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 2007. 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

We are a limited liability company focused on the development and production of natural gas and, to a lesser extent, oil principally in northern Michigan and the Appalachian Basin. In northern Michigan, we drill wells for our own account. In the Appalachian Basin, we sponsor and manage tax-advantaged investment partnerships, or the Partnerships, in which we coinvest, to finance the exploitation and development of our acreage.

We were formed in June 2006 to own and operate substantially all of the natural gas and oil assets and the investment partnership management business of Atlas America. Atlas America has been involved in the energy industry since 1968, expanding its operations in 1998 when it acquired The Atlas Group, Inc. and in 1999 when it acquired Viking Resources Corporation, both engaged in the development and production of natural gas and oil and the sponsorship of investment partnerships. We are managed by Atlas Energy Management, a wholly-owned subsidiary of Atlas America.

We operate three business segments:

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

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

As of and for the three months and nine months ended September 30, 2008, we had the following key assets and highlights:

In our Appalachia gas and oil operations:

· we own direct and indirect working interests in approximately 9,057 gross producing gas and oil wells, of which we operate approximately 85%;

· we own overriding royalty interests in approximately 627 gross producing gas and oil wells;

· net daily production was 35.7 Mmcfe per day and 34.4 Mmcfe per day for the three months and nine months ended September 30, 2008, respectively;

· we lease approximately 931,000 gross (885,000 net) acres, of which approximately 623,000 gross (616,000 net) acres are undeveloped;

· included in our gross undeveloped acreage, we control approximately 555,000 Marcellus acres in Pennsylvania, New York and West Virginia, of which approximately 271,000 of these acres are located in our core Marcellus Shale position in southwestern Pennsylvania;

· we have identified 3,739 geologically favorable shallow drilling locations in the Appalachian Basin;

· our partnership management business in Appalachia includes our equity interests in 93 investment partnerships and a registered broker-dealer which acts as the dealer-manager of our investment partnership offerings;

· we drilled 81.5 net vertical and one horizontal Marcellus Shale wells during the nine months ended September 30, 2008; and,

· we drilled and participated in 2 successful horizontal wells in the Chattanooga Shale of eastern Tennessee.

In our Michigan-Indiana gas and oil operations:

· we own direct and indirect working interests in approximately 2,416 gross producing gas and oil wells, of which we operate approximately 76%;

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

· net daily production was 60.5 Mmcfe per day and 59.8 Mmcfe per day for the three months and nine months ended September 30, 2008, respectively;

In Michigan:

· we lease approximately 346,600 gross (272,200 net) acres, of which approximately 44,200 gross (33,600 net) acres, are undeveloped; and

· we drilled 135 gross wells (111 net wells) during the nine months ended September 30, 2008.

In Indiana:

· we lease approximately 114,000 net acres, all of which are undeveloped.

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, EBITDA, Adjusted EBITDA and distributable cash flow. These measures are not calculated or presented in accordance with generally accepted accounting principles, or GAAP.

Adjusted EBITDA is a significant performance metric used by our management to indicate (prior to the establishment of any cash reserves) the cash distributions we expect to pay to our unit holders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDA is also used as a quantitative standard 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.

Distributable cash flow is intended to reflect the level of cash that we can expect to be available for distribution to all unit holders. 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 (in thousands):

                                        Three Months Ended         Nine Months Ended
                                          September 30,              September 30,
                                        2008          2007         2008         2007
Reconciliation of net income to
non-GAAP measures:
Net income                           $    38,180   $   31,612   $  114,082   $   93,218
Depreciation and amortization             23,586       19,013       68,344       31,688
Interest expense                          14,798       13,032       42,666       14,972
EBITDA                                    76,564       63,657      225,092      139,878
Adjustment to reflect cash impact
of derivatives(1)                          2,560        6,503       10,508        6,503
Gain on mark-to-market
derivatives(2)                                 -            -            -      (26,257 )
Non-recurring derivative fees                  -            -            -        3,873
Non-cash compensation expense              1,362        1,294        4,021        3,382
Adjusted EBITDA                      $    80,486   $   71,454   $  239,621   $  127,379
Interest expense                         (14,798 )    (13,032 )    (42,666 )    (14,972 )
Amortization of deferred financing
costs
(included within interest expense)           670          360        2,182          858
Maintenance capital expenditures         (12,975 )    (12,975 )    (38,925 )    (30,475 )
Distributable cash flow              $    53,383   $   45,807   $  160,212   $   82,790


_______________

(2)Represents ineffective non-cash gains related to the change in value of derivative contracts associated with the acquisition of AGO on June 29, 2007.

RECENT DEVELOPMENTS

Acquisition of Indiana Assets

Beginning July 1, 2008 through October 31, 2008, we began establishing a position in the New Albany Shale in southwestern Indiana totaling approximately $15.0 million. We acquired 114,000 net undeveloped acres and entered into a farm-out agreement that will give us rights to an additional 78,000 net undeveloped acres. These leases are located in Sullivan, Knox, Greene, Owen, Clay and Lawrence counties, Indiana. In addition, we acquired a 50% undivided interest in a gas gathering system with related compression and fluid disposal facilities in Sullivan County.

