For the Years Ended December 31,
	2009			2008			2007

Cash paid for early termination	$	(5,000	)	$	(273,987	)	$	–
Less: Deferred recognition of loss on early termination⁽¹⁾		–			(76,345	)		–

		(5,000	)		(197,642	)		–
Net cash derivative expense included within transmission, gathering and processing revenue		–			2,322			–
Net cash derivative expense included within loss on mark-to-market derivatives		(5,000	)		(199,964	)		–
Recognition of deferred hedge loss from prior periods included within transmission, gathering and processing revenue		(68,479	)		(32,389	)		–
Recognition of deferred hedge loss from prior periods included within loss on mark-to-market derivatives		44,861			(39,218	)		–

Total recognized loss from early termination	$	(28,618	)	$	(269,249	)	$	–

⁽¹⁾	Deferred recognition based upon effective portion of hedges deferred to accumulated other comprehensive income (loss), plus theoretical premium related to unwound options which had previously been purchased or sold as part of costless collars.

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In addition, APL will recognize $14.6 million, $2.3 million and $2.0 million of income in years 2010, 2011 and 2012, respectively, the remaining period for which the hedged physical transactions are scheduled to be settled, in the Company’s consolidated statement of operations. This $18.9 million includes $23.5 million of income related to the theoretical premiums for unwound options, which had previously been purchased or sold as part of costless collars, with an offsetting expense of $4.6 million, which will be reclassified from accumulated other comprehensive income within shareholders’ equity on the Company’s consolidated balance sheet.

The following table summarizes AHD’s and APL’s cumulative derivative activity for the periods indicated including the amounts shown above (amounts in thousands):


	Years Ended December 31,
	2009			2008			2007
Cash Settlements:
Gain (loss) from cash settlement of effective portion of qualifying commodity derivatives⁽¹⁾	$	22,211		$	(49,268	)	$	(48,601	)
Loss from cash settlement of ineffective portion of qualifying commodity derivatives⁽¹⁾		(123	)		(23,359	)		(792	)
Loss from cash settlement of qualifying interest rate derivatives⁽²⁾		(12,260	)		(1,289	)		–
Loss from cash settlement of non-qualifying /ineffective commodity derivatives⁽³⁾		(53,699	)		(211,636	)		(10,158	)
Loss from cash settlement of non-qualifying interest rate derivatives⁽³⁾		(608	)		–			–

Total loss from cash settlements	$	(44,479	)	$	(285,552	)	$	(59,551	)

Non-cash gain (loss):
Loss from recognition of effective portion of qualifying commodity derivatives settled in a prior period⁽¹⁾		(68,479	)		(32,389	)		–
Gain from non-cash recognition of non-qualifying derivatives settled in a prior period⁽³⁾⁽⁴⁾		44,861			(39,218	)		–
Gain (loss) from change in market value of non-qualifying and ineffective commodity derivatives⁽²⁾		(27,126	)		187,374			(169,423	)
Loss from change in market value of non-qualifying interest rate derivatives⁽²⁾		(972	)		–			–

Total non-cash gain (loss)	$	(51,716	)	$	115,767		$	(169,423	)

Total derivative loss	$	(96,195	)	$	(169,785	)	$	(228,974	)

⁽¹⁾	Included within transmission, gathering, and processing revenue on the Company’s consolidated statements of operations.

⁽²⁾	Included within interest expense on the Company’s consolidated statements of operations.

⁽³⁾	Included within loss on mark-to-market derivatives on the Company’s consolidated statements of operations.

⁽⁴⁾	Non-cash recognition of non-qualifying derivatives includes the theoretical premium related to calls sold in conjunction with puts purchased in costless collars in which the puts were sold as part of the equity unwinds in 2008.

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The following tables summarize the gross effect of AHD’s and APL’s derivative instruments on the Company’s consolidated statement of operations for the period indicated (amounts in thousands):


Gain (Loss) Recognized in Accumulated Other Comprehensive Income										Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion)
	Years ended December 31										Years ended December 31
	2009			2008			2007			Location	2009			2008			2007
Interest rate contracts⁽¹⁾	$	(2,412	)	$	(13,741	)	$	–		Interest expense	$	(12,260	)	$	(1,289	)	$	–
Interest rate contracts⁽²⁾		–			–			–		Loss on mark-to-market derivatives		(292	)		–			–
Commodity contracts⁽¹⁾		–			(112,824	)		(101,176	)	Transmission, gathering and processing revenue		(46,268	)		(81,657	)		(48,601	)
Commodity contracts⁽²⁾		–			–			–		Loss on mark-to-market derivatives		–			–			(12,611	)

	$	(2,412	)	$	(126,565	)	$	(101,176	)		$	(58,820	)	$	(82,946	)	$	(61,212	)

⁽¹⁾

Hedges previously designated as cash flow hedges

⁽²⁾

Reclassified from other comprehensive income as a result of the dedesignation of derivatives


	Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
		Years ended December 31
	Location	2009			2008			2007
Interest rate contracts⁽¹⁾	Loss on mark-to-market derivatives	$	(1,288	)	$	–		$	–
Commodity contracts⁽¹⁾	Transmission, gathering and processing revenue		(123	)		(23,359	)		(792	)
Commodity contracts⁽¹⁾	Loss on mark-to-market derivatives		–			(263,977	)		(4,093	)
Commodity contracts⁽²⁾	Loss on mark-to-market derivatives		(35,964	)		200,497			(162,877	)

		$	(37,375	)	$	(86,839	)	$	(167,762	)

⁽¹⁾	Hedges previously designated as cash flow hedges

⁽²⁾	Dedesignated cash flow hedges and non-designated hedges

The fair value of the derivatives included in the Company’s consolidated balance sheets is as follows (in thousands):


	December 31,
	2009			2008
Current portion of derivative asset	$	74,064		$	152,726
Long-term derivative asset		59,291			69,451
Current portion of derivative liability		(38,485	)		(73,776	)
Long-term derivative liability		(25,441	)		(59,103	)

Total Company net asset	$	69,429		$	89,298

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NOTE 12 – 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 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, AHD’s and APL’s outstanding derivative contracts (see Note 11) and the Company’s Supplemental Employment Retirement Plans (“SERPs” - see Note 18). The Company’s and APL’s commodity derivative contracts, with the exception of APL’s NGL fixed price swaps and NGL options, 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, AHD’s and APL’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. The Company’s SERPs are calculated based on observable actuarial inputs developed by a third-party actuary and therefore is defined as a Level 2 fair value measurement, while the asset related to the funding of the SERPs are based on publicly traded equity and debt securities and is therefore defined as a Level 1 fair value measurement. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGL’s for similar locations, and therefore are defined as Level 3 fair value measurements. Valuations for APL’s NGL options are based on forward price curves developed by the related financial institution, and therefore are defined as Level 3 fair value measurements.

In June 2009, APL changed the basis for its valuation of crude oil options. Previously, APL utilized forward price curves developed by its derivative counterparties. Effective June 2009, APL utilized crude oil option prices quoted from a public commodity exchange. With this change in valuation basis, APL reclassified the inputs for the valuation of its crude oil options from a Level 3 input to a Level 2 input. The change in valuation basis did not materially impact the fair value of its derivative instruments on its consolidated statements of operations.

Assets and liabilities measured at fair value at December 31, 2009 were as follows (in thousands):


	Level 1		Level 2			Level 3		Total
SERP liability	$	–	$	(3,968	)	$	–	$	(3,968	)
SERP asset funded in rabbi trust		3,778		–			–		3,778
Company commodity-based derivatives		–		117,003			–		117,003
APL commodity-based derivatives		–		(41,742	)		1,268		(40,474	)
Interest rate derivatives		–		(7,100	)		–		(7,100	)

Total	$	3,778	$	64,193		$	1,268	$	69,239

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APL’s Level 3 fair value amount relates to its derivative contracts on NGL fixed price swaps and crude oil options. The following table provides a summary of changes in fair value of APL’s Level 3 derivative instruments as of December 31, 2009 (in thousands):


	NGL Fixed Price Swaps			NGL Sales Options			Crude Oil Options			Total
Balance – December 31, 2008	$	1,509		$	12,316		$	(23,436	)	$	(9,611	)
New contracts		(1,593	)		(9,462	)		–			(11,055	)
Cash settlements from unrealized gain (loss)⁽¹⁾		(5,527	)		(7,065	)		(37,671	)		(50,263	)
Cash settlements from other comprehensive income⁽²⁾		7,153			–			11,618			18,771
Net change in unrealized gain (loss)⁽¹⁾		(1,542	)		(1,090	)		14,886			12,254
Deferred option premium recognition		–			6,569			2,239			8,808
Transfer to Level 2		–			–			32,364			32,364

Balance – December 31, 2009	$	–		$	1,268		$	–		$	1,268

⁽¹⁾	Included within transmission, gathering and processing revenue on the Company’s consolidated statements of operations.

⁽²⁾	Included within loss on mark-to-market derivatives on the Company’s consolidated statements of operations.

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 APL’s term loan, ATN and APL’s Senior Notes and borrowings under the ATN’s, AHD’s and APL’s credit facilities, were $2,055.2 million and $1,911.4 million, respectively, compared with the carrying amounts of $2,048.6 million and $2,413.1 million, respectively. The Senior Notes were valued based upon recent trading activity. The carrying value of outstanding borrowings under the credit facilities, 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 8). Information for assets that are measured at fair value on a nonrecurring basis for the year ended December 31, 2009 is as follows (in thousands):


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

Total	$	944	$	944

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NOTE 13 — 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 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 Resource America, Inc. The Company has two agreements that govern its ongoing relationship with Resource America, Inc. (“RAI”), its former parent, that are still in effect at December 31, 2009. These agreements are the tax matters agreement and the transition services agreement. The tax matters agreement governs the respective rights, responsibilities and obligations of the Company and RAI with respect to tax liabilities and benefits, tax attributes, tax contests and other matters regarding income taxes, non-income taxes and related tax matters. The transition services agreement governs the provision of support services by the Company to RAI and by RAI to the Company, such general and administrative functions. The Company reimburses RAI for various costs and expenses it incurs for these services on behalf of the Company, primarily payroll and rent. For the years ended December 31, 2009, 2008, and 2007, the Company’s reimbursements to RAI totaled $1.1 million, $1.0 million, and $0.9 million, respectively. At December 31, 2009 and 2008, reimbursements to RAI totaling $0.2 million and $0.1 million, respectively, which remain to be settled between the parties, were reflected in the Company’s consolidated balance sheets as advances to/from affiliate.

Relationship with Laurel Mountain. 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. Under the new gas gathering agreements, the Company is obligated to pay Laurel Mountain all of the gathering fees it collects from the Partnerships, which generally ranges from $0.35 per Mcf to the amount of the competitive gathering fee (which is currently defined as 13% of the gross sales price received for the Partnerships gas) plus any excess amount of the gathering fees collected up to an amount equal to approximately 16% of the natural gas sales price. 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.

RAI’s relationship with Anthem Securities (a wholly-owned subsidiary of the Company). Anthem Securities, Inc. (“Anthem”) is a wholly-owned subsidiary of the Company and a registered broker-dealer which served as the dealer-manager of investment partnerships sponsored by RAI’s real estate and equipment finance segments. Some of the personnel performing services for Anthem have been paid by RAI, and Anthem reimburses RAI for the allocable costs of such personnel. In addition, RAI has agreed to cover some of the operating costs for Anthem’s office of supervisory jurisdiction, principally licensing fees and costs. RAI paid $5.2 million toward such operating costs of Anthem for the year ended December 31, 2007. During the year ended December 31, 2007, Anthem reimbursed RAI $3.2 million, for costs incurred on Anthem’s behalf. During the first quarter 2007, RAI commenced its own broker-dealer operations and ceased using the services of Anthem.

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.

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NOTE 14 — COMMITMENTS AND CONTINGENCIES

General Commitments

The Company leases office space and equipment under leases with varying expiration dates through 2020. Rental expense was $11.9 million, $11.5 million and $6.6 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		6,703
2011		5,530
2012		4,948
2013		2,687
2014		515
Thereafter		3,663

	$	24,046

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.

As of December 31, 2009, the Company and its subsidiaries are committed to expend approximately $12.8 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

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 the Company and ATN’s various officers and directors as defendants (the “Defendants”), alleged violations of fiduciary duties in connection with the Merger, and requested injunctive relief and damages.

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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 ATN’s public unitholders in connection with their negotiation of the Merger. In particular, plaintiffs allege that the Merger was not entirely fair to ATN’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. ATN 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 15 — INCOME TAXES

The Company accounts for income taxes under the asset and liability method pursuant to prevailing accounting literature. Under such literature, deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value. As of December 31, 2009 and 2008, the Company determined that no valuation allowance was necessary. In conjunction with the Merger, the Company recognized a reduction of its deferred tax liability of $197.4 million, based on previously recorded unrealized gains on the issuance of ATN units and book and tax basis differences in the Company’s investment in ATN.

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 there were no additions, reductions or settlements in unrecognized tax benefits during the years ended December 31, 2009, 2008 and 2007. The Company has no material uncertain tax positions at December 31, 2009.

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The following table details the components of the Company’s provision (benefit) for income taxes from continuing operations attributable to common shareholders for the periods indicated (in thousands):


	Years Ended December 31,
	2009			2008			2007
Provision (benefit) for income taxes:
Current:
Federal	$	(6,670	)	$	(1,929	)	$	14,312
State		701			(331	)		585
Deferred		(43,100	)		(2,761	)		(1,614	)

	$	(49,069	)	$	(5,021	)	$	13,283

A reconciliation between the statutory federal income tax rate and the Company’s effective income tax rate from continuing operations attributable to common shareholders is as follows:


	Years Ended December 31,
	2009	2008		2007
Statutory tax rate	35%	35%		35%
Statutory depletion	—	2		(1	)
Tax exempt interest	—	1		(2	)
Section 199 deduction	—	1		(2	)
State income taxes, net of federal tax benefit	4	4		2
Other, net	—	(3	)	(3	)

	39%	40%		29%

The components of the Company’s net deferred tax asset and liability are as follows at the dates indicated:


	December 31,
	2009			2008
Deferred tax assets:
Unrealized loss on investments	$	2,153		$	5,363
Investment in partnerships		94,746			—
Accrued expenses		2,957			15,104
Capital loss carryforwards		—			8,587
Net operating loss carryforwards		23,698			24,758
Alternative minimum tax credit		621			—
Valuation allowance on deferred tax assets		—			(155	)
Other		512			308

		124,687			53,965

Deferred tax liabilities:
Unrealized gain on investments		(39,446	)		(18,894	)
Gain on sale of subsidiary units		(81,922	)		(190,615	)
Investment in partnerships		—			(55,171	)

		(121,368	)		(264,680	)

Net deferred tax asset (liability)	$	3,319		$	(210,715	)

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Deferred income tax assets and liabilities are classified as current or long-term consistent with the classification of the related temporary difference and are recorded in the Company’s consolidated balance sheets as follows:


	December 31,
	2009			2008
Current deferred tax asset (liability)	$	(26,415	)	$	31,343
Non-current deferred tax asset (liability)		29,734			(242,058	)

	$	3,319		$	(210,715	)

At December 31, 2009, the Company has a federal net operating loss carryforward of $52.9 million that will expire during 2028, and a state net operating loss carryforward of $72.5 million that will expire beginning in 2019 and ending in 2029 if unused. The Company had deferred tax assets of $23.7 million for the net operating loss carryforwards. Management believes it is more likely than not that the deferred tax asset will be fully realized. The valuation allowance of $0.2 million at December 31, 2008, all of which was established prior to 2008 and reversed during 2009, was based on uncertainty of generating future taxable income in certain states during the limited period that the net operating loss carryforwards could be carried forward.

For the years ended December 31, 2009 and 2008, the Company received net cash refunds from income taxes of $5.3 million and $12.1 million, respectively, compared with cash paid for income taxes of $36.9 million for the year ended December 31, 2007.

The Company is subject to income taxes in the U.S. federal jurisdiction and various states. Tax regulations within each jurisdiction are subject to the interpretations of the related tax laws and regulations and require significant judgment to apply. With few exceptions, the Company is no longer subject to U.S. federal, state, and local, or non-U.S. income tax examinations by tax authorities for the years before 2006. The Company’s policy is to reflect interest and penalties related to uncertain tax positions as part of the income tax expense, when and if they become applicable.

NOTE 16 – ISSUANCE OF SUBSIDIARY UNITS

The Company recognizes gains on its subsidiaries’ equity transactions as a credit to equity rather than as income. These gains represent the Company’s portion of the excess net offering price per unit of each of its subsidiary’s units to the book carrying amount per unit.

In August 2009, APL sold 2,689,765 common units in a private placement at an offering price of $6.35 per unit, yielding net proceeds of approximately $16.1 million. APL also received a capital contribution from AHD of $0.4 million for AHD to maintain its 2.0% general partner interest in the APL. In addition, APL issued warrants granting investors in its private placement the right to purchase an additional 2,689,765 common units at a price of $6.35 per unit for a period of two years following the issuance of the original common units. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan (see Note 10), and will make similar repayments with net proceeds from future exercises of the warrants.

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In June 2008, APL sold 5,750,000 common limited partner units in a public offering at a price of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, the Company purchased 308,109 AHD common units and 1,112,000 APL common limited partner units through a private placement transaction at a price of $32.50 and $36.02 per unit, respectively, for net proceeds of approximately $10.0 million and $40.1 million, respectively. AHD utilized the net proceeds from the sale to purchase 278,000 common units of APL, which in turn utilized the proceeds to partially fund the early termination of certain derivative agreements (see Note 11).

In May 2008, ATN sold 2,070,000 of its Class B common units in a public offering yielding net proceeds of approximately $82.5 million. The net proceeds were used to repay a portion of ATN’s outstanding balance under its revolving credit facility. A gain of $17.7 million, net of an income tax provision of $8.7 million, in accordance with prevailing accounting literature was as an increase in additional paid-in capital within shareholder’s equity as well as a corresponding adjustment of $26.4 million to non-controlling interest, during the year ended December 31, 2008.

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

In July 2007, APL sold 25,568,175 common units through a private placement to investors at a negotiated purchase price of $44.00 per unit, yielding net proceeds of approximately $1.125 billion. Of the 25,568,175 common units sold by APL, 3,835,227 common units were purchased by AHD for $168.8 million. APL also received a capital contribution from AHD of $23.1 million for AHD to maintain its 2.0% general partner interest in APL. AHD funded this capital contribution and other transaction costs through borrowings under its revolving credit facility of $25.0 million. APL utilized the net proceeds from the sale to partially fund the acquisition of control of the Chaney Dell natural gas gathering system and processing plants and a 72.8% interest in the Midkiff/Benedum natural gas gathering system and processing plants (see Note 4).

In July 2007, AHD issued 6,249,995 common units (an approximate 27% interest in it at that moment) for net proceeds of $167.0 million after offering costs in a private placement offering. In addition, in July 2007 APL issued 25,568,175 common units through a private placement to investors, of which 3,835,227 common units were purchased by AHD. A gain of $53.0 million, net of an income tax provision of $34.3 million, was recorded as an increase in additional paid-in capital within shareholders’ equity as well as a corresponding adjustment of $87.3 million to non-controlling interest, during the year ended December 31, 2007.

In June 2007, ATN issued 24,001,009 Class B common (an approximate 31% interest in ATN at that moment) for net proceeds of $597.5 million after offering costs in a private placement offering. A gain of $147.9 million, net of an income tax provision of $87.5 million, was recorded as an increase in additional paid-in capital within shareholders’ equity as well as a corresponding adjustment of $235.4 million to non-controlling interest, during the year ended December 31, 2007.

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NOTE 17 – SUBSIDIARY CASH DISTRIBUTIONS

Prior to the Merger, ATN 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, ATN suspended further distributions due to the announcement of its intent to effectuate the Merger (see Note 3). Distributions declared by ATN from inception through December 2008 were as follows:


Date Cash Distribution Paid or Payable	For Quarter Ended	Cash Distribution Per Common Unit			Total Cash Distribution to the Company
					(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 ATN’s initial public offering, through December 31, 2006.

