**UNITED
      STATES**


**SECURITIES
      AND EXCHANGE COMMISSION**


**Washington,
      D.C. 20549**


**FORM
      10-K**


(Mark
      One)


**x**  **ANNUAL
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
      1934**





For
      the
      fiscal year ended December 31, 2007


**OR**





** ̈**  **TRANSITION
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE** **ACT
      OF 1934**


For
      the
      transition period from _________ to __________





Commission
      file number: 1-33193





**ATLAS
      ENERGY RESOURCES, LLC**


(Exact
      name of registrant as specified in its charter)





**Delaware**
            **75-3218520**(State
                or other jurisdiction or
            (I.R.S.
                Employerincorporation
                or organization)
            Identification
                No.)**Westpointe
                Corporate Center One****1550
                Coraopolis Heights Road****Moon
                Township, PA**
            **15108**(Address
                of principal executive offices)
            Zip
                CodeRegistrant’s
                telephone number, including area code:
            **412-262-2830**Securities
                registered pursuant to Section 12(b) of the Act:





Title
                of each class
            Name
                of each exchange on which registered**Common
                units representing Class B**
            **New
                York Stock Exchange****limited
                liability company interests**





Securities
      registered pursuant to Section 12(g) of the Act: None


Title
      of
      class





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


Yes x  No  ̈





Indicate
      by check mark if the registrant is not required to file reports pursuant to
      Section 13 or Section 15(d) of the Act.


Yes  ̈  No x





Indicate
      by check mark whether the registrant (1) has filed all reports required to
      be
      filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
      the
      preceding 12 months (or for such shorter period that the registrant was required
      to file such reports), and (2) has been subject to such filing requirements
      for
      the past 90 days. Yes x  No  ̈





Indicate
      by check mark if disclosure of delinquent filers pursuant to Item 405 of
      Regulation S-K is not contained herein, and will not be contained, to the best
      of registrant's knowledge, in definitive proxy or information statements
      incorporated by reference in Part III of this Form 10-K or any amendment to
      this
      Form 10-K.   ̈





Indicate
      by check mark whether the registrant is a large accelerated filer, an
      accelerated filer, or a non-accelerated filer. See definition of “accelerated
      filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (Check
      one):





Large
                accelerated filer ̈
            Accelerated
                filerx
            Non-accelerated
                filer ̈





Indicate
      by check mark whether the registrant is a shell company (as defined in Rule
      12b-2 of the Act). Yes  ̈ No x





The
      aggregate market value of common units held by non-affiliates of the registrant
      on June 30, 2007 was approximately $500.7 million.





DOCUMENTS
      INCORPORATED BY REFERENCE: None










**ATLAS
      ENERGY RESOURCES, LLC AND SUBSIDIARIES**


**INDEX
      TO ANNUAL REPORT**


**ON
      FORM 10** **-** **K**





Page**PART
                I**
            Item
                1:
            Business
            4Item
                1A:
            Risk
                Factors
            20Item
                1B:
            Unresolved
                Staff Comments
            33Item
                2:
            Properties
            33Item
                3:
            Legal
                Proceedings
            37Item
                4:
            Submission
                of Matters to a Vote of Security Holders
            37**PART
                II**
            Item
                5:
            Market
                for Registrant's Common Equity and Related Shareholder Mattersand Issuer Purchases of Equity Securities
            38Item
                6:
            Selected
                Financial Data
            39Item
                7:
            Management’s
                Discussion and Analysis of Financial Condition and****Results
                of Operations
            42Item
                7A:
            Quantitative
                and Qualitative Disclosures about Market Risk
            62Item
                8:
            Financial
                Statements and Supplementary Data
            65Item
                9:
            Changes
                in and Disagreements with Accountants on Accounting andFinancial
                Disclosure
            102Item
                9A:
            Controls
                and Procedures
            102Item
                9B:
            Other
                Information
            104**PART
                III**
            Item
                10:
            Directors
                and Executive Officers of the Registrant
            104Item
                11:
            Executive
                Compensation
            107Item
                12:
            Security
                Ownership of Certain Beneficial Owners and Management
            117Item
                13:
            Certain
                Relationships and Related Transactions
            119Item
                14:
            Principal
                Accounting Fees and Services
            120**PART
                IV**
            Item
                15:
            Exhibits
                and Financial Statement Schedules
            121**SIGNATURES**
            123




3





*The
      matters discussed within this report include forward-looking statements. These
      statements may be identified by the use of forward-looking terminology such
      as
“anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,”
“may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the
      negative thereof or other variations thereon or comparable terminology. In
      particular, statements about our expectations, beliefs, plans, objectives,
      assumptions or future events or performance contained in this report are
      forward-looking statements. We have based these forward-looking statements
      on
      our current expectations, assumptions, estimates, and projections. While we
      believe these expectations, assumptions, estimates, and projections are
      reasonable, such forward-looking statements are only predictions and involve
      known and unknown risks and uncertainties, many of which are beyond our control.
      These and other important factors may cause our actual results, performance
      or
      achievements to differ materially from any future results, performance or
      achievements expressed or implied by these forward-looking
      statements.*





*Factors
      that could cause actual results to differ from those implied by the
      forward-looking statements in this report are more fully described under Item
      1A, “Risk Factors” in this report. Given these risks and uncertainties, you are
      cautioned not to place undue reliance on these forward-looking statements.
      The
      forward-looking statements included in this report are made only as of the
      date
      hereof. We do not undertake and specifically decline any obligation to update
      any such statements or to publicly announce the results of any revisions to
      any
      of these statements to reflect future events or developments.*





*We
      commenced operations in December 2006. References in this report to operations
      before that date are to our predecessor, Atlas America E&P Operations. In
      June 2006, Atlas America E&P Operations changed its fiscal year end from
      September 30 to December 31 and, therefore, information is included in this
      report for the year ended September 30, 2005, the three-month transition period
      ended December 31, 2005, and the years ended December 31, 2006 and 2007.*





**PART
      I**





**ITEM
      1:**  **BUSINESS**





**General**





We
      are an
      independent developer and producer of natural gas and oil, with operations
      in
      northern Michigan’s Antrim Shale and the Appalachian Basin. We are a leading
      sponsor and manager of tax-advantaged direct investment natural gas and oil
      partnerships in the United States. We believe we have established a strong
      track
      record of growing our reserves, production and cash flows through a balanced
      mix
      of natural gas and oil exploitation and development and sponsorship of
      investment partnerships. As of December 31, 2007, our es timated
      proved reserves were 896.7 Bcfe, including the reserves net to our equity
      interest in our investment partnerships. Of our reserves, approximately 68%
      are
      proved developed and approximately 99% are natural gas. For the year ended
      December 31, 2007, our average daily production was approximately 89.5 Mmcfe
      per
      day and we
      generated revenues of $577.9 million and net income of $117.5
      million.




In
      Michigan, as of December 31, 2007 we had reserves of approximately 666.8 Bcfe
      and our average daily production for the year ended December 31, 2007 was
      approximately 59.8 Mmcfe per day.





Since
      2003, we have grown our Appalachian reserves and production at compound annual
      growth rates of approximately 8%. In Appalachia, as of December 31, 2007, we
      had
      proved reserves of approximately 229.9 Bcfe and our average daily production
      for
      the year ended December 31, 2007 was approximately 29.7 Mmcfe per day. We have
      experienced drilling success rates of approximately 99% over the last four
      years. We fund our Appalachian operations through sponsoring and managing
      investment partnerships. We generate both upfront and ongoing fees from the
      drilling, production, servicing, and administration of our Appalachian wells
      in
      these partnerships.





4





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,
      Inc. (Nasdaq: ATLS). 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, Inc., a wholly-owned subsidiary of Atlas
      America. On June 29, 2007, we acquired DTE Gas & Oil Company from DTE Energy
      Company (NYSE: DTE), which we refer to as DTE, for $1.273 billion in
      cash.




As
      of and
      for the year ended December 31, 2007, we had the following key
      assets:




In
      our
      Appalachia gas and oil operations:




·
            proved
                reserves of 229.9 Bcfe including the reserves net to our equity interest
                in our investment partnerships and our direct interests in producing
                wells;




·
            direct
                and indirect working interests in approximately 7,722 gross producing
                gas
                and oil wells;




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




·
            net
                daily production of 29.7 Mmcfe per
                day;




·
            approximately
                797,800 gross (697,300 net) acres, of which approximately 508,600
                gross
                (501,400 net) acres, are undeveloped;
                and




·
            an
                interest in a joint venture that gave us the right to drill up to
                77
                additional net wells before March 31, 2008 on approximately 212,000
                acres
                in Tennessee.




In
      our
      Michigan gas and oil operations:




·
            proved
                reserves of 666.8 Bcfe




·
            direct
                and indirect working interests in approximately 2,292 gross producing
                gas
                and oil wells;




·
            overriding
                royalty interests in approximately 78 gross producing gas and oil
                wells;




·
            net
                daily production of 59.8 Mmcfe per day;
                and




·
            approximately
                357,000 gross (285,100 net) acres, of which approximately 63,000
                gross
                (53,300 net) acres, are
                undeveloped.




In
      our
      partnership management business:




·
            our
                investment partnership business, which includes equity interests
                in 92
                investment partnerships and a registered broker-dealer which acts
                as the
                dealer-manager of our investment partnership offerings;
                and




·
            managed
                total proved reserves of 503.7
                Bcfe.




For
      the
      year ended December 31, 2007, we produced 89.5 Mcfe/d, which includes the
      proportionate share of production from our investment partnerships as well
      as
      our direct interests in producing wells .





**Acquisition
      of DTE Antrim assets.** On
      June
      29, 2007, we acquired DTE Gas & Oil, now known as Atlas Gas & Oil
      Company, or AGO, from DTE Energy Company (“DTE” -NYSE:DTE) for $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 gas and oil
      operations. We funded the purchase price from borrowings under a new credit
      facility with an initial borrowing base of $850.0 million that matures in June
      2012. We intend to continue to expand our business through strategice
      acquisitions and internal growth projects that increase distributable cash
      flow.





**Private
      equity offering** .
      We
      financed a portion of the purchase price for the DTE Gas & Oil acquisition
      with the proceeds of a private offering, completed on June 29, 2007. We raised
      net proceeds of $597.5 million through the sale of 7,298,181 Class B common
      units and 16,702,828 Class D units at a weighted average price of $25.00. On
      November 10, 2007, the Class D units automatically converted to common units
      on
      a one-for-one basis. On February 20, 2008, a registration statement with the
      Securities and Exchange Commission covering the resale of these units went
      effective.




5




**New
      credit facility** .
      Upon
      the closing of the DTE Gas & Oil acquisition, we replaced our credit
      facility with a new 5-year, credit facility with an initial borrowing base
      of
      $850.0 million. The credit facility has a current borrowing base of $672.5
      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% of 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 1.25% for base rate
      loans
      and 1.00% to 2.25% for LIBOR loans. At December 31, 2007, the weighted average
      interest rate on outstanding borrowings was 7.2%.





**Recent
      Developments**





**Private
      debt offering** . In
      January 2008, we issued $250.0 million of 10-year, 10.75% senior unsecured
      notes
      due 2018. We used the proceeds of the note offering to reduce the balance
      outstanding on our senior secured 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 certain 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 its assets.





**New
      interest rate swap** .
      In
      January 2008, we entered into an interest rate swap contract for $150 million,
      swapping the floating rate incurred on a portion of our existing senior secured
      credit facility for a fixed rate of approximately 4.36%, which includes an
      initial margin of 1.25% over the three year fixed swap rate of 3.11%. The
      interest rate swap contract will mature in January 2011. Combining the 4.36%
      interest rate on the new swap and the 10.75% interest rate on the new senior
      notes, we have fixed $400 million of our outstanding debt at a weighted average
      interest rate of approximately 8.35%.




**An** **trim
      Shale Overview**





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





Antrim
      Shale wells produce substantial volumes of water, especially during the early
      production stages, which must be removed from the formation to initiate gas
      production. The gas is transported from the well to a centrally located
      separation, compression and dehydration facility, where water is separated
      from
      it and disposed of, usually in a dedicated salt water disposal well to minimize
      water disposal costs.




**Appalachian
      Basin Overview**





The
      Appalachian Basin includes the states of Kentucky, Maryland, New York, Ohio,
      Pennsylvania, Virginia, West Virginia and Tennessee. It is the most mature
      oil
      and gas producing region in the United States, having established the first
      oil
      production in 1860. Because the Appalachian Basin is located near the
      energy-consuming regions of the mid-Atlantic and northeastern United States,
      Appalachian producers have historically sold their natural gas at a premium
      to
      the benchmark price for natural gas on the NYMEX. For the twelve months ended
      December 31, 2007, the average premium over NYMEX for natural gas delivered
      to our primary delivery points in the Appalachian Basin was $.337 per MMBtu.




6





During
      the first several years of production, Appalachian Basin wells generally
      experience higher initial production rates and decline rates, which are followed
      by an extended period of significantly lower production rates and decline
      rates.





Shallow
      reserves in the Appalachian Basin are typically in blanket formations and have
      a
      high degree of step-out development success; that is, as development progresses,
      reserves from newly completed wells are reclassified from the proved undeveloped
      to the proved developed category and additional adjacent locations are added
      to
      proved undeveloped reserves. As a result, the cumulative amount of total proved
      reserves tends to increase as development progresses. Wells in the Appalachian
      Basin generally produce little or no water, contributing to a low cost of
      operation. In addition, most wells produce dry natural gas, which does not
      require processing.





**Gas
      and Oil Production**





At
      December 31, 2007, we owned interests in approximately 10,719 gross wells,
      of
      which we operated approximately 8,829. During the year ended December 31, 2007,
      we drilled 1,232 gross wells, 99% of which were successful in producing natural
      gas in commercial quantities.




**Appalachia**





In
      Appalachia, as of December 31, 2007, we owned interests in approximately 8,349
      gross wells, of which we operated approximately 7,091. During the year ended
      December 31, 2007, average daily production from our wells was approximately
      29.7 Mmcfe/d. During the year ended December 31, 2007, we drilled 1,117 gross
      (381.6 net) wells, 99% of which were successful in producing natural gas in
      commercial quantities. As of December 31, 2007, we had approximately 797,800
      gross (697,300 net) acres, of which approximately 508,600 gross (501,400 net)
      acres are undeveloped. In September 2004, we expanded operations into Tennessee
      through a joint venture with Knox Energy, LLC that gave us an exclusive right
      to
      drill wells through December 31, 2007 on approximately 212,000 acres owned
      by
      Knox Energy. This agreement was extended through March 31, 2008; we are
      currently negotiating terms of a further joint venture agreement with Knox.
      As
      of December 31, 2007, we had drilled 321.0 net wells under this agreement.
      In
      addition, as of that date we had identified over 580 proved undeveloped drilling
      locations and approximately 2,600 additional potential drilling locations on
      our
      Appalachia acreage and the Tennessee joint venture acreage.





In
      the
      fourth quarter of 2006, we and our investment partnerships began drilling wells
      to multiple pay zones, including the Marcellus Shale of Western Pennsylvania.
      The Marcellus Shale is a black, organic rich shale formation located at depths
      between 6,000 and 8,500 feet and ranges in thickness from 75 to 150 feet on
      our
      acreage in Western Pennsylvania. As
      of
      February 20, 2008, we control approximately 483,000 Marcellus Shale acres in
      Pennsylvania, New York and West Virginia, and we continue to expand our
      position. As of that date, we had drilled
      27 vertical wells and are currently producing 21 wells into a pipeline. The
      remaining 6 wells are scheduled to be completed and turned into line shortly. We
      are
      currently focused on our approximately 224,000 existing Marcellus acres in
      southwestern Pennsylvania, where we have drilled all but one of our Marcellus
      wells and have now, through this drilling, largely delineated our acreage.
      Almost all of this acreage in southwestern Pennsylvania has ample pipeline
      capacity that is controlled by our affiliate, Atlas Pipeline Partners, L.P.
      (NYSE: APL). Wright & Company, Inc., our independent petroleum engineering
      consultants, has evaluated our first 14 southwestern Pennsylvania Marcellus
      wells and assigned proved reserves that averaged 961 million cubic feet ("Mmcf")
      per well. These wells included five initial wells where we utilized. For the
      nine subsequent wells where we implemented our advanced drilling, completion
      and
      production techniques, Wright & Company assigned reserves that averaged 1.3
      billion cubic feet ("Bcf") per well and were as high as 1.8 Bcf. Since
      implementing the advanced drilling, completion and production techniques, our
      initial daily rates (24 hours) into a pipeline have averaged 1.3 Mmcf per day
      in
      southwestern Pennsylvania. We plan to drill and complete at least 150 vertical
      Marcellus Shale wells over the next 18 months.





**Michigan**





In
      Michigan, as of December 31, 2007, we owned interests in approximately 2,370
      gross wells, of which we operated approximately 1,738. During the six months
      ended December 31, 2007, average daily production from our wells was
      approximately 59.8 Mmcfe/d. During the six months ended December 31, 2007,
      we
      have drilled 102 gross (88.6 net) wells, 100% of which were successful in
      producing natural gas in commercial quantities. As of December 31, 2007, we
      had
      approximately 357,000 gross (285,100 net) acres, of which approximately 63,000
      gross (53,300 net) acres are undeveloped.




7





For
      information concerning our natural gas and oil production, see Item 2:
‘‘Properties.”





**I** **nvestment
      Partnerships**





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 partnerships. We raised
      $363.3 million in the year ended December 31,
      2007
      and $218.5 million in fiscal 2006. During the year ended December 31, 2007,
      our
      investment partnerships invested $423.1 million in drilling and completing
      wells, of which we contributed $137.6 million. During fiscal 2006, our
      investment partnerships invested $272.2 million in drilling and completing
      wells, of which we contributed $73.6 million.





We
      generally structure our investment partnerships so that, upon formation of
      a
      partnership, we coinvest in and contribute leasehold acreage to it, enter into
      drilling and well operating agreements with it and become its managing general
      partner. In addition to providing capital for our drilling activities, our
      investment partnerships are a source of fee-based revenues, which are not
      directly dependent on natural gas and oil prices. We receive an interest in
      our
      investment partnerships proportionate to the amount of capital and the value
      of
      the leasehold acreage we contribute, typically 27% to 30% of the overall
      capitalization in a particular partnership. We also receive an additional
      interest in each partnership, typically 7%, for which we do not make any
      additional capital contribution.





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





·
            *Well
                construction and completion.*For
                each well that is drilled by an investment partnership, we receive
                a 15%
                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 of
                approximately $15,000 ($45,000 for Marcellus wells). Additionally,
                the
                partnership pays us a monthly per well administrative fee of $75
                for the
                life of the well. Because we coinvest in the partnerships, the net
                fee
                that we receive is reduced by our proportionate interest in the
                well.





·
            *Well
                services.*Each
                partnership pays us a monthly per well operating fee, currently $100
                to
                $477, for the life of the well. Because we coinvest in the partnerships,
                the net fee that we receive is reduced by our proportionate interest
                in
                the well.





·
            *Gathering.*Historically,
                each partnership paid us a gathering fee which was typically insufficient
                to cover all of the gathering fees due to Atlas Pipeline. Since the
                completion of our initial public offering in December 2006, pursuant
                to
                the terms of our contribution agreement with Atlas America, our gathering
                revenues and costs within our partnership management segment net
                to $0.
                Please read “− Other Agreements with Atlas America and Its Affiliates −
                Contribution Agreement.” We also pay our proportionate share of gathering
                fees based on our percentage interest in the well, which are included
                in
                gas and oil production expense.





We
      generally agree to subordinate up to 50% of our share of production revenues
      to
      specified returns to the investor partners, typically 10% per year for the
      first
      five years of distributions. We have not subordinated our share of revenues
      from
      any of our investment partnerships since March 2005, but did subordinate $91,000
      in fiscal 2005, $335,000 in fiscal 2004 and $362,000 in fiscal 2003. We do
      not
      believe any amounts which may be subordinated in the future will be material
      to
      our operations.





Our
      investment partnerships provide tax advantages to their investors because an
      investor’s share of the partnership’s intangible drilling cost deduction may be
      used to offset ordinary income. Intangible drilling costs include items that
      do
      not have salvage value, such as labor, fuel, repairs, supplies and hauling.
      Historically, under our partnership agreements, approximately 90% of the
      subscription proceeds received by each partnership have been used to pay 100%
      of
      the partnership’s intangible drilling costs. For example, an investment of
      $10,000 has generally permitted the investor to deduct approximately $9,000
      in
      the year in which the investor invests.




8




**Natural
      Gas Sales**





**Appalachia**





In
      Appalachia, we have a natural gas supply agreement with Hess Corporation, which
      is valid through March 31, 2009. Subject to certain exceptions, Hess
      Corporation has a last right of refusal to buy all of the natural gas produced
      and delivered by us and our affiliates, including our investment partnerships,
      at certain delivery points with the facilities of:






·
            East
                Ohio Gas Company, National Fuel Gas Distribution, Columbia of Ohio,
                and
                Peoples Natural Gas Company, which are local distribution companies;
                and




·
            National
                Fuel Gas Supply, Columbia Gas Transmission Corporation, Tennessee
                Gas
                Pipeline Company, and Texas Eastern Transmission Company, which are
                interstate pipelines.




A
      portion
      of our and our investment partnerships’ natural gas is subject to the agreement
      with Hess Corporation, with the following exceptions:




·
            natural
                gas we sell to Warren Consolidated, an industrial end-user and direct
                delivery customer;




·
            natural
                gas that at the time of the agreement was already dedicated for the
                life
                of the well to another buyer;




·
            natural
                gas that is produced by a company which was not an affiliate of ours
                at
                the time of the agreement;




·
            natural
                gas sold through interconnects established subsequent to the
                agreement;




·
            natural
                gas that is delivered to interstate pipelines or local distribution
                companies other than those described above;
                and




·
            natural
                gas that is produced from wells operated by a third party or subject
                to an
                agreement under which a third party was to arrange for the gathering
                and
                sale of the natural gas.




Based
      on
      the most recent monthly production data available to us as of December 31,
      2007, we anticipate that we and our affiliates, including our investment
      partnerships, will sell approximately 18% of our Appalachian natural gas
      production during the year ending December 31, 2008 under the Hess Corporation
      agreement. The agreement requires the parties to negotiate a new pricing
      arrangement at each annual delivery point. If, at the end of any applicable
      period, the parties cannot agree to a new price for any delivery point, then
      we
      may solicit offers from third parties to buy the natural gas for that delivery
      point. If Hess Corporation does not match this price, then we may sell the
      natural gas to the third party. We market the remainder of our natural gas,
      which is principally located in the Fayette County, PA area, primarily to
      Colonial Energy, Inc., UGI Energy Services, and others. See “—Major Customers.”
During the year ended December 31, 2007, we received an average of $8.91
      per Mcf of natural gas, compared to $8.83 per Mcf in fiscal 2006 and $8.34
      per
      Mcf in fiscal 2005.




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**





In
      Michigan, we have natural gas sales agreements with DTE, 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 with the facilities of:




9




·
            Merit
                Plant/Michigan Consolidated Gas Company (MCGC)
                Kalkaska;




·
            MCGC
                Jordan 4, Chestonia 17, Mancelona 19, Saginaw Bay and Woolfolk;
                and




·
            Consumers
                Energy Goose Creek and Wilderness
                Plant,




Based
      on
      the most recent monthly production data available to us as of December 31,
      2007,
      we anticipate that we and our affiliates will sell approximately 50% of our
      Michigan natural gas production during the year ending December 31, 2008 under
      the DTE agreements in most cases at NYMEX pricing. During the six months ended
      December 31, 2007, AGO received an average of $8.44 per Mcf of natural
      gas.




**Crude
      Oil Sales**





Crude
      oil
      produced from our wells flows directly into storage tanks where it is picked
      up
      by the oil company, a common carrier, or pipeline companies acting for the
      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.




