Forward-Looking Statements
When used in this Form 10-Q, the words "believes," "anticipates," "expects" and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties more particularly described in Item 1A, "Risk Factors", in our annual report on Form 10-K for the year ended December 31, 2008. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.
GENERAL
The following discussion provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this report.

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 (NYSE: ATN), 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 focus our drilling and production 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 Appalachian Basin major operations are located in eastern Ohio, western Pennsylvania, and north central Tennessee. We have additional operations in New York, West Virginia and Kentucky. We specialize in development of these natural gas basins because they provide it with 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 its 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 becomes its managing general partner.
KEY PERFORMANCE INDICATORS
In our Appalachia gas and oil operations:
• we own direct and indirect working interests in approximately 8,658 gross productive gas and oil wells;

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

• our net daily production was 41.3 million cubic feet equivalents per day ("Mmcfed") and 42.4 Mmcfed for the three and nine months ended September 30, 2009, respectively;

• we lease approximately 919,200 gross (873,600 net) acres, of which approximately 606,800 gross (599,800 net) acres are undeveloped;

• included in our undeveloped acreage are approximately 215,600 Marcellus acres in Pennsylvania, New York and West Virginia, of which approximately 160,400 acres are located in our core Marcellus Shale position in southwestern Pennsylvania;

• we drilled 153 gross wells (including 73 Marcellus Shale wells), during the nine months ended September 30, 2009, on our own behalf and that of our investment partnerships;

• we have drilled 184 vertical and 15 horizontal gross Marcellus Shale wells to date, of which 159 vertical and 7 horizontal Marcellus Shale wells have been successfully completed and have been turned on-line and are producing;

• of the 159 vertical completed Marcellus Shale wells we drilled to date, we have utilized the multi-frac technique on 68 wells, with successful results;

• we turned on-line 274 gross wells during the nine months ended September 30, 2009; and

• we drilled and participated in 25 horizontal wells in the Chattanooga Shale of eastern Tennessee to date. We have leased approximately 130,700 gross acres (128,200 net undeveloped) in this shale area.

In our Michigan gas and oil operations:
• we own direct and indirect working interests in approximately 2,498 gross producing gas and oil wells;

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

• our net daily production was 57.8 Mmcfed and 58.3 Mmcfed for the three and nine months ended September 30, 2009, respectively;

• we have leased approximately 345,000 gross (271,900 net) acres, of which approximately 34,900 gross (26,400 net) acres are undeveloped; and

• we drilled 32 gross wells (27 net wells) during the nine months ended September 30, 2009.

In our Indiana gas and oil operations:
• we own direct and indirect working interests in approximately 20 gross producing gas and oil wells;

• our net daily production was 0.8 Mmcfed and 0.4 Mmcfed for the three and nine months ended September 30, 2009, respectively;

• we have leased approximately 249,600 gross (122,800 net) acres, of which approximately 242,600 gross (117,200 net) acres are undeveloped; and

• we drilled 19 gross wells (17 net wells) during the nine months ended September 30, 2009.

In our partnership management business:
• our investment partnership business includes equity interests in 96 investment partnerships and a registered broker-dealer which acts as the dealer manager of our investment partnership offerings; and

• during 2009, we have raised $122.8 million in investor funds for Atlas Resources Public #18B-2009(B) L.P., and have begun raising funds for our most recent investment partnership, Atlas Resources Public #18-2009(C) L.P. in which we have registered subscriptions of up to $275.7 million (A written prospectus meeting the requirements of Section 10 of the Securities Act may be obtained from Anthem Securities, Inc. (a subsidiary of Atlas Energy), 1550 Coraopolis Heights Rd. - 3rd Floor, Moon Township, PA 15108).

OTHER OWNERSHIP INTERESTS
In addition to our production operations, we also maintain ownership interests in the following entities at September 30, 2009:
• 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;

• 17,808,109 common units, representing a 64.4% 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

• 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 $20.0 million in Lightfoot LP. We also have a direct and indirect ownership interests in Lightfoot LP.