Atlas Pipeline Partners Cash Distributions. APL is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and AHD, as general partner. If APL’s common unit distributions in any quarter exceed specified target levels, AHD will receive between 15% and 50% of such distributions in excess of the specified target levels. Common unit and general partner distributions declared by APL for the period from January 1, 2006 through December 31, 2009 were as follows (in thousands, except per unit amounts):


Date Cash Distribution Paid	For Quarter Ended	APL Cash Distribution per Common Limited Partner Unit		Total APL Cash Distribution to Common Limited Partners		Total APL Cash Distribution to the General Partner
February 14, 2006	December 31, 2005	$	0.83	$	10,416	$	3,638

May 15, 2006	March 31, 2006	$	0.84	$	10,541	$	3,766
August 14, 2006	June 30, 2006	$	0.85	$	11,118	$	4,059
November 14, 2006	September 30, 2006	$	0.85	$	11,118	$	4,059
February 14, 2007	December 31, 2006	$	0.86	$	11,249	$	4,193

May 15, 2007	March 31, 2007	$	0.86	$	11,249	$	4,193
August 14, 2007	June 30, 2007	$	0.87	$	11,380	$	4,326
November 14, 2007	September 30, 2007	$	0.91	$	35,205	$	4,498
February 14, 2008	December 31, 2007	$	0.93	$	36,051	$	5,092

May 15, 2008	March 31, 2008	$	0.94	$	36,450	$	7,891
August 14, 2008	June 30, 2008	$	0.96	$	44,096	$	9,308
November 14, 2008	September 30, 2008	$	0.96	$	44,105	$	9,312
February 13, 2009	December 31, 2008	$	0.38	$	17,463	$	2,545

May 13, 2009	March 31, 2009	$	0.15	$	7,147	$	1,010

138

On May 29, 2009, APL entered into an amendment to its senior secured credit facility (see Note 10), which, among other things, required that it pay no cash distributions during the remainder of the year ended December 31, 2009 and allows it to pay cash distributions commencing with the quarter ending March 31, 2010 if its senior secured leverage ratio is below certain thresholds and it has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million.

In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 4), AHD, which holds all of the incentive distribution rights in APL, agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. AHD also agreed that the resulting allocation of incentive distribution rights back to APL would be after AHD receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter.

Atlas Pipeline Holdings Cash Distributions. AHD has a cash distribution policy under which it distributes, within 50 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders. Distributions declared by AHD for the period from inception through December 31, 2009 were as follows (in thousands except per unit amounts):


Date Cash Distribution Paid or Payable	For Quarter Ended	Cash Distribution per Common Limited Partner Unit			Total Cash Distribution to the Company (in thousands)
November 19, 2006	September 30, 2006	$	0.17	⁽¹⁾	$	2,975
February 19, 2007	December 31, 2006	$	0.25		$	4,375

May 18, 2007	March 31, 2007	$	0.25		$	4,375
August 17, 2007	June 30, 2007	$	0.26		$	4,550
November 19, 2007	September 30, 2007	$	0.32		$	5,600
February 19, 2008	December 31, 2007	$	0.34		$	5,950

May 20, 2008	March 31, 2008	$	0.43		$	7,525
August 19, 2008	June 30, 2008	$	0.51		$	9,082
November 19, 2008	September 30, 2008	$	0.51		$	9,082
February 19, 2009	December 31, 2008	$	0.06		$	1,068

⁽¹⁾	Represents a pro-rated cash distribution of $0.24 per common unit for the period from July 26, 2006, the date of the AHD’s initial public offering, through September 30, 2006.

On June 1, 2009, AHD entered into an amendment to its credit facility agreement, which, among other changes, prohibited it from paying any cash distributions on its equity while the credit facility is in effect (see Note 10).

NOTE 18 — BENEFIT PLANS

Stock Incentive Plan

The Company has a Stock Incentive Plan (the “2004 Plan”) which authorizes the granting of up to 4,499,999 shares of the Company’s common stock to employees, affiliates, consultants and directors of the Company in the form of incentive stock options (“ISOs”), non-qualified stock options, stock appreciation rights (“SARs”), restricted stock and deferred units. The Company also has a 2009 Stock Incentive Plan (the “2009 Plan” and together with the 2004 Plan, the “Plans”) which authorizes the granting of up to 4,800,000 shares of the Company’s common stock to employees, affiliates, consultants and directors of the Company in the form of ISOs, non-qualified stock options, SARs, restricted stock, restricted stock units and deferred units. Generally, all

139

share-based payments to employees, including grants of employee stock options, are required to be recognized in the financial statements based on their fair values.

2009 Plan Stock Options. Generally, options granted under the 2009 Plan at December 31, 2009 vest 25% per year upon the anniversary of the grant and expire not later than ten years after the date of grant. Compensation cost is recorded on a straight-line basis. The Company issues new shares when stock options are exercised or units are converted to shares. The following tables set forth the 2009 Plan activity for the year ended December 31, 2009:


	Shares	Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding at January 1, 2009	—		—
Granted	2,500	$	29.10
Exercised	—		—
Cancelled	—		—
Forfeited or expired	—		—

Outstanding at December 31, 2009	2,500	$	29.10	10.0	$	3

Options exercisable at December 31, 2009	—		—
Available for grant at December 31, 2009	4,784,867

The Company used the Black-Scholes option pricing model in 2009 to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the periods indicated:


	Year Ended December 31, 2009
Expected dividend yield		—
Expected stock price volatility		47%
Risk-free interest rate		3.0%
Expected term (in years)		6.88
Fair value of stock options granted	$	15.08

2009 Plan Restricted Shares and Restricted Stock Units. Under the 2009 Plan, non-employee directors of the Company are awarded deferred units that vest over a four-year period. Each unit represents the right to receive one share of the Company’s common stock upon vesting. Units will vest sooner upon a change in control of the Company or death or disability of a grantee, provided that a grantee has completed at least six months’ service. The fair value of the grants is based on the closing stock price on the grant date, and is being charged to operations over the requisite service periods using a straight-line attribution method. Upon termination of service by a grantee, all unvested units are forfeited.

Restricted shares are granted from time to time to employees of the Company. Each unit represents the right to receive one share of the Company’s common stock upon vesting. The shares are issued to the participant, held in escrow, and paid to the participant upon vesting. The vesting schedule is determined by the Compensation Committee of the Company’s Board of Directors. The fair value of the grant is based on the closing price on the grant date, and is expensed over the requisite service period using a straight-line attribution method.

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The following table summarizes the activity of deferred and restricted units for the year ended December 31, 2009:


	Units	Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2008	—		—
Granted	12,633	$	29.50
Vested	—		—
Forfeited	—		—

Non-vested shares outstanding at December 31, 2009⁽¹⁾	12,633	$	29.50

⁽¹⁾

The aggregate intrinsic value for restricted stock unit awards outstanding at December 31, 2009 was $0.4 million.

At December 31, 2009, the Company had unamortized compensation expense related to its unvested portion of the 2009 Plan options and units of $0.4 million that the Company expects to recognize over the next four years.

2004 Plan Stock Options. For options granted under the 2004 Plan, 25% of the granted amount becomes exercisable each year upon the grant date anniversary, except options totaling 1,687,500 shares awarded in fiscal 2005 to Messrs. Edward Cohen and Jonathan Cohen, which are immediately exercisable, and expire not later than ten years after the date of grant. Compensation cost is recorded on a straight-line basis. The Company issues new shares when stock options are exercised or units are converted to shares. For the years ended December 31, 2009, 2008 and 2007, the Company received $0.2 million, $0.4 million and $0.9 million, respectively, from the exercise of options. The following tables set forth the Plan activity for the years ended December 31, 2009, 2008 and 2007:


	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding at January 1, 2007	2,766,432		$	11.82

Granted	30,000		$	35.82
Exercised	(81,051	)	$	11.32		$	1,696
Forfeited or expired	—			—

Outstanding at December 31, 2007	2,715,381		$	12.10
Granted	825,000		$	32.67
Exercised	(45,030	)	$	11.32		$	969
Forfeited or expired	—			—

Outstanding at December 31, 2008	3,495,351		$	16.96
Granted	107,500		$	13.80
Exercised	(20,234	)	$	11.32		$	144
Cancelled	(15,187	)	$	11.32
Forfeited or expired	(60,376	)	$	23.49

Outstanding at December 31, 2009⁽¹⁾	3,507,054		$	16.81	6.5	$	48,853

Options exercisable at December 31, 2009	2,744,241		$	13.30	5.7
Available for grant at December 31, 2009	759,270

⁽¹⁾	The non-cash compensation expense recognized for option awards for the years ending December 31, 2009, 2008 and 2007 was $3.1 million, $3.9 million and $1.5 million, respectively.

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The Company used the Black-Scholes option pricing model during the years ended December 31, 2009, 2008 and 2007 to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the periods indicated:


	Years Ended December 31,
	2009		2008		2007
Expected dividend yield		0.6%		0.4%		0.4%
Expected stock price volatility		37%		33%		35%
Risk-free interest rate		2.3%		2.6%		4.7%
Expected term (in years)		6.29		6.25		6.25
Fair value of stock options granted	$	5.23	$	11.75	$	15.08

2004 Plan Deferred Units and Restricted Shares. Under the 2004 Plan, non-employee directors of the Company are awarded deferred units that vest over a four-year period. Each unit represents the right to receive one share of the Company’s common stock upon vesting. Units will vest sooner upon a change in control of the Company or death or disability of a grantee, provided that a grantee has completed at least six months’ service. The fair value of the grants is based on the closing stock price on the grant date, and is being charged to operations over the requisite service periods using a straight-line attribution method. Upon termination of service by a grantee, all unvested units are forfeited.

Restricted shares are granted from time to time to employees of the Company. Each unit represents the right to receive one share of the Company’s common stock upon vesting. The shares are issued to the participant, held in escrow, and paid to the participant upon vesting. The units vest one-fourth at each anniversary date over a four-year service period. The fair value of the grant is based on the closing price on the grant date, and is being expensed over the requisite service period using a straight-line attribution method.

The following table summarizes the activity of deferred and restricted units for the years ended December 31, 2009, 2008 and 2007:


	Units		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at January 1, 2007	26,967		$	10.61
Granted	3,221		$	27.93
Vested⁽¹⁾	(9,074	)	$	7.43
Forfeited	—			—

Non-vested shares outstanding at December 31, 2007⁽²⁾	21,114		$	14.61
Granted	1,920		$	46.87
Vested⁽¹⁾	(10,522	)	$	9.27
Forfeited	—			—

Non-vested shares outstanding at December 31, 2008⁽²⁾	12,512		$	24.05
Granted	31,760		$	21.41
Vested⁽¹⁾	(9,906	)	$	19.43
Forfeited	—			—

Non-vested shares outstanding at December 31, 2009^{(2) (3)}	34,366		$	22.94

⁽¹⁾

The intrinsic values for phantom unit awards vested during the years ended at December 31, 2009, 2008 and 2007 were $0.2 million, $0.5 million and $0.2 million, respectively.

⁽²⁾

The aggregate intrinsic values for phantom unit awards outstanding at December 31, 2009 was $1.0 million.

⁽³⁾

The non-cash compensation expense recognized for phantom unit awards was $0.2 million for the year ended December 31, 2009 and $0.1 million for each of the years ending December 31, 2008 and 2007.

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For the years ended December 31, 2009, 2008 and 2007, the Company recorded non cash compensation expense of $3.3 million, $4.0 million and $1.5 million, respectively, for the Company’s options and units. At December 31, 2009, the Company had unamortized compensation expense related to its unvested portion of the options and units of $6.1 million that the Company expects to recognize over the next four years.

Amended and Restated Atlas Energy, Inc. Assumed Long-Term Incentive Plan

Prior to the Merger on September 29, 2009, ATN 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, the Company assumed ATN’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 the Company’s 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 the Company’s 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 the Company. 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.

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Assumed Plan Restricted and Phantom Units. The fair value of the grants under the Assumed LTIP was based on the closing stock 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 and the post-Merger converted restricted stock and phantom unit activity from September 30, 2009 through December 31, 2009:


	Units		Weighted Average Grant Date Fair Value
Non-vested units 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 units 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 units 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 units outstanding at September 29, 2009	738,279		$	23.16
Shares converted on September 29, 2009⁽¹⁾	118,125			N/A

Non-vested shares outstanding at September 30, 2009	856,404		$	19.97
Granted	—			—
Vested	—			—
Forfeited	(232	)	$	30.17

Non-vested shares outstanding at December 31, 2009	856,172		$	19.97

⁽¹⁾

Converted at a ratio of 1.0 ATN common unit to 1.16 common shares of the Company.

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Stock Options. Option awards under the Assumed LTIP expire 10 years from the date of grant and were generally granted with an exercise price equal to the market price of ATN’s stock at the date of grant. For the period from December 31, 2006 to September 29, 2009, the following table summarizes the unconverted number of the ATN Class B units prior to the Merger on September 29, 2009. The converted number of the Company’s common shares subsequent to the Merger and the weighted average exercise price underlying the converted stock options are listed from September 30, 2009 through December 31, 2009. The following table sets for the Assumed Plan option activity for the periods indicated:


	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
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
Stock options converted at September 29, 2009⁽¹⁾	285,488			N/A

Outstanding at September 30,2009	2,069,790		$	20.38
Granted	N/A			N/A
Exercised	—			—		$	—
Forfeited or expired	(1,276	)	$	24.56

Outstanding at December 31, 2009	2,068,514		$	20.38	6.9	$	20,240

Options exercisable at December 31, 2009	325,164		$	18.10	6.3

Available for grant at December 31, 2009	—

⁽¹⁾	Converted at a ratio of 1.0 ATN common unit to 1.16 common shares of the Company.

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.

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The following tables summarize information about stock options outstanding and exercisable under the Assumed LTIP at December 31, 2009 subsequent to the Merger and the weighted average exercise price underlying the converted stock options:


	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number of Shares Outstanding	Weighted Average Remaining Contractual Life in Years	Weighted Average Exercise Price		Number of Shares Exercisable	Weighted Average Exercise Price
$18.10 – 22.22	1,895,906	6.8	$	19.48	325,164	$	18.10
$26.07 – 30.17	163,908	7.5	$	29.98	—		—
$34.30 and above	8,700	8.4	$	34.30	—		—

	2,068,514	6.9	$	20.38	325,164	$	18.10

The Company recognized $4.9 million, $5.5 million and $4.7 million in compensation expense related to the Assumed LTIP restricted stock units, phantom units and unit options for the years ended December 31, 2009, 2008 and 2007, respectively. ATN 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 non-controlling interests on the Company’s consolidated balance sheet during the respective period. At December 31, 2009, the Company had approximately $7.3 million of unrecognized compensation expense related to the unvested portion of the restricted shares, phantom shares and stock options.

Employee Stock Ownership Plan

The Company has an Employee Stock Ownership Plan (“ESOP”), which is a qualified non-contributory retirement plan, that was established to acquire shares of the Company’s common stock for the benefit of all employees who are 21 years of age or older and have completed 1,000 hours of service. Contributions to the ESOP were made at the discretion of the Company’s Board of Directors. Any dividends which may be paid on allocated shares will reduce retained earnings.

The common stock purchased by the ESOP is held by the ESOP trustee in a suspense account. On an annual basis, a portion of the common stock will be released from the suspense account and allocated to participating employees. As of December 31, 2009, all shares were allocated to participants. Participants will receive shares upon vesting, which occurs over a five year period, beginning after the participant’s second year of service.

Supplemental Employment Retirement Plans (“SERPs”)

The Company has employment agreements with certain executive officers, pursuant to which the Company has agreed to provide them with SERPs and with certain financial benefits upon termination of their employment. Under the SERPs, the executive officers entitled to SERP benefits will be paid an annual benefit upon retirement, death or other termination of employment based upon their salary at the time of the termination of their employment, number of years of service to the Company and other factors. During the years ended December 31, 2009, 2008 and 2007, expense recognized with respect to these commitments were $0.6 million, $1.1 million and $1.1 million, respectively.

146

During the year ended December 31, 2009, the Company funded $3.2 million of the outstanding liability with a financial institution in a rabbi trust for the SERP Plans, which is included in other assets on the Company’s consolidated balance sheet. As of December 31, 2009, the actuarial present value of the expected postretirement obligation due under these SERPs was $4.0 million, which is included in other long-term liabilities on the Company’s consolidated balance sheets. The following table provides information about amounts recognized in the Company’s consolidated balance sheets at the dates indicated (in thousands):


	December 31,
	2009			2008
Other liabilities	$	(3,968	)	$	(3,209	)
Accumulated other comprehensive income		461			255
Deferred income tax asset		97			150

Net amount recognized	$	(3,410	)	$	(2,804	)

The estimated amount that will be amortized from accumulated other comprehensive income into expense for the year ended December 31, 2010 is $0.3 million.

AHD Long-Term Incentive Plan

The Board of Directors of AHD approved and adopted AHD’s Long-Term Incentive Plan (“AHD LTIP”), which provides equity incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for AHD. The AHD LTIP is administered by a committee (the “AHD LTIP Committee”), appointed by AHD’s board, which is the Compensation Committee of the Company’s Board of Directors. Under the AHD LTIP, phantom units and/or unit options may be granted, at the discretion of the AHD LTIP Committee, to all or designated Participants, at the discretion of the AHD LTIP Committee. The AHD LTIP Committee may grant such awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units. At December 31, 2009, AHD had 1,093,875 phantom units and unit options outstanding under the AHD LTIP, with 960,650 phantom units and unit options available for grant.

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AHD Phantom Units. A phantom unit entitles a Participant to receive a common unit of AHD, without payment of an exercise price, upon vesting of the phantom unit or, at the discretion of the AHD LTIP Committee, cash equivalent to the then fair market value of a common limited partner unit of AHD. In tandem with phantom unit grants, the AHD LTIP Committee may grant a Participant a distribution equivalent right (“DER”), which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions AHD makes on a common unit during the period such phantom unit is outstanding. The AHD LTIP Committee will determine the vesting period for phantom units. Through December 31, 2009, phantom units granted under the AHD LTIP generally will vest 25% of the original granted amount three years from the date of grant and the remaining 75% of the original granted amount four years from the date of grant. Awards will automatically vest upon a change of control of AHD, as defined in the AHD LTIP. Of the phantom units outstanding under the AHD LTIP at December 31, 2009, 131,675 units will vest within the following twelve months. All phantom units outstanding under the AHD LTIP at December 31, 2009 include DERs granted to the Participants by the AHD LTIP Committee. The amounts paid with respect to AHD’s LTIP DERs were $0.4 million and $0.3 million for the years ended December 31, 2008 and 2007, respectively. There were no amounts paid with respect to AHD’s LTIP DERs for the year ended December 31, 2009. These amounts were recorded as an adjustment of non-controlling interests on the Company’s consolidated balance sheet. The following table sets forth the AHD LTIP phantom unit activity for the periods indicated:


	Years Ended December 31,
	2009			2008			2007
Outstanding, beginning of year		226,300			220,825			220,492
Granted⁽¹⁾		2,000			6,150			708
Matured⁽³⁾		(44,425	)		(675	)		(375	)
Forfeited		(45,000	)		—			—

Outstanding, end of year⁽²⁾		138,875			226,300			220,825


Non-cash compensation expense recognized (in thousands)	$	515		$	1,427		$	1,420

⁽¹⁾

The weighted average price for phantom unit awards on the date of grant, which is utilized in the calculation of compensation expense and does not represent an exercise price to be paid by the recipient, was $3.60, $26.51 and $37.46 for awards granted for the year ended December 31, 2009, 2008 and 2007, respectively.

⁽²⁾

The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2009 is $0.9 million.

⁽³⁾

The intrinsic value for phantom unit awards exercised during the year ended December 31, 2009 was $0.2 million.

At December 31, 2009, AHD had approximately $0.7 million of unrecognized compensation expense related to unvested phantom units outstanding under AHD’s LTIP based upon the fair value of the awards.

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AHD Unit Options. A unit option entitles a Participant to receive a common unit of AHD upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of AHD’s common unit as determined by the AHD LTIP Committee on the date of grant of the option. The AHD LTIP Committee also shall determine how the exercise price may be paid by the Participant. The AHD LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through December 31, 2009, unit options granted under the AHD LTIP generally will vest 25% of the original granted amount three years from the date of grant and the remaining 75% of the original granted amount four years from the date of grant. Awards will automatically vest upon a change of control of AHD, as defined in the AHD LTIP. There are 641,250 unit options outstanding under the AHD LTIP at December 31, 2009 that will vest within the following twelve months. The following table sets forth the AHD LTIP unit option activity for the periods indicated:


	Years Ended December 31,
	2009					2008				2007
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of year		1,215,000		$	22.56		1,215,000	$	22.56		1,215,000	$	22.56
Granted		100,000		$	3.24		–		–		–		–
Forfeited		(360,000	)	$	22.56		–		–		–		–

Outstanding, end of year⁽¹⁾⁽²⁾		955,000		$	20.54		1,215,000	$	22.56		1,215,000	$	22.56


Options exercisable, end of year⁽³⁾		213,750		$	22.56		–		–		–		–


Weighted average fair value of unit options per unit granted during the year	$	0.61					–				–

Non-cash compensation expense recognized (in thousands)	$	48				$	1,237			$	1,237

⁽¹⁾	The weighted average remaining contractual life for outstanding options at December 31, 2009 was 7.1 years.

⁽²⁾	The aggregate intrinsic value of options outstanding at December 31, 2009 was approximately $0.4 million.