Agreement with Miller Petroleum, Inc.

On June 19, 2008, we entered into a $19.6 million agreement with Miller Petroleum, Inc. ("Miller") whereby Miller assigned (i) 100% of the working interest in its oil and gas leases comprising 27,620 acres in the Koppers North and Koppers South section of Campbell County, Tennessee, (ii) 100% of the working interest in 8 existing wells, and (iii) 100% of the working interest in its oil and gas leases comprising 1,952 acres adjacent to the Koppers acreage. The agreement also provides Miller with an option to participate up to 25% in up to 10 wells to be drilled on the assigned acreage. In addition, we entered into two agreements with Miller whereby (i) Miller will provide drilling services to us for a two-year term and (ii) we or our affiliates will transport and process natural gas for Miller from its existing wells.

Public Equity Offering

On May 16, 2008, we sold 2,070,000 of our Class B common units at $41.50 per common unit in a public offering with UBS Investment Bank and Wachovia Securities acting as joint book-running managers and underwriters. The net proceeds of approximately $82.5 million (after underwriting expenses of $3.4 million) were used to repay a portion of our outstanding balance under our revolving credit facility. The increased borrowing capacity will be used to fund additional acreage acquisitions and accelerated development of the Marcellus Shale as well as further development of our other drilling programs and lease acquisition activities.

Senior Unsecured Notes

In January 2008, we completed a private placement of $250.0 million of Senior Notes to institutional buyers pursuant to Rule 144A under the Securities Act of 1933. On May 5, 2008, we issued an additional $150.0 million of 10.75% senior unsecured notes ("Senior Notes") due 2018 at 104.75% of par to yield 9.85% to the par call on February 1, 2016. We intend to treat both the May 2008 and the January 2008 issuances as a single class of debt securities. We used the net proceeds of $402.7 million (including accrued interest paid of $4.7 million and net underwriting fees of $9.2 million) to reduce the balance outstanding on our revolving credit facility.

Interest on the Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year. The Senior Notes are redeemable at any time at specified redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, before February 1, 2011, we may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The Senior Notes are also subject to repurchase by us 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 we do not reinvest the net proceeds within 360 days.

The Senior Notes are junior in right of payment to our secured debt, including our obligations under our credit facility. The indenture governing the 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.

Private Equity Offering

On May 7, 2008, we sold 600,000 Class B common units to Atlas America in a private placement at $42.00 per common unit, increasing Atlas America's ownership of our Class B common units to 29,952,996 common units or 46.3%. The proceeds of $25.2 million were used to repay a portion of our outstanding balance under our revolving credit facility.

Interest Rate Swap

In January 2008, we entered into an interest rate swap contract for $150.0 million, swapping the floating rate incurred on a portion of our existing senior secured credit facility for a three-year fixed rate of 3.11%. The interest rate swap contract will mature in January 2011.

Partnership Management

We generally fund our drilling activities, other than those of our Michigan business unit, 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 investment partnerships. We have budgeted to raise between $450.0 and $500.0 million in fiscal 2008 and have raised $238.4 million in the nine months ended September 30, 2008. During the nine months ended September 30, 2008, our investment partnerships invested $414.5 million in drilling and completing wells, of which we contributed $110.6 million.

Acquisition of DTE Antrim assets

On June 29, 2007, we acquired DTE Gas & Oil Company, now known as Atlas Gas & Oil Company, or AGO, from DTE Energy Company ("DTE" -NYSE:DTE) for approximately $1.3 billion in cash. The assets acquired, which consisted principally of interests in natural gas wells in the Antrim Shale, are the basis for the formation of our Michigan gas and oil operations. We funded the purchase price from $713.9 million borrowed under our credit facility and the issuance of 24,001,009 Class B common units at $25.00 per unit for proceeds of $597.5 million. We intend to continue to expand our business through strategic acquisitions and internal growth projects that increase distributable cash flow.

Credit Facility

Upon the closing of the DTE Gas & Oil acquisition, we replaced our credit facility with a new 5-year, $850.0 million credit facility. As of September 30, 2008, the credit facility has a current borrowing base of $697.5 million, which will be redetermined semi-annually based on changes in our oil and gas reserves. The facility is secured by our assets and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR rate plus the applicable margin, elected at our option. The base rate for any day equals the higher of the federal funds rate plus 0.50% or the JPMorgan prime rate. 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. The applicable margin ranges from 0.0% to 0.75% for base rate loans and 1.00% to 1.75% for LIBOR loans. At September 30, 2008, the weighted average interest rate on outstanding borrowings under our credit facility was 4.9%.

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.

Currently, there is an 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 and raising additional capital, and an increase in the volatility of the market price of our common unit. 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.

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Historically, natural gas and oil prices have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital.

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.

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 "Item 3: Quantitative and Qualitative Disclosures About Market Risk."