AHD, which owns the general partner and manages APL, had the following ownership interests in APL at September 30, 2009:
• a 2.0% general partner interest, which entitles it to receive 2% of the cash distributed by APL;

• all of the incentive distribution rights, 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. AHD, the holder of all of the incentive distribution rights in APL, 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;

• 5,754,253 common units, representing approximately 11.4% of the outstanding common units at September 30, 2009, or a 11.2% ownership interest in APL; and

• 15,000 $1,000 par value 12.0% cumulative preferred limited partner units at September 30, 2009.

FINANCIAL PRESENTATION
Our consolidated financial statements contain our accounts and those of our subsidiaries, all of which are wholly-owned at September 30, 2009 except for AHD, which we control, and APL, which is controlled by AHD. Prior to the Merger on September 29, 2009, ATN was a controlled subsidiary of ours but was not wholly-owned. The non-controlling interests in ATN prior to the Merger and AHD and APL are reflected as income (loss) attributable to non-controlling interests in our consolidated statements of operations and as a component of stockholders' 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).

RECENT DEVELOPMENTS
On September 29, 2009, we completed our merger with ATN pursuant to the definitive merger agreement previously executed between us and ATN, 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 creates 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. Due to the Merger, we recognized a reduction of $556.4 million in non-controlling interest and a decrease to deferred tax liability of $179.4 million, all of which was reflected as an increase to additional paid-in-capital on our consolidated balance sheets. On September 7, 2009, we began fundraising for Atlas Resources Public #18-2008 Drilling Program, in which we have the capacity to raise approximately $275.7 million, representing the third partnership (Atlas Resources Public #18-2009(C) L.P.) in the program. During the first six months of 2009, we raised $122.8 million for our second partnership (Atlas Resources Public #18-2009 (B) L.P.). Atlas Resources, LLC, our wholly-owned subsidiary, serves as the managing general partner for each partnership. A written prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended, may be obtained from Anthem Securities, Inc. (a subsidiary of Atlas Energy), 1550 Coraopolis Heights Rd. - 3rd Floor, Moon Township, PA 15108.
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"). Under the terms of the credit facility, the borrowing base is automatically reduced by 25% of the stated principal amount of any senior unsecured notes offering by ATN. As such, the borrowing base of the credit facility was reduced by $50.0 million to $600.0 million upon the issuance of the ATN 12.125% Senior Notes. 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 or APL's senior notes, including the ATN 12.125% Senior Notes, ATN's or APL's credit facilities, or APL's term loan. 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.
SUBSEQUENT EVENTS
On November 2, 2009, APL's agreement with Pioneer Natural Resources Company ("Pioneer"), whereby Pioneer had an option to purchase up to an additional 22.0% interest in the Midkiff/Benedum system, expired without Pioneer exercising its option (see Note 2 under Item 1, "Financial Statements").

Natural Gas Derivative Contracts
On October 22, 2009, we entered into the following natural gas derivative
contracts:
Natural Gas Fixed Price Swaps

                    Production
                    Period Ending                      Average
                    December 31,      Volumes        Fixed Price
                                      (MMBtu)        (per MMBtu)
                    2010              2,520,000     $       6.250
                    2011              1,260,000     $       6.863


Natural Gas Costless Collars

            Production
            Period Ending                                          Average
            December 31,     Option Type         Volumes        Floor and Cap
                                                 (MMBtu)         (per MMBtu)
            2012            Puts purchased       3,480,000     $         6.550
            2012            Calls sold           3,480,000     $         7.750
            2013            Puts purchased       3,480,000     $         6.700
            2013            Calls sold           3,480,000     $         7.800