⁽³⁾	The weighted average remaining contractual life for options exercisable at December 31, 2009 was 6.9 years.

AHD used the Black-Scholes option pricing model to estimate the weighted average fair value of each unit option granted. The following weighted average assumptions were used for the period indicated:


		Year Ended December 31, 2009
Expected dividend yield		7.0%
Expected stock price volatility		40%
Risk-free interest rate		2.3%
Expected term (in years)		6.9

At December 31, 2009, AHD had approximately $0.5 million of unrecognized compensation expense related to unvested unit options outstanding under AHD’s LTIP based upon the fair value of the awards.

149

APL Long-Term Incentive Plan

APL has a Long-Term Incentive Plan (“APL LTIP”), in which officers, employees and non-employee managing board members of the General Partner and employees of the General Partner’s affiliates and consultants are eligible to participate. The APL LTIP is administered by a committee (the “APL LTIP Committee”) appointed by AHD’s managing board. The APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 435,000 common units.

APL Phantom Units. A phantom unit entitles a grantee to receive a common unit, without payment of an exercise price, upon vesting of the phantom unit or, at the discretion of the APL LTIP Committee, cash equivalent to the fair market value of an APL common unit. In addition, the APL LTIP Committee may grant a participant a DER, which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions APL makes on a common unit during the period the phantom unit is outstanding. A unit option entitles the grantee to purchase APL’s common limited partner units at an exercise price determined by the APL LTIP Committee at its discretion. The APL LTIP Committee also has discretion to determine how the exercise price may be paid by the participant. Except for phantom units awarded to non-employee managing board members of AHD, the APL LTIP Committee will determine the vesting period for phantom units and the exercise period for options. Through December 31, 2009, phantom units granted under the APL LTIP generally had vesting periods of four years. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards will automatically vest upon a change of control, as defined in the APL LTIP. Of the units outstanding under the APL LTIP at December 31, 2009, 28,961 units will vest within the following twelve months. All phantom units outstanding under the APL LTIP at December 31, 2009 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $0.1 million, $0.5 million and $0.6 million for the years ended December 31, 2009, 2008 and 2007, respectively. These amounts were recorded as reductions of non-controlling interest on the Company’s consolidated balance sheet. The following table sets forth the APL LTIP phantom unit activity for the periods indicated:


	Years Ended December 31,
	2009			2008			2007
Outstanding, beginning of year		126,565			129,746			159,067
Granted⁽¹⁾		2,000			54,796			25,095
Matured⁽²⁾		(58,257	)		(56,227	)		(51,166	)
Forfeited		(18,075	)		(1,750	)		(3,250	)

Outstanding, end of year⁽³⁾		52,233			126,565			129,746


Non-cash compensation expense recognized (in thousands)	$	694		$	2,313		$	2,936

⁽¹⁾

The weighted average prices for phantom unit awards on the date of grant, which are utilized in the calculation of compensation expense and do not represent exercise prices to be paid by the recipients, were $4.75, $44.28 and $50.09 for awards granted for the years ended December 31, 2009, 2008 and 2007, respectively.

⁽²⁾

The intrinsic values for phantom unit awards exercised during the years ended at December 31, 2009, 2008 and 2007 were $0.3 million, $2.0 million and $2.6 million, respectively.

⁽³⁾

The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2009 is $0.5 million.

At December 31, 2009, APL had approximately $0.7 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIP based upon the fair value of the awards.

APL Unit Options. A unit option entitles a Participant to receive a common unit of APL upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of APL’s common unit as determined by the APL LTIP Committee on the date of grant of the option. The APL LTIP Committee also shall determine how the exercise price may be paid by the Participant. The APL LTIP Committee will determine the vesting and exercise

150

period for unit options. Unit option awards expire 10 years from the date of grant. Through December 31, 2009, unit options granted under APL’s LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. Awards will automatically vest upon a change of control of APL, as defined in the APL’s LTIP. There were 25,000 unit options outstanding under APL’s LTIP at December 31, 2009 that will vest within the following twelve months. The following table sets forth the APL LTIP unit option activity for the periods indicated:

Years Ended December 31,

2009

2008

2007

Number
of Unit
Options

Weighted
Average
Exercise
Price

Number
of Unit
Options

Weighted
Average
Exercise
Price

Number
of Unit
Options

Weighted
Average
Exercise
Price

Outstanding, beginning of year

–

Granted

100,000

6.24

–

Matured

–

Forfeited

–

Outstanding, end of year⁽¹⁾⁽²⁾

100,000

6.24

–

Options exercisable, end of year

–

Weighted average fair value of unit options per unit granted during the year

100,000

0.14

–

Non-cash compensation expense recognized (in thousands)

–

⁽¹⁾	The weighted average remaining contractual life for outstanding options at December 31, 2009 was 9.0 years.

⁽²⁾	The aggregate intrinsic value of options outstanding at December 31, 2009 was $0.4 million.

APL used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the period indicated:


		Year Ended December 31, 2009
Expected dividend yield		11.0%
Expected stock price volatility		20.0%
Risk-free interest rate		2.2%
Expected term (in years)		6.3

APL Incentive Compensation Agreements

APL had incentive compensation agreements which granted awards to certain key employees retained from previously consummated acquisitions. These individuals were entitled to receive common units of APL upon the vesting of the awards, which was dependent upon the achievement of certain predetermined performance targets through September 30, 2007. At September 30, 2007, the predetermined performance targets were achieved and all of the awards under the incentive compensation agreements vested. Of the total common units issued under the incentive compensation agreements, 58,822 common units were issued during the year ended December 31, 2007. The ultimate number of common units issued under the incentive compensation agreements was determined principally by the financial performance of certain APL assets during the year ended December 31, 2008 and the market value of APL’s common units at December 31, 2008. APL’s incentive compensation agreements also dictated that no individual covered under the agreements would receive an amount of common units in excess of one percent of the outstanding

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common units of APL at the date of issuance. Common unit amounts due to any individual covered under the agreements in excess of one percent of the outstanding common units of APL would have been paid in cash.

Compensation expense is recognized on a straight-line basis over the vesting period. As of December 31, 2008, APL recognized the compensation expense associated with the vesting of awards issued under APL’s incentive compensation agreements in full within the Company’s consolidated statements of operations. As such, no compensation expense was recognized for these incentive compensation agreements during the year ended December 31, 2009. APL recognized income of $36.3 million and expense of $33.4 million for the years ended December 31, 2008 and 2007, respectively, related to the vesting of awards under these incentive compensation agreements. The non-cash compensation expense adjustments for the year ended December 31, 2008 were principally attributable to changes in APL’s common unit market price, which was utilized in the calculation of the non-cash compensation expense for these awards, at December 31, 2008 when compared with the common unit market price at earlier periods and adjustments based upon the achievement of actual financial performance targets through December 31, 2008. APL recognized compensation expense related to these awards based upon the fair value method. During the year ended December 31, 2009, APL issued 348,620 common units to the certain key employees covered under APL’s incentive compensation agreements. No additional common units will be issued with regard to these agreements.

APL Employee Incentive Compensation Plan and Agreement

In June 2009, a wholly-owned subsidiary of APL adopted an incentive plan (the “APL Plan”) which allows for equity-indexed cash incentive awards to employees of APL (the “Participants”), but expressly excludes as an eligible Participant any “Named Executive Officer” of APL (as such term is defined under the rules of the Securities and Exchange Commission) at the time of the award. The APL Plan is administered by a committee appointed by the chief executive officer of APL. Under the APL Plan, cash bonus units may be awarded to Participants at the discretion of the committee and bonus units totaling 325,000 were awarded under the APL Plan in June 2009. In September 2009, the APL subsidiary entered into an agreement with an APL executive officer that granted an award of 50,000 bonus units on substantially the same terms as the bonus units available under the APL Plan (the bonus units issued under the APL Plan and under the separate agreement are, for purposes hereof, referred to as “APL Bonus Units”). An APL Bonus Unit entitles the employee to receive the cash equivalent of the then-fair market value of an APL common limited partner unit, without payment of an exercise price, upon vesting of the APL Bonus Unit. APL Bonus Units vest ratably over a three year period from the date of grant and will automatically vest upon a change of control, death, or termination without cause, each as defined in the governing document. Vesting will terminate upon termination of employment with cause. During the year ended December 31, 2009, APL granted 375,000 APL Bonus Units to Participants. Of the APL Bonus Units outstanding at December 31, 2009, 123,750 APL Bonus Units will vest within the following twelve months. APL recognized $1.2 million of compensation expense related to these awards based upon the fair value of the awards within general and administrative expense on the Company’s consolidated statements of operations with respect to the vesting of these awards for the year ended December 31, 2009. At December 31, 2009, the Company has recognized $1.2 million within accrued liabilities on its consolidated balance sheet with regard to the awards, which represents their fair value at December 31, 2009.

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NOTE 19 — OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS

The Company’s operations include four reportable operating segments. These operating segments reflect the way the Company manages its operations and makes business decisions. The Company does not allocate income taxes to its operating segments. Operating segment data for the periods indicated are as follows (in thousands):


	Years Ended December 31,
	2009			2008⁽³⁾			2007⁽³⁾
Gas and oil production
Revenues⁽¹⁾	$	278,184		$	311,850		$	206,382
Operating costs and expenses		(45,737	)		(48,194	)		(24,184	)
Depreciation, depletion and amortization expense		(103,988	)		(91,991	)		(54,383	)
Goodwill and other asset impairment		(156,359	)		—			—

Segment income (loss)	$	(27,900	)	$	171,665		$	127,815

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	$	40,260		$	20,209		$	21,586
Gain (loss) on asset sales		(6,435	)		(32	)		111
Costs and expenses		(29,557	)		(11,187	)		(9,374	)
Depreciation, depletion and amortization expense		(4,302	)		(3,436	)		(2,552	)

Segment income (loss)	$	(34	)	$	5,554		$	9,771

Atlas Pipeline⁽³⁾
Revenues ⁽⁴⁾	$	775,342		$	1,308,056		$	577,856
Revenues – affiliates		16,766			43,726			33,571
Loss on asset sales		111,440			—			805
Operating costs and expenses		(659,872	)		(1,153,022	)		(617,317	)
Depreciation and amortization expense		(92,435	)		(82,842	)		(43,903	)
Goodwill and other asset impairment		(10,324	)		(676,860	)		—

Segment income (loss)	$	140,917		$	(560,942	)	$	(48,988	)

Reconciliation of segment income (loss) to net income (loss) before income tax provision (benefit)
Segment income (loss)
Gas and oil production	$	(27,900	)	$	171,665		$	127,815
Well construction and completion		56,499			55,427			41,931
Other partnership management		(34	)		5,554			9,771
Atlas Pipeline		140,917			(560,942	)		(48,988	)

Total segment income (loss)		169,482			(328,296	)		130,529
General and administrative expenses⁽⁵⁾		(108,421	)		(57,787	)		(111,180	)
Interest expense⁽⁵⁾		(169,983	)		(144,065	)		(93,677	)
Gain on early extinguishment of debt		—			19,867			—

Net income (loss) from continuing operations before income tax provision (benefit)	$	(108,922	)	$	(510,281	)	$	(74,328	)

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	Years Ended December 31,
	2009		2008⁽³⁾		2007⁽³⁾
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
Atlas Pipeline		154,916		300,723		120,833
Corporate and other		1,420		1,260		4,753

Total capital expenditures	$	322,976	$	648,379	$	322,002


	December 31,
	2009		2008⁽³⁾
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
Atlas Pipeline		—		—

	$	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
Atlas Pipeline⁽³⁾		2,135,860		2,157,590
Discontinued operations		—		255,606
Corporate and other		98,071		169,090

	$	4,406,163	$	4,890,131

⁽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⁾	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 6).

⁽⁴⁾	Includes losses on mark-to-market derivatives of $37.0 million, $63.5 million and $179.6 million for years ended December 31, 2009, 2008 and 2007, respectively.

⁽⁵⁾	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 year ended December 31, 2009, the Company’s APL segment had two customers that individually accounted for approximately 51% and 11% of the segment’s consolidated revenues. No other single customer exceeded ten percent of segment revenues or accounts receivable for the year ended December 31, 2009. For the year ended December 31, 2008, the Company’s APL segment had two customers that individually accounted for approximately 50% and 13% of the segment’s consolidated revenues. For the year ended December 31, 2007, the Company’s APL segment had one customer that individually accounted for approximately 50% of the segment’s consolidated revenues. Additionally, the Company’s APL segment had one customer that individually accounted for 37% of its accounts receivable at December 31, 2008, and two customers that individually accounted for 26% and 11% of its accounts receivable at December 31, 2007. 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. No other single customer exceeded ten percent of segment revenues or accounts receivable for the years shown.

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NOTE 20 – 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 ATN’s revolving credit facility.

NOTE 21 — 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 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		(45,737	)		(48,194	)		(24,184	)
Exploration expenses⁽²⁾		(6,522	)		(6,029	)		(4,065	)
Depreciation, depletion and amortization		(103,988	)		(91,991	)		(54,383	)
Goodwill and other asset impairment⁽³⁾		(156,359	)		—			—
Income tax benefit (expense)⁽⁴⁾		13,425			(64,598	)		(36,259	)

	$	(20,997	)	$	101,038		$	87,491

⁽¹⁾	Includes unrealized gains from mark-to-market derivatives of $26.3 million during the year ended December 31, 2007.

⁽²⁾	Represents ATN’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.

⁽⁴⁾	Estimate of attributable income taxes based upon the Company’s overall effective income tax rates of 39%, 39%, and 29% for the years ended December 31, 2009, 2008 and 2007, respectively.

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.

155

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,
Property acquisition costs:	2009		2008		2007
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 ATN’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.

156

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 AGO 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.

157

The following schedule presents the standardized measure of estimated discounted future net cash flows relating to proved oil and gas reserves. The estimated future production is priced at 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 income tax expense		(247,532	)		(756,278	)		(996,877	)

Future net cash flows	$	1,645,606		$	2,661,962		$	3,219,180

Less 10% annual discount for estimated timing of cash flows	$	(1,241,082	)	$	(1,737,221	)	$	(2,074,190	)

Standardized measure of discounted future net cash flows	$	404,524		$	924,741		$	1,144,990

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 standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves, net of income taxes (in thousands):


	Years Ended December 31,
	2009			2008			2007
Balance, beginning of year	$	924,741		$	1,144,990		$	205,520
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs		(232,447	)		(263,655	)		(155,992	)
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
Net changes in future income taxes		175,241			128,987			(261,459	)
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		39,163			71,916			39,859

Outstanding, end of year	$	404,524		$	924,741		$	1,144,990

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NOTE 22 — QUARTERLY RESULTS (Unaudited)


	Fourth Quarter⁽¹⁾			Third Quarter⁽¹⁾			Second Quarter			First Quarter
Year ended December 31, 2009:	(in thousands, except share data)
Revenues	$	442,338		$	367,184		$	415,959		$	362,121
Income (loss) from continuing operations, net of income tax provision (benefit) of ($54,624), ($716), $3,677, and $2,594	$	(117,067	)	$	(9,886	)	$	82,418		$	(15,318	)
Income (loss) from discontinued operations, net of income tax provision of $0, $0, $2,327 and $399		—			—			51,292			8,477

Net income (loss)		(117,067	)		(9,886	)		133,710			(6,841	)
Income (loss) attributable to non-controlling interests		31,784			9,172			(124,342	)		11,484

Net income (loss) attributable to common shareholders	$	(85,283	)	$	(714	)	$	9,368		$	4,643

Net income (loss) attributable to common shareholders per share – basic:
Income (loss) from continuing operations attributable to common shareholders	$	(1.09	)	$	(0.02	)	$	0.15		$	0.10
Income from discontinued operations attributable to common shareholders		—			—			0.09			0.02

Net income (loss) attributable to common shareholders	$	(1.09	)	$	(0.02	)	$	0.24		$	0.12

Net income (loss) attributable to common shareholders per share – diluted:
Income (loss) from continuing operations attributable to common shareholders	$	(1.09	)	$	(0.02	)	$	0.15		$	0.10
Income from discontinued operations attributable to common shareholders		—			—			0.09			0.02

Net income (loss) attributable to common shareholders	$	(1.09	)	$	(0.02	)	$	0.24		$	0.12

⁽¹⁾	For the third and fourth quarter of the year ended December 31, 2009, approximately 925,000 and 2,516,000 stock awards, respectively, were excluded from the computation of diluted net income (loss) per common share because the inclusion of such units would have been anti-dilutive.

159


	Fourth Quarter⁽¹⁾			Third Quarter⁽¹⁾			Second Quarter			First Quarter⁽¹⁾
Year ended December 31, 2008:	(in thousands, except share data)
Revenues	$	515,372		$	771,002		$	340,088		$	472,383
Income (loss) from continuing operations, net of income tax provision (benefit) of ($17,309), $13,647, ($4,952), and $3,593	$	(447,056	)	$	211,896		$	(246,859	)	$	(23,241	)
Income (loss) from discontinued operations, net of income tax provision of $27, $277, $323 and $248		(510	)		6,261			7,922			5,998

Net income (loss)		(447,566	)		218,157			(238,937	)		(17,243	)
Income (loss) attributable to non-controlling interests		418,654			(194,054	)		231,166			23,665

Net income (loss) attributable to common shareholders	$	(28,912	)	$	24,103		$	(7,771	)	$	6,422

Net income (loss) attributable to common shareholders per share – basic:
Income (loss) from continuing operations attributable to common shareholders	$	(0.74	)	$	0.59		$	(0.21	)	$	0.15
Income from discontinued operations attributable to common shareholders		—			0.01			0.02			0.01

Net income (loss) attributable to common shareholders	$	(0.74	)	$	0.60		$	(0.19	)	$	0.16

Net income (loss) attributable to common shareholders per share – diluted:
Income (loss) from continuing operations attributable to common shareholders	$	(0.74	)	$	0.56		$	(0.21	)	$	0.14
Income from discontinued operations attributable to common shareholders		—			0.01			0.02			0.01

Net income (loss) attributable to common shareholders	$	(0.74	)	$	0.59		$	(0.19	)	$	0.15

⁽¹⁾	For the second and fourth quarters of the year ended December 31, 2008, approximately 1,910,000 and 1,332,000 stock awards, respectively, were excluded from the computation of diluted net income (loss) per common share because the inclusion of such units would have been anti-dilutive.

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*****

ATLAS ENERGY, INC.

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT

BALANCE SHEETS


	December 31,
	2009		2008
ASSETS		(in thousands)
Current assets:
Cash and cash equivalents	$	15,885	$	91,556
Accounts receivable - affiliates		21,670		—
Deferred tax asset		—		31,343
Prepaid expenses and other		1,544		277

Total current assets		39,099		123,176
Investment in subsidiaries		990,411		487,239
Deferred tax asset		29,734		—
Other assets, net		16,972		12,355

	$	1,076,216	$	622,770

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Deferred tax liability	$	26,415	$	—
Accrued liabilities		17,113		17,826

Total current liabilities		43,528		17,826
Deferred tax liability		—		242,058
Other long-term liabilities		3,969		3,208
Commitments and contingencies
Shareholders’ equity		1,028,719		359,678

	$	1,076,216	$	622,770

⁽¹⁾	Investments in subsidiaries are recorded in accordance with the equity method of accounting

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ATLAS ENERGY, INC.

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT

STATEMENTS OF OPERATIONS


	Years Ended December 31,
	2009			2008			2007
Revenues:	(in thousands)
Equity income (loss) in subsidiaries	$	(104,545	)	$	12,167		$	64,955
Other, net		963			2,259			4,457

Total revenues		(103,582	)		14,426			69,412

Costs and expenses:
Transmission, gathering and processing		3,979			13,335			11,879
General and administrative		10,768			11,395			8,584

Total costs and expenses		14,747			24,730			20,463

Income (loss) before income tax provision (benefit)		(118,329	)		(10,304	)		48,949
Income tax provision (benefit)		(46,343	)		(4,146	)		13,613

Net income (loss)	$	(71,986	)	$	(6,158	)	$	35,336

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ATLAS ENERGY, INC.

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT

STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2009			2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:	(in thousands)
Net income (loss)	$	(71,986	)	$	(6,158	)	$	35,336
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Non-cash compensation expense (income)		4,782			4,023			1,542
Equity (income) loss in unconsolidated companies		104,545			(11,292	)		(35,154	)
Distributions received from unconsolidated companies		20,717			107,741			63,419
Deferred income taxes		(43,040	)		15,030			25,164
Other		(4,257	)		4,094			878
Changes in operating assets and liabilities		(13,267	)		(7,442	)		(66,307	)

Net cash provided by (used in) operating activities		(2,506	)		105,996			24,878

CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in unconsolidated companies		(57,784	)		(76,277	)		(10,447	)
Other		(3,353	)		(2,074	)		(13	)

Net cash used in investing activities		(61,137	)		(78,351	)		(10,460	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Costs related to Atlas Energy, Inc. and Atlas Energy Resources, LLC Merger		(11,653	)		—			—
Dividends paid		(1,968	)		(6,664	)		(3,584	)
Purchases of treasury stock		(2,281	)		(40,027	)		(80,449	)
Other		3,874			2,454			3,393

Net cash used in financing activities		(12,028	)		(44,237	)		(80,640	)

Net change in cash and cash equivalents		(75,671	)		(16,592	)		(66,222	)
Cash and cash equivalents, beginning of year		91,556			108,148			174,370

Cash and cash equivalents, end of year	$	15,885		$	91,556		$	108,148

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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.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Atlas Energy, Inc.

