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, under the caption "Risk Factors", in our annual report on Form 10-K for fiscal 2008 and Part II, Item 1A of this report. These risks and uncertainties could cause actual results to differ materially. 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 thereto appearing elsewhere in this report. We are a publicly-traded Delaware limited liability Company (NYSE: ATN) formed in June 2006. We are an independent developer and producer of natural gas and oil, with operations in the Appalachian Basin, where we focus on the development of the Marcellus Shale, northern Michigan's Antrim Shale, and Indiana's New Albany Shale. Our Appalachian Basin major operations are located in eastern Ohio, western Pennsylvania, and north central Tennessee. We have additional operations in New York, West Virginia and Kentucky. We specialize in the development of these natural gas basins because they provide us with repeatable, low-risk drilling opportunities. We are a leading sponsor and manager of tax-advantaged, direct investment natural gas and oil partnerships in the United States. Our focus is to increase our own reserves, production, and cash flows through a balanced mix of generating new opportunities of geologic prospects, natural gas and oil exploitation and development, and sponsorship of investment partnerships. We generate both upfront and ongoing fees from the drilling, production, servicing, and administration of our wells in these partnerships.

Our business is conducted through three reportable business segments:

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

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

Unless otherwise indicated, references in this report to we, our or us include Atlas Energy Resources, LLC, our wholly-owned subsidiaries and our interests in sponsored drilling programs.

RECENT DEVELOPMENTS

Merger with Atlas America, Inc.

On April 27, 2009, we and Atlas America executed a definitive merger agreement, pursuant to which a newly formed subsidiary of Atlas America will merge with and into us, with us surviving as a wholly-owned subsidiary of Atlas America. In the merger, each Class B common unit of ours not currently held by Atlas America will be converted into 1.16 shares of Atlas America common stock, and Atlas America will be renamed "Atlas Energy, Inc." The Atlas America board of directors has approved the merger agreement and has resolved to recommend that the Atlas America stockholders vote in favor of the transactions contemplated by the merger agreement. Our board of directors and a special committee of our directors comprised entirely of independent directors have also approved the merger agreement and have resolved to recommend that our unitholders vote in favor of the merger. Pending consummation of the merger, we have suspended distributions to our Class A and Class B members' interests. The transaction will be subject to approval by holders of a majority of the outstanding Atlas America common stock and a majority of our outstanding Class B units, consent of a majority of the lenders under our credit agreement and other customary closing conditions.

Sale of Natural Gas Gathering Assets

On March 31, 2009, we entered into an agreement to sell two natural gas processing plants and associated pipelines located in southwestern Pennsylvania for cash of $12.0 million to Laurel Mountain Midstream, LLC ("Laurel Mountain"), a newly-formed joint venture between our affiliate, Atlas Pipeline Partners, L.P. (NYSE: APL) ("Atlas Pipeline"), and The Williams Companies, Inc. (NYSE: WMB). ("Williams"). This agreement was entered into in connection with Atlas Pipeline's March 31, 2009 agreement with Williams that it will form Laurel Mountain and, upon contributing its Appalachia Basin natural gas gathering system to Laurel Mountain, will receive $90.0 million in cash, a preferred equity right to proceeds under a $25.5 million obligation by Laurel Mountain and a 49% equity interest in Laurel Mountain. Atlas Pipeline is a subsidiary of our indirect parent company, Atlas America, Inc. (NASDAQ: ATLS), ("Atlas America"). The joint venture will own and operate all of Atlas Pipeline's northern Appalachian assets, excluding its northern Tennessee operations, of which we will be the largest customer. Our and Atlas Pipeline's transactions with Williams are expected to close in the second quarter of 2009 and are subject to customary closing conditions. We will use the net proceeds from the transaction to reduce borrowings under our credit facility.

Upon completion of the Williams' transaction, we will enter into new gas gathering agreements which will supersede the existing master natural gas gathering agreement and omnibus agreement between us and Atlas Pipeline. Under the proposed gas gathering agreement, we will be obligated to pay Laurel Mountain all of the gathering fees we collect from the partnerships plus any excess amount over the amount of the competitive gathering fee (which is currently defined as 13% of the gross sales price received for the partnerships gas). The proposed 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.

Credit Agreement Amendment

Effective April 9, 2009, we entered into a second amendment to our credit agreement with a syndicate of banks. Among other things, the amendment adjusts the credit facility borrowing base to $650 million and amends the definition of applicable margin to, among other items, adjust the Eurodollar Loans rate from a range of 100 to 175 basis points to a range of 200 to 300 basis points, subject to amounts drawn against the facility.

Hedge Monetization

In May 2009, we received approximately $28.5 million in proceeds from the early settlement of natural gas hedge positions related to periods from 2011 through 2013. In conjunction with the hedge monetization, these hedge positions were effectively replaced with similar hedge contracts at current prevailing prices. The net proceeds from the hedge monetization were used to reduce indebtedness.