**A** **sset
      Retirement Obligations**




When
      we
      determine that a well is no longer capable of producing natural gas or oil
      in
      economic quantities, we must dismantle the well and restore and reclaim the
      surrounding area before we can abandon the well. We contract these operations
      to
      independent service providers to whom we pay a fee. The contractor will also
      salvage the equipment on the well, which we then sell in the used equipment
      market. Under the partnership agreements of our investment partnerships, which
      own the majority of our Appalachia wells, we are allocated abandonment costs
      in
      proportion to our partnership interest (generally between 27% and 35%) and
      are
      allocated between 65% and 100% of the salvage proceeds. As a consequence, we
      generally receive proceeds from salvaged equipment at least equal to, and
      typically exceeding, our share of the related costs.




**Natural
      Gas Hedging**




We
      seek
      to provide greater stability in our cash flows through our use of financial
      hedges and physical hedges. The financial hedges may include purchases of
      regulated NYMEX futures and options contracts and non-regulated over-the-counter
      futures contracts with qualified counterparties. The futures contracts are
      commitments to purchase or sell natural gas at future dates and generally cover
      one-month periods for up to six years in the future. To assure that the
      financial instruments will be used solely for hedging price risks and not for
      speculative purposes, we have a management committee to assure that all
      financial trading is done in compliance with our hedging policies and
      procedures. We do not intend to contract for positions that we cannot offset
      with actual production. As of December 31, 2007, we had financial hedges and
      physical hedges in place for approximately 65% of our expected Appalachian
      production and for approximately 87% of our Michigan production for the twelve
      months ending December 31, 2008.




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




**Natural
      Gas Gathering**




**Appalachia**




We
      conduct our natural gas transportation and processing operations through Atlas
      America’s affiliate, Atlas Pipeline Partners. Atlas Pipeline owns approximately
      1,600 miles of gathering systems located in eastern Ohio, western New York
      and
      western Pennsylvania serving approximately 6,600 wells.




10




In
      connection with the completion of our initial public offering, and the
      contribution by Atlas America of its natural gas and oil development and
      production assets to us, we entered into the following agreements with Atlas
      Pipeline.





**Omnibus
      Agreement**




Under
      the
      omnibus agreement, Atlas America and its affiliates agreed to add wells to
      Atlas
      Pipeline's gathering systems and provide consulting services when Atlas Pipeline
      constructs new gathering systems or extends existing systems. We joined the
      omnibus agreement as an obligor (except for the provisions of the omnibus
      agreement imposing conditions upon the disposition of the general partner
      interest of Atlas Pipeline's general partner), and Atlas America became
      secondarily liable as a guarantor of our performance. The omnibus agreement
      is a
      continuing obligation, having no specified term or provisions regarding
      termination except for a provision terminating the agreement if Atlas Pipeline's
      general partner is removed without cause.







*Well
      connections.* We are
      required to construct, at our sole cost and expense, up to 2,500 feet of small
      diameter (two inches or less) sales or flow lines from the wellhead of any
      well
      we drill and operate to a point of connection to Atlas Pipeline’s gathering
      systems. Where we have extended sales and flow lines to within 1,000 feet of
      one
      of Atlas Pipeline’s gathering systems, we may require Atlas Pipeline to extend
      its system to connect to that well. With respect to other wells that are more
      than 2,500 feet from Atlas Pipeline’s gathering systems, Atlas Pipeline has the
      right, at its cost and expense, to extend its gathering system to within 2,500
      feet of the well and to require us, at our cost and expense, to construct up
      to
      2,500 feet of flow line to connect to the gathering system extension. If Atlas
      Pipeline elects not to exercise its right to extend its gathering systems,
      we
      may connect a well to a natural gas gathering system owned by a third party
      or
      to any other delivery point; however, Atlas Pipeline will have the right to
      assume the cost of construction of the necessary flow lines, which then become
      its property and part of its gathering systems.




*Consulting
      services.* The
      omnibus agreement requires us to assist Atlas Pipeline in identifying existing
      gathering systems for possible acquisition and to provide consulting services
      to
      Atlas Pipeline in evaluating and making a bid for these systems. We must give
      Atlas Pipeline notice of identification by us or any of our affiliates of any
      gathering system as a potential acquisition candidate, and must provide Atlas
      Pipeline with information about the gathering system, its seller and the
      proposed sales price, as well as any other information or analyses we compile
      with respect to the gathering system. Atlas Pipeline must determine, within
      a
      time period specified by our notice to it, which must be a reasonable time
      under
      the circumstances, whether it wants to acquire the identified system and advise
      us of its intent. If Atlas Pipeline advises us that it does not intend to make
      the acquisition, does not complete the acquisition within a reasonable time
      period, or advises us that it does not intend to acquire the system, then we
      may
      do so.




*Gathering
      system construction.* We will
      provide Atlas Pipeline with construction management services if Atlas Pipeline
      determines to expand one or more of its gathering systems. We are entitled
      to
      reimbursement for our costs, including an allocable portion of employee
      salaries, in connection with our construction management services.





**Natural
      Gas Gathering Agreements**





Under
      our
      master natural gas gathering agreement with Atlas Pipeline, we pay gathering
      fees as follows:





·
            for
                natural gas from our well interests, other than those of our investment
                partnerships, that were connected to Atlas Pipeline’s gathering systems at
                February 2, 2000, the greater of $0.40 per thousand cubic feet, or
                Mcf,
                16% of the gross sales price of the natural gas
                transported;




·
            for
                (i) natural gas from well interests allocable to our investment
                partnerships that drilled or drill wells on or after December 1,
                1999 that
                are connected to the gathering systems (ii) natural gas from our
                well
                interests, other than those of our investment partnerships, that
                are
                connected to the gathering systems after February 2, 2000, and (iii)
                well
                interests allocable to third parties in wells connected to the gathering
                systems at February 2, 2000, the greater of $0.35 per Mcf or 16%
                of the
                gross sales price of the natural gas transported;
                and




·
            for
                natural gas from well interests we operate and drilled after December
                1,
                1999 that are connected to a gathering system that is not owned by
                Atlas
                Pipeline and for which Atlas Pipeline assumes the cost of constructing
                the
                connection to that gathering system, an amount equal to the greater
                of
                $0.35 per Mcf or 16% of the gross sales price of the natural gas
                transported, less the gathering fee charged by the other gathering
                system.




11




We
      receive gathering fees from contracts or other arrangements with the owners
      of
      well interests connected to Atlas Pipeline’s gathering systems. Pursuant to the
      contribution agreement described below under "—Other Agreements with Atlas
      America and its Affiliates—Contribution Agreement,” Atlas America agreed to
      assume our obligation to pay gathering fees to Atlas Pipeline. We, in turn,
      assigned to Atlas America the gathering fees we receive from our investment
      partnerships and gathering fees attributable to our production interest. The
      gathering fees payable to Atlas Pipeline generally exceed the amount we receive
      from our investment partnerships for gathering services. If Atlas America fails
      to pay gathering fees to Atlas Pipeline as required by its assumption agreement
      with us, we will have to pay to Atlas Pipeline the difference between the
      gathering fee payable and the amount we receive from our investment partnerships
      for gathering services out of our own resources.





The
      master natural gas gathering agreement is a continuing obligation and,
      accordingly, has no specified term or provisions regarding termination. However,
      if Atlas Pipeline’s general partner is removed as the general partner of Atlas
      Pipeline without cause, then no gathering fees will be due under the agreement
      with respect to new wells drilled by us.





In
      addition to the master natural gas gathering agreement, we are party to three
      other gas gathering agreements with Atlas Pipeline:





·
            Under
                two agreements, relating to wells located in southeastern Ohio, which
                were
                originally acquired from Kingston Oil Corporation, and wells located
                Fayette County, Pennsylvania, which were originally acquired from
                American
                Refining and Exploration Company, we pay Atlas Pipeline gathering
                fees of
                $0.80 per Mcf. These wells are owned directly by our subsidiaries,
                and
                Atlas America has not assumed any part of our obligation to pay the
                gathering fees to Atlas Pipeline under these
                agreements.




·
            Under
                another agreement, which covers wells owned by third parties unrelated
                to
                our investment partnerships and us, we pay Atlas Pipeline gathering
                fees
                that range between $0.20 and $0.29 per Mcf or between 10% to 16%
                of the
                weighted average sales price. The gathering fees payable under this
                agreement are a direct pass-through of the gathering fees we receive
                from
                the third party wells. Accordingly, Atlas America has not assumed
                any part
                of our obligation to pay the gathering fees to Atlas Pipeline under
                this
                agreement, and has been removed as an obligor under
                it.





**Michigan**





We
      transport our natural gas from our Michigan wells through our 1,157 miles of
      polypropylene flow lines to centrally located separation, compression and
      dehydration facilities, which we refer to as CPFs, where water is separated
      from
      the natural gas and disposed of. We own interests in 81 CPFs, of which we
      operate 61. The wells generally produce natural gas and water for 3 to 12
      months, after which they produce only gas.





We
      then
      transport the compressed and dehydrated gas stream from CPFs via our 181 miles
      of sales lines to the northern Michigan high pressure gathering system, which
      is
      composed of a number of gathering systems owned by third party transporters
      that
      deliver gas to delivery points. Compressed and dehydrated gas exiting the CPF
      typically has carbon dioxide (CO2) levels in excess of the 2% pipeline
      specifications required at the delivery point. Therefore, it is treated at
      CO2
      processing plants located along the northern Michigan high pressure gathering
      system before delivery to the delivery points. The CO2 plants utilize either
      an
      amine or membrane treating process. We currently own and operate one amine
      processing plant and operate on behalf of DTE four other amine plants and one
      membrane plant. We pay third parties an average of $0.30/Mcfe on a net basis
      for
      these transportation and treating services.





**Other
      Agreements with Atlas America and Its Affiliates**





**Contribution
      Agreement**





*Contribution
      of assets by Atlas America.* The
      substantial majority of the Appalachian assets we own were held, directly or
      indirectly, by subsidiaries of Atlas America. In connection with our initial
      public offering, Atlas America entered into a contribution agreement pursuant
      to
      which it contributed to us all of the stock of its natural gas and oil
      development and production subsidiaries as well as the development and
      production assets owned by it. As consideration for this contribution, we
      distributed to Atlas America the net proceeds we received from that offering,
      as
      well as 29,352,996 of our common units, the Class A units and the management
      incentive interests. As part of the contribution agreement, Atlas America has
      agreed to indemnify us for losses attributable to title defects to our oil
      and
      gas property interests for three years after the closing of the offering, and
      indefinitely for losses attributable to retained liabilities and income taxes
      attributable to pre-closing operations and formation transactions. Furthermore,
      we have agreed to indemnify Atlas America for all losses attributable to the
      post-closing operations of the assets contributed to us, to the extent not
      subject to its indemnification obligations.





12




*Atlas
      America’s assumption of obligations under the master natural gas gathering
      agreement with Atlas Pipeline.* Upon
      completion of our initial public offering, we became a party to an existing
      master natural gas gathering agreement between Atlas America and Atlas Pipeline
      pursuant to which Atlas Pipeline gathers substantially all of the natural gas
      from wells operated by us. Pursuant to the contribution agreement, Atlas America
      has agreed to assume our obligation to pay gathering fees to Atlas Pipeline
      under the master natural gas gathering agreement; we have agreed to pay Atlas
      America the gathering fees we receive from our investment partnerships and
      fees
      associated with production to our interest.





**Management
      Agreement**





Upon
      completion of our initial public offering, we entered into a management
      agreement with Atlas Energy Management, a subsidiary of Atlas America, pursuant
      to which Atlas Energy Management will manage our business affairs under the
      supervision of our board of directors. Atlas Energy Management will provide
      us
      with all services necessary or appropriate for the conduct of our business.
      In
      exercising its powers and discharging its duties under the management agreement,
      Atlas Energy Management must act in good faith.





Before
      making any distribution on our common units, we will reimburse Atlas Energy
      Management for all expenses that it incurs on our behalf pursuant to the
      management agreement. These expenses will include costs for providing corporate
      staff and support services to us. Atlas Energy Management will charge on a
      fully
      allocated cost basis for services provided to us. This fully allocated cost
      basis is based on the percentage of time spent by personnel of Atlas Energy
      Management and its affiliates on our matters and includes the compensation
      paid
      by Atlas Energy Management and its affiliates to such persons and their
      allocated overhead. The allocation of compensation expense for such persons
      will
      be determined based on a good faith estimate of the value of each such person’s
      services performed on our business and affairs, subject to the periodic review
      and approval of our audit or conflicts committee.





Atlas
      Energy Management, its stockholders, directors, officers, employees and
      affiliates will not be liable to us, our directors or unit holders for acts
      or
      omissions performed in good faith and in accordance with and pursuant to the
      management agreement, except because of acts constituting gross negligence,
      bad
      faith, willful misconduct, fraud or a knowing violation of criminal law. We
      will
      indemnify Atlas Energy Management, its stockholders, directors, officers,
      employees and affiliates with respect to all expenses, losses, damages,
      liabilities, demands, charges and claims arising from acts of Atlas Energy
      Management, its stockholders, directors, officers, employees and affiliates
      not
      constituting gross negligence, bad faith, willful misconduct, fraud or a knowing
      violation of criminal law performed in good faith in accordance with and
      pursuant to the management agreement. Atlas Energy Management and its affiliates
      will indemnify us and our directors and officers with respect to all expenses,
      losses, damages, liabilities, demands, charges and claims arising from acts
      of
      Atlas Energy Management or its affiliates constituting gross negligence, bad
      faith, willful misconduct, fraud or a knowing violation of criminal law or
      any
      claims by employees of Atlas Energy Management or its affiliates relating to
      the
      terms and conditions of their employment. Atlas Energy Management and/or Atlas
      America will carry errors, omissions, and other customary
      insurance.





The
      management agreement may not be amended without the prior approval of our
      conflicts committee if the proposed amendment will, in the reasonable discretion
      of our board, adversely affect our common unit holders.





The
      management agreement does not have a specific term; however, Atlas Energy
      Management may not terminate the agreement before December 18, 2016. We may
      terminate the management agreement only upon the affirmative vote of holders
      of
      at least two-thirds of our outstanding common units, including units held by
      Atlas America. In the event we terminate the management agreement, Atlas Energy
      Management will have the option to require the  successor
      manager, if any, to purchase its membership interests and management incentive
      interests for their fair market value as determined by agreement between the
      departing manager and the successor manager.





13





**Anthem
      Securities, Inc.**





Anthem
      Securities is our registered broker-dealer subsidiary, which acts as the
      dealer-manager for our investment partnership offerings. Anthem Securities
      is
      registered as a broker-dealer solely involved in direct participation programs
      such as our investment partnerships, and does not maintain customer accounts
      or
      custody of securities. Anthem Securities has been a member of FINRA, formerly
      known as the National Association of Securities Dealers, Inc., since
      1997.




**A** **vailability
      of Oil Field Services**




We
      contract for drilling rigs and purchase goods and services necessary for the
      drilling and completion of wells from a number of drillers and suppliers, none
      of which supplies a significant portion of our annual needs. During fiscal
      2007,
      we faced no shortage of these goods and services. We cannot predict the duration
      or stability of the current level of supply and demand for drilling rigs and
      other goods and services required for our operations with any certainty due
      to
      numerous factors affecting the energy industry, including the demand for natural
      gas and oil.





**Major
      Customers**





Our
      natural gas sold under contract to various purchasers. For the year ended
      September 30, 2005 and the years ended December 31, 2006 and 2007, gas sales
      to
      Hess Corporation (formerly First Energy Solutions Corp.) accounted for 12%,
      10%
      and 18%, respectively, of our total Appalachian gas and oil production revenues.
      For the six months, ended December 31, 2007, sales to DTE accounted for 46%
      of
      our Michigan oil and gas production revenues. No other single customer accounted
      for more than 10% of our total revenues during these periods.





**Competition**





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





Many
      of
      our competitors possess greater financial and other resources than ours, which
      may enable them to identify and acquire desirable properties and market their
      natural gas and oil production more effectively than we do.





Moreover,
      we also compete with a number of other companies that offer interests in
      investment partnerships. As a result, competition for investment capital to
      fund
      investment partnerships is intense.





**Markets**





The
      availability of a ready market for natural gas and oil and the price obtained,
      depends upon numerous factors beyond our control, as described in “Risk factors”
Product availability and price are the principal means of competition in selling
      natural gas and oil. During the year ended December 31, 2007, we did not
      experience problems in selling our natural gas and oil, although prices have
      varied significantly during this period.





**Natural
      Gas and Oil Leases**





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





14




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





Sometimes
      these third party owners of natural gas and oil leases retain the option to
      participate in the drilling of wells on leases farmed out or assigned to us.
      Normally the retained interest is a 25% working interest. In this event, our
      working interest ownership will be reduced by the amount retained by the third
      party operator. In all other instances we anticipate owning a 100% working
      interest in newly drilled wells.





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





**Seasonal
      Nature of Business**





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





**E** **nvironmental
      Matters and Regulation**





**General**





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




·
            require
                the acquisition of various permits before drilling
                commences;




·
            require
                the installation of expensive pollution control
                equipment;




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




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




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




15




·
            impose
                substantial liabilities for pollution resulting from our operations;
                and




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




These
      laws, rules and regulations may also restrict the rate of natural gas and oil
      production below the rate that would otherwise be possible. The regulatory
      burden on the natural gas and oil industry increases the cost of doing business
      in the industry and consequently affects profitability. Additionally, Congress
      and federal and state agencies frequently enact new, and revise existing,
      environmental laws and regulations, and any new laws or changes to existing
      laws
      that result in more stringent and costly waste handling, disposal and clean-up
      requirements for the natural gas and oil industry could have a significant
      impact on our operating costs. We believe that our operations overall
      substantially comply with all currently applicable environmental laws and
      regulations and that our continued compliance with existing requirements will
      not have a material adverse impact on our financial condition and results of
      operations. However, we cannot predict how environmental laws and regulations
      that may take effect in the future may affect our properties or operations.
      For
      the years ended December 31, 2006 and 2007, we did not incur any material
      capital expenditures for installation of remediation or pollution control
      equipment at any of our facilities. We are not aware of any environmental issues
      or claims that will require material capital expenditures during 2008, or that
      will otherwise have a material impact on our financial position or results
      of
      operations.




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





**National
      Environmental Policy Act**





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





**Waste
      Handling**





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





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




**Comprehensive
      Environmental Response, Compensation and Liability Act**





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




16





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





**Water
      Discharges**





The
      Federal Water Pollution Control Act, also known as the Clean Water Act, and
      analogous state laws impose restrictions and strict controls on the discharge
      of
      pollutants, including produced waters and other natural gas and oil wastes,
      into
      navigable waters of the United States. The discharge of pollutants into
      regulated waters is prohibited, except in accordance with the terms of a permit
      issued by EPA or the relevant state. The Clean Water Act also prohibits the
      discharge of dredge and fill material in regulated waters, including wetlands,
      unless authorized by a permit issued by the U.S. Army Corps of Engineers. The
      Clean Water Act also requires specified facilities to maintain and implement
      spill prevention, control and countermeasure plans and to take measures to
      minimize the risks of petroleum spills. Federal and state regulatory agencies
      can impose administrative, civil and criminal penalties for failure to obtain
      or
      non-compliance with discharge permits or other requirements of the federal
      Clean
      Water Act and analogous state laws and regulations. We believe our operations
      on
      the whole are in substantial compliance with the requirements of the Clean
      Water
      Act.





**Air
      Emissions**





The
      Clean
      Air Act, and associated state laws and regulations, regulate emissions of
      various air pollutants through permits and other requirements. In addition,
      EPA
      has developed, and continues to develop, stringent regulations governing
      emissions of toxic and other air pollutants at specified sources. Some of our
      new facilities may be required to obtain permits before work can begin, and
      existing facilities may be required to incur capital costs in order to comply
      with new emission limitations. These regulations may increase the costs of
      compliance for some facilities, and federal and state regulatory agencies can
      impose administrative, civil and criminal penalties for non-compliance. These
      laws and regulations also apply to entities that use natural gas as fuel, and
      may increase the costs of compliance of our customers to the point where demand
      for natural gas is affected. We believe that our operations are in substantial
      compliance with the requirements of the Clean Air Act.





**OSHA
      and Other Regulations**





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





**Other
      Laws and Regulation**





The
      Kyoto
      Protocol to the United Nations Framework Convention on Climate Change became
      effective in February 2005. Under the Protocol, participating nations are
      required to implement programs to reduce emissions of certain gases, generally
      referred to as greenhouse gases that are suspected of contributing to global
      warming. The United States is not currently a participant in the Protocol,
      and
      Congress has resisted recent proposed legislation directed at reducing
      greenhouse gas emissions. However, there has been support in various regions
      of
      the country for legislation that requires reductions in greenhouse gas
      emissions, and some states have already adopted legislation addressing
      greenhouse gas emissions from various sources, primarily power plants. The
      natural gas and oil industry is a direct source of certain greenhouse gas
      emissions, namely carbon dioxide and methane, and future restrictions on such
      emissions could affect our future operations. Our operations are not adversely
      impacted by current state and local climate change initiatives and, at this
      time, it is not possible to accurately estimate how potential future laws or
      regulations addressing greenhouse gas emissions would affect our
      business.




17





**Other
      Regulation of the Natural Gas and Oil Industry**





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





Legislation
      continues to be introduced in Congress and development of regulations continues
      in the Department of Homeland Security and other agencies concerning the
      security of industrial facilities, including natural gas and oil facilities.





Our
      operations may be subject to such laws and regulations. Presently, it is not
      possible to accurately estimate the costs we could incur to comply with any
      such
      facility security laws or regulations, but such expenditures could be
      substantial.





**Drilling
      and Production**





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







·
            the
                location of wells;




·
            the
                method of drilling and casing
                wells;




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




·
            the
                plugging and abandoning of wells;
                and




·
            notice
                to surface owners and other third
                parties.




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





**Natural
      Gas Regulation**





The
      availability, terms and cost of transportation significantly affect sales of
      natural gas. The interstate transportation and sale for resale of natural gas
      is
      subject to federal regulation, including regulation of the terms, conditions
      and
      rates for interstate transportation, storage and various other matters,
      primarily by the Federal Energy Regulatory Commission. Federal and state
      regulations govern the price and terms for access to natural gas pipeline
      transportation. The Federal Energy Regulatory Commission’s regulations for
      interstate natural gas transmission in some circumstances may also affect the
      intrastate transportation of natural gas.




18





Although
      natural gas prices are currently unregulated, Congress historically has been
      active in the area of natural gas regulation. We cannot predict whether new
      legislation to regulate natural gas might be proposed, what proposals, if any,
      might actually be enacted by Congress or the various state legislatures, and
      what effect, if any, the proposals might have on the operations of the
      underlying properties. Sales of condensate and natural gas liquids are not
      currently regulated and are made at market prices.





**State
      Regulation**





The
      various states regulate the drilling for, and the production, gathering and
      sale
      of, natural gas, including imposing severance taxes and requirements for
      obtaining drilling permits. For example, Michigan imposes a 5.6% severance
      tax
      on natural gas and a 7.3% severance tax on oil, Tennessee imposes a 3% severance
      tax on natural gas and oil production and Ohio imposes a severance tax of $0.25
      per Mcf of natural gas and $0.10 per Bbl of oil. States also regulate the method
      of developing new fields, the spacing and operation of wells and the prevention
      of waste of natural gas resources. States may regulate rates of production
      and
      may establish maximum daily production allowables from natural gas wells based
      on market demand or resource conservation, or both. States do not regulate
      wellhead prices or engage in other similar direct economic regulation, but
      there
      can be no assurance that they will not do so in the future. The effect of these
      regulations may be to limit the amounts of natural gas that may be produced
      from
      our wells, and to limit the number of wells or locations we can
      drill.