We have audited Atlas Energy, Inc.’s (a Delaware corporation) (formerly Atlas America, Inc.) 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, Inc.’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, Inc.’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, Inc. 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, Inc. and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, comprehensive income, shareholders’ 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

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ITEM 8B.

OTHER INFORMATION

None.

PART III

ITEM 9.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Our Board of Directors is divided into three classes with directors in each class serving three year terms. There are no family relationships among the directors and executive officers except that Edward E. Cohen, our Chairman and Chief Executive Officer, is the father of Jonathan Z. Cohen, the Vice Chairman of our Board of Directors. The following table sets forth information regarding our executive officers and directors:


Name	Age	Position	Term Expires
Edward E. Cohen	71	Chairman and Chief Executive Officer	2011
Jonathan Z. Cohen	39	Vice Chairman	2010
Richard D. Weber	46	President	—
Matthew A. Jones	48	Chief Financial Officer and Executive Vice President	—
Sean P. McGrath	38	Chief Accounting Officer	—
Eugene N. Dubay	61	Executive Vice President	—
Freddie M. Kotek	54	Executive Vice President	—
Carlton M. Arrendell	48	Director	2010
Mark C. Biderman	64	Director	2012
Jessica K. Davis	33	Director	2012
Donald W. Delson	58	Director	2010
Dennis A. Holtz	69	Director	2011
Gayle P.W. Jackson	63	Director	2012
Walter C. Jones	47	Director	2010
Harmon S. Spolan	74	Director	2011
Ellen F. Warren	53	Director	2011
Bruce M. Wolf	61	Director	2012

Directors

Edward E. Cohen has been the Chairman of our Board of Directors and our Chief Executive Officer since our organization in September 2000. Mr. Cohen served as our President from September 2000 until October 2009, when Atlas Energy Resources became our wholly-owned subsidiary following our merger transaction. Mr. Cohen has served as the Chairman of the Board and Chief Executive Officer of Atlas Energy Resources since its formation in June 2006. Mr. Cohen has been the Chairman of the Managing Board of Atlas Pipeline Partners GP since its formation in 1999, and Chief Executive Officer of Atlas Pipeline Partners from 1999 until January 2009. Mr. Cohen has been the Chairman of the Board of Atlas Pipeline Holdings GP, LLC, the general partner of Atlas Pipeline Holdings, L.P., since its formation in January 2006, and Chief Executive Officer of Atlas Pipeline Holdings from January 2006 until February 2009. In addition, Mr. Cohen has been Chairman of the Board of Directors of Resource America, Inc. (a publicly-traded specialized asset management company) since 1990, and was its Chief Executive Officer from 1988 until 2004, and President from 2000 until 2003; Chairman of the Board of Resource Capital Corp. (a publicly-traded real estate investment trust) since its formation in September 2005 until November 2009 and still serves on its board; a director of TRM Corporation

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(a publicly traded consumer services company) from 1998 to July 2007; and Chairman of the Board of Brandywine Construction & Management, Inc. (a property management company) since 1994. Mr. Cohen is the father of Jonathan Cohen. Mr. Cohen has been active in the oil and gas business since the late 1970s. Mr. Cohen brings to the board the vast experience that he has accumulated through his activities as a financier, investor and operator in various parts of the country.

Jonathan Z. Cohen has been Vice Chairman of our Board of Directors since our formation in September 2000 and Chairman of our executive committee since October 2009. Mr. Cohen has served as the Vice Chairman of Atlas Energy Resources since its formation in June 2006. Mr. Cohen has been Vice Chairman of the Managing Board of Atlas Pipeline Partners GP since its formation in 1999 and Vice Chairman of the Board of Atlas Pipeline Holdings GP since its formation in January 2006. Mr. Cohen has been a senior officer of Resource America since 1998, serving as the Chief Executive Officer since 2004, President since 2003 and a director since 2002. Mr. Cohen has been Chief Executive Officer, President and a director of Resource Capital Corp. since its formation in 2005, and was the trustee and secretary of RAIT Financial Trust (a publicly-traded real estate investment trust) from 1997, and its Vice Chairman from 2003, until December 2006. Mr. Cohen is a son of Edward E. Cohen. Mr. Cohen’s financial and business experience helps him to bring a strategic vision to our board to assist with our growth and development.

Carlton M. Arrendell has been a director since February 2004. Mr. Arrendell has been the Chief Investment Officer and a Vice President of Full Spectrum of NY LLC since May 2007. Prior to joining Full Spectrum, Mr. Arrendell served as a special real estate consultant to the AFL-CIO Investment Trust Corporation following six years of service as Investment Trust Corporation’s Chief Investment Officer. Mr. Arrendell is also an attorney admitted to practice law in Maryland and the District of Columbia. Mr. Arrendell’s investment expertise is valuable to our company and its subsidiaries in the pursuit of acquisitions. In addition, the board is benefitted by his strong background in finance which enabled him to serve as the chairman of our audit committee until the merger.

Mark C. Biderman has been a director since July 2009. Mr. Biderman was Vice Chairman of National Financial Partners Corp., a publicly-traded financial services company, from September 2008 to December 2008. Before that, from November 1999 to September 2008, he was National Financial’s Executive Vice President and Chief Financial Officer. From May 1987 to October 1999, Mr. Biderman served as Managing Director and Head of the Financial Institutions Group at CIBC World Markets Group, an investment banking firm, and its predecessor, Oppenheimer & Co., Inc. Mr. Biderman is a Chartered Financial Analyst. Mr. Biderman brings extensive financial expertise to the board as well as to the audit committee.

Jessica K. Davis has been a director since September 2009. Ms. Davis was a corporate litigation attorney with the law firm of Drinker Biddle & Reath LLP from August 2005 to June 2009. Before that, from September 2002 through August 2005, Ms. Davis with a corporate litigation attorney with the law firm of Stroock & Stroock & Lavan LLP. Ms. Davis served as an independent member of the Board of Directors of Atlas Energy Resources from March 2009 until September 2009. Ms. Davis’s relative youth, combined with her legal experience helps satisfy our commitment to a board that is diversified by both profession and age.

Donald W. Delson has been a director since February 2004. Mr. Delson has been a Senior Advisor at Keefe, Bruyette & Woods, Inc. since February 2009 and served as a Managing Director, Corporate Finance Group from 1997 to February 2009. Before joining Keefe, Bruyette & Woods, Inc., Mr. Delson served as a Managing Director in the Corporate Finance Group at Alex. Brown & Sons from 1982 to 1997. He has served as a member of the Board of Directors of WSFS Bank since February 2009. Mr. Delson served as an independent member of the Managing Board of Atlas Pipeline Partners GP from June 2003 until May 2004. Mr. Delson has served on our board or that of our subsidiary for almost seven years, a length of service which has provided him with extensive knowledge of our business and industry. Additionally, Mr. Delson’s extensive and varied background in energy and corporate finance makes him especially suited to serve as the chairman of our compensation committee.

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Dennis A. Holtz has been a director since February 2004. Mr. Holtz maintained a corporate and real estate law practice in Philadelphia and New Jersey from 1988 until his retirement in January 2008. Mr. Holtz has served on our board for six years, since our spin-off from Resource America and his length of service on our board provides him with extensive knowledge of our business and industry. Since our company interacts in the Appalachian region with many small firms, Mr. Holtz’s experience as an operator of his own law office is believed to provide insight into interacting with smaller companies.

Gayle P.W. Jackson has been a director since July 2009. Dr. Jackson has been President of Energy Global, Inc., a consulting firm which specializes in corporate development, diversification and government relations strategies for energy companies, since December 2004. From 2001 to 2004, Dr. Jackson served as Managing Director of FE Clean Energy Group, a global private equity management firm that invests in energy companies and projects in Asia, Central and Eastern Europe and Latin America. From 1985 to 2001, Dr. Jackson was President of Gayle P.W. Jackson, Inc., a consulting firm that advised energy companies on corporate development and diversification strategies and also advised national and international governmental institutions on energy policy. From 1985 to 1995, she was also Chief of Staff of the International Energy Agency’s Coal Industry Advisory Board. Dr. Jackson served as Deputy Chairman of the Federal Reserve Bank of St. Louis in 2004-05 and was a member of the Federal Reserve Bank Board from 2000 to 2005. She is a member of the Board of Directors of Ameren Corporation, a publicly-traded public utility holding company, and of the Advisory Panel of Climate Change Capital Private Equity, a London-based private equity buyout fund manager that invests in clean technology companies. Dr. Jackson served as an independent member of the managing board of Atlas Pipeline Partners GP from March 2005 until July 2009. Dr. Jackson brings to the board her extensive experience in the energy industry, including her previous service as a director of Atlas Pipeline Partners GP. Dr. Jackson also has a strong background in finance.

Walter C. Jones has been a director since September 2009. Since June 2008, Mr. Jones has served as a Senior Finance Officer at the Overseas Private Investment Corporation and from May 1994 to May 2005, Mr. Jones was Manager for Asia, Africa, the Middle East, Latin America and the Caribbean, and also served as a Senior Investment Officer in the Finance Department. From June 2005 to June 2007, Mr. Jones served as the General Counsel and Senior Director for Private Equity at Gravitas Capital Advisors, LLC. Prior to that, Mr. Jones was an International Consultant at the Washington, DC firm of Neill & Co. Mr. Jones began his career at the law firm of Sidley & Austin. Mr. Jones served as an independent member of the Board of Directors of Atlas Energy Resources from December 2006 until September 2009. Since the energy industry is highly regulated, Mr. Jones’s background in public-private businesses has been extremely valuable to our board. Mr. Jones has been nominated to serve as the United States Executive Director for the African Development Bank.

Harmon S. Spolan has been a director since August 2006. Since January 2007, Mr. Spolan has served as of counsel to the law firm Cozen O’Connor, where he is chairman of the firm’s charitable foundation. From 1999 until January 2007, Mr. Spolan was a member of the firm and served as chairman of its Financial Services Practice Group and as co-marketing partner. Before joining Cozen O’Connor, Mr. Spolan served as President, Chief Operating Officer, and a director of JeffBanks, Inc., and its subsidiary bank for 22 years. Mr. Spolan has served as a director of Coleman Cable, Inc., since November 2007. Mr. Spolan served as director of TRM Corporation from June 2002 until April 2008. Mr. Spolan’s varied experience in law and finance over many decades is highly compatible with the board’s emphasis on achieving diversity of age and professional backgrounds.

Ellen F. Warren has been a director since September 2009. She is founder and President of OutSource Communications, a marketing communications firm that services corporate and nonprofit clients. Prior to founding OutSource Communications in August 2005, she was President of Levy Warren Marketing Media, a public relations and marketing firm she co-founded in March 1998. She was previously Vice President of Marketing/Communications for Jefferson Bank, a Philadelphia-based financial institution, from September 1992 to February 1998. Ms. Warren served as an independent member of the Board of Directors of Atlas Energy

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Resources from December 2006 until September 2009. Ms. Warren is a seasoned director, having previously served on the board of our subsidiary, Atlas Energy Resources from its formation until the merger. Ms. Warren brings management, communication and leadership skills to our board.

Bruce M. Wolf has been a director since September 2009. He has been President of Homard Holdings, LLC, a wine manufacturer and distributor, since September 2003. Mr. Wolf has been of counsel with Picadio, Sneath, Miller & Norton, P.C., Pittsburgh, PA, since May 2003. Additionally, since June 1999, Mr. Wolf has been a consultant in connection with energy and securities matters, conducting research and providing expert testimony and litigation support. Mr. Wolf was a Senior Vice President of Atlas Energy from October 1998 to May 1999 and, before that, Secretary and General Counsel of Atlas Energy Group from 1980. Mr. Wolf served as an independent member of the Board of Directors of Atlas Energy Resources from December 2006 until September 2009. Mr. Wolf is a seasoned director, having previously served on the board of our subsidiary, Atlas Energy Resources, from its formation until the merger. Mr. Wolf combines his extensive knowledge of energy with a strong legal and financial knowledge.

We have assembled a board of directors comprised of individuals who bring diverse but complementary skills and experience to oversee our business. Our directors collectively have a strong background in energy, finance, law, communications and management. Based upon the experience and attributes of the directors discussed herein, our board determined that each of the directors should, as of the date hereof, serve on our board.

Non-Director Principal Officers

Richard D. Weber has been our President since October 2009. Mr. Weber has been the President, Chief Operating Officer and a director of Atlas Energy Resources and President, Chief Operating Officer and a director of Atlas Energy Resources and Atlas Energy Management since their formation in June 2006. Mr. Weber served from June 1997 until March 2006 as Managing Director and Group Head of the Energy Group of KeyBanc Capital Markets, a division of KeyCorp, and its predecessor, McDonald & Company Securities, Inc., where he oversaw activities with oil and gas producers, pipeline companies and utilities.

Matthew A. Jones has been our Chief Financial Officer since March 2005 and an Executive Vice President since October 2009. Mr. Jones has been the Chief Financial Officer of Atlas Energy Resources and Atlas Energy Management since their formation. Mr. Jones served as the Chief Financial Officer of Atlas Pipeline Holdings GP from January 2006 until September 2009 as the Chief Financial Officer of Atlas Pipeline GP from March 2005 to September 2009. From 1996 to 2005, Mr. Jones worked in the Investment Banking Group at Friedman Billings Ramsey, concluding as Managing Director. Mr. Jones worked in Friedman Billings Ramsey’s Energy Investment Banking Group from 1999 to 2005, and in Friedman Billings Ramsey’s Specialty Finance and Real Estate Group from 1996 to 1999. Mr. Jones has served as a director of Atlas Pipeline Holdings GP since February 2006. Mr. Jones Mr. Jones is a Chartered Financial Analyst.

Sean P. McGrath has been our Chief Accounting Officer and the Chief Accounting Officer of Atlas Energy Resources since December 2008. Mr. McGrath served as the Chief Accounting Officer of Atlas Pipeline Holdings GP from January 2006 until November 2009 and as the Chief Accounting Officer of Atlas Pipeline GP from May 2005 until November 2009. Mr. McGrath was the Controller of Sunoco Logistics Partners L.P., a publicly-traded partnership that transports, terminals and stores refined products and crude oil, from 2002 to 2005. From 1998 to 2002, Mr. McGrath was Assistant Controller of Asplundh Tree Expert Co., a utility services and vegetation management company. Mr. McGrath is a Certified Public Accountant.

Eugene N. Dubay has been our Executive Vice President since October 2009. Before that he was our Senior Vice President from January 2009 to October 2009. Mr. Dubay has also been President and Chief Executive Officer of Atlas Pipeline Partners and Atlas Pipeline Mid-Continent, LLC since January 2009. Mr. Dubay has served as a member of the managing board of Atlas Pipeline Partners GP since October 2008,

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where he served as an independent member until his appointment as President and Chief Executive Officer. Mr. Dubay has been the Chief Executive Officer and President of Atlas Pipeline Holdings since February 2009 and has served as a director of Atlas Pipeline Holdings since February 2009. Mr. Dubay was the Chief Operating Officer of Continental Energy Systems LLC (a successor to SEMCO Energy) from 2002 to January 2009. Mr. Dubay has also held positions with ONEOK, Inc. and Southern Union Company and has over 20 years experience in midstream assets and utilities operations, strategic acquisitions, regulatory affairs and finance. Mr. Dubay is a certified public accountant and a graduate of the U.S. Naval Academy.

Freddie M. Kotek has been an Executive Vice President since February 2004 and served as a director from September 2001 until February 2004. Mr. Kotek has been Chairman of Atlas Resources, LLC since September 2001 and has served as an Executive Vice President since October 2009. He has also served as Chief Executive Officer and President of Atlas Resources since January 2002. Mr. Kotek was our Chief Financial Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice President of Resource America from 1995 until May 2004 and President of Resource Leasing, Inc. (a wholly-owned subsidiary of Resource America) from 1995 until May 2004.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Section 16(a) of the Securities Exchange Act of 1934 requires our officers, directors and persons who own more than 10% of a registered class of our equity securities to file reports of ownership and changes in ownership with the SEC and to furnish us with copies of all such reports.

Based solely on our review of the reports we have received, or written representations from certain reporting persons that no filings were required for those persons, we believe that during fiscal 2009 our executive officers, directors and greater than 10% stockholders complied with all applicable filing requirements of Section 16(a) of the Securities Exchange Act, except Dr. Jackson and Messrs. Biderman and Weber each inadvertently filed one Form 3 late and Ms. Davis, Dr. Jackson, Ms. Warren and Messrs. Arrendell, Biderman, Jones and Wolf each inadvertently filed one Form 4 late.

Code of Ethics

We have adopted a code of business conduct and ethics applicable to all directors, officers and employees. We believe our code meets the definition of a code of ethics under the Securities Act. Our code of business conduct and ethics is available, and any waivers we grant to the code will be available, on our web site at www.atlasenergy.com.

Information Concerning our Company and the Board of Directors

Our common stock is listed for trading on the Nasdaq Global Market under the symbol “ATLS.” The Board held 13 meetings during fiscal 2009 and one special meeting in connection with our merger, whereby our merger subsidiary merged with Atlas Energy Resources, LLC (“ATN”), with ATN surviving as our wholly-owned subsidiary (the “Merger”). Each of the directors attended at least 75% of the meetings of the Board and all meetings of the committees on which the director served during fiscal 2009. The Board currently consists of twelve members, ten of whom are independent directors as defined by Nasdaq standards and the Securities Act. The ten independent directors are Ms. Davis, Dr. Jackson, Ms. Warren and Messrs. Arrendell, Biderman, Delson, Holtz, Jones, Spolan and Wolf. Messrs. William R. Bagnell and Nicholas A. DiNubile served as independent directors during fiscal 2009 until they determined not to stand for re-election at our annual meeting of our stockholders held on July 13, 2009.

Our chairman of the board is also our chief executive officer. We believe that by having this combined position, our chief executive officer chairman serves as a bridge between management and the board, ensuring that both act with a common purpose. In addition, we believe that the combined position facilitates our

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company’s focus on both long- and short- term strategies. Further, we believe that the advantages of having a chief executive officer chairman with extensive knowledge of our company, as opposed to a relatively less informed independent chairman, outweigh potential disadvantages. Additionally, of our 12 current board members, ten have been deemed to be independent by our board. Accordingly, we believe that our super-majority of independent directors provides sufficient independent oversight of our management. Our compensation committee annually reviews our corporate goals and presents our chief executive officer’s compensation for board approval, and our bylaws allow special meetings to be called by a majority of our directors, the president or vice chairman, rather than solely by the chairman or the chief executive officer.

We administer our risk oversight function through our audit committee as well as through our board of directors as a whole. Our audit committee is empowered to appoint and oversee our independent auditors, monitor the integrity of our financial reporting processes and systems of internal controls and provide an avenue of communication among our independent auditors, management, our internal auditing department and our board of directors. Additionally, reports are provided during our board meetings by the individuals who oversee risk management in liquidity and credit areas, environmental, safety, litigation and other operational areas.

Communications with the Board

The Board has also established a process for stockholders to send communications to it. Any stockholder who wishes to send a communication to the Board should write to our Secretary at our Moon Township address stated herein. Beneficial owners must include in their communication a good faith representation that they are beneficial owners of our common stock. Our Secretary will promptly forward to the Chairman of the Board any and all such stockholder communications.

Board Committees

The Board has four standing committees which are the audit committee, the compensation committee, the nominating and governance committee and the investment committee.

Audit Committee. The principal functions of the audit committee are to assist the Board in monitoring the integrity of our financial statements, the independent auditor’s qualifications and independence, the performance of our independent auditors and our compliance with legal and regulatory requirements. The audit committee reviews the adequacy of our internal controls. The audit committee also reviews the scope and effectiveness of audits by the independent accountants and has the sole authority to retain and terminate our independent auditors and to approve the compensation paid to the independent auditors. The audit committee held five meetings during fiscal 2009. The audit committee is also responsible for overseeing our internal audit function. All of the members of the audit committee are independent directors as defined by Nasdaq rules. The members of the audit committee are Ms. Davis, Dr. Jackson and Messrs. Biderman and Delson, with Mr. Biderman acting as the chairman. The Board has determined that Mr. Delson is an “audit committee financial expert,” as defined by SEC rules. The Board previously adopted a written charter for the audit committee, a current copy of which is available on our web site at www.atlasenergy.com.