Credit Agreement Amendment
Effective October 14, 2009, in conjunction with a regularly scheduled borrowing base redetermination, ATN's borrowing base under its revolving credit facility of $575.0 million was approved.
On October 13, 2009 AHD repaid $4.0 million of its outstanding credit facility borrowings in accordance with the amendment through a subordinate loan with us.
CONTRACTUAL REVENUE ARRANGEMENTS
Appalachia Natural Gas. We market our natural gas, which is principally located in the Fayette County, PA area, primarily to Hess Corporation, Colonial Energy, Inc., South Jersey Resources Group and others. We expect that natural gas produced from our wells drilled in areas of the Appalachian Basin other than those described above will be primarily tied to the spot market price and supplied to:
• gas marketers;

• local distribution companies;

• industrial or other end-users; and/or

• companies generating electricity.

Michigan Natural Gas. In Michigan, we have natural gas sales agreements with DTE Energy Company, which are valid through December 31, 2012. DTE has the obligation to purchase all of the natural gas produced and delivered by us and our affiliates from specific projects at certain delivery points. Based on recent production data available to us, we anticipate that we and our affiliates will sell approximately 49% of our Michigan natural gas production during the year ending December 31, 2009 under the DTE agreements, in most cases at NYMEX pricing.

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. 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.

• Administration and oversight. For each well drilled by an investment partnership, we receive a fixed fee that currently ranges from $15,700 to $248,964. The fixed fee is based on factors such as well type (vertical or horizontal), depth, formation, and area. 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 its 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.

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 three months ended September 30, 2009 when compared with the prior year, we believe that the current development of the Marcellus Shale and the New Albany 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. Although the number of natural gas wells drilled in the United States has increased overall in recent years, a corresponding increase in production has not been realized, primarily as a result of smaller discoveries and the decline in production from existing wells. We believe that an increase in United States drilling activity, additional sources of supply such as liquefied natural gas and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for, and to compensate for the slowing production of, natural gas in the United States. However, 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 decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. In order to sustain and grow our cash flow, we may need to make acquisitions.
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. 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 shows our total net gas and oil production volumes and production per day during the three and nine months ended September 30, 2009 and 2008, respectively (in thousands, except for production per day):

                                  Three Months Ended          Nine Months Ended
                                     September 30,              September 30,
                                   2009          2008         2009          2008
           Production:(1)(2)
           Appalachia:(3)
           Natural gas (MMcf)        3,549        3,057        10,851        8,748
           Oil (000's Bbls)             42           39           120          112
           Total (MMcfe)             3,801        3,291        11,571        9,420
           Michigan/Indiana:
           Natural gas (MMcf)        5,384        5,561        15,910       16,373
           Oil (000's Bbls)              1            1             3            3
           Total (MMcfe)             5,390        5,567        15,928       16,391
           Total:
           Natural gas (MMcf)        8,933        8,618        26,761       25,121
           Oil (000's Bbls)             43           40           123          115
           Total (MMcfe)             9,191        8,858        27,499       25,811

                                      Three Months Ended          Nine Months Ended
                                         September 30,              September 30,
                                       2009          2008         2009          2008
        Production per day:(1)(2)
        Appalachia:(3)
        Natural gas (Mcfd)              38,579       33,228        39,749       31,929
        Oil (Bpd)                          460          413           442          410
        Total (Mcfed)                   41,339       35,706        42,401       34,389
        Michigan/Indiana:
        Natural gas (Mcfd)              58,519       60,436        58,277       59,755
        Oil (Bpd)                            9           11             9           11
        Total (Mcfed)                   58,573       60,502        58,331       59,821
        Total:
        Natural gas (Mcfd)              97,098       93,664        98,026       91,684
        Oil (bpd)                          469          424           451          421
        Total (Mcfed)                   99,912       96,208       100,732       94,210

(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.

Production Revenues, Prices and Costs. 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, 2008. The following table shows our production revenues and average sales prices for our oil and gas production during the three and nine months ended September 30, 2009 and 2008, along with our average production costs, taxes, and transmission and compression costs in each of the reported periods:

. . .