Formation of Atlas Resources Public #18-2009(B) L.P.

On February 10, 2009, the Post-Effective Amendment No. 1 to the Atlas Resources Public #18-2008 Drilling Program Registration Statement became effective with the Securities and Exchange Commission, representing the second partnership (Atlas Resources Public #18-2009(B) L.P.) in the program. We plan to raise approximately $100.0 million in investor subscriptions whereby, Atlas Resources, LLC, our wholly-owned subsidiary, will serve as the managing general partner.

Key Performance Indicators as of and for the three months ended March 31, 2009:

In our Appalachia gas and oil operations:

· we own direct and indirect working interests in approximately 8,602 gross productive gas and oil wells;

· we own overriding royalty interests in approximately 628 gross productive gas and oil wells;

· our net daily production was 42.3 Mmcfe per day;

· we lease approximately 952,000 gross (906,000 net) acres, of which approximately 640,000 gross (633,000 net) acres are undeveloped;

· included in our undeveloped acreage are approximately 546,000 Marcellus acres in Pennsylvania, New York and West Virginia, of which approximately 274,000 acres are located in our core Marcellus Shale position in southwestern Pennsylvania;

· we drilled 105 gross wells (including 30 Marcellus Shale wells), all of which were productive on behalf of our investment partnerships;

· we have drilled 135 vertical and 7 horizontal Marcellus Shale wells to date, all of which have been successfully drilled, cased and cemented;

· of the 135 Marcellus Shale wells we drilled, we have completed 28 wells using a two-stage frac technique with successful results;

· we connected 105 gross wells to our affiliate, Atlas Pipeline's gathering systems; and

· we drilled and participated in 21 horizontal wells in the Chattanooga Shale of eastern Tennessee.

In our Michigan gas and oil operations:

· we own direct and indirect working interests in approximately 2,479 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 58.1 Mmcfe per day;

· we lease approximately 345,400 gross (273,000 net) acres, of which approximately 39,400 gross (30,500 net) acres are undeveloped; and

· we drilled 20 gross wells (17 net wells).

In our Indiana gas and oil operations:

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

· our net daily production was 0.2 Mmcfe per day;

· we have leased approximately 245,200 gross (118,900 net) acres, of which approximately 244,600 gross (118,400 net) acres are undeveloped; and

· we drilled 7 gross (5.5 net) wells.

In our partnership management business:

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

How We Evaluate our Operations

Non-GAAP Financial Measures

We use a variety of financial and operations measures to assess our performance, including non-GAAP financial measures, such as EBITDA, Adjusted EBITDA and distributable cash flow. These measures are not calculated or presented in accordance with generally accepted accounting principles, or GAAP.

EBITDA, Adjusted EBITDA and distributable cash flow are significant performance metrics used by our management to indicate (prior to the establishment of any cash reserves) the cash distributions we expect to pay to our unitholders (see "RECENT DEVELOPMENTS" related to our anticipated merger with Atlas America, Inc. and "CASH DISTRIBUTIONS" which describes our cash distribution policy). Specifically, these financial measures assist our investors in their assessment of whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. EBITDA, Adjusted EBITDA and distributable cash flow are also used as quantitative standards by our management and by external users of our financial statements such as investors, research analysts and others to assess:

· the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

· the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and

· our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure.

Our EBITDA, Adjusted EBITDA and distributable cash flow should not be considered as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our EBITDA, Adjusted EBITDA and distributable cash flow excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our EBITDA, Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies.

The following table presents a reconciliation of net income, our most directly comparable GAAP performance measure, to EBITDA, Adjusted EBITDA and distributable cash flow for each of the periods presented:

                                                                 Three Months Ended
                                                                      March 31,
                                                                 2009          2008
Reconciliation of net income to non-GAAP measures:
Net income                                                     $  25,603     $  37,564
Income attributable to non-controlling interests                     (15 )         (21 )
Depreciation and amortization                                     28,028        21,810
Interest expense                                                  12,984        13,305
EBITDA                                                            66,600        72,658
Adjustment to reflect cash impact of derivatives(1)                1,604         5,028
Non-cash compensation expense                                      1,528         1,320
Adjusted EBITDA                                                   69,732        79,006
Interest expense                                                 (12,984 )     (13,305 )
Amortization of deferred financing costs (included within
interest expense)                                                    665           770
Maintenance capital expenditures                                 (12,975 )     (12,975 )
Distributable cash flow                                        $  44,438     $  53,496

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.

Financial Markets

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

Commodity Prices

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

Commodity prices for natural gas continued to decline during the three months ended March 31, 2009 from year-end commodity prices at December 31, 2008. This decline may cause some of our oil and gas properties to become uneconomic to develop or operate. Please read "Part II, Item 1A: - Risk Factors" included in this report.