Compensation Committee. The principal functions of the compensation committee are to administer our employee benefit plans (including incentive plans), annually evaluate salary grades and ranges, establish guidelines concerning average compensation increases, establish performance criteria for and evaluate the performance of our chief executive officer and approve compensation of all officers and directors. The compensation committee held ten meetings during fiscal 2009. The compensation committee is comprised solely of independent directors, consisting of Ms. Warren and Messrs. Delson, Arrendell and Holtz, with Mr. Delson acting as the chairman. The Board previously adopted a written charter for the compensation committee, a current copy of which is available on our web site at www.atlasenergy.com.

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Nominating and Governance Committee. The principal functions of the nominating and governance committee are to recommend persons to be selected by the Board as nominees for election as directors, recommend persons to be elected to fill any vacancies on the Board, consider and recommend to the Board qualifications for the office of director and policies concerning the term of office of directors and the composition of the Board and consider and recommend to the Board other actions relating to corporate governance. The nominating and governance committee held two meetings during fiscal 2009. The nominating and governance committee is comprised solely of independent directors, consisting of Ms. Warren and Messrs. Arrendell, Holtz and Spolan, with Mr. Holtz acting as the chairman.

The nominating and governance committee has adopted a charter with respect to its nominating function, a current copy of which is available on our web site at www.atlasenergy.com. The nominating and governance committee will consider nominees recommended by stockholders for the 2011 annual meeting of stockholders if submitted in writing to our Secretary in accordance with rules promulgated by the SEC and our bylaws.

ITEM 10.

EXECUTIVE COMPENSATION

COMPENSATION DISCUSSION AND ANALYSIS

We hereby provide information regarding the compensation program in place as of December 31, 2009, for our CEO, CFO and the three other most highly-compensated executive officers. In this report, we refer to our CEO, CFO and the three other most highly-compensated executive officers as our “Named Executive Officers” or “NEOs.

Our compensation committee is responsible for formulating and presenting recommendations to the Board of Directors with respect to the compensation of our NEOs. The compensation committee is also responsible for administering our employee benefit plans, including incentive plans. The compensation committee is comprised solely of independent directors, consisting of Messrs. Delson, Arrendell, Holtz; and Ms. Warren, with Mr. Delson acting as the chairperson.

Compensation Objectives

We believe that our compensation program must support our business strategy, be competitive, and provide both significant rewards for outstanding performance and clear financial consequences for underperformance. We also believe that a significant portion of the NEOs’ compensation should be “at risk” in the form of annual and long-term incentive awards that are paid, if at all, based on individual and company accomplishment. Accounting and cost implications of compensation programs are considered in program design; however, the essential consideration is that a program is consistent with our business needs.

Compensation Methodology

Our compensation committee generally makes recommendations to the board on compensation amounts shortly after the close of our fiscal year. In the case of base salaries, the committee recommends the amounts to be paid for the new fiscal year. In the case of annual bonus and long-term incentive compensation, the committee recommends the amount of awards based on the most recently concluded fiscal year. We typically pay cash awards and issue equity awards in February, although our compensation committee has the discretion to recommend salary adjustments and the issuance of equity awards at other times during the fiscal year. In addition, our NEOs and other employees who perform services for our publicly-traded subsidiaries, Atlas Pipeline Partners and Atlas Pipeline Holdings, may receive stock-based awards from these subsidiaries, each of which have delegated compensation decisions to our compensation committee since neither of those companies has their own employees.

Our Chief Executive Officer provides the compensation committee with key elements of our company’s and the NEOs’ performance during the year. Our CEO makes recommendations to the compensation committee

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regarding the salary, bonus, and incentive compensation component of each NEO’s total compensation. Our CEO, at the compensation committee’s request, may attend committee meetings; however, his role during the meetings is to provide insight into our company’s performance, as well as the performance of other comparable companies in the same industry.

Compensation Consultant

The compensation committee retains Mercer (US) Inc., an independent compensation consulting firm, to assist it in evaluating and setting executive compensation. The compensation committee originally retained Mercer in June 2006 to analyze and review the competitiveness and appropriateness of all elements of the compensation we paid to our NEOs, individually and as a group, for fiscal 2006. The purpose of the analysis was to determine whether our compensation practices were within the norm for companies of similar size and focus. The peer group analysis was not aimed at establishing benchmarks for our compensation program, but rather to provide a “reality check” to obtain a general understanding of then current compensation levels. Because of the importance to our company of our direct-placement energy investment programs and our creation of new initiatives and entities, Mercer looked not only to the energy industry in evaluating our compensation levels but also to the financial services and alternative asset industries. Mercer’s analysis established that our fiscal 2006 compensation amounts fell between the median and the 75^th percentile of the peer group it used, which our compensation committee found acceptable in the context of its evaluation of the performance of the NEOs.

Between 2006 and 2009, Mercer continued to assist the compensation committee in setting executive compensation but did not conduct a similar peer group analysis. In June 2009, the compensation committee engaged Mercer to conduct a competitive review of our then current NEO compensation program. Mercer provided a proxy analysis based on a peer group of 14 energy companies, which we refer to as the full peer group, against which we compete for executive talent, land and mineral rights, oil and gas services, pipeline and takeaway capacity, and/ or water disposal capacity. The peer group consists of: Anadarko Petroleum Corporation, Chesapeake Energy Corporation, Cabot Oil & Gas Corporation, CONSOL Energy Inc., EQT Corporation, Exco Resources, Inc., Linn Energy, LLC, MarkWest Energy Partners, L.P., Quicksilver Resources Inc., Pioneer Natural Resources Company, Range Resources Corporation, Southwestern Energy Company, The Williams Companies, Inc., and XTO Energy Inc. In the pipeline business, we compete against some of the members of the peer group for takeaway capacity, processing services and/or water disposal capacity.

Mercer also analyzed a 10-company subset of the full peer group, which we refer to as the size-adjusted peer group, that included companies’ 2008 revenues of between $750 million to $3 billion, that is, approximately one-half to twice our revenues. The size-adjusted peer group excluded Anadarko Petroleum, Chesapeake Energy, Williams, and XTO Energy. In addition, Mercer provided a survey analysis of competitive data gathered from published surveys.

Our compensation committee does not set a specific percentile range for our NEO compensation amounts. Rather, it uses the comparative information as part of the total mix of information it considers.

In addition to the competitive analysis of our NEO compensation program, at the compensation committee’s direction, Mercer provided the following services for the committee during fiscal 2009:

•

provided advice with respect to our new long-term incentive plan;

•

advised the committee with respect to awards for 2009 under our Senior Executive Plan, discussed below, and established performance measures and performance targets for 2010; and

•

provided advice on Matthew Jones’s employment agreement.

In the course of conducting its activities for fiscal 2009, Mercer attended five meetings of the compensation committee and presented its findings and recommendations for discussion.

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The compensation committee has established procedures that it considers adequate to ensure that Mercer’s advice remains objective and is not unduly influenced by our management. These procedures include: a direct reporting relationship of the Mercer consultant to the chairman of the compensation committee; provisions in the engagement letter with Mercer specifying the information, data, and recommendations that can and cannot be shared with management; an annual update to the compensation committee on Mercer’s financial relationship with us, including a summary of the work performed for us during the preceding 12 months; and written assurances from Mercer that, within the Mercer organization, the Mercer consultant who performs services for the compensation committee has a reporting relationship and compensation determined separately from Mercer’s other lines of business and from its other work for us. In fact, Mercer did not perform non-executive compensation consulting services for our company during the last fiscal year or during any other year. With the consent of the compensation committee chair, Mercer may contact our executive officers for information necessary to fulfill its assignment and may make reports and presentations to and on behalf of the compensation committee that the executive officers also receive.

In making its compensation decisions, the compensation committee meets in executive session, without management, both with and without Mercer. Ultimately, the decisions regarding executive compensation are made by the compensation committee after extensive discussion regarding appropriate compensation and may reflect factors and considerations other than the information and advice provided by Mercer and our CEO. The compensation committee’s decisions are then submitted to the Board.

Elements of our Compensation Program

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

Base Salary

Base salary is intended to provide fixed compensation to the NEOs for their performance of core duties that contributed to our success as measured by the elements of corporate performance mentioned above. Base salaries are not intended to compensate individuals for extraordinary performance or for above average company performance.

Annual Incentives

Annual incentives are intended to tie a significant portion of each of the NEO’s compensation to our annual performance and/or that of our subsidiaries or divisions for which the officer is responsible. Generally, the higher the level of responsibility of the executive within our company, the greater is the incentive component of that executive’s target total cash compensation. The compensation committee may recommend awards of performance-based bonuses and discretionary bonuses.

Performance-Based Bonuses—Our Annual Incentive Plan for Senior Executives, which we refer to as the Senior Executive Plan, was initially approved by our shareholders at our 2007 annual meeting. The Senior Executive Plan is designed to permit us to qualify for an exemption from the $1,000,000 deduction limit under Section 162(m) of the Internal Revenue Code for compensation paid to our NEOs. The Senior Executive Plan provides awards for the achievement of predetermined, objective performance measures over a specified 12-month performance period, generally our fiscal year. Awards under the Senior Executive Plan are paid in cash. In 2008, the Senior Executive Plan was amended by shareholder vote to increase the maximum award payable to an individual to $15 million from $5 million and to allow awards to be paid in either cash or shares of common stock under our stock incentive plan. In addition, in 2008 the Senior Executive Plan was clarified to allow the compensation committee to make such adjustments as it deems appropriate to performance goals in the

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event of a change of control. Notwithstanding the existence of our Senior Executive Plan, the compensation committee believes that shareholder interests are best served by not restricting its discretion and flexibility in crafting compensation, even if the compensation amounts result in non-deductible compensation expense. Therefore, the committee reserves the right to approve compensation that is not fully deductible, although to date it has not done so.

In March 2009, the compensation committee approved 2009 target bonus awards to be paid from a bonus pool. The bonus pool is equal to 18.3% of our adjusted distributable cash flow unless the adjusted distributable cash flow includes any capital transaction gains in excess of $50 million, in which case only 10% of that excess will be included in the bonus pool. If the adjusted distributable cash flow does not equal at least 75% of the average adjusted distributable cash flow for the previous 3 years, no bonuses will be paid. Adjusted distributable cash flow means the sum of (i) cash available for distribution to us by any of our subsidiaries (regardless of whether such cash is actually distributed), plus (ii) interest income during the year, plus (iii) to the extent not otherwise included in adjusted distributable cash flow, any realized gain on the sale of securities, including securities of a subsidiary, less (iv) our stand-alone general and administrative expenses for the year excluding any bonus expense (other than non-cash bonus compensation included in general and administrative expenses), and less (v) to the extent not otherwise included in adjusted distributable cash flow, any loss on the sale of securities, including securities of a subsidiary. A return of our capital investment in a subsidiary is not intended to be included and, accordingly, if adjusted distributable cash flow includes proceeds from the sale of all or substantially all of the assets of a subsidiary, the amount of such proceeds to be included in adjusted distributable cash flow will be reduced by our basis in the subsidiary. The maximum award payable, expressed as a percentage of our estimated 2009 adjusted distributable cash flow, for each participant is as follows: Edward E. Cohen, 6.14%; Jonathan Z. Cohen, 4.37%; Matthew A. Jones, 3.46%; Richard D. Weber, 2.60% and Freddie Kotek, 1.73%. Pursuant to the terms of the Senior Executive Plan, the compensation committee has the discretion to recommend reductions, but not increases, in awards under the plan. As set forth below, actual awards for 2009 were substantially less than the maximum award permitted under the plan. In February 2010, the compensation committee approved target bonus awards identical to the 2009 target bonus awards.

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

Long-Term Incentives

We believe that our long-term success depends upon aligning our executives’ and shareholders’ interests. To support this objective, we provide our executives with various means to become significant shareholders, including our long-term incentive programs and those of our public subsidiaries. These awards are usually a combination of stock options, restricted stock and phantom units which vest over four years to support long-term retention of executives and reinforce our long-term goals.

Grants under our Stock Incentive Plans: Awards under our stock plans, which we refer to as our Plans, may be in the form of incentive stock options, non-qualified stock options, restricted stock units and restricted stock.

Stock Options—From time to time, our compensation committee has recommended awards of stock options. Stock option grants have a ten-year term and usually vest 25% per year. These stock options provide value to the recipient only if our share price is higher than on the date of the grant.

Restricted Stock Units—Restricted stock units entitle the recipient to receive shares of common stock upon vesting. They reward shareholder value creation slightly differently than stock options: restricted stock units are impacted by all stock price changes, both increases and decreases. The vesting schedules for these grants are dictated by the committee and may vest 25% per year or 25% on the third anniversary and 75% on the fourth anniversary of the grant date.

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Restricted Stock—On very limited occasions, restricted stock grants have been awarded. They reward shareholder value creation slightly differently than stock options: restricted stock units are impacted by all stock price changes, both increases and decreases. These awards vest 25% per year on the anniversary of the date of grant.

Grants under Subsidiary Plans: As described above, our NEOs who perform services for one or more of our publicly-traded subsidiaries may receive stock-based awards under the long-term incentive plan of the appropriate subsidiary.

Supplemental Benefits, Deferred Compensation and Perquisites

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

Employment Agreements

Generally, we do not favor employment agreements unless they are required to attract or to retain executives to the organization. We have entered into employment agreements with Messrs. E. Cohen, J. Cohen, Jones and Weber. See “—Employment Agreements and Potential Payments Upon Termination or Change of Control.” Our compensation committee takes termination compensation payable under these agreements into account in determining annual compensation awards, but ultimately its focus is on recognizing each individual’s contribution to our performance during the year.

Determination of 2009 Compensation Amounts

As described above, after the end of our 2009 fiscal year, our compensation committee reviewed the base salaries of our NEOs for the 2009 fiscal year and recommended incentive awards based on the prior year’s performance. In carrying out its function, the compensation committee acted in consultation with Mercer.

In determining the actual amounts to be paid to the NEOs, the compensation committee considered both individual and company performance. Our CEO makes recommendations of award amounts based upon the NEOs’ individual performances as well as the performance of our subsidiaries for which each NEO provides service; however, the compensation committee has the discretion to approve, reject, or modify the recommendations. The compensation committee noted that our management team, among other accomplishments, successfully restructured our company through the merger, positioning Atlas Energy to exploit our Marcellus Shale holdings despite the prevailing straitened credit environment, and repositioned Atlas Pipeline through renegotiation of bank arrangements, strengthened hedging, increased volumes, effectuated a joint venture with Williams, and restructured the Mid-Continent division. In addition, the compensation committee reviewed the calculations of our adjusted distributable cash flow and determined that 2009 adjusted distributable cash flow exceeded the pre-determined minimum threshold of 75% of the average adjusted distributable cash flow for the previous three years by more than 50%.

Base Salary. Following a review of the analysis conducted by Mercer in June 2009 of our NEOs’ compensation, the compensation committee determined to increase each NEO’s base salary by $100,000 effective July 1, 2009. In light of these interim increases, the compensation committee determined at the end of our 2009 fiscal year that the adjusted base salaries were appropriate for the 2010 fiscal year.

Annual Incentives. As described above, our company substantially outperformed the incentive goals that had been set under the Senior Executive Plan. Based upon this performance, the compensation committee recommended that we award cash incentive bonuses as follows: Edward E. Cohen, $2,500,000; Jonathan Z. Cohen, $2,000,000; Matthew A. Jones, $800,000; Richard D. Weber, $800,000 and Freddie M. Kotek, $500,000. The compensation committee also recommended that each of the NEOs receive an amount of restricted stock

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units equivalent to their cash bonuses. The restricted stock units will vest 25% per annum. Because the restricted stock unit awards were made after our fiscal year end, they are not included, under new SEC rules, in our Summary Compensation Table for 2009, but will be included in the table for 2010. The aggregate annual incentive awards were less than the maximum amount payable to each of the NEOs pursuant to the predetermined percentages established under the Senior Executive Plan, which were as follows: Edward E. Cohen, $8,639,000; Jonathan Z. Cohen, $6,148,000; Matthew A. Jones, $4,878,000; Richard D. Weber, $3,658,000 and Freddie M. Kotek, $2,439,000.

Long-Term Incentives. In order to retain management and in recognition of company and individual accomplishments in 2009 as set forth above, the compensation committee determined to award stock options at an exercise price of $29.05 as follows: Messrs. E. and J. Cohen, 220,000 options; and Messrs. Jones, Weber and Kotek, 70,000 options each. Because these awards were made after our fiscal year end, they are not included, under new SEC rules, in our Summary Compensation Table for 2009, but will be included in the table for 2010.

SUMMARY COMPENSATION TABLE

The following table sets forth information concerning the compensation for fiscal 2009, 2008 and 2007 for our Chief Executive Officer, Chief Financial Officer and each of our other three most highly compensated executive officers whose aggregate salary and bonus exceeded $100,000.


Name and principal position	Year	Salary ($)		Bonus ($)		Stock awards ($)⁽¹⁾		Option awards ($)⁽²⁾		Non-equity incentive plan compensation ($)		Change in pension value and nonqualified deferred compensation earnings ($)⁽³⁾		All other compensation ($)			Total ($)
Edward E. Cohen, Chairman of the Board and Chief Executive Officer	2009	$	983,846		—		—		—	$	2,500,000	$	759,235	$	134,600	⁽⁴⁾	$	4,377,681
	2008	$	900,000		—		—	$	3,507,000	$	1,950,000	$	734,078	$	733,938		$	7,825,016
	2007	$	900,000		—	$	4,612,160	$	1,205,000	$	5,000,000	$	1,150,222	$	554,777		$	13,422,159

Matthew A. Jones, Chief Financial Officer	2009	$	360,770		—		—		—	$	800,000		—	$	16,150	⁽⁵⁾	$	1,176,920
	2008	$	300,000		—		—	$	1,402,800	$	1,500,000		—	$	115,313		$	3,318,113
	2007	$	300,000		—	$	461,216	$	120,500	$	2,000,000		—	$	134,597		$	3,016,313

Jonathan Z. Cohen, Vice Chairman	2009	$	676,923		—		—		—	$	2,000,000		—	$	88,163	⁽⁶⁾	$	2,765,086
	2008	$	600,000		—		—	$	2,805,600	$	500,000		—	$	386,550		$	4,292,150
	2007	$	600,000		—	$	2,306,080	$	482,000	$	4,000,000		—	$	300,906		$	7,688,986

Richard D. Weber, President	2009	$	360,770		—		—		—	$	800,000		—	$	8,543	⁽⁷⁾	$	1,169,313
	2008	$	300,000		—		—	$	1,052,100	$	1,200,000		—	$	10,473		$	2,562,573
	2007	$	300,000		—		—		—	$	1,500,000		—	$	2,857		$	1,802,857

Freddie M. Kotek, Executive Vice President	2009	$	360,770		—		—		—	$	500,000		—	$	22,461	⁽⁸⁾	$	883,230
	2008	$	300,000		—		—	$	701,400	$	1,000,000		—	$	48,780		$	2,050,180
	2007	$	300,000	$	1,000,000	$	461,216	$	120,500		—		—	$	47,996		$	1,929,712

⁽¹⁾

Represents the fair value on the date of grant of the (i) phantom units granted under the AHD Plan, (ii) phantom units granted under the APL Plan; and (iii) phantom units granted under the Assumed LTIP, all in accordance with prevailing accounting literature. See note 18 to our consolidated financial statements for an explanation of the assumptions we make for this valuation.

⁽²⁾

Represents the fair value on the date of grant of the (i) options granted under our 2004 Plan, (ii) options granted under the AHD Plan; and (iii) options granted under the Assumed LTIP, all in accordance with prevailing accounting literature. See note 18 to our consolidated financial statements for an explanation of the assumptions we make for this valuation.

⁽³⁾	Represents the aggregate annual change in the present-value of accumulated pension benefits under the Supplemental Employment Retirement Plan for Mr. E. Cohen.

⁽⁴⁾	Includes payments on DERs of $ 7,200 with respect to the phantom units awarded under the APL Plan, $ 5,400 with respect to phantom units awarded under the AHD Plan, and $ 122,000 with respect to the phantom units awarded under the Assumed LTIP.

⁽⁵⁾	Includes payments on DERs of $ 2,750 with respect to the phantom units awarded under the APL Plan, $ 1,200 with respect to phantom units awarded under the AHD Plan, and $ 12,200 with respect to the phantom units awarded under the Assumed LTIP.

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⁽⁶⁾	Represents payments on DERs of $5,163 with respect to the phantom units awarded under the APL Plan, $2,700 with respect to phantom units awarded under the AHD Plan, and $ 61,000 with respect to the phantom units awarded under the Assumed LTIP.