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





**Employees**





We
      do not
      have any employees. To carry out our operations, our manager and its affiliates
      employed approximately 467 persons as of December 31, 2007.





19




**Available
      Information**




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





The
      NYSE
      requires the chief executive officer of each listed company to certify annually
      that he is not aware of any violation by the company of the NYSE corporate
      governance listing standards as of the date of the certification, qualifying
      the
      certification to the extent necessary. The Chief Executive Officer of our
      general partner provided such certification to the NYSE in 2007 without
      qualification. In addition, the certifications of the Chief Executive Officer
      and Chief Financial Officer of our general partner required by Sections 302
      and
      906 of the Sarbanes-Oxley Act have been included as exhibits to this
      report.





**ITEM
      1A:**  **RISK
      FACTORS**





*We
      may not have sufficient cash flow from operations to pay the initial quarterly
      distribution, or IQD, following the establishment of cash reserves and payment
      of fees and expenses, including payments to our manager.* We
      may
      not have sufficient cash flow from operations each quarter to pay the IQD.
      Under
      the terms of our limited liability company agreement, the amount of cash
      otherwise available for distribution will be reduced by our operating expenses
      and the amount of any cash reserve amounts that our board of directors
      establishes to provide for future operations, future capital expenditures,
      future debt service requirements and future cash distributions to our unit
      holders and the holders of the management incentive interests. The amount of
      cash we can distribute on our common units principally depends upon the amount
      of cash we generate from our operations, which will fluctuate from quarter
      to
      quarter based on, among other things:





·
            the
                amount of natural gas and oil we
                produce;




·
            the
                price at which we sell our natural gas and
                oil;




·
            the
                level of our operating costs;




·
            our
                ability to acquire, locate and produce new
                reserves;




·
            results
                of our hedging activities;




·
            the
                level of our interest expense, which depends on the amount of our
                indebtedness and the interest payable on it;
                and




·
            the
                level of our capital expenditures.





The
      actual amount of cash we will have available for distribution will depend on
      other factors, some of which are beyond our control, including:





·
            our
                ability to make working capital borrowings to pay
                distributions;




·
            the
                cost of acquisitions, if any;




·
              fluctuations
                  in our working capital needs;


·
            timing
                and collectability of receivables;




·
            restrictions
                on distributions imposed by
                lenders;




20




·
            payments
                to our manager;




·
            the
                amount of our estimated maintenance capital
                expenditures;




·
            prevailing
                economic conditions; and




·
            the
                amount of cash reserves established by our board of directors for
                the
                proper conduct of our business.





As
      a
      result of these factors, the amount of cash we distribute in any quarter to
      our
      unit holders may fluctuate significantly from quarter to quarter and may be
      significantly less than the IQD amount that we expect to
      distribute.





*If
      commodity prices decline significantly, our cash flow from operations will
      decline.* Our
      revenue, profitability and cash flow substantially depend upon the prices and
      demand for natural gas and oil. The natural gas and oil markets are very
      volatile and a drop in prices can significantly affect our financial results
      and
      impede our growth. Changes in natural gas and oil prices will have a significant
      impact on the value of our reserves and on our cash flow. Prices for natural
      gas
      and oil may fluctuate widely in response to relatively minor changes in the
      supply of and demand for natural gas or oil, market uncertainty and a variety
      of
      additional factors that are beyond our control, such as:




·
            the
                level of the domestic and foreign supply and
                demand;




·
            the
                price and level of foreign imports;




·
            the
                level of consumer product demand;




·
            weather
                conditions and fluctuating and seasonal
                demand;




·
            overall
                domestic and global economic
                conditions;




·
            political
                and economic conditions in natural gas and oil producing countries,
                including those in the Middle East and South
                America;




·
            the
                ability of members of the Organization of Petroleum Exporting Countries
                to
                agree to and maintain oil price and production
                controls;




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




·
            technological
                advances affecting energy
                consumption;




·
            domestic
                and foreign governmental relations, regulations and
                taxation;




·
            the
                impact of energy conservation
                efforts;




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




·
            the
                price and availability of alternative
                fuels.




In
      the
      past, the prices of natural gas and oil have been extremely volatile, and we
      expect this volatility to continue. For example, during the year ended
      December 31, 2007, the NYMEX Henry Hub natural gas index price ranged from
      a high of $7.59 per MMBtu to a low of $5.43 per MMBtu, and West Texas
      Intermediate oil prices ranged from a high of $95.10 per Bbl to a low of $51.13
      per Bbl.





*Unless
      we replace our reserves, our reserves and production will decline, which would
      reduce our cash flow from operations and impair our ability to make payments
      on
      our debt.* Producing
      natural gas reservoirs generally are characterized by declining production
      rates
      that vary depending upon reservoir characteristics and other factors. Based
      on
      our December 31, 2007 reserve reports, our average annual decline rate for
      proved developed producing reserves is approximately 8% during the first
      five years, approximately 5% in the next five years and less than 5%
      thereafter. Because total estimated proved reserves include proved undeveloped
      reserves at December 31, 2007, production will decline at this rate even if
      those proved undeveloped reserves are developed and the wells produce as
      expected. This rate of decline will change if production from our existing
      wells
      declines in a different manner than we have estimated and can change when we
      drill additional wells, make acquisitions and under other circumstances. Thus,
      our future natural gas reserves and production and, therefore, our cash flow
      and
      income are highly dependent on our success in efficiently developing and
      exploiting our current reserves and economically finding or acquiring additional
      recoverable reserves. Our ability to find and acquire additional recoverable
      reserves to replace current and future production at acceptable costs depends
      on
      our generating sufficient cash flow from operations and other sources of
      capital, including our investment partnerships, all of which are subject to
      the
      risks discussed elsewhere in this section.




21




*Our
      estimated reserves are based on many assumptions that may prove to be
      inaccurate. Any material inaccuracies in these reserve estimates or underlying
      assumptions will materially affect the quantities and present value of our
      reserves.* Underground
      accumulations of natural gas and oil cannot be measured in an exact way. Natural
      gas and oil reserve engineering requires subjective estimates of underground
      accumulations of natural gas and oil and assumptions concerning future natural
      gas prices, production levels, and operating and development costs. As a result,
      estimated quantities of proved reserves and projections of future production
      rates and the timing of development expenditures may prove to be inaccurate.
      Our
      independent petroleum engineers prepare estimates of our proved reserves. Over
      time, our internal engineers may make material changes to reserve estimates
      taking into account the results of actual drilling and production. Some of
      our
      reserve estimates are made without the benefit of a lengthy production history,
      which are less reliable than estimates based on a lengthy production history. Also,
      we
      make certain assumptions regarding future natural gas prices, production levels,
      and operating and development costs that may prove incorrect. Any significant
      variance from these assumptions by actual figures could greatly affect our
      estimates of reserves, the economically recoverable quantities of natural gas
      and oil attributable to any particular group of properties, the classifications
      of reserves based on risk of recovery and estimates of the future net cash
      flows. For example, if natural gas prices decline by $1.00 per Mcf, then the
      PV-10 value of our proved reserves as of December 31, 2007 would decrease from
      $1.5 billion to $1.2 billion. Our PV-10 is calculated using natural gas prices
      that include our physical hedges but not our financial hedges. Numerous changes
      over time to the assumptions on which our reserve estimates are based, as
      described above, often result in the actual quantities of natural gas and oil
      we
      ultimately recover being different from our reserve estimates. The present
      value
      of future net cash flows from our proved reserves is not necessarily the same
      as
      the current market value of our estimated natural gas reserves. We base the
      estimated discounted future
      net cash flows from our proved reserves on prices and costs in effect on the
      day
      of estimate. However, actual future net cash flows from our natural gas
      properties also will be affected by factors such as:





·
            actual
                prices we receive for natural gas;




·
            the
                amount and timing of actual
                production;




·
            the
                amount and timing of our capital
                expenditures;




·
            supply
                of and demand for natural gas; and




·
            changes
                in governmental regulations or
                taxation.




The
      timing of both our production and our incurrence of expenses in connection
      with
      the development and production of natural gas properties will affect the timing
      of actual future net cash flows from proved reserves, and thus their actual
      present value. In addition, the 10% discount factor we use when calculating
      discounted future net cash flows may not be the most appropriate discount factor
      based on interest rates in effect from time to time and risks associated with
      us
      or the natural gas and oil industry in general. Any significant variance in
      our
      assumptions could materially affect the quantity and value of reserves, the
      amount of PV-10 described in this report,
      and our financial condition and results of operations. In addition, our reserves
      or PV-10 may be revised downward or upward based upon production history,
      results of future exploitation and development activities, prevailing natural
      gas and oil prices and other factors. A material decline in prices paid for
      our
      production can reduce the estimated volumes of our reserves because the economic
      life of our wells could end sooner. Similarly, a decline in market prices for
      natural gas or oil may reduce our PV-10.





*Our
      operations require substantial capital expenditures, which will reduce our
      cash
      available for distribution. Additionally, each quarter we are required to deduct
      estimated maintenance capital expenditures from operating surplus, which may
      result in less cash available to unit holders than if actual maintenance capital
      expenditures were deducted.*We
      will
      need to make substantial capital expenditures to maintain our capital asset
      base
      over the long term. These maintenance capital expenditures may include the
      drilling and completion of additional wells to offset the production decline
      from our producing properties or additions to our inventory of unproved or
      proved reserves. These expenditures could increase as a result
      of:




22




·
            changes
                in our reserves;




·
            changes
                in natural gas prices;




·
            changes
                in labor and drilling costs;




·
            our
                ability to acquire, locate and produce
                reserves;




·
            changes
                in leasehold acquisition costs; and




·
            government
                regulations relating to safety and the
                environment.





Our
      significant maintenance capital expenditures will reduce the amount of cash
      we
      have available for distribution to our unit holders. Additionally, our actual
      maintenance capital expenditures will vary from quarter to quarter. Our limited
      liability company agreement requires us to deduct estimated, rather than actual,
      maintenance capital expenditures from operating surplus. The amount of estimated
      maintenance capital expenditures deducted from operating surplus will be subject
      to review and approval by our board of directors, including a majority of our
      conflicts committee, at least once a year. In years when our estimated
      maintenance capital expenditures are higher than actual maintenance capital
      expenditures, the amount of cash available for distribution to unit holders
      will
      be lower than if we deducted actual maintenance capital expenditures from
      operating surplus. If we underestimate the appropriate level of estimated
      maintenance capital expenditures, we may have less cash available for
      distribution in future periods when actual capital expenditures begin to exceed
      our previous estimates. Over time, if we do not set aside sufficient cash
      reserves or have available sufficient sources of financing and make sufficient
      expenditures to maintain our capital asset base, we will be unable to pay
      distributions at the anticipated level and may have to reduce our
      distributions.





*The
      scope and costs of the risks involved in making acquisitions may prove greater
      than estimated at the time of the acquisition.* Any
      acquisition involves potential risks, including, among other
      things:




·
            mistakenassumptionsabout revenues and costs, including
                synergies;




·
            significantincreases in our indebtedness and working capital
                requirements;




·
            an
                inability tointegratesuccessfully or timely the businesses we
                acquire;




·
            theassumptionof
                unknown liabilities;




·
            limitationson
                rights to indemnity from the
                seller;




·
            the
                diversion ofmanagement’sattention from other business
                concerns;




·
            increaseddemands on existing personnel;




·
            customeror
                key employee losses at the acquired businesses;
                and




·
            the
                failure to realizeexpectedgrowth or profitability.




The
      scope
      and cost of these risks may ultimately be materially greater than estimated
      at
      the time of the acquisition.  Further, our future acquisition costs may be
      higher than those we have achieved historically.  Any of these factors
      could adversely affect our future growth and our ability to increase
      distributions.




*We
      may be unsuccessful in integrating the operations from our recent acquisition
      or
      any future acquisitions with our operations and in realizing all of the
      anticipated benefits of these acquisitions.* We
      acquired DTE Gas & Oil in June 2007 and are currently in the process of
      integrating its operations with ours. We also have an active, on-going program
      to identify other potential acquisitions. The integration of previously
      independent operations with ours can be a complex, costly and time-consuming
      process. The difficulties of combining these systems, as well as any operations
      we may acquire in the future, with us include, among other things:





·
            operating
                a significantly larger combined
                entity;




23




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




·
            integrating
                personnel with diverse business backgrounds and organizational
                cultures;




·
            consolidating
                operational and administrative
                functions;




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




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




·
            customer
                or key employee loss from the acquired
                businesses;




·
            a
                significant increase in our indebtedness;
                and




·
            potential
                environmental or regulatory liabilities and title
                problems.




We
      acquired DTE Gas & Oil with the expectation that combining it with our
      existing operations will result in benefits, including, among other things,
      increased geographic diversification and reserve life. There can be no assurance
      that we will realize any of these benefits or that the acquisition will not
      result in the deterioration or loss of our business. Costs incurred and
      liabilities assumed in connection with an acquisition and increased capital
      expenditures and overhead costs incurred to expand our operations could harm
      our
      business or future prospects, and result in significant decreases in our gross
      margin and cash flows.





*The
      DTE Gas & Oil acquisition has substantially changed our business, making it
      difficult to evaluate our business based upon our historical financial
      information* .
      The DTE
      Gas & Oil acquisition has significantly increased our size, redefined our
      business plan, expanded our geographic market and resulted in large changes
      to
      our revenues and expenses. As a result of this acquisition, and our continued
      plan to acquire and integrate additional companies that we believe present
      attractive opportunities, our financial results for any period or changes in
      our
      results across periods may continue to dramatically change. Our historical
      financial results, therefore, should not be relied upon to accurately predict
      our future operating results, thereby making the evaluation of our business
      more
      difficult.





*We
      have limited experience in drilling wells to the Marcellus Shale, less
      information regarding reserves and decline rates in the Marcellus Shale than
      in
      other areas of our Appalachian operations and wells drilled to the Marcellus
      Shale will be deeper, more expensive and more susceptible to mechanical problems
      in drilling and completing than wells in the other areas.* We
      have
      limited experience in drilling development wells to the Marcellus Shale. As
      of
      December 31, 2007, we have drilled 19 wells to the Marcellus Shale, 15 of which
      have been turned on-line, but those wells have been producing for only a short
      period of time. Other operators in the Appalachian Basin also have limited
      experience in drilling wells to the Marcellus Shale.
      Thus, we have much less information with respect to the ultimate recoverable
      reserves and the production decline rate in the Marcellus Shale than we have
      in
      our other areas of operation. In addition, the wells to be drilled in the
      Marcellus Shale will be drilled deeper than in our other primary areas, which
      makes the Marcellus Shale wells more expensive to drill and complete.
      The wells will also be more susceptible to mechanical problems associated with
      the drilling and completion of the wells, such as casing collapse and lost
      equipment in the wellbore. In addition, the fracturing of the Marcellus Shale
      will be more extensive and complicated than fracturing the geological formations
      in our other areas of operation.





*Changes
      in tax laws may impair our ability to obtain capital funds through investment
      partnerships .* Under
      current federal tax laws, there are tax benefits to investing in investment
      partnerships such as those we sponsor, including deductions for intangible
      drilling costs and depletion deductions. Changes to federal tax law that reduce
      or eliminate these benefits may make investment in our investment partnerships
      less attractive and, thus, reduce our ability to obtain funding from this
      significant source of capital funds.





*We
      have a substantial amount of indebtedness which could adversely affect
      our*  *financial
      position* ***.*** ** We
      currently have a substantial amount of indebtedness. As of February 20, 2008,
      we
      had total debt of approximately $770.1 million, consisting of
      $250.0 million of senior notes, $520.0 million of borrowings under our
      credit facility, and $0.1 million of other debt. We may also incur
      significant additional indebtedness in the future. Our substantial indebtedness
      may:





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




24




•
            limit
                our ability to borrow additional funds for working capital, capital
                expenditures, acquisitions or other general business
                purposes;





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





•
            require
                us to use a substantial portion of our cash flow from operations
                to make
                debt service payments;





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





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





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





Our
      ability to service our indebtedness will depend upon, among other things, our
      future financial and operating performance, which will be affected by prevailing
      economic conditions and financial, business, regulatory and other factors,
      some
      of which are beyond our control. If our operating results are not sufficient
      to
      service our current or future indebtedness, we will be forced to take actions
      such as reducing distributions, reducing or delaying business activities,
      acquisitions, investments and/or capital expenditures, selling assets,
      restructuring or refinancing our indebtedness, or seeking additional equity
      capital or bankruptcy protection. We may not be able to affect any of these
      remedies on satisfactory terms or at all.





*Covenants
      in our debt agreements restrict our business in many ways.* The
      indenture governing our senior notes and our credit facility contain various
      covenants that limit our ability and/or our subsidiaries’ ability to, among
      other things:





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





•
            issue
                redeemable stock and preferred stock;





•
            pay
                dividends or distributions or redeem or repurchase capital
                stock;





•
            prepay,
                redeem or repurchase debt;





•
            make
                loans, investments and capital expenditures;





•
            enter
                into agreements that restrict distributions from our
                subsidiaries;





•
            sell
                assets and capital stock of our subsidiaries;





•
            enter
                into certain transactions with affiliates; and





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





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




25





*Changes
      in tax laws may impair our ability to obtain capital funds through
      investment*  *partnerships.* Under
      current federal tax laws, there are tax benefits to investing in investment
      partnerships such as those we sponsor, including deductions for intangible
      drilling costs and depletion deductions. Changes to federal tax law that reduce
      or eliminate these benefits may make investment in our investment partnerships
      less attractive and, thus, reduce our ability to obtain funding from this
      significant source of capital funds.





*We
      may not be able to continue to raise funds through our investment partnerships
      at the levels we have recently experienced, which may in turn restrict our
      ability to maintain our drilling activity at the levels recently experienced.* We
      have
      sponsored limited and general partnerships to raise funds from investors to
      finance our development drilling activities in Appalachia. Accordingly, the
      amount of development activities we undertake there depends in large part upon
      our ability to obtain investor subscriptions to invest in these partnerships.
      During the past three years we have raised successively larger amounts of funds
      through these investment partnerships, raising $148.7 million in fiscal 2005,
      and $52.2 million in the three months ended December 31, 2005 and $218.5 million
      and $363.3 million in calendar 2006 and 2007, respectively. In the future,
      we
      may not be successful in raising funds through these investment partnerships
      at
      the same levels we have recently experienced, and we also may not be successful
      in increasing the amount of funds we raise as we have done in recent years.
      Our
      ability to raise funds through our investment partnerships depends in large
      part
      upon the perception of investors of their potential return on their investment
      and their tax benefits from investing in them, which perception is influenced
      significantly by our historical track record of generating returns and tax
      benefits to the investors in our existing partnerships.





In
      the
      event that our investment partnerships do not achieve satisfactory returns
      on
      investment or the anticipated tax benefits, we may have difficulty in continuing
      to increase the amount of funds we raise through these partnerships or in
      maintaining the level of funds we have recently raised through these
      partnerships. In this event, we may need to obtain financing for our drilling
      activities on a less attractive basis than the financing we realize through
      these partnerships or we may determine to reduce our drilling
      activity.





*Our
      fee-based revenues may decline if we are unsuccessful in continuing to sponsor
      investment partnerships, and our fee-based revenue may not increase at the
      same
      rate as recently experienced if we are unable to raise funds at the same or
      higher levels as we have recently experienced.* Our
      fee-based revenues are based on the number of investment partnerships we sponsor
      and the number of partnerships and wells we manage or operate. If we are
      unsuccessful in sponsoring future investment partnerships, our fee-based
      revenues may decline. Additionally, our fee-based revenue may not increase
      at
      the same rate as recently experienced if we are unable to raise funds at the
      same or higher levels as we have recently experienced.





*Our
      revenues may decrease if investors in our investment partnerships do not receive
      a minimum return.*


We
      have
      agreed to subordinate up to 50% of our share of production revenues to specified
      returns to the investor partners in our investment partnerships, typically
      10%
      per year for the first five years of distributions. Thus, our revenues from
      a
      particular partnership will decrease if it does not achieve the specified
      minimum return and our ability to make distributions to unit holders may be
      impaired. We have not subordinated our share of revenues from any of our
      investment partnerships since March 2005, but did subordinate $91,000 in 2005
      and $335,000 in 2004.





*Competition
      in the natural gas and oil industry is intense, which may hinder our ability
      to
      acquire gas and oil properties and companies and to obtain capital, contract
      for
      drilling equipment and secure trained personnel.* We
      operate in a highly competitive environment for acquiring properties and other
      natural gas and oil companies, attracting capital through our investment
      partnerships, contracting for drilling equipment and securing trained personnel.
      We will also compete with the exploration and production divisions of public
      utility companies for natural gas and oil property acquisitions. Our competitors
      may be able to pay more for natural gas and oil properties and drilling
      equipment and to evaluate, bid for and purchase a greater number of properties
      than our financial or personnel resources permit. Moreover, our competitors
      for
      investment capital may have better track records in their programs, lower costs
      or better connections in the securities industry segment that markets oil and
      gas investment programs than we do. All of these challenges could make it more
      difficult for us to execute our growth strategy. We may not be able to compete
      successfully in the future in acquiring leasehold acreage or prospective
      reserves or in raising additional capital.





Furthermore,
      competition arises not only from numerous domestic and foreign sources of
      natural gas and oil but also from other industries that supply alternative
      sources of energy. Competition is intense for the acquisition of leases
      considered favorable for the development of natural gas and oil in commercial
      quantities. Product availability and price are the principal means of
      competition in selling natural gas and oil. Many of our competitors possess
      greater financial and other resources than ours, which may enable them to
      identify and acquire desirable properties and market their natural gas and
      oil
      production more effectively than we do.




26





*We
      depend on certain key customers for sales of our natural gas. To the extent
      these customers reduce the volumes of natural gas they purchase from us, our
      revenues and cash available for distribution could decline.* In
      Appalachia, our natural gas is sold under contracts with various purchasers.
      Under a natural gas supply agreement with Hess Corporation, which expires on
      March 31, 2009, Hess Corporation has a last right of refusal to buy all of
      the natural gas produced and delivered by our affiliates, and us including
      our
      investment partnerships. During fiscal 2007, natural gas sales to Hess
      Corporation accounted for approximately 18% of our total Appalachian oil and
      gas
      revenues. In Michigan, during the six months ended December 31, 2007, gas under
      contracts to a former affiliate of Atlas Gas & Oil, which expire at various
      dates through 2012, accounted for approximately 62% of our total Michigan oil
      and gas revenues. To the extent these and other key customers reduce the amount
      of natural gas they purchase from us, our revenues and cash available for
      distributions to unitholders could temporarily decline in the event we are
      unable to sell to additional purchasers.





*Our
      Appalachia business depends on the gathering and transportation facilities
      of
      Atlas Pipeline. Any limitation in the availability of those facilities would
      interfere with our ability to market the natural gas we produce and could reduce
      our revenues and cash available for distribution* Atlas
      Pipeline gathers more than 90% of our current Appalachia production and
      approximately 50% of our total production. The marketability of our natural
      gas
      production depends in part on the availability, proximity and capacity of
      gathering and pipeline systems owned by Atlas Pipeline and other third parties.
      The amount of natural gas that can be produced and sold is subject to
      curtailment in circumstances such as pipeline interruptions due to scheduled
      and
      unscheduled maintenance or excessive pressure or physical damage to the
      gathering or transportation system. The curtailments arising from these and
      similar circumstances may last from a few days to several months.