Natural Gas Supply and Outlook

We believe that current natural gas prices will continue to cause relatively high levels of natural gas-related drilling in the United States 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. The areas in which we operate are experiencing significant drilling activity as a result of recent high natural gas prices, new increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques.

While we anticipate continued high levels of exploration and production activities 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 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 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.

Impact of Inflation

Inflation in the United States did not have a material impact on our results of operations for the three-year period ended December 31, 2007. If inflation occurs in the future, to the extent permitted by competition and our existing agreements, we have and will continue to pass along increased costs to our investors and customers in the form of higher fees. For further discussion, see -"CHANGES IN PRICES AND INFLATION".

RESULTS OF OPERATIONS

GAS AND OIL PRODUCTION

The following table sets forth information relating to our production segments
during the periods indicated:
                                        Three Months Ended       Nine Months Ended
                                          September 30,            September 30,
                                         2008         2007       2008        2007
Production revenues (in thousands):
Gas (1)                               $    77,253   $ 60,302   $ 224,345   $ 102,439
Oil                                   $     3,956   $  2,938   $  12,014   $   7,357
Production volume:(2)
Appalachia
Gas (Mcf/day) (1)                          33,228     29,324      31,929      26,220
Oil (Bbls/day)                                413        443         410         422
Michigan
Gas (Mcf/day)                              60,436     59,304      59,755      59,325
Oil (Bbls/day)                                 11          3          11           3
Total (Mcfe/day)                           96,209     91,304      94,210      88,095
Average sales prices:
Gas (per Mcf) (3) (6)                 $      9.26   $   8.19   $    9.35   $    8.55
Oil (per Bbl)(5)                      $    101.34   $  71.63   $  104.15   $   63.75
Production costs:(7)
Lease operating expenses
As a percent of production revenues             9 %       10 %         9 %        10 %
Per Mcfe                              $       .85   $    .74   $     .82   $     .78
Taxes - Per Mcfe                      $       .41   $    .25   $     .39   $     .17
Total production costs per Mcfe       $      1.26   $    .99   $    1.21   $     .95


Depletion per Mcfe                    $      2.57   $   2.19   $    2.55   $    2.24


____________

(2) 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.

(3) Our average sales price for gas before the effects of financial hedging was $10.49 and $6.55 per Mcf for the three months ended September 30, 2008 and 2007, respectively and $10.03 and $7.12 per Mcf for the nine months ended September 30, 2008 and 2007, respectively.

(4) We acquired AGO on June 29, 2007, and production volume from these assets has only been included from that date.

(5) Our average sales price for oil before the effects of financial hedging were $106.94 and $108.09 per Bbl for the three months and nine months ended September 30, 2008. There were no oil financial hedges for the three months and nine months ended September 30, 2007.

(6) Includes $2.6 million and $6.5 million in derivative proceeds, which were not included as gas revenue in the three months ended September 30, 2008 and 2007, respectively and $10.5 million and $6.5 million for the nine months ended September 30, 2008 and 2007, respectively.

(7) Production costs consist of labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, insurance, production overhead, and production taxes.

Three Months Ended September 30, 2008 Compared to the Three Months Ended September 30, 2007

Our natural gas revenues were $77.3 million in the three months ended September 30, 2008, an increase of $17.0 million (28%) from $60.3 million in the three months ended September 30, 2007. The $17.0 million increase in natural gas revenues consisted of $4.2 million attributable to increases in natural gas sales production volumes, and $12.8 million attributable to increases in natural gas sales prices (after the effect of financial hedges).

The increase in our gas production volumes of 463,000 Mcfs was attributable to an increase of 104,000 Mcfs (22%) produced in Michigan from our acquisition of AGO which we acquired on June 29, 2007, and an increase of 359,000 Mcfs (78%) in our Appalachian natural gas production volumes due to production associated with wells we drilled for our investment partnerships in the twelve months ended September 30, 2008. We believe that gas volumes will continue to be favorably impacted in the remainder of 2008 with the contribution of our Michigan business unit and as ongoing projects to extend and enhance the gathering systems of Atlas Pipeline are completed and wells drilled are connected in these areas of expansion.

Our oil revenues were $3.9 million in the three months ended September 30, 2008, an increase of $1.0 million (35%) from $2.9 million during the three months ended September 30, 2007. The increase resulted from a 41% increase in the average sales price of oil, partially offset by a 5% decrease in production volumes. The $1.0 million increase consisted of $1.2 million attributable to increases in sales prices (after the effect of financial hedges), and $202,000 attributable to volume decreases, as we primarily drill for natural gas, rather than oil.

Our Appalachian production costs were $7.5 million in the three months ended September 30, 2008, an increase of $2.8 million (60%) from $4.7 million in the three months ended September 30, 2007. The increase includes a $819,000 increase attributable to labor, water hauling and maintenance costs associated with an increase in the number of wells we own from the prior year period and a $1.9 million increase in transportation fees charged to our wells connected to Atlas Pipeline's gathering system due to an increase in volumes produced and prices received as compared to the prior year period.

Our Michigan production costs were $8.8 million in the three months ended . . .