⁽⁷⁾	Represents reimbursements for lease payments on Mr. Weber’s vehicle.

⁽⁸⁾	Includes payments on DERs of $ 95 with respect to the phantom units awarded under the APL Plan, $ 12,200 with respect to the phantom units awarded under the Assumed LTIP.

2009 GRANTS OF PLAN-BASED AWARDS TABLE


	Estimated Future Payouts Under Non-Equity Incentive Plan Awards⁽¹⁾

Name	Threshold ($)	Target ($)	Maximum ($)
Edward E. Cohen	N/A	N/A	$	8,639,000

Matthew A. Jones	N/A	N/A	$	4,878,000

Jonathan Z. Cohen	N/A	N/A	$	6,148,000

Richard D. Weber	N/A	N/A	$	3,658,000

Freddie Kotek	N/A	N/A	$	2,439,000

⁽¹⁾

Represents performance-based bonuses under our Senior Executive Plan. As discussed under “Compensation Discussion and Analysis—Elements of our Compensation Program—Annual Incentives—Performance-Based Bonuses,” the Compensation Committee set performance goals based on our adjusted distributable cash flow and established maximum awards, but not minimum or target amounts, for each eligible NEO. Our Senior Executive Plan sets an individual limit of $15,000,000 per annum regardless of the maximum amounts that might otherwise be payable.

Employment Agreements and Potential Payments Upon Termination or Change of Control

Edward E. Cohen

In May 2004, we entered into an employment agreement with Edward E. Cohen, who currently serves as our Chairman and Chief Executive Officer. The agreement was amended as of December 31, 2008 to comply with requirements under Section 409A of the Code relating to deferred compensation. The agreement requires Mr. Cohen to devote such time to us as is reasonably necessary to the fulfillment of his duties, although it permits him to invest and participate in outside business endeavors. The agreement provided for initial base compensation of $350,000 per year, which may be increased by the compensation committee based upon its evaluation of Mr. Cohen’s performance. Mr. Cohen is eligible to receive incentive bonuses and stock option grants and to participate in all employee benefit plans in effect during his period of employment. The agreement has a term of three years and, until notice to the contrary, the term is automatically extended so that on any day on which the agreement is in effect it has a then-current three-year term. We entered into Mr. Cohen’s employment agreement around the time of our spin-off from Resource America. At that time, it was important to establish a long-term commitment to and from Mr. Cohen as our Chief Executive Officer and then-President. We determined that the rolling three-year term was an appropriate amount of time to reflect that commitment and was a term that was commensurate with Mr. Cohen’s position.

We may terminate the agreement without cause, including upon or after a change of control, upon 30 days’ prior notice, in the event of Mr. Cohen’s death, if he is disabled for 180 days consecutive days during any 12-month period or at any time for cause. Mr. Cohen also has the right to terminate the agreement for good reason or because of a change of control. Mr. Cohen must provide us with 30 days’ notice of a termination by him for good reason within 60 days of the event constituting good reason. We then would have 30 days in which to cure and, if we do not do so, Mr. Cohen’s employment will terminate 30 days after the end of the cure period. Mr. Cohen may also terminate the agreement without cause upon 60 days’ notice. Termination amounts will not be paid until 6 months after the termination date, if such delay is required by Section 409A.

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Change of control is defined as:

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the acquisition of beneficial ownership, as defined in the Securities Exchange Act, of 25% or more of our voting securities or all or substantially all of our assets by a single person or entity or group of affiliated persons or entities, other than an entity affiliated with Mr. Cohen or any member of his immediate family;

•

we consummate a merger, consolidation, combination, share exchange, division or other reorganization or transaction with an unaffiliated entity in which either (a) our directors immediately before the transaction constitute less than a majority of the board of the surviving entity, unless 1/2 of the surviving entity’s board were our directors immediately before the transaction and our chief executive officer immediately before the transaction continues as the chief executive officer of the surviving entity; or (b) our voting securities immediately prior to the transaction represent less than 60% of the combined voting power immediately after the transaction of us, the surviving entity or, in the case of a division, each entity resulting from the division;

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during any period of 24 consecutive months, individuals who were Board members at the beginning of the period cease for any reason to constitute a majority of the Board, unless the election or nomination for election by our shareholders of each new director was approved by a vote of at least 2/3 of the directors then still in office who were directors at the beginning of the period; or

•

our shareholders approve a plan of complete liquidation of winding up of our company, or agreement of sale of all or substantially all of our assets or all or substantially all of the assets of our primary subsidiaries to an unaffiliated entity.

Good reason is defined as a reduction in Mr. Cohen’s base pay, a demotion, a material reduction in his duties, relocation, his failure to be elected to our Board of Directors or our material breach of the agreement. Cause is defined as a felony conviction or conviction of a crime involving fraud, embezzlement or moral turpitude, intentional and continual failure by Mr. Cohen to perform his material duties after notice, or violation of confidentiality obligations.

The agreement provides for a Supplemental Executive Retirement Plan, or SERP, pursuant to which Mr. Cohen will receive, upon the later of his retirement or reaching the age of 70, an annual retirement benefit equal to the product of:

•

6.5% multiplied by

•

his base salary as of the time Mr. Cohen’s employment with us ceases, multiplied by

•

the number of years (or portions thereof) which Mr. Cohen is employed by us but, in any case, not less than four. If Mr. Cohen’s employment is terminated due to disability, the 3-year period following the termination will be deemed a portion of his employment term for purposes of accruing SERP benefits.

The maximum benefit under the SERP is limited to 65% of his final base salary. The benefit is guaranteed to his estate for up to 10 years if he should die before receiving 10 years’ of SERP benefits. If there is a change of control, if Mr. Cohen resigns for good reason, or if we terminate his employment without cause, then the SERP benefit will be the greater of the accrued benefit pursuant to the above formula, or 40% of his final base salary.

The agreement provides the following termination benefits:

•

Upon termination of employment due to death, Mr. Cohen’s estate will receive (a) a lump sum payment in an amount equal to three times his final base salary, (b) payment of his SERP benefit and (c) automatic vesting of all stock and option awards.

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•

Upon termination due to disability, Mr. Cohen will receive (a) a lump sum payment in an amount equal to three times his final base salary, (b) a lump sum amount equal to the COBRA premium cost for continued health coverage, less the premium charge that is paid by our employees, during the three years following his termination, (c) a lump sum amount equal to the cost we would incur for life, disability and accident insurance coverage during the three-year period, less the premium charge that is paid by our employees, (d) payment of his SERP benefit, (e) automatic vesting of all stock and option awards and (f) any amounts payable under our long-term disability plan.

•

Upon termination by us without cause, by Mr. Cohen for good reason or by either party in connection with a change of control, he will be entitled to either (a) if Mr. Cohen does not sign a release, severance benefits under our then current severance policy, if any, or (b) if Mr. Cohen signs a release, (i) a lump sum payment in an amount equal to three times average compensation (defined as the average of the three highest amounts of annual total compensation), (ii) a lump sum amount equal to the COBRA premium cost for continued health coverage, less the premium charge that is paid by our employees, during the three years following his termination, (iii) a lump sum amount equal to the cost we would incur for life, disability and accident insurance coverage during the three-year period, less the premium charge that is paid by our employees, (iv) payment of his SERP benefit and (v) automatic vesting of all stock and option awards.

•

Upon termination by Mr. Cohen without cause, if he signs a release he will receive (a) a lump sum payment equal to one-half of one year’s base salary then in effect, (b) automatic vesting of all stock and option awards and (c) if he has reached retirement age, his SERP benefits.

In the event that any amounts payable to Mr. Cohen upon termination become subject to any excise tax imposed under Section 4999 of the Code, we must pay Mr. Cohen an additional sum such that the net amounts retained by Mr. Cohen, after payment of excise, income and withholding taxes, equals the termination amounts payable, unless Mr. Cohen’s employment terminates because of his death or disability. We believe that the multiples of the compensation components payable to Mr. Cohen upon termination were generally aligned with competitive market practice for similar executives at the time that his employment agreement was negotiated.

If a termination event had occurred as of December 31, 2009, we estimate that the value of the benefits to Mr. Cohen would have been as follows:


Reason for termination	Lump sum severance payment			SERP⁽¹⁾		Benefits⁽²⁾		Accelerated vesting of stock awards and option awards⁽³⁾		Tax gross- up⁽⁴⁾
Death	$	2,951,540	⁽⁵⁾	$	3,197,501	$	—	$	13,449,980	$	—
Disability		2,951,540	⁽⁵⁾		3,197,501		38,020		13,449,980		—
Termination by us without cause⁽⁶⁾		14,733,847	⁽⁷⁾		3,935,386		38,020		13,449,980		—
Termination by Mr. Cohen for good reason⁽⁶⁾		14,733,847	⁽⁷⁾		3,935,386		38,020		13,449,980		—
Change of control⁽⁶⁾		14,733,847	⁽⁷⁾		3,935,386		38,020		13,449,980		6,176,361
Termination by Mr. Cohen without cause		491,924	⁽⁵⁾		3,197,501		—		13,449,980		—

⁽¹⁾	Represents the value of vested benefits payable calculated by multiplying the per year benefit by the minimum of 10 years.

⁽²⁾	Represents rates currently in effect for COBRA insurance benefits for 36 months.

⁽³⁾

Represents the value of unvested and accelerated option awards and stock awards disclosed in the “Outstanding Equity Awards at Fiscal Year-End Table.” The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable stock on December 31, 2009. The payments relating to stock awards are calculated by multiplying the number of accelerated shares by the closing price of the applicable stock on December 31, 2009.

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⁽⁴⁾	Calculated after deduction of any excise tax imposed under section 4999 of the Code, and any federal, state and local income tax, FICA and Medicare withholding taxes, taking into account the 20% excess parachute payment rate and a 36.45% combined effective tax rate.

⁽⁵⁾	Calculated based on Mr. Cohen’s 2009 base salary.

⁽⁶⁾	These amounts are contingent upon Mr. Cohen executing a release. If Mr. Cohen does not execute a release he would receive severance benefits under our current severance plan.

⁽⁷⁾	Calculated based on Mr. Cohen’s average 2009, 2008 and 2007 base salary and bonus.

Matthew A. Jones

In July 2009, we entered into an employment agreement with Matthew A. Jones, who currently serves as our Chief Financial Officer. The agreement provides for initial base compensation of $300,000 per year, which may be increased at the discretion of our Board of Directors. Mr. Jones is eligible to receive grants of equity based compensation from APL, AHD and other affiliates of ours, which we refer to as the Atlas Entities, and to participate in all employee benefit plans in effect during his period of employment. The agreement provides that any unvested equity compensation will be subject to forfeiture in accordance with the long-term incentive plan of the applicable entity except that, if we terminate Mr. Jones’s employment without cause, including his disability, or if Mr. Jones terminates his employment for good reason or in the event of his death, all of his unvested awards will be fully vested.

The agreement has a term of two years. We may terminate the agreement:

•

at any time for cause;

•

without cause upon 90 days’ prior written notice;

•

if Mr. Jones is physically or mentally disabled for 180 days in the aggregate or 90 consecutive days during any 365-day period and our Board of Directors determines, in good faith based upon medical evidence, that he is unable to perform his duties; or

•

in the event of Mr. Jones’s death.

Mr. Jones has the right to terminate the agreement for good reason, defined as material breach by us of the agreement or a change of control. Mr. Jones must provide notice of a termination by him for good reason within 30 days of the event constituting good reason. We then would have 30 days in which to cure and, if we do not do so, Mr. Jones’s employment will terminate 30 days after the end of the cure period. Mr. Jones may also terminate the agreement without good reason upon 30 days’ notice. Termination amounts will not be paid until six months after the termination date, if such delay is required by Section 409A of the Internal Revenue Code.

Cause is defined as (a) Mr. Jones’ having committed a demonstrable and material act of fraud, (b) illegal or gross misconduct that is willful and results in damage to the business or reputation of the Atlas Entities, (c) being charged with a felony, (d) continued failure by Mr. Jones to perform his duties after notice other than as a result of physical or mental illness, or (e) Mr. Jones’s failure to follow our reasonable written directions consistent with his duties. Good reason is defined as any action or inaction that constitutes a material breach by us of the agreement or a change of control. Change of control is defined as:

•

the acquisition of beneficial ownership, as defined in the Securities Exchange Act, of 50% or more of our voting securities or all or substantially all of our assets by a single person or entity or group of affiliated persons or entities, other than by a related entity, defined as any of the Atlas Entities or any affiliate of us or of Mr. Jones or any member of his immediate family;

•

the consummation of a merger, consolidation, combination, share exchange, division or other reorganization or transaction with an unaffiliated entity, other than a related entity, in which either (a) our directors immediately before the transaction constitute less than a majority of the board of

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directors of the surviving entity, unless ¹/2 of the surviving entity’s board were our directors immediately before the transaction and our Chief Executive Officer immediately before the transaction continues as the Chief Executive Officer of the surviving entity; or (b) our voting securities immediately before the transaction represent less than 60% of the combined voting power immediately after the transaction of us, the surviving entity or, in the case of a division, each entity resulting from the division;

•

during any period of 24 consecutive calendar months, individuals who were Board members at the beginning of the period cease for any reason to constitute a majority of the Board, unless the election or nomination for the election by our stockholders of each new director was approved by a vote of at least 2/3 of the directors then still in office who were directors at the beginning of the period; or

•

our stockholders approve a plan of complete liquidation or winding-up, or agreement of sale of all or substantially all of our assets or all or substantially all of the assets of our primary subsidiaries other than to a related entity.

The agreement provides the following regarding termination and termination benefits:

•

upon termination of employment due to death, Mr. Jones’s designated beneficiaries will receive a lump sum cash payment within 60 days of the date of death of (a) any unpaid portion of his annual salary earned and not yet paid; (b) an amount representing the incentive compensation earned for the period up to the date of termination computed by assuming that the amount of all such incentive compensation would be equal to the amount that Mr. Jones earned during the prior fiscal year, pro-rated through the date of termination; (c) any accrued but unpaid incentive compensation and vacation pay; and (d) all equity compensation awards will immediately vest.

•

upon termination by us for cause or by Mr. Jones for other than good reason, Mr. Jones will receive only base salary and vacation pay to the extent earned and not paid. Mr. Jones’s equity awards that have vested as of the date of termination will not be subject to forfeiture.

•

upon termination by us other than for cause, including disability, or by Mr. Jones for good reason, he will be entitled to either (a) if Mr. Jones does not sign a release, severance benefits under our then current severance policy, if any, or (b) if Mr. Jones signs a release, (i) a lump sum payment in an amount equal to two years of his average compensation (which is defined as his base salary in effect immediately before termination plus the average of the cash bonuses earned for the three calendar years preceding the year in which the date of terminated occurred), less, in the case of termination by reason of disability, any amounts paid under disability insurance provided by us; (ii) monthly reimbursement of any COBRA premium paid Mr. Jones, less the amount Mr. Jones would be required to contribute for health and dental coverage if he were an active employee, for the 24 months following the date of termination, and (iii) automatic vesting of Mr. Jones’s equity awards.

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If a termination event had occurred as of December 31, 2009, we estimate that the value of the benefits to Mr. Jones would have been as follows:


Reason for termination	Lump sum severance payment			Benefits	Accelerated vesting of stock awards and option awards⁽¹⁾
Death		—		—	$	1,408,291
Termination by us other than for cause (including disability) or by Mr. Jones for good reason (including a change of control)	$	3,588,207	⁽²⁾	—	$	1,408,291

⁽¹⁾

Represents the value of unexercisable option and unvested stock awards disclosed in the “Outstanding Equity Awards at Fiscal Year-End Table.” The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable stock on December 31, 2009. The payments relating to stock awards are calculated by multiplying the number of accelerated shares by the closing price of the applicable stock on December 31, 2009.

⁽²⁾	Calculated based on Mr. Jones’s 2009 base salary and the average of his 2009, 2008 and 2007 cash bonuses. Assumes Mr. Jones executes a release.

Jonathan Z. Cohen

In January 2009, we entered into an employment agreement with Jonathan Z. Cohen, to continue his service as Vice-Chairman, in which position he has served in since 1998. We entered into the agreement in order to define Mr. Cohen’s role with our company, particularly in light of the fact that he devotes a substantial amount of his time to us. Thus, the agreement specifies that his duties include capital raising, strategic transactions and activities, building and minding shareholder and lender relationships, developing and implementing short- and long-term plans and approaches, and being available to assist our Chairman and Board of Directors with respect to other matters. The agreement provides that Mr. Cohen’s position will not be full-time and requires him to devote such time to us as is reasonably necessary to the fulfillment of his duties, and permits him to invest and participate in outside business endeavors.

The agreement provides for initial base compensation of $600,000 per year, which may be increased at the discretion of our Board of Directors. Mr. Cohen is eligible to receive grants of equity-based compensation from us, Atlas Energy Resources, Atlas Pipeline Partners, Atlas Pipeline Holdings or other of our affiliates, which we refer to collectively as the Atlas Entities, and to participate in all employee benefit plans in effect during his period of employment.

The agreement has a term of three years and will be renewed for an additional three-year period, unless either party elects to terminate the agreement by providing notice at least 180 days before the expiration of the then current term. We may terminate the agreement:

•

without cause upon 90 days’ prior notice;

•

in the event of Mr. Cohen’s death;

•

if he is physically or mentally disabled for 180 days in the aggregate or 90 consecutive days during any 365-day period and our Board of Directors determines, in good faith based upon medical evidence, that he is unable to perform his duties; or

•

at any time for cause.

Mr. Cohen has the right to terminate the agreement for good reason, including a change of control. Mr. Cohen must provide us with notice of a termination by him for good reason within 30 days of the event

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constituting good reason. We then would have 30 days in which to cure and, if we do not do so, Mr. Cohen’s employment will terminate 30 days after the end of the cure period. Mr. Cohen may also terminate the agreement without cause upon 30 days’ notice. Termination amounts will not be paid until 6 months after the termination date, if such delay is required by Section 409A of the Code.

Cause is defined as a felony conviction or conviction of a crime involving fraud, deceit or misrepresentation, failure by Mr. Cohen to materially perform his duties after notice other than as a result of physical or mental illness, or violation of confidentiality obligations or representations in the agreement. Good reason is defined as any action or inaction that constitutes a material breach by us of the agreement or a change of control. Change of control is defined as:

•

the consummation of a merger, consolidation, combination, share exchange, division or other reorganization or transaction with an unaffiliated entity in which either (a) our directors immediately before the transaction constitute less than a majority of the board of the surviving entity, unless 1/2 of the surviving entity’s board were our directors immediately before the transaction and Our Chief Executive Officer immediately before the transaction continues as the Chief Executive Officer of the surviving entity; or (b) our voting securities immediately prior to the transaction represent less than 60% of the combined voting power immediately after the transaction of us, the surviving entity or, in the case of a division, each entity resulting from the division;

•

our shareholders approve a plan of complete liquidation of winding up, or agreement of sale of all or substantially all of our assets or all or substantially all of the assets of our primary subsidiaries to an unaffiliated entity.

The agreement provides for a SERP, which will provide a monthly benefit to Mr. Cohen, upon the later of his reaching the age of 60 or 30 days after his retirement, equal to 1/12 of the product of:

•

the highest annual base salary Mr. Cohen received during his service to the Atlas Entities, multiplied by

•

2%, multiplied by

•

the number of years (or fractions thereof) during which Mr. Cohen was an officer or director of any of the Atlas Entities on and after January 1, 2004.

The percentage calculated by multiplying the second and third bullet points above cannot exceed 65%. The aggregate amount of the payments made to Mr. Cohen pursuant to the SERP will be offset by the aggregate amounts paid to Mr. Cohen by the Atlas Entities under their qualified benefit programs.

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The agreement provides the following regarding termination and termination benefits:

•

Upon termination of employment due to death, Mr. Cohen’s estate will receive (a) accrued but unpaid bonus and vacation pay, (b) up to 120 monthly SERP payments if he should die before receiving 120 monthly payments and (c) automatic vesting of all equity-based awards.

•

Upon termination by us other than for cause, including disability, or by Mr. Cohen for good reason, Mr. Cohen will receive either (a) if Mr. Cohen does not sign a release, severance benefits under our then current severance policy, if any, or (b) if Mr. Cohen signs a release, (i) a lump sum payment in an amount equal to three years of his average compensation (which is defined as his base salary in effect immediately before termination plus the average of the cash bonuses earned for the three calendar years preceding the year in which the termination occurred), less, in the case of termination by reason of disability, any amounts paid under disability insurance provided by us, (ii) monthly reimbursement of any COBRA premium paid by Mr. Cohen, less the amount Mr. Cohen would be required to contribute for health and dental coverage if he were an active employee, (iv) payment of his SERP benefits if he has reached retirement age and (v) automatic vesting of all equity-based awards.