*If
      Atlas America fails to pay gathering fees to Atlas Pipeline as required by
      its
      assumption agreement with us, we will have to pay to Atlas Pipeline the
      difference between the gathering fee payable and the amount we receive from
      our
      investment partnerships for gathering services out of our own resources.* We
      are a
      party to master gas gathering agreements with Atlas Pipeline, which requires,
      among other things, paying Atlas Pipeline gathering fees for gathering our
      gas.
      The gathering agreement is a continuing obligation and not terminable by us,
      except that if Atlas Pipeline’s general partner is removed without cause, then
      no gathering fees will be due under the agreement with respect to new wells
      drilled by us. Atlas America assumed our obligation to pay these gathering
      fees
      pursuant to the contribution agreement entered into at the completion of our
      initial public offering, and we agreed to pay Atlas America the gathering fees
      we receive from our investment partnerships and fees associated with production
      to our interest. The gathering fees payable to Atlas Pipeline generally exceed
      the amount we receive from our investment partnerships for gathering services.
      For the year ended December 31, 2007, this excess amount was approximately
      $11.9
      million. If Atlas America defaulted on its obligation to us under the assumption
      agreement to pay gathering fees to Atlas Pipeline, we would be liable to Atlas
      Pipeline for the payment of the fees, which would reduce our income and cash
      available for payments on the notes.





*Shortages
      of drilling rigs, equipment and crews could delay our operations.* Higher
      natural gas and oil prices generally increase the demand for drilling rigs,
      equipment and crews and can lead to shortages of, and increasing costs for,
      drilling equipment, services and personnel. Over the past three years, we and
      other natural gas and oil companies have experienced higher drilling and
      operating costs. Shortages of, or increasing costs for, experienced drilling
      crews and oil field equipment and services could restrict our ability to drill
      the wells and conduct the operations which we currently have planned. Any delay
      in the drilling of new wells or significant increase in drilling costs could
      reduce our revenues.





*Because
      we handle natural gas and oil, we may incur significant costs and liabilities
      in
      the future resulting from a failure to comply with new or existing environmental
      regulations or an accidental release of hazardous substances into the
      environment.* The
      operations of our wells and other facilities are subject to stringent and
      complex federal, state and local environmental laws and regulations. These
      include, for example:




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




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




27




·
            RCRA
                and comparable state laws that impose requirements for the handling
                and
                disposal of waste from our facilities;
                and




·
            CERCLA
                and comparable state laws that regulate the cleanup of hazardous
                substances that may have been released at properties currently or
                previously owned or operated by us or at locations to which we have
                sent
                waste for disposal.




Failure
      to comply with these laws and regulations may trigger a variety of
      administrative, civil and criminal enforcement measures, including the
      assessment of monetary penalties, the imposition of remedial requirements,
      and
      the issuance of orders enjoining future operations. Certain environmental
      statutes, including the RCRA, CERCLA, the federal Oil Pollution Act and
      analogous state laws and regulations, impose strict, joint and several liability
      for costs required to clean up and restore sites where hazardous substances
      have
      been disposed of or otherwise released. Moreover, it is not uncommon for
      neighboring landowners and other third parties to file claims for personal
      injury and property damage allegedly caused by the release of hazardous
      substances or other waste products into the environment.





There
      is
      an inherent risk that we may incur environmental costs and liabilities due
      to
      the nature of our business and the substances we handle. For example, an
      accidental release from one of our wells could subject us to substantial
      liabilities arising from environmental cleanup and restoration costs, claims
      made by neighboring landowners and other third parties for personal injury
      and
      property damage, and fines or penalties for related violations of environmental
      laws or regulations. Moreover, the possibility exists that stricter laws,
      regulations or enforcement policies may be enacted or adopted and could
      significantly increase our compliance costs and the cost of any remediation
      that
      may become necessary. We may not be able to recover remediation costs under
      our
      insurance policies.





*Many
      of our leases are in areas that have been partially depleted or drained by
      offset wells.* Our
      key
      project areas are located in active drilling areas in the Appalachian Basin.
      As
      a result, many of our leases are in areas that have already been partially
      depleted or drained by earlier offset drilling. This may inhibit our ability
      to
      find economically recoverable quantities of natural gas in these
      areas.





*Our
      identified drilling location inventories are susceptible to uncertainties that
      could materially alter the occurrence or timing of our drilling activities,
      which may result in lower cash from operations.* Our
      management has specifically identified and scheduled drilling locations as
      an
      estimation of our future multi-year drilling activities on our existing acreage.
      As of December 31, 2007, we had identified over 3,950 potential drilling
      locations. These identified drilling locations represent a significant part
      of
      our growth strategy. Our ability to drill and develop these locations depends
      on
      a number of factors, including the availability of capital, seasonal conditions,
      regulatory approvals, natural gas prices, costs and drilling results. In
      addition, our independent petroleum engineering consultants have not assigned
      any proved reserves to the over 2,650 unproved potential drilling locations
      we
      have identified and therefore there may exist greater uncertainty with respect
      to the success of drilling wells at these drilling locations. Our final
      determination on whether to drill any of these drilling locations will be
      dependent upon the factors described above as well as, to some degree, the
      results of our drilling activities with respect to our proved drilling
      locations. Because of these uncertainties, we do not know if the numerous
      drilling locations we have identified will be drilled within our expected
      timeframe or will ever be drilled or if we will be able to produce natural
      gas
      and oil from these or any other potential drilling locations. As such, our
      actual drilling activities may materially differ from our anticipated drilling
      activities.





*Some
      of our undeveloped leasehold acreage is subject to leases that may expire in
      the
      near future.* Leases
      covering approximately 44,900 of our 1,037,300 net acres, or 4%, are scheduled
      to expire on or before December 31, 2008. If we are unable to renew these leases
      or any leases scheduled for expiration beyond December 31, 2008, on favorable
      terms, we will lose the right to develop the acreage that is covered by an
      expired lease and our production would decline, which would reduce our cash
      flows from operations and could impair our ability to make payments on the
      notes.





*Drilling
      for and producing natural gas are high-risk activities with many uncertainties.* Our
      drilling activities are subject to many risks, including the risk that we will
      not discover commercially productive reservoirs. Drilling for natural gas can
      be
      uneconomic, not only from dry holes, but also from productive wells that do
      not
      produce sufficient revenues to be commercially viable. In addition, our drilling
      and producing operations may be curtailed, delayed or canceled as a result
      of
      other factors, including:




28




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




·
            unexpected
                operational events and drilling
                conditions;




·
            adverse
                weather conditions;




·
            facility
                or equipment malfunctions;




·
            title
                problems;




·
            pipeline
                ruptures or spills;




·
            compliance
                with environmental and other governmental
                requirements;




·
            unusual
                or unexpected geological
                formations;




·
            formations
                with abnormal pressures;




·
            injury
                or loss of life;




·
            environmental
                accidents such as gas leaks, ruptures or discharges of toxic gases,
                brine
                or well fluids into the environment or oil leaks, including groundwater
                contamination;




·
            fires,
                blowouts, craterings and explosions;
                and




·
            uncontrollable
                flows of natural gas or well
                fluids.




Any
      one
      or more of the factors discussed above could reduce or delay our receipt of
      drilling and production revenues, thereby reducing our earnings, and could
      reduce revenues in one or more of our investment partnerships, which may make
      it
      more difficult to finance our drilling operations through sponsorship of future
      partnerships. In addition, any of these events can cause substantial losses,
      including personal injury or loss of life, damage to or destruction of property,
      natural resources and equipment, pollution, environmental contamination, loss
      of
      wells and regulatory penalties.





Although
      we will maintain insurance against various losses and liabilities arising from
      our operations, insurance against all operational risks is not available to
      us.
      Additionally, we may elect not to obtain insurance if we believe that the cost
      of available insurance is excessive relative to the perceived risks presented.
      Losses could, therefore, occur for uninsurable or uninsured risks or in amounts
      in excess of existing insurance coverage. The occurrence of an event that is
      not
      fully covered by insurance could reduce our results of operations.





*Properties
      that we buy may not produce as projected and we may be unable to determine
      reserve potential, identify liabilities associated with the properties or obtain
      protection from sellers against such liabilities.* One
      of
      our growth strategies is to capitalize on opportunistic acquisitions of natural
      gas reserves. However, our reviews of acquired properties are inherently
      incomplete because it generally is not feasible to review in depth every
      individual property involved in each acquisition. Even a detailed review of
      records and properties may not necessarily reveal existing or potential
      problems, nor will it permit a buyer to become sufficiently familiar with the
      properties to assess fully their deficiencies and potential. Inspections may
      not
      always be performed on every well we acquire. Potential problems, such as
      deficiencies in the mechanical integrity of equipment or environmental
      conditions that may require significant remedial expenditures, are not
      necessarily observable even when we inspect a well. Any unidentified problems
      could result in material liabilities and costs that negatively affect our
      financial condition and results of operations.





Even
      if
      we are able to identify problems with an acquisition, the seller may be
      unwilling or unable to provide effective contractual protection or indemnity
      against all or part of these problems. Even if a seller agrees to provide
      indemnity, the indemnity may not be fully enforceable and may be limited by
      floors and caps on such indemnity.





*Hedging
      transactions may limit our potential gains or cause us to lose money.* Pricing
      for natural gas has been volatile and unpredictable for many years. To limit
      exposure to changing natural gas prices, we use financial and physical hedges
      for our natural gas production. Physical hedges are not deemed hedges for
      accounting purposes because they require firm delivery of natural gas and are
      considered normal sales of natural gas. We generally limit these arrangements
      to
      smaller quantities than those projected to be available at any delivery point.
      In addition, we may enter into financial hedges, which may include purchases
      of
      regulated NYMEX futures and options contracts and non-regulated over-the-counter
      futures contracts with qualified counterparties. The futures contracts are
      commitments to purchase or sell natural gas at future dates and generally cover
      one-month periods for up to six years in the future. By removing the price
      volatility from a significant portion of our natural gas production, we have
      reduced, but not eliminated, the potential effects of changing natural gas
      prices on our cash flow from operations for those periods. Furthermore, while
      intended to help reduce the effects of volatile natural gas prices, such
      transactions, depending on the hedging instrument used, may limit our potential
      gains if natural gas prices were to rise substantially over the price
      established by the hedge. Under circumstances in which, among other things,
      production is substantially less than expected, the counterparties to our
      futures contracts fail to perform under the contracts or a sudden, unexpected
      event materially impacts natural gas prices, we may be exposed to the risk
      of
      financial loss.




29




*We
      may be exposed to financial and other liabilities as the managing general
      partner in investment partnerships.* We
      serve
      as the managing general partner of 92 investment partnerships and will be the
      managing general partner of new investment partnerships that we sponsor. As
      a
      general partner, we are contingently liable for the obligations of these
      partnerships to the extent that partnership assets or insurance proceeds are
      insufficient. We have agreed to indemnify each investor partner in our
      investment partnerships from any liability that exceeds such partner’s share of
      the investment partnership’s assets.





*We
      are subject to comprehensive federal, state, local and other laws and
      regulations that could increase the cost and alter the manner or feasibility
      of
      our doing business.* Our
      operations are regulated extensively at the federal, state and local levels.
      Environmental and other governmental laws and regulations have increased the
      costs to plan, design, drill, install, operate and abandon natural gas and
      oil
      wells. Under these laws and regulations, we could also be liable for personal
      injuries, property damage and other damages. Failure to comply with these laws
      and regulations may result in the suspension or termination of our operations
      and subject us to administrative, civil and criminal penalties. Moreover, public
      interest in environmental protection has increased in recent years, and
      environmental organizations have opposed, with some success, certain drilling
      projects.





Part
      of
      the regulatory environment in which we operate includes, in some cases, legal
      requirements for obtaining environmental assessments, environmental impact
      studies and/or plans of development before commencing drilling and production
      activities. In addition, our activities are subject to the regulations regarding
      conservation practices and protection of correlative rights. These regulations
      affect our operations and limit the quantity of natural gas we may produce
      and
      sell. A major risk inherent in our drilling plans is the need to obtain drilling
      permits from state and local authorities. Delays in obtaining regulatory
      approvals or drilling permits, the failure to obtain a drilling permit for
      a
      well or the receipt of a permit with unreasonable conditions or costs could
      inhibit our ability to develop our properties. Additionally, the natural gas
      and
      oil regulatory environment could change in ways that might substantially
      increase the financial and managerial costs of compliance with these laws and
      regulations and, consequently, reduce our profitability. Furthermore, we may
      be
      put at a competitive disadvantage to larger companies in our industry who can
      spread these additional costs over a greater number of wells and larger
      operating staff. Please read “Business—Environmental Matters and Regulation” and
“Business—Other Regulation of the Natural Gas and Oil Industry” for a
      description of the laws and regulations that affect us.





*Our
      limited liability company agreement limits and modifies our directors’ and
      officers’ fiduciary duties.* Our
      limited liability company agreement contains provisions that modify and limit
      our directors’ and officers’ fiduciary duties to our unit holders and us. For
      example, our limited liability company agreement provides that:





·
            our
                directors and officers will not have any liability to us or our unit
                holders for decisions made in good faith, which is defined so as
                to
                require that they believed the decision was in our best interests;
                and




·
            our
                directors and officers will not be liable for monetary damages to
                us or
                our unit holders for any acts or omissions unless there has been
                a final
                and non-appealable judgment entered by a court of competent jurisdiction
                determining that the directors or officers acted in bad faith or
                engaged
                in fraud or willful misconduct or, in the case of a criminal matter,
                acted
                with knowledge that such conduct was
                unlawful.





*Members
      of our board of directors and Atlas America and its affiliates, including our
      manager, may have conflicts of interest with us.* Conflicts
      of interest may arise between us and our unit holders and members of our board
      of directors and Atlas America and its affiliates, including our manager. These
      potential conflicts may relate to the divergent interests of these parties.
      Situations in which the interests of members of our board of directors and
      Atlas
      America and its affiliates, may differ from interests of owners of common units
      include, among others, the following situations:




30





·
            Our
                limited liability company agreement gives our board of directors
                broad
                discretion in establishing cash reserves for the proper conduct of
                our
                business, which will affect the amount of cash available for distribution.
                For example, our board of directors will use its reasonable discretion
                to
                establish and maintain cash reserves sufficient to maintain our asset
                base.




·
            Our
                manager will recommend to our board of directors the timing and extent
                of
                our drilling program and related capital expenditures, asset purchases
                and
                sales, and financing alternatives and reserve adjustments, all of
                which
                will affect the amount of cash that we distribute to our unit
                holders.




·
            In
                some instances our board of directors may cause us to borrow funds
                in
                order to permit us to pay cash distributions to our unit holders,
                even if
                the purpose or effect of the borrowing is to make management incentive
                distributions.




·
            Except
                as provided in our omnibus agreement with Atlas America, members
                of our
                board of directors and Atlas America and its affiliates, including
                our
                manager, are not prohibited from investing or engaging in other businesses
                or activities that compete with us.




·
            We
                do not have any employees and rely solely on employees of our manager
                and
                its affiliates. Our officers and the officers of our manager who
                provide
                services to us are not required to work full time on our affairs.
                These
                officers may devote significant time to the affairs of our manager’s
                affiliates. There may be significant conflicts between us and our
                affiliates regarding the availability of these officers to manage
                us.





*Our
      limited liability company agreement provides for a limited call right that
      may
      require unit holders to sell their common units at an undesirable time or price.* If,
      at
      any time, any person owns more than 87.5% of the common units then outstanding,
      such person has the right, but not the obligation, which it may assign to any
      of
      its affiliates or to us, to acquire all, but not less than all, of the remaining
      common units then outstanding at a price not less than the then-current market
      price of the common units. As a result, our unit holders may be required to
      sell
      their common units at an undesirable time or price and therefore may receive
      a
      lower or no return on their investment. Unit holders may also incur tax
      liability upon a sale of their units.





*Our
      manager may transfer its interests in us to a third party without common
      unitholder consent.* Our
      manager may transfer its Class A units and management incentive interests
      to a third party in a merger or in a sale of all or substantially all of its
      assets without the consent of our common unit holders. Furthermore, Atlas
      America is not restricted from transferring its equity interest in our
      manager.





*Atlas
      America may sell common units in the future, which could reduce the market
      price
      of our outstanding units.* Atlas
      America owns 29,352,996 common units. In addition, our manager has the right
      to
      convert its Class A units and management incentive interests into common
      units if we terminate the management agreement, and its Class A units will
      automatically convert into common units, and it will have the option of
      converting its management incentive interests, if the common unit holders vote
      to eliminate the special voting rights of our Class A units. We have agreed
      to register for sale common units held by Atlas America and its affiliates.
      These registration rights allow Atlas America, our manager and their affiliates
      to request registration of their common units and to include any of those units
      in a registration of other securities by us. If Atlas America and its affiliates
      were to sell a substantial portion of their units, it could reduce the market
      price of our outstanding common units.





*We
      depend on our manager and Atlas America, and may not find suitable replacements
      if the management agreement terminates.* We
      have
      no employees. Our support personnel are employees of Atlas America. We have
      no
      separate facilities and completely rely on our manager and, because our manager
      has no direct employees, Atlas America. If our management agreement terminates,
      we may be unable to find a suitable replacement for them.





*Our
      management agreement was not negotiated at arm’s-length and, as a result, may
      not be as favorable to us as if it had been negotiated with a third party.* Our
      officers and four of our directors, Edward E. Cohen, Jonathan Z. Cohen, Richard
      D. Weber and Matthew A. Jones, are officers or directors of our manager, and
      Messrs. Cohen are directors of Atlas America. As a consequence, our management
      agreement was not the result of arm’s-length negotiations and its terms may not
      be as favorable to us as if it had been negotiated with an unaffiliated third
      party.




31





*Expense
      reimbursements due to our manager under our management agreement will reduce
      cash available for distribution to our unit holders.* Before
      making any distribution on our common units, we will reimburse our manager
      for
      all expenses that it incurs on our behalf pursuant to the management agreement.
      These expenses will include all costs incurred on our behalf, including costs
      for providing corporate staff and support services to us. Our manager will
      charge on a fully allocated cost basis for services provided to us. This fully
      allocated cost basis is based on the percentage of time spent by personnel
      of
      our manager and its affiliates on our matters and includes the compensation
      paid
      by our manager and its affiliates to such persons and their allocated overhead.
      The allocation of compensation expense for such persons will be determined
      based
      on a good faith estimate of the value of each such person’s services performed
      on our business and affairs, subject to the periodic review and approval of
      our
      audit or conflicts committee.





*Termination
      of the management agreement by us is difficult.* Termination
      of our management agreement is difficult: we may terminate the management
      agreement only upon the affirmative vote of at least two-thirds of our
      outstanding common units, including units owned by Atlas America and its
      affiliates. Upon any termination, our manager will have the right to convert
      its
      Class A units into common units on a one-for-one basis and convert its
      management incentive interests into common units based on their fair market
      value if the successor manager does not purchase them. Atlas America will be
      able to prevent the removal of our manager so long as it owns at least
      two-thirds of our common units.





*Our
      manager’s liability is limited under the management agreement, and we have
      agreed to indemnify our manager against certain liabilities.* Our
      manager will not assume any responsibility under the management agreement other
      than to render the services called for under it, and will not be responsible
      for
      any action of our board of directors in following or declining to follow its
      advice or recommendations. Our manager, its directors, officers, employees
      and
      affiliates will not be liable to us, any subsidiary of ours, our directors
      or
      our unit holders for acts performed in good faith and in accordance with the
      management agreement, except by reason of acts constituting bad faith, willful
      misconduct, fraud or criminal conduct. We have agreed to indemnify the parties
      for all damages and claims arising from acts not constituting bad faith, willful
      misconduct, fraud or criminal conduct and performed in good faith in accordance
      with and pursuant to the management agreement.





*Our
      limited liability company agreement restricts the voting rights of unit holders
      owning 20% or more of our common units.* Our
      limited liability company agreement restricts the voting rights of common unit
      holders by providing that any units held by a person that owns 20% or more
      of
      any class of units then outstanding, other than Atlas America, our manager,
      their affiliates or transferees and persons who acquire such units with the
      prior approval of our board of directors, cannot vote on any matter. Our limited
      liability company agreement also contains provisions limiting the ability of
      common unit holders to call meetings or to acquire information about our
      operations, as well as other provisions limiting common unit holders’ ability to
      influence the manner or direction of management.





*If
      the holders of our common units vote to eliminate the special voting rights
      of
      the holders of our Class A units, the Class A units will automatically
      convert into common units on a one-for-one basis and our manager will have
      the
      option of converting the management incentive interests into common units at
      their fair market value, which may be dilutive to you.* The
      holders of our Class A units have the right to vote as a separate class on
      extraordinary transactions submitted to a unitholder vote such as a merger
      or
      sale of all or substantially all of our assets. This right can be eliminated
      upon a vote of the holders of not less than two-thirds of our outstanding common
      units. If such elimination is so approved, the Class A units will
      automatically convert into common units on a one-for-one basis and our manager
      will have the right to convert its management incentive interests into common
      units based on their then fair market value, which may be dilutive to
      you.





*Our
      tax treatment depends on our status as a partnership for federal income tax
      purposes, as well as our not being subject to entity-level taxation by
      individual states. If the IRS were to treat us as a corporation for federal
      income tax purposes or we were to become subject to entity-level taxation for
      state tax purposes, taxes paid, if any, would reduce the amount of cash
      available for distribution.* The
      anticipated after-tax benefit of an investment in our common units depends
      largely on our being treated as a partnership for federal income tax purposes.
      We have not requested, and do not plan to request, a ruling from the IRS on
      this
      or any other tax matter that affects us.If we were treated as a corporation
      for
      federal income tax purposes, we would pay federal income tax on our taxable
      income at the corporate tax rates, currently at a maximum rate of 35%, and
      would
      likely pay state income tax at varying rates. Distributions to you would
      generally be taxed as corporate distributions, and no income, gain, loss,
      deduction or credit would flow through to you. Because a tax may be imposed
      on
      us as a corporation, our cash available for distribution to our unit holders
      could be reduced. Therefore, our treatment as a corporation could result in
      a
      material reduction in the anticipated cash flow and after-tax return to our
      unit
      holders and therefore result in a substantial reduction in the value of our
      common units. Current law or our business may change so as to cause us to be
      treated as a corporation for federal income tax purposes or otherwise subject
      us
      to entity-level taxation. In addition, because of widespread state budget
      deficits, several states are evaluating ways to subject partnerships to
      entity-level taxation through the imposition of state income, franchise or
      other
      forms of taxation. If any state were to impose a tax upon us as an entity,
      the
      cash available for distribution to you would be reduced. Our limited liability
      company agreement provides that if a law is enacted or existing law is modified
      or interpreted in a manner that subjects us to taxation as a corporation or
      otherwise subjects us to entity-level taxation for federal, state or local
      income tax purposes, the IQD amount and the incentive distribution amounts
      will
      be adjusted to reflect the impact of that law on us.




32




*We
      will be considered to have terminated for tax purposes due to a sale or exchange
      of 50% or more of our interests within a twelve-month period.* We
      will
      be considered to have terminated for tax purposes if there is a sale or exchange
      of 50% or more of the total interests in our capital and profits within a
      twelve-month period. A constructive termination results in the closing of our
      taxable year for all unit holders and in the case of a unitholder reporting
      on a
      taxable year other than a fiscal year ending December 31, may result in
      more than 12 months of our taxable income or loss being includable in
      taxable income for the year of termination. A constructive termination occurring
      on a date other than December 31 will result in us filing two tax returns,
      and unit holders receiving two Schedule K-1s, for one fiscal year and the
      cost of the preparation of these returns will be borne by all unit
      holders.





**ITEM
      1B:****UNRESOLVED
      STAFF COMMENTS**





None





**ITEM
      2:**  **PROPERTIES**





**Office
      Properties**





We
      lease
      a 27,000 square foot office building in Moon Township, Pennsylvania. We own
      a
      17,000 square foot field office and warehouse facility in Jackson Center,
      Pennsylvania, a 24,000 square foot office in Fayette County, Pennsylvania and
      an
      office in Deerfield, Ohio. We lease a 13,800 square foot office building in
      Traverse City, Michigan under a lease expiring in 2012. We lease a 1,400 square
      foot field office in Ohio under a lease expiring in 2009. We also rent 17,200
      square feet of office space in Uniontown, Ohio under a lease expiring in August
      2008. We also lease other field offices in Ohio and New York on a month-to-month
      basis.