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

Natural Gas Supply and Outlook

While commodity prices for natural gas have declined during the three months ended March 31, 2009, 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. However, 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 our debt and distributions (see "RECENT DEVELOPMENTS" for information related to anticipated merger with Atlas America and the amendment to our credit agreement) depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. We face the challenge of natural production declines. As initial reservoir pressures are depleted, natural gas production from a given well decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. In order to sustain and grow our level of distributions, we may need to make acquisitions that are accretive to distributable cash flow per unit. In addition, we intend to reserve a portion of our cash flow from operations to allow us to develop our oil and gas properties at a level that will allow us to maintain a flat production profile and reserve levels.

RESULTS OF OPERATIONS

GAS AND OIL PRODUCTION

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

Production Volumes. The following table shows our total net gas and oil production volumes and production per day during the three months ended March 31, 2009 and 2008 (in thousands, except for production per day):

                                            Three Months Ended
                                                 March 31,
                                             2009          2008
                    Production (1):
                    Appalachia: (2)
                    Natural gas (MMcf)         3,592        2,756
                    Oil (000's Bbls)              35           36
                    Total (MMcfe)              3,803        2,971
                    Michigan/Indiana:
                    Natural gas (MMcf)         5,242        5,374
                    Oil (000's Bbls)               1            1
                    Total (MMcfe)              5,247        5,380
                    Total:
                    Natural gas (MMcf)         8,834        8,130
                    Oil (000's Bbls)              36           37
                    Total (MMcfe)              9,050        8,351

                    Production per day:
                    Appalachia:
                    Natural gas (Mcf/d)       39,908       30,286
                    Oil (Bbl)                    392          399
                    Total (Mcfe/d)            42,260       32,680
                    Michigan/Indiana:
                    Natural gas (Mcf/d)       58,250       59,056
                    Oil (Bbl)                      6            6
                    Total (Mcfe/d)            58,286       59,092
                    Total:
                    Natural gas (Mcf/d)       98,158       89,342
                    Oil (bpd)                    398          405
                    Total (Mcfe/d)           100,546       91,772

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

Production Revenues, Prices and Costs. Our production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised 99% of our proved reserves on an energy equivalent basis at the end of 2008. The following table shows our production revenues and our average sales prices for our oil and gas production during the three months ended March 31, 2009 and 2008, along with our average production costs, taxes, and transmission and compression costs in each of the reported periods.

                                                    Three Months Ended
                                                         March 31,
                                                     2009           2008
           Production Revenues (in thousands):
           Appalachia:
           Natural gas revenue                    $    27,544     $ 25,606
           Oil revenue                                  2,050        3,302
           Total revenues                         $    29,594     $ 28,908
           Michigan/Indiana:
           Natural gas revenue                    $    42,330     $ 47,268
           Oil revenue                                     19           50
           Total revenues                         $    42,349     $ 47,318
           Total:
           Natural gas revenue                    $    69,874     $ 72,874
           Oil revenue                                  2,069        3,352
           Total revenues                         $    71,943     $ 76,226

           Average Sales Price:
           Appalachia:
           Natural gas (per Mcf)
           Total realized price, after hedge      $      7.67     $   9.29
           Total realized price, before hedge     $      5.59     $   8.79
           Michigan/Indiana:
           Natural gas (per Mcf)
           Total realized price, after hedge(1)   $      8.38     $   9.73
           Total realized price, before hedge     $      4.95     $   8.08
           Total:
           Natural gas (per Mcf)
           Total realized price, after hedge(1)   $      8.09     $   9.58
           Total realized price, before hedge     $      5.21     $   8.32
           Appalachia:
           Oil (per Bbl)
           Total realized price, after hedge      $     64.97     $  91.02
           Total realized price, before hedge     $     42.89     $  91.02
           Michigan/Indiana:
           Oil (per Bbl)
           Total realized price, after hedge      $     37.39     $  91.23
           Total realized price, before hedge     $     37.39     $  91.23
           Total:
           Oil (per Bbl)
           Total realized price, after hedge      $     64.52     $  91.03
           Total realized price, before hedge     $     42.74     $  91.03

Production Costs (per Mcfe):
Appalachia:
Lease operating expenses         $ 1.04     $ 0.87
Production taxes                   0.04       0.04
Transportation and compression     0.87       0.78
                                 $ 1.95     $ 1.69
Michigan/Indiana:
Lease operating expenses         $ 0.81     $ 0.74
Production taxes                   0.30       0.48
Transportation and compression     0.26       0.28
                                 $ 1.37     $ 1.50
Total:
Lease operating expenses         $ 0.91     $ 0.78
Production taxes                   0.19       0.32
Transportation and compression     0.51       0.46
                                 $ 1.61     $ 1.56

Our natural gas revenues were $69.9 million for the three months ended March 31, 2009, a decrease of $3.0 million (4%) from $72.9 million for the three months ended March 31, 2008. The $3.0 million decrease in natural gas revenues consisted of $5.6 million attributable to increases in natural gas production volumes, offset by $8.6 million attributable to decreases in realized natural gas sales prices.

. . .