•

Upon termination by us for cause or by Mr. Cohen for other than good reason, Mr. Cohen will receive his SERP benefits if he has reached retirement age, and his vested equity-based awards will not be subject to forfeiture.

We believe that the multiples of the compensation components payable to Mr. Cohen upon termination were generally aligned with competitive market practice for similar executives at the time that his employment agreement was negotiated.

If a termination event had occurred as of December 31, 2009, we estimate that the value of the benefits to Mr. Cohen would have been as follows:


Reason for termination	Lump sum severance payment			SERP		Benefits⁽¹⁾	Accelerated vesting of stock awards and option awards⁽²⁾
Death		—		$	209,916	—	$	5,989,623
Termination by us other than for cause (including disability) or by Mr. Cohen for good reason (including a change of control)	$	11,590,770	⁽³⁾	$	209,916	—	$	5,989,623
Termination by us for cause or by Mr. Cohen for other than good reason		—		$	209,916	—		—

⁽¹⁾	Mr. Cohen does not currently receive benefits from Atlas Energy.

⁽²⁾

⁽³⁾	Calculated based on Mr. Cohen’s 2009 base salary and the average of his 2009, 2008 and 2007 bonuses. Assumes Mr. Cohen signs a release.

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Richard D. Weber

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

•

Upon execution of the agreement, Mr. Weber was granted options to purchase 75,000 shares of our stock at $21.27, as adjusted for stock splits.

•

In January 2007, Mr. Weber received a grant of 47,619 shares of restricted units of Atlas Energy Resources with a value of $1,000,000.

•

In January 2007, Mr. Weber received options to purchase 373,752 common units of Atlas Energy Resources at $21.00.

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

•

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

•

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

•

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

The change of control triggering events relating to the possible absence of Messrs. Cohen reflects that Mr. Weber’s belief that Messrs. Cohen effectively controlled us at the time of his employment and their separation would therefore constitute a change of control.

Good reason is defined as a material breach of the agreement, reduction in his base pay, a demotion, a material reduction in his duties or his failure to be elected to the Atlas Energy Resources Board of Directors. Cause is defined as fraud in connection with his employment, conviction of a crime other than a traffic offense, material failure to perform his duties after written demand by our Board or breach of the representations made by Mr. Weber in the employment agreement if the breach impacts his ability to fully perform his duties. Disability is defined as becoming disabled by reason of physical or mental disability for more than 180 days in the aggregate or a period of 90 consecutive days during any 365-day period and the good faith determination by our Board based upon medical evidence that Mr. Weber is unable to perform his duties under his employment agreement.

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

•

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

•

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

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

If a termination event had occurred as of December 31, 2009, we estimate that the value of the benefits to Mr. Weber would have been as follows:


Reason for termination	Lump sum severance payment			Benefits⁽¹⁾		Accelerated vesting of stock awards and option awards⁽²⁾		Tax gross-up
Death	$	1,600,000	⁽³⁾	$	19,429	$	—	—
Disability		—			21,396		—	—
Termination by us other than for cause (including for disability) or by Mr. Weber for good reason		1,960,770	⁽⁴⁾		21,396		1,969,610	—
Change of control		—			—		1,969,610	—

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

⁽²⁾

Represents the value of unexercisable option and unvested unit awards disclosed in the “Outstanding Equity Awards at Fiscal Year-End Table.” The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable units on December 31, 2009. The payments relating to unit awards are calculated by multiplying the number of accelerated shares or units by the closing price of the applicable stock on December 31, 2009.

⁽³⁾	Represents Mr. Weber’s 2009 bonus.

⁽⁴⁾	Calculated as the sum of Mr. Weber’s 2009 base salary and bonus.

Long-Term Incentive Plans

Our Plans

Our Stock Incentive Plan (the “2004 Plan”) authorizes the granting of up to 4.5 million shares of our common stock to our employees, affiliates, consultants and directors in the form of incentive stock options (“ISOs”), non-qualified stock options, stock appreciation rights (“SARs”), restricted stock and deferred units. We also have a 2009 Stock Incentive Plan (the “2009 Plan”) which authorizes the granting of up to 4.8 million shares

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of our common stock to our employees, affiliates, consultants and directors in the form of ISOs, non-qualified stock options, SARs, restricted stock, restricted stock units and deferred units. SARs represent a right to receive cash in the amount of the difference between the fair market value of a share of our common stock on the exercise date and the exercise price, and may be free-standing or tied to grants of options. A deferred unit or a restricted stock unit represents the right to receive one share of our common stock upon vesting. Generally, awards under our 2004 Plan and 2009 Plan become exercisable as to 25% each anniversary after the date of grant except that deferred units awarded to our non-executive board members vest 33 1/3% on each of the second, third and fourth anniversaries of the grant, and expire not later than ten years after the date of grant.

Senior Executive Plan

For a description of our Senior Executive Plan, please see “Compensation Discussion and Analysis — Elements of our Compensation Program — Annual Incentives — Performance-Based Bonuses.”

ATN Assumed Plan

In connection with the Merger, we agreed to assume Atlas Energy Resources’ Long-Term Incentive Plan (the “Assumed LTIP”), which applies to all of Atlas Energy Resources’ awards that were outstanding at the time of the Merger. Under the Assumed LTIP, each outstanding unit option, phantom unit and restricted unit granted under Atlas Energy Resources’ previous plan was converted to an equivalent stock option, phantom share or restricted share of our stock at a ratio of 1.0 unit to 1.16 common shares. No new grant awards will be issued under the Assumed LTIP.

AHD Plan

The AHD Plan provides equity incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners who perform services for Atlas Pipeline Holdings. The AHD Plan is administered by our compensation committee under delegation from the Atlas Pipeline Holdings’ board. The compensation committee may grant awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units.

AHD Phantom Units. A phantom unit entitles a participant to receive an Atlas Pipeline Holdings common unit upon vesting of the phantom unit. Non-employee board members receive an annual grant of a maximum of 500 phantom units which, upon vesting, entitles the grantee to receive the equivalent number of common units or the cash equivalent to the fair market value of the units. In tandem with phantom unit grants, the compensation committee may grant a DER. The compensation committee determines the vesting period for phantom units. Phantom units granted under the AHD Plan generally vest 25% on the third anniversary of the date of grant and 75% on the fourth anniversary of the date of grant. Awards will automatically vest upon a change of control, as defined in the AHD Plan.

AHD Unit Options. A unit option entitles a participant to receive a common unit upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of a common unit as determined by the compensation committee on the date of grant of the option. The compensation committee determines the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Unit options granted generally will vest 25% on the third anniversary of the date of grant and the remaining 75% on the fourth anniversary of the date of grant. Awards will automatically vest upon a change of control, as defined in the AHD Plan.

APL Plan

Officers, employees and non-employee managing board members of Atlas Pipeline Partners’ general partner and employees of the general partner’s affiliates and consultants are eligible to receive awards under the APL Plan of either phantom units or unit options for an aggregate of 435,000 common units. The APL Plan is administered by our compensation committee under delegation from the general partner’s managing board.

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APL Phantom Units. A phantom unit entitles a grantee to receive a common unit upon vesting of the phantom unit. Non-employee managing board members receive an annual grant of a maximum of 500 phantom units which, upon vesting, entitles the grantee to receive the equivalent number of common units or the cash equivalent to the fair market value of the units. In addition, the compensation committee may grant a participant a DER, which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions Atlas Pipeline Partners makes on a common unit during the period the phantom unit is outstanding. A unit option entitles the grantee to purchase common units at an exercise price determined by the compensation committee at its discretion. Phantom units vest over a four year period. Awards will automatically vest upon a change of control, as defined in the APL Plan.

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

2009 OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END TABLE


	Option awards						Stock awards
Name	Number of securities underlying unexercised options (#)	Number of securities underlying unexercised options (#)		Option exercise price ($)		Option expiration date	Number of shares or units of stock that have not vested (#)		Market value of shares or units of stock that have not vested ($)
Name	Exercisable	Unexercisable		Option exercise price ($)		Option expiration date
Edward E. Cohen	1,012,500	—		$	11.32	7/1/2015	—		$	—
	75,000	225,000	⁽¹⁾	$	32.53	1/29/2018	—		$	—
	—	580,000	⁽²⁾	$	19.88	1/24/2017	232,000	⁽³⁾	$	6,992,480	⁽⁴⁾
	—	—			—	—	5,000	⁽⁵⁾	$	49,050	⁽⁶⁾
	125,000	375,000	⁽⁷⁾	$	22.56	11/10/2016	67,500	⁽⁸⁾	$	457,650	⁽⁹⁾

Matthew A. Jones	270,000	—		$	11.32	7/1/2015	—		$	—
	30,000	90,000	⁽¹⁰⁾	$	32.53	1/29/2018	—		$	—
	0	58,000	⁽¹¹⁾	$	19.88	1/24/2017	23,200	⁽¹²⁾	$	699,248	⁽⁴⁾
	—	—			—	—	1,250	⁽⁵⁾	$	12,263	⁽⁶⁾
	25,000	75,000	⁽⁷⁾	$	22.56	11/10/2016	15,000	⁽⁸⁾	$	101,700	⁽⁹⁾

Jonathan Z. Cohen	675,000	—		$	11.32	7/1/2015	—		$	—
	60,000	180,000	⁽¹³⁾	$	32.53	1/29/2018	—		$	—
	—	232,000	⁽¹⁴⁾	$	19.88	1/24/2017	116,000	⁽¹⁵⁾	$	3,496,240	⁽⁴⁾
	—	—			—	—	3,750	⁽⁵⁾	$	36,788	⁽⁶⁾
	—	150,000	⁽⁷⁾	$	22.56	11/10/2016	11,250	⁽⁸⁾	$	76,275	⁽⁹⁾

Richard D. Weber	84,375	28,125	⁽¹⁶⁾	$	21.27	4/17/2016	—		$	—
	22,500	67,500	⁽¹⁷⁾	$	32.53	1/29/2018	—		$	—
	325,164	108,388	⁽¹⁶⁾	$	18.11	4/17/2016	13,810	⁽¹⁸⁾	$	416,233	⁽⁴⁾
	—	—			—	—	—		$	—
	—	—			—	—	—		$	—

Freddie Kotek	135,000	—		$	11.32	7/1/2015	—		$	—
	15,000	45,000	⁽¹⁹⁾	$	32.53	1/29/2018	—		$	—
	—	58,000	⁽¹¹⁾	$	19.88	1/24/2017	23,200	⁽¹²⁾	$	699,248	⁽⁴⁾
	—	—			—	—	—		$	—
	—	—			—	—	—		$	—

⁽¹⁾	Represents options to purchase our stock, which vest as follows: 1/29/10—75,000, 1/29/11—75,000 and 1/29/12—75,000.

⁽²⁾	Represents options to purchase our stock, which vest as follows: 1/24/10 – 145,000 and 1/24/11 – 435,000.

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⁽³⁾	Represents our phantom stock, which vests as follows: 1/24/10 – 58,000 and 1/24/17 – 174,000.

⁽⁴⁾	Based upon closing price of our stock on December 31, 2009 of $ 30.14.

⁽⁵⁾	Represents Atlas Pipeline Partners phantom units, which vest on 11/1/10.

⁽⁶⁾	Based on closing market price of Atlas Pipeline Partners common units on December 31, 2009 of $ 9.81.

⁽⁷⁾	Represents Atlas Pipeline Holdings options, which vest on 11/10/10.

⁽⁸⁾	Represents Atlas Pipeline Holdings phantom units, which vest on 11/10/10.

⁽⁹⁾	Based on closing market price of Atlas Pipeline Holdings common units on December 31, 2009 of $ 6.78.

⁽¹⁰⁾	Represents options to purchase our stock, which vest as follows: 1/29/10—30,000, 1/29/11—30,000 and 1/29/12—30,000.

⁽¹¹⁾	Represents options to purchase our stock, which vest as follows: 1/24/10 – 14,500 and 1/24/11 – 43,500.

⁽¹²⁾	Represents our phantom stock, which vests as follows: 1/24/10 – 5,800 and 1/24/17 – 17,400.

⁽¹³⁾	Represents options to purchase our stock, which vest as follows: 1/29/10—60,000, 1/29/11—60,000 and 1/29/12—60,000.

⁽¹⁴⁾	Represents options to purchase our stock, which vest as follows: 1/24/10 – 58,000 and 1/24/11 – 174,000.

⁽¹⁵⁾	Represents our phantom stock, which vests as follows: 1/24/10 – 29,000 and 1/24/17 – 87,000.

⁽¹⁶⁾	Represents options to purchase our stock, which vest on 4/17/10.

⁽¹⁷⁾	Represents options to purchase our stock, which vest as follows: 1/29/10—22,500, 1/29/11—22,500 and 1/29/12—22,500.

⁽¹⁸⁾	Represents restricted stock, which vest on 4/17/10.

⁽¹⁹⁾	Represents options to purchase our stock, which vest as follows: 1/29/10—15,000, 1/29/11—15,000 and 1/29/12—15,000.

2009 OPTION EXERCISES AND STOCK VESTED TABLE


	Stock awards
Name	Number of shares acquired on vesting		Value realized on vesting ($)
Edward E. Cohen	32,500	⁽¹⁾	$	802,850
Matthew A. Jones	10,000	⁽²⁾	$	289,363
Jonathan Z. Cohen	18,125	⁽³⁾	$	449,550
Richard D. Weber	13,809	⁽⁴⁾	$	569,759
Freddie M. Kotek	250	⁽⁵⁾	$	10,275

⁽¹⁾	Represents 10,000 common units of Atlas Pipeline Partners and 22,500 common units of Atlas Pipeline Holdings.

⁽²⁾	Represents 5,000 common units of Atlas Pipeline Partners and 5,000 common units of Atlas Pipeline Holdings.

⁽³⁾	Represents 6,875 common units of Atlas Pipeline Partners and 11,250 common units of Atlas Pipeline Holdings.

⁽⁴⁾	Represents our common stock.

⁽⁵⁾	Represents Atlas Pipeline Partners common units.

2009 PENSION BENEFITS TABLE


Name	Plan name	Number of years credited service (#)	Present value of accumulated benefit ($)		Payments during last fiscal year ($)
Edward E. Cohen	SERP	7	$	3,968,149	—

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For a description of Mr. Cohen’s SERP, please see “Employment Agreements—Edward E. Cohen”, and for a discussion of the valuation method and material assumptions applied in quantifying the present value of the accumulated benefit, please see note 18 to our consolidated financial statements.

2009 DIRECTOR COMPENSATION TABLE


Name	Fees earned or paid in cash ($)		Stock awards ($)			Total ($)
Carlton M. Arrendell	$	62,691	$	14,992	⁽¹⁾	$	77,683
William R. Bagnell	$	32,120	$	14,992	⁽¹⁾	$	47,112
Mark C. Biderman	$	30,734	$	14,995	⁽²⁾	$	45,729
Jessica K. Davis	$	17,691	$	14,990	⁽⁴⁾	$	32,681
Donald W. Delson	$	62,691	$	14,992	⁽¹⁾	$	77,683
Nicholas A. DiNubile	$	45,000	$	14,992	⁽¹⁾	$	59,992
Dennis A. Holtz	$	62,691	$	14,992	⁽¹⁾	$	77,683
Gayle P.W. Jackson	$	30,734	$	14,995	⁽²⁾	$	45,729
Walter C. Jones	$	17,691	$	14,990	⁽⁴⁾	$	32,681
Harmon S. Spolan	$	62,691	$	14,994	⁽³⁾	$	77,685
Ellen F. Warren	$	17,691	$	14,990	⁽⁴⁾	$	32,681
Bruce M. Wolf	$	17,691	$	14,990	⁽⁴⁾	$	32,681

⁽¹⁾

For Messrs. Arrendell, Bagnell, Delson, DiNubile and Holtz, represents 961deferred shares granted under the 2004 Plan, having a grant date fair value of $15.60. The shares vest one-third on each of the second, third and fourth anniversaries of the date of grant, as follows: 5/14/11—320, 5/14/12—320 and 5/14/13—321. Messrs. Bagnell and DiNubile did not stand for re-election and, in connection with their departure from the Board, were granted accelerated vesting for these and all other unvested shares they were awarded in connection with their service on the Board.

⁽²⁾	For Mr. Biderman and Dr. Jackson, represents 892 deferred shares granted under the 2004 Plan, having a grant date fair value of $16.81. The shares vest one-third on each of the second, third and fourth anniversaries of the date of grant, as follows: 7/13/11—297, 7/13/12—297 and 7/13/13—298.

⁽³⁾	For Mr. Spolan, represents 608 deferred shares granted under the 2004 Plan, having a grant date fair value of $24.66. The shares vest one-third on each of the second, third and fourth anniversaries of the date of grant, as follows: 8/24/11—202, 8/24/12—203 and 8/24/13—203.

⁽⁴⁾

For Messrs. Jones and Wolf and Mmes. Davis and Warren, represents 573 deferred shares granted under the 2004 Plan, having a grant date fair value of $ 26.16. The shares vest one-third on each of the second, third and fourth anniversaries of the date of grant, as follows: 9/29/11—191, 9/29/12—191, and 9/29/13—191.

Director Compensation

The independent directors receive a flat fee of $75,000 per year, which was increased from $60,000 in October 2009. In addition to the cash compensation, independent directors receive an annual grant of deferred stock having a fair market value of $15,000 with a vesting schedule in which 33% of the award vests on the second, third and fourth anniversaries of the grant date.

Compensation Committee Interlocks and Insider Participation

The compensation committee of the Board of Directors consists of Ms. Warren and Messrs. Delson, Arrendell and Holtz. There are no compensation committee interlocks.

Compensation Committee Report

The compensation committee has reviewed and discussed the Compensation Discussion and Analysis with management and, based on its review and discussions, the compensation committee recommended to the board of directors that the Compensation Discussion and Analysis be included in the annual report on Form 10-K for the year ended December 31, 2009.

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This report has been provided by the compensation committee of the Board of Directors of Atlas Energy, Inc.

Donald W. Delson, Chairman

Dennis A. Holtz

Carlton M. Arrendell

Ellen F. Warren

ITEM 11.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the number and percentage of shares of common stock owned, as of February 22, 2010, by (a) each person who, to our knowledge, is the beneficial owner of more than 5% of the outstanding shares of common stock, (b) each of our present directors and nominees, (c) each of our executive officers serving during the 2009 fiscal year, and (d) all of our directors, nominees and executive officers as a group. This information is reported in accordance with the beneficial ownership rules of the Securities and Exchange Commission under which a person is deemed to be the beneficial owner of a security if that person has or shares voting power or investment power with respect to such security or has the right to acquire such ownership within 60 days. Shares of common stock issuable pursuant to options or warrants are deemed to be outstanding for purposes of computing the percentage of the person or group holding such options or warrants but are not deemed to be outstanding for purposes of computing the percentage of any other person. Unless otherwise indicated in footnotes to the table, each person listed has sole voting and dispositive power with respect to the securities owned by such person.


	Common stock Amount and nature of beneficial ownership		Percent of class
Beneficial owner
Directors ⁽¹⁾
Carlton M. Arrendell	4,528		*
Mark C. Biderman	2,000		*
Edward E. Cohen	4,107,025	⁽²⁾⁽⁴⁾	5.17	%
Jonathan Z. Cohen	2,480,713	⁽³⁾⁽⁴⁾	3.14	%
Jessica K. Davis	145		*
Donald W. Delson	5,603		*
Dennis A. Holtz	9,022		*
Gayle P.W. Jackson	0		*
Walter C. Jones	870		*
Harmon S. Spolan	1,222		*
Ellen F. Warren	580		*
Bruce M. Wolf	186,903		*

Non-director principal officers⁽¹⁾
Freddie M. Kotek	352,153	⁽⁴⁾	*
Matthew A. Jones	423,692	⁽⁴⁾	*
Sean P. McGrath	16,258	⁽⁴⁾	*
Richard D. Weber	511,153	⁽⁴⁾	*
All executive officers, directors and nominees as a group (16 persons)	6,652,369	⁽⁵⁾	8.18	%

Other owners of more than 5% of outstanding shares
Omega Advisors, Inc./Leon G. Cooperman	7,019,275	⁽⁶⁾	8.98	%
BlackRock, Inc.	5,059,039	⁽⁷⁾	6.47	%
Iridian Asset Management LLC	4,964,905	⁽⁸⁾	6.35	%
Goldman Sachs Asset Management	4,681,199	⁽⁹⁾	5.99	%
Cobalt Capital Management, Inc.	4,108,435	⁽¹⁰⁾	5.26	%
Alan Fournier/Pennant Capital Management, L.L.C.	4,084,988	⁽¹¹⁾	5.23	%

*	Less than 1%

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⁽¹⁾	The business address for each director, director nominee and executive officer is 1550 Coraopolis Heights Road—2^nd Floor, Moon Township, Pennsylvania 15108.