**Natural
      Gas and Oil Reserves**





The
      following tables summarize information regarding our estimated proved natural
      gas and oil reserves as of the dates indicated. Proved reserves are the
      estimated quantities of crude oil, natural gas, and natural gas liquids, which
      geological and engineering data demonstrate with reasonable certainty to be
      recoverable in future years from known reservoirs under existing economic and
      operating conditions, i.e., prices and costs as of the date the estimate is
      made. Prices include consideration of changes in existing prices provided only
      by contractual arrangements, but not on escalations based upon future
      conditions. The estimated reserves include reserves attributable to our direct
      ownership interests in oil and gas properties as well as the reserves
      attributable to our percentage interests in the oil and gas properties owned
      by
      investment partnerships in which we own partnership interests. All of the
      reserves are generally located in the Appalachian
      Basin and in Michigan’s Lower Peninsula .
      We base
      these estimated proved natural gas and oil reserves and future net revenues
      of
      natural gas and oil reserves upon reports prepared by independent petroleum
      engineers. **** In
      accordance with SEC guidelines, we make the standardized measure and PV-10
      estimates of future net cash flows from proved reserves using natural gas and
      oil sales prices in effect as of the dates of the estimates, which are held
      constant throughout the life of the properties. We based our estimates of proved
      reserves upon the following weighted average prices as of the dates
      indicated:




33




**At
                December 31,**
            
            **At
                September 30,****2007**
            
            **2006**
            
            **2005**
            
            **2005**Natural
                gas (per Mcf)
            
            $
            6.93
            
            $
            6.33
            
            $
            10.84
            
            $
            14.75Oil
                (per Bbl)
            
            $
            90.30
            
            $
            57.26
            
            $
            57.54
            
            $
            63.29





Reserve
      estimates are imprecise and may change as additional information becomes
      available. Furthermore, estimates of natural gas and oil reserves are
      projections based on engineering data. There are uncertainties inherent in
      the
      interpretation of this data as well as the projection of future rates of
      production and the timing of development expenditures. Reservoir engineering
      is
      a subjective process of estimating underground accumulations of natural gas
      and
      oil that cannot be measured in an exact way and the accuracy of any reserve
      estimate is a function of the quality of available data and of engineering
      and
      geological interpretation and judgment. Reserve reports of other engineers
      might
      differ from the reports of our consultants, Wright & Company. Results
      of drilling, testing and production subsequent to the date of the estimate
      may
      justify revision of this estimate. Future prices received from the sale of
      natural gas and oil may be different from those estimated by our independent
      petroleum engineering firm in preparing their reports. The amounts and timing
      of
      future operating and development costs may also differ from those used.
      Accordingly, the reserves set forth in the following tables ultimately may
      not
      be produced and the proved undeveloped reserves may not be developed within
      the
      periods anticipated. Please read “Item1A: Risk factors” You should not construe
      the estimated PV-10 and standardized measure values as representative of the
      current or future fair market value of our proved natural gas and oil
      properties. PV-10 and standardized measure values are based upon projected
      cash
      inflows, which do not provide for changes in natural gas and oil prices or
      for
      the escalation of expenses and capital costs. The meaningfulness of these
      estimates depends upon the accuracy of the assumptions upon which they were
      based.





We
      evaluate natural gas reserves at constant temperature and pressure. A change
      in
      either of these factors can affect the measurement of natural gas reserves.
      We
      deduct operating costs, development costs and production-related and ad valorem
      taxes in arriving at the estimated future cash flows. We base the estimates
      on
      operating methods and conditions prevailing as of the dates
      indicated.





**Proved
                natural**
            
            **Proved
                natural****gas
                and oil reserves for**
            
            **gas
                and****oil
                reserves for****Atlas
                Energy Resources at**
            
            **Atlas
                America E&P Operations at****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2005**
            
            **2005**Natural
                gas reserves (Mmcf):Proved
                developed reserves
            
            
            594,709
            
            
            107,683
            
            
            108,674
            
            
            104,786Proved
                undeveloped reserves (1)
            
            
            290,050
            
            
            60,859
            
            
            49,250
            
            
            53,241Total
                proved reserves of natural gas
            
            
            884,759
            
            
            168,542
            
            
            157,924
            
            
            158,027Oil
                reserves (Mbbl):Proved
                developed reserves
            
            
            1,977
            
            
            2,064
            
            
            2,122
            
            
            2,116Proved
                undeveloped reserves
            
            
            6
            
            
            4
            
            
            135
            
            
            143Total
                proved reserves of oil
            
            
            1,983
            
            
            2,068
            
            
            2,257
            
            
            2,259Total
                proved reserves (Mmcfe)
            
            
            896,657
            
            
            180,950
            
            
            171,466
            
            
            171,581PV-10
                estimate of cash flows of proved reserves (in thousands)
                (2):Proved
                developed reserves
            
            $
            1,264,309
            
            $
            279,330
            
            $
            465,459
            
            $
            617,445Proved
                undeveloped reserves
            
            
            216,869
            
            
            4,111
            
            
            131,678
            
            
            228,206Total
                PV-10 estimate (3)
            
            $
            1,481,178
            
            $
            283,441
            
            $
            597,137
            
            $
            845,651Standardized
                measure of discounted future cash flows (in thousands) (2)
                (3)
            
            $
            1,481,178
            
            $
            283,441
            
            $
            429,272
            
            $
            606,697


**___________**




(1)
            Our
                ownership in these reserves is subject to reduction as we generally
                contribute leasehold acreage associated with our proved undeveloped
                reserves to our investment partnerships in exchange for an approximate
                30%
                equity interest in these partnerships, which effectively will reduce
                our
                ownership interest in these reserves from 100% to 30% as we make
                these
                contributions.




34




(2)
            Amounts
                shown for September 30, 2005 and December 31, 2005 reflect values
                for
                Atlas America E&P Operations, which paid income taxes. Amounts shown
                for December 31, 2006 and 2007 reflect values for our reserves. Since
                we
                are a limited liability company that allocates our taxable income
                to our
                unit holders, no provision for federal or state income taxes has
                been
                included in the December 31, 2006 and 2007 calculations of standardized
                measure which is, therefore, the same as the PV-10 value. Amounts
                include
                physical hedges but not financial hedging transactions.




(3)
            The
                following reconciles the PV-10 value to the standardized
                measure:




**Proved
                natural gas and oil reserves for**
            
            **Proved
                natural gas and oil reserves for****Atlas
                Energy Resources at**
            
            **Atlas
                America E&P Operations at****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2005**
            
            **2005**PV-10
                value
            
            $
            1,481,178
            
            $
            283,441
            
            $
            597,137
            
            $
            845,651Income
                tax effect
            
            
            —
            
            
            —
            
            
            (167,865
            )
            
            (238,954
            )Standardized
                measure
            
            $
            1,481,178
            
            $
            283,441
            
            $
            429,272
            
            $
            606,697




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





**Productive
      Wells**





The
      following table sets forth information as of December 31, 2007, regarding
      productive natural gas and oil wells in which we have a working interest.
      Productive wells consist of producing wells and wells capable of production,
      including natural gas wells awaiting pipeline connections to commence deliveries
      and oil wells awaiting connection to production facilities. Gross wells are
      the
      total number of producing wells in which we have an interest, directly or
      through our ownership interests in investment partnerships, and net wells are
      the sum of our fractional working interests in gross wells, based on the
      percentage interest we own in the investment partnership that owns the
      well.





**Number
                of productive wells****Gross****(1)**
            
            **Net****(1)**Oil
                wells
            
            
            512
            
            
            368Gas
                wells
            
            
            9,502
            
            
            5,211Total
            
            
            10,014
            
            
            5,579





____________


(1)
            Includes
                our proportionate interest in wells owned by 92 investment partnerships
                for which we serve as managing general partner and various joint
                ventures.
                Does not include royalty or overriding interests in 705
                wells.





**Gas
      and Oil Production**





The
      following table sets forth the quantities of our natural gas and oil production,
      average sales prices and average production costs per equivalent unit of
      production for the periods indicated.





**Average****production****Production**
            
            **Average
                sales price**
            
            **cost
                per****Period**
            
            **Oil
                (Bbls)**
            
            **Gas
                (Mcf)**
            
            **per
                Bbl**
            
            **per
                Mcf****(1)**
            
            **Mcfe****(2)**Year
                ended December 31, 2007
            
            
            153,465
            
            
            20,963,436
            
            $
            70.16
            
            $
            8.66
            
            $
            1.47Year
                ended December 31, 2006
            
            
            150,628
            
            
            8,946,376
            
            $
            62.30
            
            $
            8.83
            
            $
            1.41Three
                months ended December 31, 2005
            
            
            39,678
            
            
            1,975,099
            
            $
            56.13
            
            $
            11.06
            
            $
            1.10Year
                ended September 30, 2005
            
            
            157,904
            
            
            7,625,695
            
            $
            50.91
            
            $
            7.26
            
            $
            .95





(1)
            Average
                sales price before the effects of financial hedging was $7.22 and
                $7.90
                for the year ended December 31, 2007 and 2006, respectively. We did
                not
                have any financial hedging transactions in any of the other periods
                presented.


(2)
            Production
                costs include labor to operate the wells and related equipment, repairs
                and maintenance, materials and supplies, property taxes, severance
                taxes,
                insurance, gathering charges and production
                overhead.




35




**Developed
      and Undeveloped Acreage**





The
      following table sets forth information about our developed and undeveloped
      natural gas and oil acreage as of December 31, 2007. The information in this
      table includes our proportionate interest in acreage owned by our investment
      partnerships. The table does not include the approximately 212,000 acres in
      Tennessee covered by our joint venture with Knox Energy because we do not own
      this acreage.





**Developed
                acreage**
            
            **Undeveloped
                acreage****Gross**
            
            **Net**
            
            **Gross**
            
            **Net**Arkansas
            
            
            2,560
            
            
            403
            
            
            —
            
            
            —Kansas
            
            
            160
            
            
            20
            
            
            —
            
            
            —Kentucky
            
            
            924
            
            
            462
            
            
            9,060
            
            
            4,530Louisiana
            
            
            1,819
            
            
            206
            
            
            —
            
            
            —Michigan
            
            
            293,999
            
            
            231,869
            
            
            63,005
            
            
            53,262Mississippi
            
            
            40
            
            
            3
            
            
            —
            
            
            —Montana
            
            
            —
            
            
            —
            
            
            2,650
            
            
            2,650New
                York
            
            
            20,517
            
            
            14,972
            
            
            45,123
            
            
            45,123North
                Dakota
            
            
            639
            
            
            96
            
            
            —
            
            
            —Ohio
            
            
            114,033
            
            
            95,913
            
            
            32,025
            
            
            32,025Oklahoma
            
            
            4,323
            
            
            468
            
            
            —
            
            
            —Pennsylvania
            
            
            123,898
            
            
            123,898
            
            
            376,002
            
            
            376,002Tennessee
            
            
            14,689
            
            
            13,411
            
            
            31,177
            
            
            31,177Texas
            
            
            4,520
            
            
            329
            
            
            —
            
            
            —West
                Virginia
            
            
            1,078
            
            
            539
            
            
            12,530
            
            
            9,852Wyoming
            
            
            —
            
            
            —
            
            
            80
            
            
            80583,199
            
            
            482,589
            
            
            571,652
            
            
            554,701


________________


(1)
            Developed
                acres are acres spaced or assigned to productive
                wells.


(2)
            Undeveloped
                acres are acres on which wells have not been drilled or completed
                to a
                point that would permit the production of commercial quantities of
                natural
                gas or oil, regardless of whether such acreage contains proved
                reserves.


(3)
            A
                gross acre is an acre in which we own an interest. The number of
                gross
                acres is the total number of acres in which we own an
                interest.


(4)
            Net
                acres are the sum of the fractional interests owned in gross acres.
                For
                example, a 50% interest in an acre is one gross acre but is 0.50
                net
                acre.





The
      leases for our developed acreage generally have terms that extend for the life
      of the wells, while the leases on our undeveloped acreage have terms that vary
      from less than one year to five years. We paid rentals of approximately
      $ 2.4
      million in fiscal 2007 to maintain our leases.





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





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




36




**Drilling
      Activity**





The
      number of wells we drill will vary depending on the amount of money we raise
      through our investment partnerships, the cost of each well, the estimated
      recoverable reserves attributable to each well and accessibility to the well
      site. The following table sets forth information with respect to the number
      of
      wells in which we have completed drilling during the periods indicated,
      regardless of when we initiated drilling


**Development
                  wells**
              
              **Exploratory
                  wells****Productive**
              
              **Dry**
              
              **Productive**
              
              **Dry****Gross****(1)**
              
              **Net****(2)**
              
              **Gross****(1)**
              
              **Net****(2)**
              
              **Gross****(1)**
              
              **Net****(2)**
              
              **Gross****(1)**
              
              **Net****(2)**Appalachia:Year
                  ended December 31, 2007
              
              
              1106.0
              
              
              377.6
              
              
              11.0
              
              
              4.0
              
              
              —
              
              
              —
              
              
              —
              
              
              —Year
                  ended December 31, 2006
              
              
              711.0
              
              
              235.3
              
              
              4.0
              
              
              1.4
              
              
              —
              
              
              —
              
              
              —
              
              
              —Three
                  months ended December 31, 2005
              
              
              192.0
              
              
              64.1
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Year
                  ended September 30, 2005
              
              
              644.0
              
              
              210.0
              
              
              18.0
              
              
              6.3
              
              
              —
              
              
              —
              
              
              —
              
              
              —Michigan:Year
                  ended December 31, 2007
              
              
              115.0
              
              
              92.23
              
              
              ―
              
              
              ―
              
              
              —
              
              
              —
              
              
              —
              
              
              —


________________




(1)
            Includes
                the number of physical wells in which we hold any working interest,
                regardless of our percentage
                interest.




(2)
            Includes
                (i) our percentage interest in wells in which we have a direct
                ownership interest and (ii) with respect to wells in which we have an
                indirect ownership interest through our investment partnerships,
                our
                percentage interest in the wells based on our percentage interest
                in our
                investment partnerships and not those of the other partners in our
                investment partnerships.




**ITEM
      3:**  **LEGAL
      PROCEEDINGS**





One
      of
      our subsidiaries, Resource Energy, LLC, together with Resource America, Inc.,
      (the former parent of AAI), was a defendant in a class action originally filed
      in February 2000 in the New York Supreme Court, Chautauqua County, by
      individuals, putatively on their own behalf and on behalf of similarly situated
      individuals, who leased property to us. The complaint alleged that we were
      not
      paying landowners the proper amount of royalty revenues with respect to natural
      gas produced from the leased properties. The complaint was seeking damages
      in an
      unspecified amount for the alleged difference between the amount of royalties
      actually paid and the amount of royalties that allegedly should have been paid.
      In April 2007, a settlement of this lawsuit was approved by the court. Pursuant
      to the settlement terms, we paid $300,000 in May 2007, upgraded certain
      gathering systems and capped certain transportation expenses chargeable to
      the
      landowners. We were indemnified by AAI for this matter .





Atlas
      Gas
& Oil Company LLC, as successor to DTE Gas & Oil Company, was one of
      four defendants in a personal injury action filed in Antrim County Circuit
      Court
      in northern Michigan in August 2006.  The complaint alleged that plaintiff
      suffered serious personal injuries as a result of the defendants’ negligence.
      The Company paid $125,000 to the plaintiff in October 2007 in full settlement
      of
      this action.





We
      are
      also a party to various routine legal proceedings arising in the ordinary course
      of our business. Management believes that none of these actions, individually
      or
      in the aggregate, will have a material adverse effect on our financial condition
      or results of results of operations.




**ITEM
      4:**  **SUBMISSION
      OF MATTERS TO A VOTE OF SECURITY HOLDERS**





On
      November 11, 2007 Atlas America, Inc. and Atlas Energy Management, Inc. took
      action by written resolutions in lieu of a special meeting of unitholders to
      approve (a) the change in the terms of our then outstanding Class D units to
      provide that each Class D unit would convert automatically into one of our
      common units and (b) the issuance of 16,702,827 common units to be issued upon
      such conversion. On that date, Atlas America and Atlas Energy Management
      collectively held 30,591,982 of our common units and Class A units, representing
      approximately 80.61% of our then outstanding voting units. We provided an
      information statement to each unitholder relating to this action on or about
      October 22, 2007.





37




**PART
      II**


ITEM
      5: **MARKET
      FOR REGISTRANT'S COMMON EQUITY, RELATED SHAREHOLDER** **MATTERS
      AND ISSUER PURCHASES OF EQUITY SECURITIES**





Our
      common units are quoted on the New York Stock Exchange (“NYSE”) under the symbol
      "ATN." The following table sets forth the high and low sale prices, as reported
      by the NYSE, on a quarterly basis since our initial public offering in December
      2006.





**Fiscal
                2007**
            
            **High**
            
            **Low**Fourth
                Quarter
            
            $
            36.00
            
            $
            28.50Third
                Quarter
            
            $
            38.85
            
            $
            28.75Second
                Quarter
            
            $
            37.47
            
            $
            26.26First
                Quarter
            
            $
            27.46
            
            $
            22.10**Fiscal
                2006**
            
            
            **High**
            
            
            **Low**Fourth
                Quarter
            
            $
            22.88
            
            $
            21.80





As
      of
      February 11, 2008, there were 60,710,749 common units outstanding held by 48
      holders of record. For a description of our recent sale of unregistered
      securities, see our Current Report on Form 8-K filed June 29, 2007.





**Our
      Cash Distribution Policy**





Our
      limited liability company agreement requires that, within 45 days after the
      end
      of each quarter, beginning with the quarter ending December 31, 2006, we
      distribute all of our available cash to unit holders of record on the applicable
      record date.





Available
      cash generally means, for each fiscal quarter, all cash on hand at the end
      of
      the quarter:





·
            less
                the amount of cash reserves established by our board of directors
                to:


o
            provide
                for the proper conduct of our business (including reserves for future
                capital expenditures and credit
                needs);


o
            comply
                with applicable law and any of our debt instruments or other agreements;
                and


o
            provide
                funds for distributions (1) to our unit holders for any one or more
                of the
                next four quarters or (2) with respect to our management incentive
                interests;


·
            plus
                all cash on hand on the date of determination of available cash for
                the
                quarter resulting from working capital borrowings made after the
                end of
                the quarter.





Working
      capital borrowings are borrowings that are made under our credit facility or
      another arrangement and used solely for working capital purposes or to pay
      distributions to unit holders.





On
      January 28, 2008, we declared a quarterly cash distribution for the fourth
      quarter of 2007 of $0.57 per common unit, which was paid on February 14, 2008
      to
      common unit holders of record as of February 7, 2008.





For
      information concerning common units authorized for issuance under our incentive
      plan, see “Item 12: Security Ownership or Certain Beneficial Owners and
      Management─Equity
      Compensation Plan Information.”




38




**ITEM
      6.**  **SELECTED
      FINANCIAL DATA**





The
      following table sets forth selected historical combined financial and operating
      data for our predecessor, Atlas America E&P Operations before the date of
      our initial public offering on December 18, 2006 and our historical combined
      and consolidated financial and operating data after that date for the
      periods indicated. Atlas America E&P Operations were the subsidiaries of
      Atlas America which held its natural gas and oil development and production
      assets and liabilities, substantially all of which Atlas America transferred
      to
      us upon the completion of our initial public offering. We derived the historical
      financial data as of December 31, 2007 and 2006 and for the years ended December
      31, 2007 and 2006, the three months ended December 31, 2005 and the year ended
      September 30, 2005 from Atlas Energy Resources, LLC and Atlas America E&P
      Operations’ financial statements, which were audited by Grant Thornton LLP, an
      independent registered public accounting firm, and are included in this report.
      We derived the historical financial data as of December 31, 2005, September
      30,
      2005 and 2004 and for the year ended September 30, 2004 from Atlas E&P
      Operations’ audited financial statements, which are not included in this report.
      We derived the historical financial data as of September 30, 2003, and for
      the
      year ended September 30, 2003 from Atlas America E&P Operations’ unaudited
      financial statements, which are not included in this report.





You
      should read the following financial data in conjunction with “Management’s
      discussion and analysis of financial condition and results of operations” and
      our financial statements and related notes appearing elsewhere in this
      report.





39





**Three
                Months****Ended****Years
                Ended December 31,**
            
            **December
                31,**
            
            **Years
                Ended September 30,****2007**
            
            **2006**
            
            **2005**
            
            **2005**
            
            **2004**
            
            **2003**(in
                thousands)Income
                statement data:Revenues:Gas
                and oil production
            
            $
            180,125
            
            $
            88,449
            
            $
            24,086
            
            $
            63,499
            
            $
            48,526
            
            $
            38,639Partnership
                management:Well
                construction andcompletion
            
            
            321,471
            
            
            198,567
            
            
            42,145
            
            
            134,338
            
            
            86,880
            
            
            52,879Administration
                and oversight
            
            
            18,138
            
            
            11,762
            
            
            2,964
            
            
            9,590
            
            
            8,396
            
            
            5,090Well
                services
            
            
            17,592
            
            
            12,953
            
            
            2,561
            
            
            9,552
            
            
            8,430
            
            
            7,635Gathering
                (1)
            
            
            14,314
            
            
            9,251
            
            
            1,407
            
            
            4,359
            
            
            4,191
            
            
            3,898Gain
                on mark-to-market derivatives
            
            
            26,257
            
            
            ─
            
            
            ─
            
            
            ─
            
            
            ─
            
            
            ─Total
                revenues
            
            
            577,897
            
            
            320,982
            
            
            73,163
            
            
            221,338
            
            
            156,423
            
            
            108,141Expenses:Gas
                and oil production (1)
            
            
            32,193
            
            
            13,881
            
            
            2,441
            
            
            8,165
            
            
            7,289
            
            
            6,770Partnership
                management:Well
                construction andcompletion
            
            
            279,540
            
            
            172,666
            
            
            36,648
            
            
            116,816
            
            
            75,548
            
            
            45,982Well
                services
            
            
            9,062
            
            
            7,337
            
            
            1,487
            
            
            5,167
            
            
            4,398
            
            
            3,773Gathering
                (1)
            
            
            214
            
            
            —
            
            
            38
            
            
            52
            
            
            53
            
            
            29Gathering
                fee - Atlas Pipeline (1)
            
            
            13,781
            
            
            29,545
            
            
            7,930
            
            
            21,929
            
            
            17,189
            
            
            14,564General
                and administrative
            
            
            39,414
            
            
            23,367
            
            
            5,818
            
            
            13,202
            
            
            11,708
            
            
            10,106Net
                expense reimbursement - affiliate
            
            
            ─
            
            
            1,237
            
            
            163
            
            
            602
            
            
            1,050
            
            
            1,400Depreciation,
                depletion andamortization
            
            
            56,942
            
            
            22,491
            
            
            4,916
            
            
            14,061
            
            
            12,064
            
            
            9,938Total
                operating expenses
            
            
            431,146
            
            
            270,524
            
            
            59,441
            
            
            179,994
            
            
            129,299
            
            
            92,562Operating
                income
            
            
            146,751
            
            
            50,458
            
            
            13,722
            
            
            41,344
            
            
            27,124
            
            
            15,579Other
                income (expenses):Interest
                expense
            
            
            (30,096
            )
            
            ─
            
            
            ─
            
            
            ─
            
            
            ─
            
            
            ─Other
                - net
            
            
            849
            
            
            1,369
            
            
            57
            
            
            79
            
            
            444
            
            
            358Total
                other income(expense)
            
            
            (29,247
            )
            
            1,369
            
            
            57
            
            
            79
            
            
            444
            
            
            358Net
                income before cumulative effect of accounting change
            
            
            117,504
            
            
            51,827
            
            
            13,779
            
            
            41,423
            
            
            27,568
            
            
            15,937Cumulative
                effect of accounting change (2)
            
            
            ─
            
            
            6,355
            
            
            —
            
            
            —
            
            
            —
            
            
            —Net
                income
            
            $
            117,504
            
            $
            58,182
            
            $
            13,779
            
            $
            41,423
            
            $
            27,568
            
            $
            15,937Cash
                flow data:Cash
                provided by operatingactivities
            
            $
            230,982
            
            $
            80,536
            
            $
            43,596
            
            $
            90,525
            
            $
            42,523
            
            $
            20,365Cash
                used in investing activities
            
            
            (1,468,434
            )
            
            (75,588
            )
            
            (17,185
            )
            
            (59,050
            )
            
            (32,709
            )
            
            (22,112
            )Cash
                provided by (used in)financing
                activities
            
            
            1,253,877
            
            
            (17,033
            )
            
            (11,739
            )
            
            (25,401
            )
            
            (14,916
            )
            
            34Capital
                expenditures
            
            $
            196,735
            
            $
            75,635
            
            $
            17,187
            
            $
            59,124
            
            $
            33,252
            
            $
            22,607Other
                financial information(unaudited):EBITDA
            
            $
            204,542
            
            $
            74,318
            
            $
            18,695
            
            $
            55,484
            
            $
            39,632
            
            $
            25,875Adjusted
                EBITDA
            
            $
            199,099
            
            $
            94,949
            
            $
            25,649
            
            $
            73,109
            
            $
            52,747
            
            $
            36,570Balance
                sheet data (at period end):Total
                assets
            
            $
            1,891,234
            
            $
            415,463
            
            $
            315,052
            
            $
            270,402
            
            $
            198,454
            
            $
            178,451Liabilities
                associated withdrilling
                contracts
            
            
            132,517
            
            
            86,765
            
            
            70,514
            
            
            60,971
            
            
            29,375
            
            
            22,157Advances
                from affiliates
            
            
            8,696
            
            
            12,502
            
            
            4,257
            
            
            13,897
            
            
            30,008
            
            
            34,776Long-term
                debt, includingcurrent
                maturities
            
            
            740,030
            
            
            68
            
            
            156
            
            
            81
            
            
            420
            
            
            194Total
                equity
            
            $
            836,115
            
            $
            212,682
            
            $
            154,519
            
            $
            146,142
            
            $
            109,461
            
            $
            102,031





40




_____________


(1)
            We
                charge gathering fees to our investment partnership wells that are
                connected to Atlas Pipeline’s gathering systems. Historically, we in turn
                paid these fees, plus an additional amount to bring the total gathering
                charge up to, generally, 16% of the gas sales price, to Atlas Pipeline
                in
                accordance with our gathering agreements with it. Upon the completion
                of
                our initial public offering, Atlas America assumed our obligation
                to pay
                gathering fees to Atlas Pipeline. We are obligated to pay the gathering
                fees we receive from our investment partnerships to Atlas America,
                with
                the result that our gathering revenues and expenses within our partnership
                management segment net to $0. We also pay our proportionate share
                of
                gathering fees based on our percentage interest in the well, which
                are
                included in gas and oil production expense. Atlas America E & P
                Operations also owned several small gathering systems. The expenses
                associated with these systems are shown as gathering fees on our
                combined
                statements of income. We do not own these gathering systems after
                the
                completion of our initial public
                offering.





