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. 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.

We are a publicly-traded Delaware limited liability Company (NYSE: ATN) and 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 operations are primarily 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 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; and

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

RECENT DEVELOPMENTS

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

On June 29, 2009, we completed fundraising for Atlas Resources Public #18-2008 Drilling Program, raising $122.8 million representing the second partnership (Atlas Resources Public #18-2009(B) L.P.) in the program. Atlas Resources, LLC, our wholly-owned subsidiary, serves as the managing general partner.

Sale of Natural Gas Gathering and Processing Assets

On June 1, 2009, we completed the sale of two natural gas processing plants and associated pipelines located in southwestern Pennsylvania for cash of $10.0 million to Laurel Mountain Midstream, LLC ("Laurel Mountain"), a newly-formed joint venture between our affiliate, Atlas Pipeline Partners, L.P. (NYSE: APL) ("Atlas Pipeline"), and The Williams Companies, Inc. (NYSE: WMB). ("Williams"). Upon contribution of its Appalachia Basin natural gas gathering system to Laurel Mountain, Atlas Pipeline 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. Atlas Pipeline is a subsidiary of our indirect parent company, Atlas America, Inc. (NASDAQ: ATLS), ("Atlas America"). Laurel Mountain owns and operates all of Atlas Pipeline'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 as "Loss on asset sale" on our consolidated statements of income for the three and six months ended June 30, 2009. We used the net proceeds to reduce borrowings under our 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 Atlas Pipeline. 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 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.

Early Termination of Derivative Instruments

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 position at the prevailing prices at the time of the transaction. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under our revolving credit facility (see "Credit Facility").

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 and other customary closing conditions.

Credit Agreement Amendment

Effective April 9, 2009, we entered into a second amendment to our credit agreement with a syndicate of banks, which among other things, adjusted our credit facility borrowing base to $650.0 million (see "Subsequent Events"). The amendment also modified the definition of applicable margin above adjusted LIBOR or the base rate (as defined in the credit agreement) upon which borrowings under the credit facility bear interest by adjusting the Eurodollar Loans rate (as defined in the credit agreement) from a range of 100 to 175 basis points to a range of 200 to 300 basis points and the applicable margin for base rate loans from a range of 0 to 75 basis points to a range of 112.5 to 212.5 basis points, subject to amounts drawn against the credit facility.

SUBSEQUENT EVENTS

Senior Unsecured Notes

On July 16, 2008, we issued $200.0 million of 12.125% senior unsecured notes ("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 our revolving credit facility.Under the terms of our credit facility (see "Credit Facility"), the credit facility borrowing base is automatically reduced by 25% of the stated principal amount of any senior unsecured notes offering by us. As such, the borrowing base of our credit facility was reduced by $50.0 million to $600.0 million upon the issuance of the 12.125% Senior Notes. Interest on the 12.125% Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year. The 12.125% Senior Notes are redeemable at any time 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 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 12.125% Senior Notes are junior in right of payment to our secured debt, including our obligations under the revolving credit facility. The indenture governing the 12.125% Senior Notes contains covenants, including limitations of our ability to incur certain liens, engage in sale/leaseback transactions, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of our assets.

Amendment to Revolving Credit Facility

On July 10, 2009, we received the requisite consent from our lenders to amend our revolving credit facility to permit the merger with Atlas America. The material terms of the amendment are:

• The merger with Atlas America will be permitted,

• Restrictions on our ability to make payments with respect to our equity interests will be revised to permit us to make distributions to Atlas America in an amount equal to the income tax liability at the highest marginal rate attributable to our net income. In addition, we will be permitted to make distributions to Atlas America of up to $40.0 million per year and, to the extent that we distribute less than that amount in any year, may carry over up to $20.0 million for use in the next year,

• The definition of change of control will be revised to include a change of control of Atlas America.

The amendment will become effective upon consummation of the merger.

Natural Gas Derivative Contracts

On July 20, 2009, we entered into certain natural gas derivative contracts for calendar 2013 production volume of 220,000 MMbtu per month with an average fixed price of $6.90 per MMbtu.

Key Performance Indicators as of and for the three and six months ended June 30, 2009:

In our Appalachia gas and oil operations:

· we own direct and indirect working interests in approximately 8,631 gross productive gas and oil wells;

· we own overriding royalty interests in approximately 629 gross productive gas and oil wells;

· our net daily production was 43.6 Mmcfe per day and 42.9 Mmcfe per day for the three months and six months ended June 30, 2009;

· we lease approximately 935,300 gross (889,700 net) acres, of which approximately 623,300 gross (616,400 net) acres are undeveloped;

· included in our undeveloped acreage are approximately 531,950 Marcellus acres in Pennsylvania, New York and West Virginia, of which approximately 266,100 acres are located in our core Marcellus Shale position in southwestern Pennsylvania;

· we drilled 126 gross wells (including 42 Marcellus Shale wells), during the six months ended June 30, 2009, on behalf of our investment partnerships;

· we have drilled 153 vertical and 10 horizontal gross Marcellus Shale wells to date, of which 140 vertical and 5 horizontal Marcellus Shale wells have been successfully completed and have been turned on line and are producing;

· of the 153 Marcellus Shale wells we drilled to date, we have completed 42 wells using the multi-frac technique we developed with successful results;

· we connected 179 gross wells to gathering systems during the six months ended June 30, 2009; and

· we drilled and participated in 21 horizontal wells in the Chattanooga Shale of eastern Tennessee to date. We have leased approximately 137,000 gross acres (106,000 net undeveloped) in this shale area.