⁽²⁾

Includes (i) 50,454 shares held in an individual retirement account of Betsy Z. Cohen, Mr. E. Cohen’s spouse; (ii) 1,382,268 shares held by a charitable foundation of which Mr. E. Cohen, his spouse and their children serve as co-trustees; and (iii) 141,378 shares held in trust for the benefit of Mr. E. Cohen’s spouse and/or children. Mr. E. Cohen disclaims beneficial ownership of the above referenced shares. 129,296 and 1,382,268 shares are also included in the shares referred to in footnote 3 below.

⁽³⁾

Includes (i) 129,296 shares held in a trust of which Mr. J. Cohen is a co-trustee and co-beneficiary and (ii) 1,382,268 shares held by a charitable foundation of which Mr. J. Cohen, his parents and his sibling serve as co-trustees. These shares are also included in the shares referred to in footnote 2 above. Mr. J. Cohen disclaims beneficial ownership of the above referenced shares.

⁽⁴⁾	Includes shares issuable on exercise of options granted under our Plans in the following amounts: Mr. E. Cohen — 1,307,500 shares; Mr. J. Cohen — 853,000 shares; Mr. Kotek — 179,500 shares; Mr. Jones — 344,500 shares; Mr. Weber—454,539; and Mr. McGrath—12,788.

⁽⁵⁾	This number has been adjusted to exclude 129,296 shares and 1,382,268 shares which were included in both Mr. E. Cohen’s beneficial ownership amount and Mr. J. Cohen’s beneficial ownership amount.

⁽⁶⁾	This information is based on a Schedule 13G/A filed with the SEC on February 4, 2010. The address for Mr. Cooperman and Omega Advisors, Inc. is 88 Pine Street, Wall Street Plaza, 31^st Floor, New York, New York 10005.

⁽⁷⁾	This information is based on a Schedule 13G filed with the SEC on January 29, 2010. The address for BlackRock, Inc. is 40 East 52^nd Street, New York, NY 10022.

⁽⁸⁾	This information is based on a Schedule 13G filed with the SEC on January 28, 2010. The address for Iridian Asset Management, LLC is 276 Post Road West, Westport, CT 06880-4704.

⁽⁹⁾	This information is based on a Schedule 13G filed with the SEC on February 12, 2010. The address for Goldman Sachs Asset Management is 32 Old Slip, New York, NY 10022.

⁽¹⁰⁾	This information is based on a Schedule 13G/A filed with the SEC on February 11, 2010. The address for Cobalt Capital Management, Inc. is 237 Park Avenue, Suite 900, New York, New York 10017.

⁽¹¹⁾	This information is based on a Schedule 13G filed with the SEC on February 12, 2009. The address for Alan Fournier/Pennant Capital Management, L.L.C is 26 Main Street, Suite 203, Chatham, NJ 07928.

Equity Compensation Plan Information

The following table contains information about our Plan as of December 31, 2009:


	(a)	(b)		^©
Plan category	Number of securities to be issued upon exercise of equity instruments	Weighted- average exercise price of outstanding equity instruments		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders – restricted units	46,999		n/a
Equity compensation plans approved by security holders – options	3,509,554	$	16.82
Equity compensation plans approved by security holders – Total	3,556,553			5,544,137

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The following table contains information about the ATN Assumed Plan as of December 31, 2009:


	(a)	(b)		^©
Plan category	Number of securities to be issued upon exercise of equity instruments	Weighted- average exercise price of outstanding equity instruments		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders – phantom and restricted units	856,172		n/a
Equity compensation plans approved by security holders – unit options	2,068,514	$	20.38
Equity compensation plans approved by security holders – Total	2,924,686			n/a

The following table contains information about the AHD Plan as of December 31, 2009:


	(a)	(b)		^©
Plan category	Number of securities to be issued upon exercise of equity instruments	Weighted- average exercise price of outstanding equity instruments		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders – phantom units	138,875		n/a
Equity compensation plans approved by security holders – unit options	955,000	$	20.54
Equity compensation plans approved by security holders – Total	1,093,875			960,650

The following table contains information about the APL Plan as of December 31, 2009:


	(a)	(b)	^©
Plan category	Number of securities to be issued upon exercise of equity instruments	Weighted- average exercise price of outstanding equity instruments	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders – phantom units	52,233	n/a
Equity compensation plans approved by security holders – unit options	100,000	6.24
Equity compensation plans approved by security holders – Total	152,233		71,584

ITEM 12.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Effective as of April 28, 2009, we adopted a written policy governing related party transactions. For purposes of this policy, a related party includes: (i) any executive officer, director or director nominee; (ii) any person known to be a beneficial owner of 5% or more of our common stock; (iii) an immediate family member of any person included in clauses (i) and (ii) (which, by definition, includes, a person’s spouse, parents and parents in law, step parents, children, children in law and stepchildren, siblings and brothers and sisters in law and

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anyone residing in the that person’s home); and (iv) any firm, corporation or other entity in which any person included in clauses (i) through (iii) above is employed as an executive officer, is a director, partner, principal or occupies a similar position or in which that person owns a 5% or more beneficial interest. With certain exceptions outlined below, any transaction between us and a related party that is anticipated to exceed $120,000 in any calendar year must be approved, in advance, by our Conflicts Committee. If approval in advance is not feasible, the related party transaction must be ratified by the Conflicts Committee. In approving a related party transaction the Conflicts Committee will take into account, in addition to such other factors as the Conflicts Committee deems appropriate, the extent of the related party’s interest in the transaction and whether the transaction is no less favorable to us than terms generally available to an unaffiliated third party under similar circumstances.

The following related party transactions are pre-approved under the policy: (i) employment of an executive officer to perform services on our behalf (or on behalf of one of our subsidiaries); (ii) compensation paid to directors for serving on our board of directors or any committee thereof; (iii) transactions where the related party’s interest arises solely from ownership of our common stock and all of the holders of our common stock received the same benefit on a pro rata basis, or transactions available to all employees generally; (iv) a transaction with another company where the related party is only an employee (and not an executive officer), director or beneficial owner of less than 10% of such company’s shares and the aggregate amount involved does not exceed the greater of $1,000,000 or 2% of that company’s total annual revenues; and (v) any charitable contribution, grant or endowment by us to a charitable organization, foundation or university at which the related party’s only relationship is as an employee (other than an executive officer) or director or in a similar capacity, if the aggregate amount involved does not exceed the greater of $5,000 or 2% of that organization’s total annual receipts. We are not aware of any related party transactions requiring approval under the policy that were undertaken in 2009.

In the ordinary course of our business operations, we and our affiliates have ongoing relationships with several related entities:

Relationship with Atlas Energy Resources Partnerships. Atlas Energy Resources conducts certain activities through, and a substantial portion of its revenues are attributable to, energy limited partnerships. Atlas Energy Resources serves as general partner of these partnerships and assumes customary rights and obligations for them. As the general partner, Atlas Energy Resources 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. Atlas Energy Resources is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the partnerships’ revenue, and costs and expenses according to the respective partnership agreements.

Relationship with Atlas Pipeline Holdings. On June 1, 2009, Atlas Pipeline Holdings entered into an amendment to its revolving credit facility. In connection with the execution of the amendment, Atlas Pipeline Holdings agreed to immediately repay $30 million of the approximately $46 million then-outstanding indebtedness under the credit facility. The amendment also terminated Atlas Pipeline Holdings’ right to make further borrowings under the credit facility. Atlas Pipeline Holdings agreed to repay $4 million of the remaining $16 million on each of July 13, 2009, October 13, 2009 and January 13, 2010, with the balance of indebtedness being due on the original maturity date of April 13, 2010. In connection with the execution of this amendment, we agreed to guarantee the remaining debt outstanding under the credit facility. Pursuant to this guaranty, we have paid $4 million in respect of the payments due on July 13, 2009, October 13, 2009 and January 13, 2010 under the Atlas Pipeline Holdings credit agreement.

Atlas Pipeline Holdings’ $30 million repayment was funded from the proceeds of (i) a loan from us in the amount of $15 million, with an interest rate of 12% per annum and a maturity date the day following the day Atlas Pipeline Holdings pays all outstanding indebtedness due under the credit facility, and (ii) the purchase by Atlas Pipeline Partners of $15 million of preferred equity in a newly formed subsidiary of Atlas Pipeline Holdings. Moreover, in consideration of our guaranty, Atlas Pipeline Holdings issued a guaranty note to us

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whose principal amount is increased on the first day of each fiscal quarter by an amount equal to 3.75% per annum multiplied by the outstanding principal amount of indebtedness under AHD’s credit facility plus a $1.0 million guaranty fee. The maturity date on this note is the day following the day Atlas Pipeline Holdings pays all outstanding indebtedness due under the credit facility. Both promissory notes issued to us by Atlas Pipeline Holdings are payable-in-kind until their maturity date.

Relationship with Resource America. We have the following agreements with Resource America, our former parent, for which Edward E. Cohen, our Chairman and Chief Executive Officer, serves as Chairman and is a greater than 10% shareholder, and Jonathan Z. Cohen, our Vice Chairman, serves as Chief Executive Officer and President.

Tax Matters Agreement

As part of our initial public offering in 2004, we entered into a tax matters agreement with Resource America, which governs our respective rights, responsibilities, and obligations after our initial public offering with respect to tax liabilities and benefits, tax attributes, tax contests and other matters regarding income taxes, non-income taxes and related tax returns.

In general, under the tax matters agreement:

•

Resource America is responsible for any U.S. federal income taxes of the affiliated group for U.S. federal income tax purposes of which Resource America is the common parent. With respect to any periods beginning after our initial public offering, we are responsible for any U.S. federal income taxes attributable to us or any of our subsidiaries, including taxes payable as a result of our June 2005 spin-off from Resource America.

•

Resource America is responsible for any U.S. state or local income taxes reportable on a consolidated, combined or unitary return that includes Resource America or one of its subsidiaries, on the one hand, and us or one of our subsidiaries, on the other hand. However, in the event that we or one of our subsidiaries are included in such a group for U.S. state or local income tax purposes for periods (or portions thereof) beginning after the date of our initial public offering, we are responsible for our portion of such income tax liability as if we and our subsidiaries had filed a separate tax return that included only us and our subsidiaries for that period (or portion of a period).

•

Resource America is responsible for any U.S. state or local income taxes reportable on returns that include only Resource America and its subsidiaries (excluding us and our subsidiaries), and we are responsible for any U.S. state or local income taxes filed on returns that include only us and our subsidiaries.

•

Resource America and we are each responsible for any non-income taxes attributable to our business for all periods.

Resource America is primarily responsible for preparing and filing any tax return with respect to the Resource America affiliated group for U.S. federal income tax purposes and with respect to any consolidated, combined or unitary group for U.S. state or local income tax purposes that includes Resource America or any of its subsidiaries. We generally are responsible for preparing and filing any tax returns that include only us and our subsidiaries.

We have generally agreed to indemnify Resource America and its affiliates against any and all tax-related liabilities that may be incurred by them relating to the distribution to the extent such liabilities are caused by our actions. This indemnification applies even if Resource America has permitted us to take an action that would otherwise have been prohibited under the tax-related covenants as described above.

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During 2009, we did not have any liability to Resource America pursuant to the tax matters agreement.

Transition Services Agreement

Also in connection with our initial public offering, we entered into a transition services agreement with Resource America which governs the provision support services between us, such as:

•

cash management and debt service administration;

•

accounting and tax;

•

investor relations;

•

payroll and human resources administration;

•

legal;

•

information technology;

•

data processing;

•

real estate management; and

•

other general administrative functions.

We and Resource America will pay each other a fee for these services equal to their fair market value. The fee is payable monthly in arrears, 15 days after the close of each month. We have also agreed to pay or reimburse each other for any out-of-pocket payments, costs and expenses associated with these services. During fiscal 2009, we reimbursed Resource America $1.1 million pursuant to this agreement. Certain operating expenditures totaling $0.2 million that remain to be settled between are reflected in our consolidated balance sheets as advances from affiliate.

Resource America’s relationship with Anthem Securities (a wholly-owned subsidiary of Atlas Energy Resources). Anthem Securities, until December 2006 our wholly-owned subsidiary and now a wholly-owned subsidiary of Atlas Energy Resources, is a registered broker-dealer which provides dealer-manager services for investment partnerships sponsored by Resource America’s real estate and equipment finance segments. Salaries of the personnel performing services for Anthem are paid by Resource America, and Anthem reimburses Resource America for the allocable costs of such personnel. In addition, Resource America agreed to cover some of the operating costs for Anthem’s office of supervisory jurisdiction, principally licensing fees and costs. In fiscal 2009, there was no activity requiring reimbursements.

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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⁾	$	513	$	323
Audit-related fees⁽²⁾		161		56
Tax fees⁽³⁾		20		103
All other fees		—		—

Total accounting fees and services	$	694	$	482

⁽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 professional services rendered by Grant Thornton LLP for the annual audits of our employee benefit plans.

⁽³⁾

The fees for tax services rendered related to tax compliance.

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

Schedule I – Condensed Financial Information

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(3)

Exhibits:


Exhibit No.		Description
2.1		Agreement and Plan of Merger, dated as of April 27, 2009, by and 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⁽¹³⁾

3.1		Amended and Restated Certificate of Incorporation⁽¹⁾

3.2		Amended and Restated Bylaws⁽¹⁾

4.1		Form of stock certificate⁽²⁾

10.1		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⁽¹⁴⁾

10.2		Form of 10.75% Senior Note due 2018 (included as an exhibit to the Indenture filed as Exhibit 10.1 hereto)

10.3		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⁽¹⁵⁾

10.4		First Supplemental Indenture date July 16, 2009⁽¹⁵⁾

10.5		Form of Note 12.125% Senior Notes due 2017 (contained in Annex A to the First Supplemental Indenture filed as Exhibit 10.4 hereto)

10.6		Tax Matters Agreement between Atlas America, Inc. and Resource America, Inc. dated May 14, 2004⁽⁵⁾

10.7		Transition Services Agreement between Atlas America, Inc. and Resource America, Inc. dated May 14, 2004⁽⁵⁾

10.8(a)		Employment Agreement for Edward E. Cohen dated May 14, 2004⁽⁵⁾

10.8(b)		Amendment to Employment Agreement dated as of December 31, 2008⁽¹²⁾

10.9(a)		Agreement for Services among Atlas America, Inc. and Richard Weber, dated April 5, 2006⁽⁶⁾

10.10(b)		Amendment No. 1 to Agreement for Services dated as of April 26, 2007⁽⁷⁾

10.11(c)		Amendment No. 2 to Agreement for Services dated as of December 18, 2008⁽¹²⁾

10.12		Management Agreement, dated as of December 18, 2006, among Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC and Atlas Energy Management, Inc.⁽⁴⁾

10.13		Stock Incentive Plan⁽¹²⁾

10.14		2009 Stock Incentive Plan⁽¹⁾

10.15		Assumed Long-Term Incentive Plan⁽¹⁶⁾

10.16		Atlas America Employee Stock Ownership Plan⁽⁸⁾

10.17		Atlas America, Inc. Investment Savings Plan⁽⁸⁾

10.18		Form of Stock Award Agreement⁽⁹⁾

10.19		Amended and Restated Annual Incentive Plan for Senior Executives⁽¹⁰⁾

199


Exhibit No.		Description
10.20		Employment Agreement between Atlas America, Inc. and Jonathan Z. Cohen dated as of January 30, 2009⁽¹²⁾

10.21		Securities Purchase Agreement dated April 7, 2009 by and between Atlas Pipeline Mid-Continent, LLC and Spectra Energy Partners OLP, LP⁽¹⁷⁾

10.21(a)		Revolving Credit Agreement dated as of July 26, 2006 by and among Atlas Pipeline Holdings, L.P., Atlas Pipeline Partners GP, LLC, Wachovia Bank, National Association and the lenders thereto⁽¹⁷⁾

10.22(b)		First Amendment to Revolving Credit Agreement dated as of June 1, 2009⁽¹⁸⁾

10.23		Promissory Note dated as of June 1, 2009 by Atlas Pipeline Holdings, L.P.⁽¹⁸⁾

10.24		Guaranty Note dated as of June 1, 2009 by Atlas Pipeline Holdings, L.P.⁽¹⁸⁾

10.25		Guaranty, Subordination and Cash Collateral Agreement dated as of June 1, 2009 in favor of Wachovia Bank, National Association⁽¹⁸⁾

10.26(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⁽¹⁹⁾

10.26(b)		First Amendment to Credit Agreement, dated as of October 25, 2007⁽²⁰⁾

10.26(c)		Second Amendment to Credit Agreement, dated as of April 9, 2009⁽²¹⁾

10.26(d)		Third Amendment to Credit Agreement, dated as of July 10, 2009⁽²²⁾

10.27		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⁽²³⁾

10.28		Amended and Restated Limited Liability Company Agreement of Laurel Mountain Midstream, LLC dated as of June 1, 2009⁽²³⁾

10.29		Employment Agreement for Matthew A. Jones dated July 1, 2009⁽¹⁷⁾

10.30		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.⁽²⁴⁾ 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.

10.31		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.⁽²⁴⁾ 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.

10.32		Form of Non-Qualified Stock Option Grant Agreement

10.33		Form of Incentive Stock Option Grant Agreement

10.34		Form of Restricted Stock Unit Agreement

14.1		Insider Trading Policy ⁽¹¹⁾

21.1		Subsidiaries of Atlas Energy, Inc.

23.1		Consent of Grant Thornton LLP

23.2		Consent of Wright & Company, Inc.

200


Exhibit No.		Description

31.1		Rule 13a-14(a)/15d-14(a) Certification.

31.2		Rule 13a-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 September 30, 2009

(2)	Previously filed as an exhibit to our registration statement on Form S-1 (registration no. 333-112653)

(3)	[Intentionally omitted]

(4)	[Intentionally omitted]

(5)	Previously filed as an exhibit to our Form 10-Q for the quarter ended June 30, 2004

(6)	Previously filed as an exhibit to our Form 10-Q for the quarter ended June 30, 2006

(7)	Previously filed as an exhibit to our Form 8-K filed May 1, 2007

(8)	Previously filed as an exhibit to our Form 10-K for the year ended September 30, 2005

(9)	Previously filed as an exhibit to our Form 10-Q for the quarter ended December 31, 2005

(10)	Previously filed as an exhibit to our definitive proxy statement filed May 8, 2008

(11)	Previously filed as an exhibit to our Form 8-K filed August 31, 2007

(12)	Previously filed as an exhibit to our Form 10-K for the year ended December 31, 2008

(13)	Previously filed as an exhibit to our Form 8-K filed April 27, 2009.

(14)	Previously filed as an exhibit to Atlas Energy Resources, LLC’s Form 8-K filed January 24, 2008

(15)	Previously filed as an exhibit to Atlas Energy Resources, LLC’s Form 8-K filed July 17, 2009

(16)	Previously filed as an exhibit to our Form S-8 filed September 30, 2009

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

(18)	Previously filed as an exhibit to our Form 8-K filed June 2, 2009

(19)	Previously filed as an exhibit to Atlas Energy Resources, LLC’s Form 8-K filed June 29, 2007

(20)	Previously filed as an exhibit to Atlas Energy Resources, LLC’s Form 8-K filed October 26, 2007

(21)	Previously filed as an exhibit to Atlas Energy Resources, LLC’s Form 8-K filed April 17, 2009

(22)	Previously filed as an exhibit to Atlas Energy Resources, LLC’s Form 8-K filed July 24, 2009

(23)	Previously filed as an exhibit to our Form 8-K filed June 5, 2009

(24)	Previously filed as an exhibit to Atlas Energy Resources, LLC’s Form 10-Q for the quarter ended June 30, 2009

201

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


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


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


/s/ CARLTON M. ARRENDELL Carlton M. Arrendell		Director


/s/ GAYLE P. JACKSON Gayle P. Jackson		Director


/s/ DONALD W. DELSON Donald W. Delson		Director


/s/ DENNIS A. HOLTZ Dennis A. Holtz		Director


/s/ HARMON S. SPOLAN Harmon S. Spolan		Director


/s/ MARK C. BIDERMAN Mark C. Biderman		Director


/s/ ELLEN F. WARREN Ellen F. Warren		Director

202



/s/ WALTER C. JONES Walter C. Jones		Director
/s/ WALTER C. JONES Walter C. Jones

/s/ BRUCE M. WOLF Bruce M. Wolf		Director
/s/ BRUCE M. WOLF Bruce M. Wolf

/s/ JESSICA K. DAVIS Jessica K. Davis		Director
/s/ JESSICA K. DAVIS Jessica K. Davis

203

ATLAS ENERGY, INC.

Date: February 26, 2010

/s/ EDWARD E. COHEN

Edward E. Cohen

Chairman and Chief Executive Officer