(2)
            The
                cumulative effect of accounting change results from our adoption
                of FIN 47
                (see Notes 2 and 5 to our combined and consolidated financial
                statements).





**EBITDA
      AND ADJUSTED EBITDA**





We
      define
      EBITDA as earnings before interest, taxes, depreciation, depletion, and
      amortization and cumulative effect of accounting change. We calculate Adjusted
      EBITDA by adjusting EBITDA for other non-cash items such as equity compensation.
      EBITDA and Adjusted EBITDA are not measures of performance calculated in
      accordance with GAAP. Although not prescribed under GAAP, we believe the
      presentation of EBITDA and Adjusted EBITDA are relevant and useful because
      they
      help our investors to understand our operating performance and make it easier
      to
      compare our results with other companies that have different financing and
      capital structures or tax rates. EBITDA and Adjusted EBITDA should not be
      considered in isolation of, or as a substitute for, net income as an indicator
      of operating performance or cash flows from operating activities as a measure
      of
      liquidity. EBITDA, as we calculate it, may not be comparable to EBITDA measures
      reported by other companies and may be different from the EBITDA calculation
      under our credit facility. In addition, EBITDA and Adjusted EBITDA do not
      represent funds available for discretionary use. The following reconciles our
      net income before taxes and cumulative effect of accounting change to our EBITDA
      and Adjusted EBITDA for the periods indicated:


**Three
                Months****Ended**
            
            **Years
                Ended****Years
                Ended December 31,**
            
            **December
                31,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2005**
            
            **2005**
            
            **2004**
            
            **2003****(in
                thousands)**Net
                income before cumulative effect of accounting change
            
            $
            117,504
            
            $
            51,827
            
            $
            13,779
            
            $
            41,423
            
            $
            27,568
            
            $
            15,937Plus
                interest expense
            
            
            30,096
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Plus
                depreciation, depletion and amortization
            
            
            56,942
            
            
            22,491
            
            
            4,916
            
            
            14,061
            
            
            12,064
            
            
            9,938EBITDA
            
            
            204,542
            
            
            74,318
            
            
            18,695
            
            
            55,484
            
            
            39,632
            
            
            25,875Less
                gain on mark-to-market derivatives
            
            
            (14,000
            )
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Plus
                non-recurring derivative fees
            
            
            3,873Plus
                non-cash stock compensation
            
            
            4,684
            
            
            337
            
            
            393
            
            
            300
            
            
            64
            
            
            —Plus
                gathering fee
            
            
            ─
            
            
            20,294
            
            
            6,561
            
            
            17,622
            
            
            13,051
            
            
            10,695Adjusted
                EBITDA
            
            $
            199,099
            
            $
            94,949
            
            $
            25,649
            
            $
            73,109
            
            $
            52,747
            
            $
            36,570





41




**ITEM
      7:**  **Management’s
      D** **iscussion
      and Analysis of Financial Condition and Results of
      Operations**




**GENERAL**





**Manner
      of Presentation**





The
      historical financial statements prior to our initial public offering on December
      18, 2006 included in this report reflect substantially all the assets,
      liabilities and operations of various wholly-owned subsidiaries of Atlas
      America, which were contributed to us upon the closing of our initial public
      offering. We refer to these subsidiaries’ assets, liabilities and operations as
      Atlas America E & P Operations or our predecessor. The following discussion
      analyzes and includes the financial condition and results of operations of
      Atlas
      America E & P Operations before the date of our initial public offering and
      our results after the date of our initial public offering. You should read
      the
      following discussion of the financial condition and results of operations in
      conjunction with the historical combined and consolidated financial statements
      and notes to combined and consolidated financial statements included elsewhere
      in this report. Additionally, you should read “Forward-looking statements” and
“Item 1A: Risk Factors” for information regarding some of the risks inherent in
      our business.





**Change
      in Year End**




On
      June
      15, 2006, Atlas America’s board of directors changed our predecessor’s year-end
      from September 30 to December 31. As a result, the financial results now being
      reported by us relate to the years ended December 31, 2007 and 2006, the
      three-month transitional period ended December 31, 2005, and the year ended
      September 30, 2005. Thus, our financial statements do not present a prior
      one-year financial period on which to base a comparative discussion with the
      year ended December 31, 2006.





**Comparability
      of Financial Statements**





The
      historical financial statements of Atlas America E & P Operations included
      in this report are not comparable to our results of operations following our
      initial public offering for the following reasons:





·
            Historically,
                pursuant to an agreement with Atlas America, Atlas Pipeline received
                gathering fees generally equal to 16% of the gas sales price of gas
                gathered through its system. Each partnership pays us gathering fees
                generally equal to 13% of the gas sales price. After the closing
                of our
                initial public offering, we pay the amount we receive from the
                partnerships to Atlas America so that our gathering revenues and
                expenses
                within our partnership management segment net to $0. Atlas America
                then
                remits the full amount due to Atlas Pipeline pursuant to our contribution
                agreement with it. We also pay our proportionate share of gathering
                fees
                based on our percentage interest in the well, which are included
                in gas
                and oil production expense.




·
            Atlas
                America retained a small gathering system, which accounted for the
                gathering expense in our predecessor’s income
                statement.




·
            Because
                Atlas America did not previously allocate debt or interest expense
                to its
                subsidiaries, our historical results of operations do not include
                interest
                expense. We incurred indebtedness after the closing of our initial
                public
                offering, which created interest
                expense.




·
            Because
                we report our items of taxable income, loss, deductions and credits
                as a
                master limited partnership, we now incur additional general and
                administrative expense each year for costs associated with Schedule
                K-1
                preparation and distribution to our
                unitholders.




·
            We
                acquired DTE Gas & Oil on June 29, 2007, which significantly increased
                our assets, debt and equity and will continue to significantly increase
                our revenues, expenses and cash flows in future periods.




42





**OVERVIEW**





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, 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, 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.




As
      of and
      for the year ended December 31, 2007, we had the following key
      assets:




In
      our
      Appalachia gas and oil operations:




·
            proved
                reserves of 229.9 Bcfe including the reserves net to our equity interest
                in the investment partnerships and our direct interests in producing
                wells;




·
            direct
                and indirect working interests in approximately 7,722 gross producing
                gas
                and oil wells;




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




·
            net
                daily production of 29.7 Mmcfe per
                day;




·
            approximately
                797,800 gross (697,300 net) acres, of which approximately 508,600
                gross
                (501,400 net) acres, are undeveloped;
                and




·
            an
                interest in a joint venture that gave us the right to drill up to
                77
                additional net wells before March 31, 2008 on approximately 212,000
                acres in Tennessee.




In
      our
      Michigan gas and oil operations:




·
            proved
                reserves of 666.8 Bcfe;




·
            direct
                and indirect working interests in approximately 2,292 gross producing
                gas
                and oil wells;




·
            overriding
                royalty interests in approximately 78 gross producing gas and oil
                wells;




·
            net
                daily production of 59.8 Mmcfe per day;
                and




·
            approximately
                357,000 gross (285,100 net) acres, of which approximately 63,000
                gross
                (53,300 net) acres, are
                undeveloped.




In
      our
      partnership management business:




·
            our
                investment partnership business, which includes equity interests
                in 92
                investment partnerships and a registered broker-dealer which acts
                as the
                dealer-manager of our investment partnership offerings;
                and




·
            managed
                total proved reserves of 503.7
                Bcfe.




43




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.




We
      utilize the successful efforts method of accounting for our natural gas and
      oil
      properties. Unproved properties are assessed periodically within specific
      geographic areas and impairments are charged to expense. Geological and
      geophysical expenses and delay rentals are charged to expense as incurred.
      Drilling costs are capitalized, but charged to expense if the well is determined
      to be unsuccessful. Generally, if a well does not find proved reserves within
      one year following completion of drilling, the costs of drilling the well are
      charged to expense.




Higher
      natural gas and oil prices have led to higher demand for drilling rigs,
      operating personnel and field supplies and services and have caused increases
      in
      the costs of those goods and services. To date, the higher sales prices have
      more than offset the higher drilling and operating costs.





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. Our future growth will depend in part
      on our ability to continue to add reserves in excess of production.





**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 $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
      gas and oil operations. We funded the purchase price from borrowings under
      a new
      credit facility with an initial borrowing base of $850.0 million that matures
      in
      June 2012. We intend to continue to expand our business through strategice
      acquisitions and internal growth projects that increase distributable cash
      flow.





**Private
      equity offering**





We
      financed a portion of the purchase price for the DTE Gas & Oil acquisition
      with the proceeds of a private offering, completed on June 29, 2007. We raised
      net proceeds of $597.5 million through the sale of 7,298,181 Class B common
      units and 16,702,828 Class D units at a weighted average price of $25.00. On
      November 10, 2007, the Class D units automatically converted to common units
      on
      a one-for-one basis. On February 20, 2008, a registration statement with the
      Securities and Exchange Commission covering the resale of these units became
      effective.




**New
      credit facility**




Upon
      the
      closing of the DTE Gas & Oil acquisition, we replaced our credit facility
      with a new 5-year, credit facility with an initial borrowing base of $850.0
      million ($740.0 million outstanding at December 31, 2007). In January 2008,
      the credit facility has a current borrowing base of $672.5 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% of 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 1.25% for base rate loans and 1.00% to
      2.25% for LIBOR loans. At December 31, 2007, the weighted average interest
      rate
      on outstanding borrowings was 7.2%.




RECENT
      DEVELOPMENTS




**Private
      debt offering**





In
      January 2008, we issued $250.0 million of 10-year, 10.75% senior unsecured
      notes
      due 2018. We used the proceeds of the note offering to reduce the balance
      outstanding on our senior secured 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 certain 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.




44




**New
      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 fixed rate of approximately 4.36%, which includes an
      initial margin of 1.25% over the three year fixed swap rate of 3.11%. The
      interest rate swap contract will mature in January 2011. Combining the 4.36%
      interest rate on the new swap and the 10.75% interest rate on the new senior
      notes, we have fixed $400 million of our outstanding debt at a weighted average
      interest rate of approximately 8.35%.





**GENERAL
      TRENDS AND OUTLOOK**





We
      expect
      our business to continue to be affected by the risks described in “Item 1A: Risk
      factors” as well as 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.





**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 7A: -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.





45




**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. In order to sustain and grow our level
      of distributions, we will need to make acquisitions that are accretive to
      distributable cash flow per unit. We intend to pursue acquisitions of producing
      oil and gas properties from third parties. 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. It may in the future,
      however, increase the cost to acquire or replace property, plant and equipment,
      and may increase the costs of labor and supplies. 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.





46




**RESULTS
      OF OPERATIONS**





The
      following table sets forth information relating to our production revenues
      (shown in thousands), production volumes, sales prices, production costs and
      depletion for our operations during the periods indicated:




**Three
                  Months****Years
                  Ended**
              
              **Ended**
              
              **Year
                  Ended****December
                  31,**
              
              **December
                  31,**
              
              **September
                  30,**Production
                  revenues (in thousands):
              
              **2007**
              
              **2006**
              
              **2005**
              
              **2005**Gas
                  (1)(6)
              
              $
              169,314
              
              $
              79,016
              
              $
              21,851
              
              $
              55,376Oil
              
              $
              10,768
              
              $
              9,384
              
              $
              2,227
              
              $
              8,039Production
                  volumes(2):Appalachia:Gas
                  (Mcf/d) (1)
              
              
              27,156
              
              
              24,511
              
              
              21,468
              
              
              20,892Oil
                  (Bbls/d)
              
              
              418
              
              
              413
              
              
              431
              
              
              433Michigan(5):Gas
                  (Mcf/d)
              
              
              59,737
              
              
              -
              
              
              -
              
              
              -Oil
                  (Bbls/d)
              
              
              4
              
              
              -
              
              
              -
              
              
              -Total
                  (Mcfe/d)
              
              
              89,425
              
              
              26,989
              
              
              24,054
              
              
              23,490Average
                  sales prices:Gas
                  (per Mcf) (3)(7)
              
              $
              8.66
              
              $
              8.83
              
              $
              11.06
              
              $
              7.26Oil
                  (per Bbl)
              
              $
              70.16
              
              
              62.30
              
              
              56.13
              
              $
              50.91Production
                  costs (4):As
                  a percent of production revenues
              
              
              12
              %
              
              10
              %
              
              7
              %
              
              10
              %Per
                  Mcfe-Appalachia
              
              $
              0.89
              
              $
              0.86
              
              $
              0.78
              
              $
              0.71Per
                  Mcfe-Michigan
              
              $
              1.06
              
              
              -
              
              
              -
              
              
              -Totalper
                  Mcfe
              
              $
              0.97
              
              $
              0.86
              
              $
              0.78
              
              $
              0.71Transportation
                  costs:Per
                  Mcfe-Appalachia
              
              $
              0.74
              
              $
              0.55
              
              $
              0.32
              
              $
              0.24Per
                  Mcfe-Michigan
              
              $
              0.26
              
              
              -
              
              
              -
              
              
              -Depletion
                  per Mcfe
              
              $
              2.49
              
              $
              2.08
              
              $
              2.01
              
              $
              1.42




_______________




(1)
            Excludes
                sales of residual gas and sales to
                landowners.




(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 before the effects of financial hedging were
                $7.22 per
                Mcf and $7.90 per Mcf for the years ended December 31, 2007 and 2006,
                respectively. We did not have any financial hedges in the other periods
                presented.




(4)
            Production
                costs include labor to operate the wells and related equipment, repairs
                and maintenance, materials and supplies, property taxes, severance
                taxes,
                insurance and production overhead.




(5)
            Amounts
                represent production volumes related DTE Gas & Oil from the
                acquisition date (June 29, 2007).




(6)
            Excludes
                non-qualifying hedge gains of $26.3 million associated with the DTE
                Gas
                & Oil acquisition in the year ended December 31,
                2007.




(7)
            Includes
                $12.3 million in derivative proceeds, which were not included as
                gas
                revenue in the year ended December 31,
                2007.





47





Our
      well
      construction and completion revenues and costs and expenses incurred represent
      the billings and costs associated with the completion of wells for investment
      partnerships we sponsor.  The following table sets forth information
      relating to these revenues and the related costs and number of net wells drilled
      during the periods indicated (dollars in thousands):





**Three
                Months****Years
                Ended**
            
            **Ended**
            
            **Year
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2005**
            
            **2005**Average
                construction and completion revenue per well
            
            $
            317
            
            $
            307
            
            $
            225
            
            $
            218Average
                construction and completion cost per well
            
            
            276
            
            
            267
            
            
            196
            
            
            190Average
                construction and completion segment margin per well
            
            $
            41
            
            $
            40
            
            $
            29
            
            $
            28Segment
                margin
            
            $
            41,931
            
            $
            25,901
            
            $
            5497
            
            $
            17,552Net
                wells drilled
            
            
            1,014
            
            
            647
            
            
            187
            
            
            615





**Year
      Ended December 31, 2007 Compared to Year Ended December 31,
      2006**





**Gas
      and Oil Production**





Our
      natural gas revenues were $169.3 million in the year ended December 31, 2007,
      an
      increase of $90.3 million (114%) from $79.0 million in the year ended December
      31, 2006. The increase was attributable to volumes associated with our Michigan
      operations acquired on June 29, 2007 and an 11% increase in the production
      volumes of our Appalachian operating area. The $90.3 million increase in natural
      gas revenues consisted of $97.1 million attributable to increases in production
      volumes partially, offset by $6.8 million attributable to decreases in natural
      gas prices.





We
      believe that gas volumes will continue to be favorably impacted in 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 $10.8 million in the year ended December 31, 2007, an increase
      of
      $1.4 million (15%) from $9.4 million in the year ended December 31, 2006. The
      increase resulted from a 13% increase in the average sales price of oil, and
      a
      2% increase in production volumes. The $1.4 million increase consisted of $1.2
      million attributable to increases in sales prices, and $199,000 attributable
      to
      volume increases. We drill primarily for natural gas rather than
      oil.





Our
      production costs were $32.2 million in the year ended December 31, 2007, an
      increase of $18.3 million (132%) from $13.9 million in the year ended December
      31, 2006. This increase is attributable to $14.6 million of production costs
      associated with our acquisition of DTE Gas & Oil on June 29, 2007 and a $3.1
      million increase in transportation charges, water hauling and labor and
      maintenance costs associated with an increase in the number of wells we own
      in
      Appalachia from the prior year period.





**Partnership
      Management**





*Well
      Construction and Completion*





Our
      well
      construction and completion segment margin was $41.9 million in the year ended
      December 31, 2007, an increase of $16.0 million (62%) from $25.9 million in
      the
      year ended December 31, 2006. During the year ended December 31, 2007, the
      increase of $16.0 million in segment margin was attributable to an increase
      in
      the number of wells we drilled ($15.2 million) and an increase in the gross
      profit per well ($864,000). The increase in the number of wells we drilled
      of
      367 is a result of an increase in our fundraising in 2007. Since our drilling
      contracts are on a “cost plus” basis (typically cost-plus 15%), an increase in
      our average costs per well also results in an increase in our average revenue
      per well.




48





It
      should
      be noted that “Liabilities associated with drilling contracts” on our balance
      sheet includes $118.0 million of funds raised in our investment programs that
      have not been applied to the completion of wells as of December 31, 2007 due
      to
      the timing of drilling operations, and thus have not been recognized as well
      construction and completion revenue. We expect to recognize this amount as
      revenue in the first half of 2008. During the year ended December 31, 2007,
      we
      raised $363.3 million and plan to raise approximately $400.0 million in fiscal
      2008. We anticipate favorable oil and gas prices will continue to favorably
      impact our fundraising and therefore our drilling revenues in the year ending
      December 31, 2008.





*Administration
      and Oversight*





Administration
      and oversight represents supervision and administrative fees earned for the
      drilling and subsequent management of wells for our investment partnerships.
      Our
      administration and oversight fees were $18.1 million in the year ended December
      31, 2007, an increase of $6.3 million (53%) from $11.8 million in the year
      ended
      December 31, 2006. This increase resulted from an increase in the number of
      wells drilled and managed for our investment partnerships in the year ended
      December 31, 2007 as compared to the year ended December 31, 2006.





*Well
      Services*





Our
      well
      services revenues were $17.6 million in the year ended December 31, 2007, an
      increase of $4.6 million (35%) from $13.0 million in the year ended December
      31,
      2006. This increase resulted from an increase in the number of wells operated
      for our investment partnerships due to additional wells drilled in the year
      ended December 31, 2007.





Our
      well
      services expenses were $9.1 million in year ended December 31, 2007, an increase
      of $1.8 million (25%) from $7.3 million in the year ended December 31, 2006.
      This increase was attributable to an increase in wages, benefits, and field
      office expenses associated with an increase in employees due to the increase
      in
      the number of wells we operate for our investment partnerships.





*Gathering*





We
      charge
      transportation fees to our investment partnership wells that are connected
      to
      Atlas Pipeline’s Appalachian gathering systems. Prior to our initial public
      offering, our predecessor paid these fees, plus an additional amount to bring
      the total transportation charge up to, generally, 16% of the gas sales price,
      to
      Atlas Pipeline in accordance with its gathering agreements with it. In
      connection with the completion of our initial public offering, Atlas America
      assumed our obligation to pay gathering fees to Atlas Pipeline. We are obligated
      to pay the gathering fees we receive from our investment partnerships to Atlas
      America, with the result that our Appalachian gathering revenues and expenses
      within our partnership management segment net to $0. We
      also
      pay our proportionate share of gathering fees based on our percentage interest
      in the well, which are included in gas and oil production expense. During the
      year ended December 31, 2007, we also received $327,000 in transportation and
      natural gas liquid revenues from our Michigan operations.





Our
      gathering fee paid
      to Atlas Pipeline was $13.8 million for the year ended December 31, 2007, a
      decrease of $15.7 million (53%) from $29.5 million in the year ended
      December 31, 2006. The decrease in the year ended December 31, 2007 is primarily
      a result of the assumption by Atlas America of our obligation to pay Atlas
      Pipeline under our gas gathering agreement with it.