In our Michigan gas and oil operations:

· we own direct and indirect working interests in approximately 2,488 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 57.9 Mmcfe per day and 58.0 Mmcfe per day for the three months and six months ended June 30, 2009;

· we have leased approximately 344,400 gross (272,200 net) acres, of which approximately 35,800 gross (28,100 net) acres are undeveloped; and

· we drilled 24 gross wells (19 net wells) during the six months ended June 30, 2009.

In our Indiana gas and oil operations:

· we own direct and indirect working interests in approximately 16 gross producing gas and oil wells;

· our net daily production was 0.2 Mmcfe per day for both the three months and six months ended June 30, 2009;

· we have leased approximately 244,100 gross (118,200 net) acres, of which approximately 239,100 gross (114,400 net) acres are undeveloped; and

· we drilled 16 gross wells (14 net wells) during the six months ended June 30, 2009.

In our partnership management business:

· our investment partnership business includes equity interests in 95 investment partnerships and a registered broker-dealer which acts as the dealer manager of our investment partnership offerings.

· since July 2008, we have raised $560.0 million in investor funds, including $122.8 million raised in the three months ended June 30, 2009 for our most recent investment partnership, Atlas Resources Public #18-2009(B) L.P.

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 the cash distributions we expect to pay to our unitholders, prior to the establishment of any cash reserves (see "Recent Developments" and "Cash Distributions"). 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 netincome, our most directly comparable GAAP performance
Measure, to EBITDA, Adjusted EBITDA and distributable cash flow for each of the periods presented:

                                             Three Months Ended           Six Months Ended
                                                  June 30,                    June 30,
                                             2009          2008          2009          2008
Reconciliation of net income to non-GAAP
measures:
Net income                                 $  12,246     $  38,376     $  37,849     $  75,940
Income attributable to non-controlling
interests                                        (15 )         (17 )         (30 )         (38 )
Depreciation and amortization                 27,275        22,948        55,303        44,758
Interest expense                              15,124        14,563        28,108        27,868
EBITDA                                        54,630        75,870       121,230       148,528
Adjustment to reflect cash impact of
derivatives(1)                                29,019         2,920        30,623         7,948
Non-cash loss on sale of assets                4,250             -         4,250             -
Non-cash compensation expense                  1,453         1,339         2,981         2,659
Adjusted EBITDA                            $  89,352     $  80,129     $ 159,084     $ 159,135
Interest expense                             (15,124 )     (14,563 )     (28,108 )     (27,868 )
Amortization of deferred financing costs
(included within interest expense)             1,002           742         1,667         1,512
Maintenance capital expenditures             (12,975 )     (12,975 )     (25,950 )     (25,950 )
Distributable cash flow                    $  62,255     $  53,333     $ 106,693     $ 106,829


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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 immediate plans to access additional debt or equity in the capital markets (see "Subsequent Events"), 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. We do not believe our liquidity has been materially affected by recent events in the financial markets and we will continue to monitor events and circumstances which may affect it in the near future.

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 June 30, 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 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 June 30, 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" and "Subsequent Events") 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 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 and six months ended June 30, 2009 and 2008, respectively (in thousands, except for production per day):

                                     Three Months Ended           Six Months Ended
                                          June 30,                    June 30,
                                      2009          2008         2009          2008
         Production:(1)
         Appalachia:(2)
         Natural gas (MMcf)             3,710        2,936         7,302        5,692
         Oil (000's Bbls)                  43           38            78           74
         Total (MMcfe)                  3,968        3,164         7,770        6,136
         Michigan/Indiana:
         Natural gas (MMcf)             5,284        5,439        10,526       10,813
         Oil (000's Bbls)                   1            1             2            2
         Total (MMcfe)                  5,290        5,445        10,538       10,825
         Total:
         Natural gas (MMcf)             8,994        8,374        17,828       16,504
         Oil (000's Bbls)                  44           39            80           76
         Total (MMcfe)                  9,258        8,608        18,308       16,960

         Production per day: (1)
         Appalachia:(2)
         Natural gas (Mcf/d)           40,770       32,259        40,341       31,272
         Oil (Bbl)                        471          419           432          409
         Total (Mcfe/d)                43,596       34,773        42,933       33,726
         Michigan/Indiana:
         Natural gas (Mcf/d)           58,058       59,767        58,154       59,411
         Oil (Bbl)                         11           15             9           11
         Total (Mcfe/d)                58,124       59,857        58,208       59,477
         Total:
         Natural gas (Mcf/d)           98,828       92,026        98,495       90,683
         Oil (bpd)                        482          434           441          420
         Total (Mcfe/d)               101,720       94,630       101,141       93,203


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