**All
        Other Income, Costs and Expenses**
  Gain
      on
      mark-to-market derivatives





Our
      gain
      on mark-to-market derivatives represents non-cash gains recognized on
      derivatives. We recognized a $26.3 million non-cash gain related to the change
      in value of derivative contracts associated with the acquisition of AGO on
      June
      29, 2007. The contracts entered into were derivative contracts to hedge the
      projected production volume of AGO before the closing of the acquisition. The
      production volumes of the assets to be acquired were not considered to be
“probable forecasted production” under SFAS No. 133 at the date these
      derivatives were entered into because the acquisition of the assets had not
      yet
      been completed. Accordingly, we recorded the instruments as non-qualifying
      for
      hedge accounting at inception with subsequent changes in the derivative values
      recorded within our combined and consolidated statements of income. Upon closing
      of the acquisition, the production volumes of the assets acquired was considered
      “probable forecasted production” under SFAS No. 133 and we evaluated these
      derivatives under the cash flow hedge criteria in accordance with SFAS No.
      133.
      For the year ended December 31, 2007, we received $18.4 million in proceeds
      on
      derivative contracts that settled, including, $12.3 million related to our
      mark-to-market non-cash derivative gain of $26.3 million, for a net gain
      included in gas revenues of $6.1 million.




49





*General
      and Administrative*





Our
      general and administrative expenses were $39.4 million in the year ended
      December 31, 2007, an increase of $16.0 million (69%) from $23.4 million in
      the
      year ended December 31, 2006. These expenses include, among other things,
      salaries and benefits not allocated to a specific segment, costs of running
      our
      corporate offices, partnership syndication activities and outside services.
      The
      increase of $16.0 million in the year ended December 31, 2007 is principally
      attributed to the following:





·
            costs
                associated with AGO were $3.3 million in the current
                year;




·
            exploration
                costs in Appalachia increased $1.0 million due to an increase in
                activities of our land department as we acquire additional acreage
                and
                well sites;




·
            salaries
                and wages increased $1.1 million due to an increase in executive
                salaries
                and in the number of employees as a result of our initial public
                offering
                and growth of our business;




·
            noncash
                stock compensation increased $4.4 million as a result of options
                and units
                granted upon our initial public offering and the acquisition of
                AGO;




·
            we
                paid $3.9 million in fees related to hedging natural gas volumes
                associated with the acquisition of AGO on June 29, 2007;
                and





·
            accounting
                and professional fees increased $1.8 million due to the growth of
                our
                business, higher audit fees and the implementation of Sarbanes-Oxley
                Section 404 compliance.




*Depletion*





Our
      depletion of oil and gas properties as a percentage of oil and gas revenues
      was
      30% in the year ended December 31, 2007, compared to 23% in the year ended
      December 31, 2006. Depletion expense was $2.49 per Mcfe in the year ended
      December 31, 2007, an increase of $0.41 (20%) from $2.08 per Mcfe in the year
      ended December 31, 2006. Increases in our depletable basis associated with
      the
      AGO acquisition and wells drilled for our investment partnerships and associated
      production volumes caused depletion expense to increase $33.9 million (165%)
      to
      $54.4 million in the year ended December 31, 2007 compared to $20.5 million
      in
      the year ended December 31, 2006. Depletion expense associated with our Michigan
      asset base was $28.3 million for the year ended December 31, 2007. The
      variances from period to period are directly attributable to changes in our
      oil
      and gas reserve quantities, production levels, product prices and changes in
      the
      depletable cost basis of our oil and gas properties.





*Interest
      Expense*





Interest
      expense was $30.1 million in the
      year ended December 31, 2007 which was incurred on our new credit facility.
      Atlas America did not allocate interest expense associated with its credit
      facility to us prior to our initial public offering in December
      2006.








50




*Cumulative
      Effect of Accounting Change*





We
      adopted FASB Interpretation No. 47, “Accounting for Conditional Asset
      Retirement Obligations,” or FIN 47 as of December 31, 2006 and recognized $6.4
      million as the cumulative effect of an accounting change. FIN 47 required us
      to
      record our retirement obligation without considering the probability of whether
      our wells would either be sold or otherwise disposed of without incurring a
      disposal charge.





**Three
      Months Ended December 31, 2005**





**Gas
      and Oil Production**





Our
      natural
      gas revenues were $21.9 million in the three months ended December 31, 2005.
      We
      experienced favorable natural gas prices which averaged $11.06 per Mcf for
      the
      quarter. Our oil revenues were $2.2 million in the three months ended December
      31, 2005. Oil prices were also favorably impacted and averaged $56.13 per barrel
      for the quarter. Total gas and oil production volumes for the period were 24,054
      Mcfe per day.





Our
      production costs, including transportation fees, were $2.4 million in the three
      months ended December 31, 2005. Production costs as a percentage of production
      revenue decreased to 10% of production revenue as a result of an increase in
      our
      average sales price. Additionally, we experienced an increase in production
      costs per mcfe due to increases in transportation and labor costs.





**Partnership
      Management**





*Well
      Construction and Completion*





Our
      well
      construction and completion segment margin was $5.5 million in the three months
      ended December 31, 2005. During this period, 187 wells (net to our interest)
      were drilled.





*Administration
      and Oversight*





Administration
      and oversight represents supervision and administrative fees earned for the
      drilling and subsequent management of wells for our investment partnerships.
      Our
      administration and oversight fees were $3.0 million in the three months ended
      December 31, 2005. These fees have continued to increase as a result of the
      increase in the number of wells we manage for our investment
      partnerships.





*Well
      Services*





Our
      well
      services revenues and expenses were $2.6 million and $1.5
      million, respectively, for a gross margin of $1.1 million in the three
      months ended December 31, 2005. These revenues and expenses are continuing
      to
      increase as the number of wells we operate for our investment partnerships
      increases.





*Gathering*





Our
      gathering fee to Atlas Pipeline was $7.9 million for the three months ended
      December 31, 2005, and represents fees paid to Atlas Pipeline prior to
      our initial public offering, which were generally 16% of the gas sales
      price.





**All
      Other Income, Costs and Expenses**





*General
      and Administrative*





Our
      general and administrative expenses were $5.8 million in the three months ended
      December 31, 2005, and consisted principally of the following:




51




·
            net
                syndication costs of $738,000 related to fund raising expenses in
                our
                public and private investment
                partnerships;




·
            professional
                and legal fees of $1.0 million related to insurance, audit, and the
                Sarbanes-Oxley Section 404 compliance;
                and




·
            salaries
                and wages of $3.8 million.




*Depletion*





Our
        depletion expense was $4.4 million in the three months ended December 31,
        2005. Depletion of oil and gas properties as a percentage of oil and gas revenues
        was
        18% and our depletion expense per Mcfe was $2.01 in the three months ended
        December 31, 2005.





**Year
      Ended September 30, 2005**





**Gas
      and Oil Production**





Our
      natural gas revenues were $55.4 million in the year ended September 30,
      2005.  Our natural gas prices averaged $7.26 per Mcf for the fiscal year.
      Our oil revenues were $8.0 million in the year ended September 30, 2005. Our
      oil
      prices averaged $50.91 per barrel for the fiscal year.  Total gas and oil
      production volumes for the period were 23,490 Mcfe per day.





Our
      production costs were $8.2 million in the year ended September 30, 2005.
      Production costs, including transportation as a percent of revenues, were 13%
      for the fiscal year.





**Partnership
      Management**





*Well
      Construction and Completion*





Our
      well
      construction and completion segment margin was $17.6 million in the year ended
      September 30, 2005. During this period, 615 wells (net to our interest) were
      drilled.





*Administration
      and Oversight*





Our
      administration and oversight fees were $9.6 million in the year ended September
      30, 2005. These fees represent charges to manage the wells drilled for our
      investment partnerships.





*Well
      Services*





Our
      well
      services revenues and expenses were $9.6 million and $5.2 million,
      respectively, for a gross margin of $4.4 million in the year ended
      September 30, 2005.





*Gathering*





Our
      gathering fee to Atlas Pipeline was $21.9 million in the year ended September
      30, 2005, and represents fees paid to Atlas Pipeline prior to our initial public
      offering, which were generally 16% of the natural gas sales price.




52





**All
      Other Income, Costs and Expenses**





*General
      and Administrative*





Our
      general and administrative expenses were $13.2 million in the year ended
      September 30, 2005 and consisted principally of the following:





·
            net
                syndication costs of $3.1 million related to our fundraising expenses
                in
                our public and private
                partnerships;





·
            professional
                and legal fees of $5.7 million related to insurance, audit and
                implementation of Sarbanes-Oxley Section 404 compliance;
                and





·
            salaries
                and wages of $2.0 million.





*Depletion*





Our
      depletion expense was $12.2 million in the year ended September 30, 2005.
      Depletion of oil and gas properties as a percentage of oil and gas revenues
      was
      19% in the year ended September 30, 2005 and our depletion expense was $1.42
      per
      Mcfe in the year ended September 30, 2005.





**LIQUIDITY
      AND CAPITAL RESOURCES**





**General**




We
      fund
      our development and production operations with a combination of cash generated
      by operations, capital raised through investment partnerships, issuance of
      our
      units and use of our credit facility. The following table sets forth our
      sources and uses of cash (in thousands):




**Three
                Months****Years
                Ended**
            
            **Ended**
            
            **Year
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2005**
            
            **2005**Provided
                by operations
            
            $
            230,982
            
            $
            80,536
            
            $
            43,596
            
            $
            90,525Used
                in investing activities
            
            
            (1,468,434
            )
            
            (75,588
            )
            
            (17,185
            )
            
            (59,050
            )Provided
                by (used in) financing activities
            
            
            1,253,877
            
            
            (17,033
            )
            
            (11,739
            )
            
            (25,401
            )Increase
                (decrease) in cash and cash equivalents
            
            $
            16,425
            
            $
            (12,085
            )
            $
            14,672
            
            $
            6,074




We
      had
      $25.3 million in cash and cash equivalents at December 31, 2007, as compared
      to
      $8.8 million at December 31, 2006. We had a working capital deficit of $102.0
      million at December 31, 2007, an increase of $14.0 million from a working
      capital deficit of $88.0 million at December 31, 2006.  The increase in our
      working capital deficit is due to an increase of $45.8 million in liabilities
      associated with drilling contracts, partially offset by an increase of $26.2
      million in accounts receivable primarily due to the AGO acquisition. Our level
      of liabilities associated with drilling contracts is dependent upon the
      remaining amount of our drilling obligations at any balance sheet date, which
      is
      dependent upon the timing and level of funds raised  through
      our investment partnerships. At December 31, 2007, we have $108.9 million
      available under our credit facility to fund working capital
      obligations.




**Capital
      Requirements**





*Capital
      expenditures* .
      During
      the year ended December 31, 2007, our capital expenditures consisted of
      maintenance capital expenditures and expansion capital expenditures, as defined
      below:





·
            maintenance
                capital expenditures are those capital expenditures we made on an ongoing
                basis to maintain our capital asset base and our current production
                volumes at a steady level; and




53




·
            expansion
                capital expenditures are those capital expenditures we made to expand
                our
                capital asset base for longer than the short-term and include new
                leasehold interests and the development and exploitation of existing
                leasehold interests through acquisitionsand
                investments in our drilling
                partnerships.




During
      the year ended December 31, 2007, our capital expenditures related
      primarily to investments in our investment partnerships, in which we invested
      $137.6 million. For the years ended December 31, 2006, the three months ended
      December 30, 2005 and the year ended September 30, 2005, our capital
      expenditures related primarily to investments in our partnerships, which totaled
      $73.6 million, $15.2 million and $57.9 million, respectively. We funded and
      expect to continue to fund these capital expenditures through cash on hand,
      from
      operations and from amounts available under our credit facility.





The
      level
      of capital expenditures we devote to our exploration and production operations
      depends upon any acquisitions made and the level of funds raised through our
      investment partnerships.  During the year ended December 31, 2007, we
      raised $363.3 million. For the years ended December 31, 2006 and September
      30,
      2005, we had raised $218.5 million and $148.7 million, respectively. We believe
      cash flows from operations and amounts available under our credit facility
      will
      be adequate to fund our capital expenditures.  However, the amount of funds
      we raise and the level of our capital expenditures will vary in the future
      depending on market conditions for natural gas and other factors.





We
      expect
      to fund our maintenance capital expenditures with cash flow from operations
      and
      the temporary use of funds raised in our investment partnerships in the period
      before we invest these funds, as well as funding our investment capital
      expenditures and any expansion capital expenditures that we might incur with
      borrowings under our credit facility and with the temporary use of funds raised
      in our investment partnerships in the period before we invest the funds. We
      estimate that we will have sufficient cash flow from operations after funding
      our maintenance capital expenditures to enable us to make our quarterly cash
      distributions in the amount of the initial quarterly distribution to unit
      holders through December 31, 2008.





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




The
      following table summarizes maintenance and expansion capital expenditures for
      the periods indicated (in thousands):


**Three
                Months****Years
                Ended**
            
            **Ended**
            
            **Year
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2005**
            
            **2005**Maintenance
                capital expenditures(1)
            
            $
            43,450
            
            $
            ─
            
            $
            ─
            
            $
            ─Expansion
                capital expenditures(1)
            
            
            1,421,186
            
            
            ─
            
            
            ─
            
            
            ─Total
            
            $
            1,464,636
            
            $
            75,635
            
            $
            17,187
            
            $
            59,124


___________________





(1)  We
      did
      not characterize capital expenditures as maintenance or expansion and did not
      plan capital expenditures in a manner intended to maintain or expand our asset
      base or production before our initial public offering on December 31,
      2006.





**Credit
      Facility**





Simultaneously
      with the closing of our acquisition of DTE Gas & Oil, we entered into a
      senior secured credit facility with an initial borrowing base of $850.0 million
      ($740.0 million outstanding at December 31, 2007) with JPMorgan Chase Bank,
      N.A., as administrative agent, J.P. Morgan Securities, Inc., as lead arranger,
      and other lenders. The credit facility allows us to borrow up to the determined
      amount of the borrowing base, which is based upon the loan collateral value
      assigned to our various natural gas and oil properties. The credit facility
      borrowing base will redetermined based on changes in our oil and gas reserves.
      The credit facility will mature in June 2012. In January 2008, the borrowing
      base for Atlas Energy Operating Company was reduced from $850.0 million to
      $672.5 million upon our issuance of $250.0 million in senior notes. See Item
      7:
“Management’s Discussion and Analysis of Financial Condition and Results of
      Operations, RECENT DEVELOPMENTS”.




54





**CASH
      FLOWS**





**Year
      ended December 31, 2007 compared to year ended December 31,
      2006**





*Cash
      flows from operating activities* . **** Cash
      provided by operations is an important source of short-term liquidity for
      us.  It is directly affected by changes in the price of natural gas and
      oil, interest rates and our ability to raise funds from our drilling investment
      partnerships.  Net ** cash
      provided by operating activities increased $150.5 million in the year ended
      December 31, 2007 to $231.0 million from $80.5 million in the year ended
      December 31, 2006, substantially as a result of the following:





·
            an
                increase in net income before depreciation, depletion and amortization
                of
                $96.8 million in the year ended December 31, 2007 as compared to
                the prior
                year period, principally due to the contribution of our Michigan
                operations acquired on June 29, 2007 and increases in net income
                from our
                partnership management operations and our Appalachian production
                segment;




·
            a
                decrease in non-cash items of $3.3 million related to our compensation
                expense resulting from grants under long-term incentive plans, non-cash
                gains of derivatives and the impact of cumulative change in accounting
                principle; and




·
            changes
                in operating assets and liabilities increased operating cash flows
                by
                $56.6 million in the year ended December 31, 2007, compared to the
                year
                ended December 30, 2006.




The
      change in operating assets and liabilities is primarily a result of the
      following:


·
              a
                  decrease of $12.1 million in accounts receivable and prepaid
                  expenses;
  ·
              an
                  increase of $15.0 million in accounts payable and accrued expenses;
                  and
  ·
              an
                  increase of $29.5 million in liabilities associated with our drilling
                  contracts. Our level of liabilities associated with drilling contracts
                  is
                  dependent upon the remaining amount of our drilling obligations
                  at any
                  balance sheet date, which is dependent upon the timing and level
                  of funds
                  raised through our investment
                  partnerships.




*Cash
      flows used in investing activities.* **** Cash
      used
      in our investing activities increased $1.4 billion in the year ended December
      31, 2007 to $1.5 billion from $75.6 million in the year ended December 31,
      2006
      primarily from our $1.3 billion acquisition of DTE Gas & Oil and a $121.1
      million increase in capital expenditures related to the increase in the number
      of wells we drilled in fiscal 2007.





*Cash
      flows from financing activities.* Cash
      provided by our financing activities increased $1.3 billion in the year ended
      December 31, 2007 to $1.3 billion from cash used of $17,000 in the year ended
      December 31, 2006, principally as a result of the following:





·
            to
                fund the acquisition of DTE Gas & Oil on June 29, 2007, we borrowed
                $713.9 million on our credit facility;




·
            we
                borrowed additional funds on our credit facility, net of repayments
                of
                $26.1 million, to fund our investments in our
                partnerships;




·
            net
                monies remitted to Atlas America during the year ended December 31,
                2007
                as compared to the year ended December 31, 2006 increased financing
                cash
                flows by $12.9 million;




55




·
            in
                the year ended December 31, 2006, we distributed $139.9 million to
                Atlas
                America;




·
            net
                proceeds of from issuances of units increased $457.6 million in the
                year
                ended December 31, 2007 as compared to December 31, 2006;




·
            deferred
                financing costs increased $10.3 million in the year ended December
                31,
                2007 due to our new credit facility used to fund our acquisition
                of AGO;
                and




·
            we
                paid $69.3 million in distributions to our unit holders in the year
                ended
                December 31, 2007.




**Three
      months ended December 31, 2005**





*Cash
      flows from operating activities.* Net cash
      provided by operating activities was $43.6 million in the three months ended
      December 31, 2005, substantially as a result of the following:





·
            net
                income before depreciation, depletion and amortization was $18.7
                million,
                principally as a result of higher natural gas prices and drilling
                profits;




·
            changes
                in operating assets and liabilities increased operating cash flows
                by
                $24.5 million, primarily due to an increase in accounts payable and
                liabilities associated with our drilling contracts of $26.5 million
                related to an increase in drilling
                activity.





*Cash
      flows used in investing activities.* Cash
      used by our investing activities was $17.2 million, primarily as a result of
      capital expenditures related to wells we drilled.





*Cash
      flows used in financing activities.* Cash used in our financing activities was $11.7 million primarily
      due to funds paid to our affiliate.  **Year
        ended September 30, 2005**
  *Cash
        flows from operating activities* . **** Net
        cash
        provided by operating activities was $90.5 million in the year ended September
        30, 2005 as a result of the following:
  ·
              net
                  income before depreciation, depletion and amortization was $55.5
                  million;
                  and
  ·
              changes
                  in operating assets and liabilities increased operating cash flows
                  by
                  $34.3 million in the year ended September 30, 2005, and relates
                  primarily
                  to $31.6 million in liabilities associated with our drilling
                  contracts.
  *Cash
        flows used in investing activities.* Net
        cash
        used in our investing activities was $59.1 million in the year ended September
        30, 2005 primarily related to capital expenditures we made in our investment
        partnerships.
  *Cash
        flows used in financing activities.* Net
        cash
        used in our financing activities was $25.4 million primarily due to funds
        paid
        to our affiliate.


**CHANGES
      IN PRICES AND INFLATION**





Our
      revenues, the value of our assets, our ability to obtain bank loans or
      additional capital on attractive terms and our ability to finance our drilling
      activities through investment partnerships have been and will continue to be
      affected by changes in oil and gas prices. Natural gas and oil prices are
      subject to significant fluctuations that are beyond our ability to control
      or
      predict. During the years ended December 31, 2007 and 2006, we received on
      average of $8.66 and $8.83 per Mcf of natural gas and $70.16 and $62.30 per
      Bbl
      of oil, respectively. During the three months ended December 31, 2005, we
      received an average of $11.06 per Mcf of natural gas and $56.13 per Bbl of
      oil,
      respectively. During the year ended September 30, 2005, we received an average
      of $7.26 per Mcf of natural gas and $50.91 per Bbl of oil.





Although
      certain of our costs and expenses are affected by general inflation, inflation
      has not normally had a significant effect on us. However, inflationary trends
      may occur if the price of natural gas were to increase since such an increase
      may increase the demand for acreage and for energy equipment and services,
      thereby increasing the costs of acquiring or obtaining such equipment and
      services.





**ENVIRONMENTAL
      REGULATION**





To
      date,
      compliance with environmental laws and regulations has not had a material impact
      on our capital expenditures, earnings or competitive position. We have complied
      with the spill prevention plan requirements on our operations, including pending
      changes by United States Environmental Protection Agency to the federal
      regulations that required compliance by October 31, 2007. We cannot assure
      you that compliance with environmental laws and regulations will not, in the
      future, materially adversely affect our operations through increased costs
      of
      doing business or restrictions on the manner in which we conduct our
      operations.




56





**CASH
      DISTRIBUTIONS**





We
      do not
      have a contractual obligation to make distributions to our unitholders. We
      distribute our “available cash,” to our unitholders each quarter in accordance
      with their respective percentage interests. “Available cash” is defined in our
      operating agreement, and it generally means, for each fiscal quarter:





·
            all
                cash on hand at the end of the
                quarter;




·
            less
                the amount of cash that our board of directors determines in its
                reasonable discretion is necessary or appropriate
                to:




·
            provide
                for the proper conduct of our business (including reserves for future
                capital expenditures and credit
                needs);




·
            comply
                with applicable law, any of our debt instruments, or other agreements;
                or




·
            provide
                funds for distributions to our unitholders for any one more of the
                next
                four quarters or with respect to our management incentive
                interests;




·
            plus
                all cash on hand on the date of determination of available cash for
                the
                quarter resulting from working capital borrowings made after the
                end of
                the quarter.




Working
      capital borrowings are generally borrowings that are made under our credit
      facility and in all cases are used solely for working capital purposes or to
      pay
      distributions to unitholders. We seek to maintain a coverage ratio for our
      distributions of at least 1.2x on a rolling 4-quarter basis. Our coverage ratio
      for the quarter ended December 31, 2007 was 1.3x. We c alculate
      our coverage ratio as the amount of all of our cash receipts less disbursements,
      including interest expense and estimated maintenance capital expenditures,
      divided by the amount of distributions to our unitholders.




All
      cash
      we distribute to unitholders will be characterized as either operating surplus
      or capital surplus, as defined in our limited liability company agreement and
      is
      subject to different distribution rules. We will treat all available cash
      distributed as coming from operating surplus until the sum of all available
      cash
      distributed since we began operations equals the operating surplus as of the
      most recent date of determination of available cash. We do not anticipate
      distributing any cash from capital surplus.




Available
      cash is initially distributed 98% to our common unit holders and 2% to Atlas
      Energy Management. These distribution percentages are modified to provide for
      incentive distributions (any distribution paid to Atlas Energy Management in
      excess of 2% of the aggregate amount of cash being distributed) to be paid
      to
      Atlas Energy Management if quarterly distributions to the common unit holders
      exceed specified targets as defined in our limited liability company agreement.





On
      January 28, 2008, we declared our quarterly cash distribution for the fourth
      quarter of 2007 of $0.57 per common unit. The $35.6 million distribution was
      paid on February 14, 2008 to unitholders of record as of February 7,
      2008.





Distributions
      made to Atlas America for the year ended December 31, 2006 were $139.9 million,
      representing the net proceeds of our initial public offering.




57





**CONTRACTUAL
      OBLIGATIONS AND COMMERCIAL COMMITMENTS**





The
      following table summarizes our contractual obligations at December 31,
      2007:





**Payments
                due by period****(in
                thousands)****Less
                than**
            
            **2
                - 3**
            
            **4
                - 5**
            
            **After
                5****Contractual
                cash obligations:**
            
            Total
            
            **1
                Year**
            
            **Years**
            
            **Years**
            
            **Years**Long-term
                debt(1)
            
            $
            740,030
            
            $
            30
            
            $
            —
            
            $
            740,000
            
            $
            —Secured
                revolving credit facilities
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Operating
                lease obligations
            
            
            7,103
            
            
            1,282
            
            
            2,098
            
            
            1,222
            
            
            2,501Capital
                lease obligations
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Unconditional
                purchase obligations
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Other
                long-term obligation
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Total
                contractual cash obligations
            
            $
            747,133
            
            $
            1,312
            
            $
            2,098
            
            $
            741,222
            
            $
            2,501





(1)
            
            Not
                included in the table above are estimated interest payments calculated
                at
                the rates in effect at December 31, 2007 of: 2008 - $53.3 million;
                2009 -
                $53.3 million; 2010 - $53.3 million; 2011 - $53.3 million and 2012
                - $26.5
                million.





**Payments
                due by period****(in
                thousands)****Less
                than**
            
            **1
                - 3**
            
            **4
                - 5**
            
            **After
                5****Other
                commercial commitments:**
            
            **Total**
            
            **1
                Year**
            
            **Years**
            
            **Years**
            
            **Years**Standby
                letters of credit
            
            $
            1,109
            
            $
            1,109
            
            $
            —
            
            $
            —
            
            $
            —Guarantees
            
            
            32,857
            
            
            5,434
            
            
            11,045
            
            
            10,689
            
            
            5,689Standby
                replacement commitments
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Other
                commercial commitments
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Total
                commercial commitments
            
            $
            33,966
            
            $
            6,543
            
            $
            11,045
            
            $
            10,689
            
            $
            5,689





**CRITICAL
      ACCOUNTING POLICIES**





The
      discussion and analysis of our financial condition and results of operations
      are
      based upon our combined financial statements, which have been prepared in
      accordance with accounting principles generally accepted in the United States
      of
      America. The preparation of these financial statements requires us to make
      estimates and judgments that affect the reported amounts of our assets,
      liabilities, revenues and cost and expenses, and related disclosure of
      contingent assets and liabilities. On an on-going basis, we evaluate our
      estimates, including those related to the provision for possible losses,
      goodwill and identifiable intangible assets, and certain accrued liabilities.
      We
      base our estimates on historical experience and on various other assumptions
      that we believe reasonable under the circumstances, the results of which form
      the basis for making judgments about the carrying values of assets and
      liabilities that are not readily apparent from other sources. Actual results
      may
      differ from these estimates under different assumptions or
      conditions.





We
      have
      identified the following policies as critical to our business operations and
      the
      understanding of our results of operations.





**Accounts
      Receivable and Allowance for Possible Losses**





Through
      our business segments, we engage in credit extension, monitoring, and
      collection. In evaluating our allowance for possible losses, we perform ongoing
      credit evaluations of our customers and adjust credit limits based upon payment
      history and the customer’s current creditworthiness, as determined by our review
      of our customer’s credit information. We extend credit on an unsecured basis to
      many of our energy customers. At December 31, 2007 and 2006 our credit
      evaluation indicated that we have no need for an allowance for possible losses
      for our oil and gas receivables.




58




**Derivative
      Instruments**





We
      apply
      the provisions of SFAS No. 133, “ Accounting
      for Derivative Instruments and Hedging  Activities”,
      or SFAS
      133. SFAS 133 requires each derivative instrument to be recorded in the balance
      sheet as either an asset or liability measured at fair value. Changes in a
      derivative instrument’s fair value are recognized currently in earnings unless
      specific hedge accounting criteria are met. See
      Note
      7 to our combined and consolidated financial statements.


**Reserve
      Estimates**





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





**Impairment
      of Oil and Gas Properties**





We
      review
      our producing oil and gas properties for impairment on an annual basis and
      whenever events and circumstances indicate a decline in the recoverability
      of
      their carrying values. We estimate the expected future cash flows from our
      oil
      and gas properties and compare such future cash flows to the carrying amount
      of
      the oil and gas properties to determine if the carrying amount is recoverable.
      If the carrying amount exceeds the estimated undiscounted future cash flows,
      we
      will adjust the carrying amount of the oil and gas properties to their fair
      value in the current period. The factors used to determine fair value include,
      but are not limited to, estimates of reserves, future production estimates,
      anticipated capital expenditures, and a discount rate commensurate with the
      risk
      associated with realizing the expected cash flows projected. Because of the
      complexities associated with oil and gas reserve estimates and the history
      of
      price volatility in the oil and gas markets, events may arise that will require
      us to record an impairment of our oil and gas properties. Any such impairment
      may affect or cause a reduction in our credit facilities.





**Asset
      Retirement Obligations**





As
      described in Note 4 to our combined and consolidated financial statements,
      we
      follow SFAS No. 143, “Accounting for Asset Retirement Obligations,” and on
      December 31, 2006, we adopted FASB Interpretation No. 47 “Accounting for
      Conditional Asset Retirement Obligations,” which resulted in a cumulative effect
      adjustment of $6.4 million in the year ended December 31, 2006. Under SFAS
      No.
      143, estimated asset retirement costs are recognized when the asset is placed
      in
      service, and are amortized using the units-of-production method. On an annual
      basis, we review our estimates of the costs of future dismantlement,
      restoration, reclamation and abandonment of our natural gas and oil-producing
      properties. We also review our estimates of the salvage value of equipment
      recoverable upon abandonment. As of December 31, 2007 and 2006, our estimate
      of
      salvage values was greater than or equal to our estimate of the costs of future
      dismantlement, restoration, reclamation and abandonment. A decrease in our
      salvage value or an increase in dismantlement, restoration, reclamation and
      abandonment costs from those we have estimated could reduce our gross profit
      from operations.





Inherent
      in the fair value calculation of asset retirement obligations are numerous
      assumptions and judgments including the estimated remaining lives of the wells,
      the estimated cost to plug and abandon the wells in the future, inflation
      factors, credit adjusted discount rates and changes in the legal regulatory
      requirements. To the extent future revisions to these assumptions impact the
      fair value of our existing asset retirement obligation, a corresponding
      adjustment is made to our oil and gas properties.





59





**Goodwill
      and Other Long-lived Assets**





Goodwill
      and other intangibles with an indefinite useful life are no longer amortized,
      but instead are assessed for impairment annually. We have recorded goodwill
      of
      $35.2 million in connection with several acquisitions of assets. In assessing
      impairment of goodwill, we use estimates and assumptions in estimating the
      fair
      value of reporting units. If under these estimates and assumptions we determine
      that the fair value of a reporting unit has been reduced, the reduction can
      result in an “impairment” of goodwill. However, future results could differ from
      the estimates and assumptions we use. Events or circumstances which might lead
      to an indication of impairment of goodwill would include, but might not be
      limited to, prolonged decreases in expectations of long-term well servicing
      and/or drilling activity or rates brought about by prolonged decreases in
      natural gas or oil prices, changes in government regulation of the natural
      gas
      and oil industry or other events which could affect the level of activity of
      exploration and production companies.





In
      assessing impairment of long-lived assets other than goodwill, where there
      has
      been a change in circumstances indicating that the carrying amount of a
      long-lived asset may not be recoverable, we have estimated future undiscounted
      net cash flows from the use of the asset based on actual historical results
      and
      expectations about future economic circumstances, including natural gas and
      oil
      prices and operating costs. Our estimate of future net cash flows from the
      use
      of an asset could change if actual prices and costs differ due to industry
      conditions or other factors affecting our performance.





**Revenue
      Recognition**





We
      conduct certain activities through, and a portion of our revenues are
      attributable to, our investment partnerships. These investment partnerships
      raise capital from investors to drill gas and oil wells. We serve as the
      managing general partner of the investment partnerships and assume customary
      rights and obligations for them. As a general partner, we are liable for
      partnership liabilities and can be liable to limited partners if we breach
      our
      responsibilities with respect to the operations of the partnerships. The income
      from our general partner interest is recorded when the gas and oil are sold
      by a
      partnership.





We
      contract with the investment partnerships to drill partnership wells. The
      contracts require that the investment partnerships must pay us the full contract
      price upon execution. The income from a drilling contract is recognized as
      the
      services are performed using the percentage of completion method. The contracts
      are typically completed in less than 60 days. We classify the difference between
      the contract payments we have received and the revenue earned as a current
      liability, included in liabilities associated with drilling
      contracts.





We
      recognize gathering revenues at the time the natural gas is delivered to the
      purchaser.





We
      recognize well services revenues at the time the services are
      performed.





We
      are
      entitled to receive administration and oversight fees according to the
      respective partnership agreements. We recognize such fees as income when
      earned.





We
      generally sell natural gas and crude oil at prevailing market prices. Revenue
      is
      recognized when produced quantities are delivered to a custody transfer point,
      persuasive evidence of a sales arrangement exists, the rights and responsibility
      of ownership pass to the purchaser upon delivery, collection of revenue from
      the
      sale is reasonably assured and the sales price is fixed or determinable.
      Revenues from the production of natural gas and crude oil in which we have
      an
      interest with other producers is recognized on the basis of our percentage
      ownership of working interest or overriding royalty. Generally, our sales
      contracts are based on pricing provisions that are tied to a market index,
      with
      certain adjustments based on proximity to gathering and transmission lines
      and
      the quality of our natural gas.





**Income
      Taxes**




We
      are a
      limited liability company and have elected to be treated as a partnership for
      income tax purposes.  As a result, we are not subject to U.S. federal and
      most state income taxes.  Our unitholders are liable for income taxes
      on their distributive share of our taxable income.  Such taxable income may
      vary substantially from net income reported in the accompanying combined and
      consolidated financial statements.   Certain of our corporate
      subsidiaries are subject to federal and state income tax.  The federal and
      state income taxes related to us and these corporate subsidiaries were
      immaterial to the combined and consolidated financial statements and are
      recorded in pre-tax income on a current basis only.  Accordingly, no
      federal or state deferred income tax has been provided for in the accompanying
      combined and consolidated financial statements.




60




In
      June
      2006, the FASB released FASB Interpretation No. 48 “Accounting for
      Uncertainty in Income Taxes”, an Interpretation of FASB Statement No. 109
      (“FIN 48”). FIN 48 provides guidance for how uncertain tax positions
      should be recognized, measured, presented and disclosed in the financial
      statements. FIN 48 requires the evaluation of tax positions taken or
      expected to be taken in the course of preparing our tax returns to determine
      whether the tax positions have met a “more-likely-than-not” threshold of being
      sustained by the applicable tax authority. Tax benefits related to tax positions
      not deemed to meet the more-likely-than-not threshold are not permitted to
      be
      recognized in the financial statements.  The provisions of FIN 48 were
      adopted by us effective January 1, 2007.  Implementation of FIN 48 had no
      impact on our combined and consolidated financial statements for the year ended
      December 31, 2007.  Our policy is to reflect interest and penalties
      related to uncertain tax positions as part of income tax expense, when and
      if
      they become applicable.




We file
      income tax returns in the U.S. federal and various state jurisdictions.
      With limited exceptions, we are no longer subject to income tax examinations
      by
      major tax authorities for years before 2006.





**RECENTLY
      ISSUED FINANCIAL ACCOUNTING STANDARDS**





In
      December 2007, the Financial Accounting Standards Board, or FASB, issued SFAS
      160, “Noncontrolling Interests in Consolidated Financial Statements”, or SFAS
      160. This statement amends Accounting Research Bulletin 51, “Consolidated
      Financial Statements,” to establish accounting and reporting standards for the
      noncontrolling (minority) interest in a subsidiary and for the deconsolidation
      of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary
      is
      an ownership interest in the consolidated entity that should be reported as
      equity in the consolidated financial statements. This statement is effective
      for
      fiscal periods beginning on or after December 15, 2008. We do not expect the
      adoption of SFAS 160 to have a significant impact on our financial position
      or
      results of operations.





In
      December 2007, the FASB issued SFAS No 141(R), “Business Combinations”, or SFAS
      No. 141(R). SFAS No. 141(R) replaces SFAS No. 141, “Business Combinations”,
      however, it retains the fundamental requirements that the acquisition method
      of
      accounting be used for all business combinations and for an acquirer to be
      identified for each business combination. SFAS No. 141(R) requires an acquirer
      to recognize the assets acquired, liabilities assumed, and any noncontrolling
      interest in the acquiree at the acquisition date, be measured at their fair
      values as of that date, with specified limited exceptions. Changes subsequent
      to
      that date are to be recognized in earnings, not goodwill. Additionally, SFAS
      No.
      141(R) requires costs incurred in connection with an acquisition be expensed
      as
      incurred. Restructuring costs, if any, are to be recognized separately from
      the
      acquisition. The acquirer in a business combination achieved in stages must
      also
      recognize the identifiable assets and liabilities, as well as the noncontrolling
      interests in the acquiree, at the full amounts of their fair values. SFAS No.
      141(R) is effective for business combinations occurring in fiscal years
      beginning on or after December 15, 2008. We will apply the requirements of
      SFAS
      No. 141(R) upon its adoption on January 1, 2009 and are currently evaluating
      whether SFAS No. 141(R) will have an impact on our financial position and
      results of operations.





In
      September 2007, the Emerging Issues Task Force, or EITF, reached consensus
      on
      EITF Issue No. 07-4, “Application of the two-class method under FASB Statement
      No. 128, Earnings per Share, to Master Limited Partnerships”, or EITF No. 07-4,
      an update of EITF No. 03-6. EITF No. 07-4 requires the calculation of a Master
      Limited Partnership’s (“MLPs”) net earnings per limited partner unit for each
      period presented according to distributions declared and participation rights
      in
      undistributed earnings as if all of the earnings for that period had been
      distributed. In periods with undistributed earnings above specified levels,
      the
      calculation per the two-class method results in an increased allocation of
      such
      undistributed earnings to the general partner and a dilution of earnings to
      the
      limited partners. EITF No. 07-4 is effective for fiscal years beginning after
      December 15, 2007. The application of EITF 07-4 is not expected to have an
      effect on our earnings per unit calculation.





In
      April
      2007, the FASB issued FASB Staff Position FIN 39-1, “Amendment of FASB
      Interpretation No. 39,” or FSP FIN 39-1, which refers to FASB Interpretation No.
      39, “Offsetting of Amounts Related to Certain Contracts” or FIN 39. FSP FIN 39-1
      amends FIN 39, which allows an entity to offset fair value amounts recognized
      for the right to reclaim cash collateral or the obligation to return cash
      collateral against fair value amounts recognized for derivative instruments
      executed with the same counterparty under the same master netting arrangement.
      FSP FIN 39-1 was effective for fiscal years beginning after November 15, 2007.
      We do not expect the adoption of FSP FIN 39-1 to have an impact on our
      financial position or results of operations.




61




In
      February 2007, the FASB issued Statement of Financial Accounting Standards
      No. 159, “The Fair Value Option for Financial Assets and Financial
      Liabilities,” or SFAS 159. SFAS 159 permits entities to choose to measure
      eligible financial instruments and certain other items at fair value. The
      objective is to improve financial reporting by providing entities with the
      opportunity to mitigate volatility in reported earnings caused by measuring
      related assets and liabilities differently without having to apply complex
      hedge
      accounting provisions. The Statement will be effective as of the beginning
      of an
      entity’s first fiscal year beginning after November 15, 2007. The Statement
      offers various options in electing to apply the provisions of this Statement,
      and at this time we have not made any decisions in its application to us. We
      do
      not expect the adoption of FASB 159 to have a significant impact on our
      financial position or results of operations.





In
      September 2006, the Financial Accounting Standards Board, or FASB, issued
      Statement of Financial Accounting Standards No. 157, “Fair Value Measurement,”
or SFAS 157. SFAS 157 addresses the need for increased consistency in fair
      value
      measurements, defining fair value as the price that would be received to sell
      an
      asset or paid to transfer a liability in an orderly transaction between market
      participants at the measurement date. It also establishes a framework for
      measuring fair value and expands disclosure requirements. In February 2008,
      the
      FASB issued Final FASB Staff Position, or FSP No. FAS 157-2. The FSP, which
      was
      effective upon issuance, delays the effective date of SFAS 157 for nonfinancial
      assets and nonfinancial liabilities, except for items that are recognized or
      disclosed at fair value at least once a year, to fiscal years beginning after
      November 15, 2008. The FSP also covers interim periods within the fiscal years
      for items within its scope. The delay is intended to allow the FASB and its
      constituents the time to consider the various implementation issues associated
      with SFAS 157. We do not expect the adoption of SFAS 157 to have a significant
      impact on our financial position or results of operations.




**ITEM
      7A: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
      RISK**





The
      primary objective of the following information is to provide forward-looking
      quantitative and qualitative information about our potential exposure to market
      risks. The term “market risk” refers to the risk of loss arising from adverse
      changes in interest rates and oil and gas prices. The disclosures are not meant
      to be precise indicators of expected future losses, but rather indicators of
      reasonable possible losses. This forward-looking information provides indicators
      of how we view and manage our ongoing market risk exposures. All of our market
      risk sensitive instruments were entered into for purposes other than
      trading.





**General**





We
      are
      exposed to various market risks, principally fluctuating interest rates and
      changes in commodity prices. These risks can impact our results of operations,
      cash flows and financial position. We manage these risks through regular
      operating and financing activities and periodically use derivative financial
      instruments such as forward contracts and swap agreements.





The
      following analysis presents the effect on our earnings, cash flows and financial
      position as if hypothetical changes in market risk factors occurred on December
      31, 2007. Only the potential impacts of hypothetical assumptions are analyzed.
      The analysis does not consider other possible effects that could impact our
      business.




62




**Interest
      Rate Risk**





At
      December 31, 2007, we have a revolving credit facility with an initial borrowing
      base of $850.0 million, of which $741.1 million was outstanding (including
      $1.1
      million in letters of credit). The weighted average interest rate for borrowings
      under this credit facility was 7.2% at December 31, 2007.





**New
      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 fixed rate of approximately 4.36%, which includes an
      initial margin of 1.25% over the three year fixed swap rate of 3.11%. The
      interest rate swap contract will mature in January 2011. Combining the 4.36%
      interest rate on the new swap and the 10.75% interest rate on the new senior
      notes, we have fixed $400 million of our outstanding debt at a weighted average
      interest rate of approximately 8.35%. With the subsequent changes in our debt
      structure above, a hypothetical 10% change in the weighted average interest
      rate
      would change our net income by approximately $5.5 million.





**Commodity
      Price Risk**





Our
      major
      market risk exposure in commodities is fluctuations in the pricing of our gas
      and oil production. Realized pricing is primarily driven by the prevailing
      worldwide prices for crude oil and spot market prices applicable to United
      States natural gas production. Pricing for gas and oil production has been
      volatile and unpredictable for many years. To limit our exposure to changing
      natural gas prices, we enter into natural gas, costless collar, and option
      contracts. At any point in time, such contracts may include regulated NYMEX
      futures and options contracts and non-regulated over-the-counter futures
      contracts with qualified counterparties. NYMEX contracts are generally settled
      with offsetting positions, but may be settled by the delivery of natural
      gas.





Our
      risk
      management objective is to lock in a range of pricing for expected production
      volumes. Considering those volumes for which we have entered into financial
      hedge agreements for the year ending December 31, 2008, and current indices,
      a
      theoretical 10% upward or downward change in the price of natural gas would
      result in a change in net income of approximately $5.7 million.





We
      formally document all relationships between hedging instruments and the items
      being hedged, including the risk management objective and strategy for
      undertaking the hedging transactions. This includes matching the natural gas
      futures and options contracts to the forecasted transactions. We assess, both
      at
      the inception of the hedge and on an ongoing basis, whether the derivatives
      are
      highly effective in offsetting changes in the fair value of hedged items.
      Historically these contracts have qualified and been designated as cash flow
      hedges in accordance with SFAS No. 133, “Accounting
      for
      Derivative Instruments and Hedging Activities”, or SFAS
      133, and
      are recorded at their fair values. Gains or losses on future contracts are
      determined as the difference between the contract price and a reference price,
      generally prices on NYMEX. Changes in fair value are recognized in combined
      equity and recognized within the combined statements of income in the
      month the hedged commodity is sold. If it is determined that a derivative
      is not highly effective as a hedge or it has ceased to be a highly effective
      hedge, due to the loss of correlation between changes in reference prices
      underlying a hedging instrument and actual commodity prices, we will
      discontinue hedge accounting for the derivative and subsequent changes in fair
      value for the derivative will be recognized immediately into earnings.





As
      of
      December 31, 2007, we had financial hedges in place for approximately 80% of
      our
      expected production volumes for the year ending December 31, 2008. At December
      31, 2007, we had 360 open natural gas futures contracts related to natural
      gas
      sales covering 130.6 million MMBtus of natural gas, (which includes 72.6 million
      MMBtus covering natural gas production assets acquired from AGO), maturing
      through December 31, 2012 at an average settlement price of $8.32 per MMBtu.
      On
      May 18, 2007, we signed a definitive agreement to acquire AGO (see Note 3 to
      our
      combined and consolidated financial statements). In connection with the
      financing of this transaction, we agreed as a condition precedent to closing
      that we would hedge 80% of our projected natural gas volumes for no less than
      three years from the closing date of the transaction. During May 2007, we
      entered into derivative instruments to hedge 80% of the projected production
      of
      the assets to be acquired as required under the financing agreement. The
      production volume of the assets to be acquired was not considered to be
“probable forecasted production” under SFAS No. 133 at the date these
      derivatives were entered into because the acquisition of the assets had not
      yet
      been completed. Accordingly, we recognized the instruments as non-qualifying
      for
      hedge accounting at inception with subsequent changes in the derivative value
      recorded within revenues in our combined and consolidated statements of income.
      We recognized non-cash income of $26.3 million related to the change in value
      of
      these derivatives from May 22, 2007 to June 28, 2007, which is shown as “Gain on
      mark-to-market derivatives” in the combined and consolidated statements of
      income for the years ended December 31, 2007 and 2006. Upon closing of the
      acquisition on June 29, 2007, the production volumes of the assets acquired
      were
      considered “probable forecasted production” under SFAS No. 133 and we evaluated
      these derivatives under the cash flow hedge criteria in accordance with SFAS
      No.
      133. In addition, we recognized gains on settled contracts covering natural
      gas
      production of $17.6 million and $7.1 million for the years ended December 31,
      2007 and 2006, respectively.  As
      the
      underlying prices and terms in our hedge contracts were consistent with the
      indices used to sell our natural gas, there were no gains or losses recognized
      during the years ended December 31, 2007 and 2006, respectively for hedge
      ineffectiveness or as a result of the discontinuance of these cash flow hedges.
      We did not enter into any hedging contracts in the three months ended December
      31, 2005 or year ended September 30, 2005 .




63




Of
      the
      $5.1 million net loss in accumulated other comprehensive income (loss) at
      December 31, 2007, we will reclassify $21.1 million of gains to our consolidated
      statements of income over the next twelve month period as these contracts expire
      and $26.2 million of losses will be reclassified in later periods if the fair
      values of the instruments remain at current market values.




Of
      the
      $5.5 million net unrealized hedge asset at December 31, 2007, our portion is
      $8.9 million, and $3.4 million of unrealized hedge losses have been reallocated
      to our investment partnerships.





As
      of
      December 31, 2007, we had the following natural gas volumes hedged :





**Fixed
      Price Swaps**




**Twelve
                Month**
            
            
            
            **Average**
            
            **Fair
                Value****Period
                Ending**
            
            **Volumes**
            
            **Fixed
                Price**
            
            **Asset
                (Liability)****December
                31,**
            
            **(MMBtu)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands)****(1)**2008
            
            
            35,960,000
            
            $
            8.86
            
            $
            37,4572009
            
            
            32,720,000
            
            
            8.50
            
            
            1702010
            
            
            23,000,000
            
            
            8.01
            
            
            (11,398
            )2011
            
            
            17,600,000
            
            
            7.79
            
            
            (10,939
            )2012
            
            
            9,000,000
            
            
            7.74
            
            
            (5,242
            )$
            10,048





**Costless
      Collars**





**Twelve
                Month**
            
            
            
            
            
            **Average**
            
            **Fair
                Value****Period
                Ending**
            
            
            
            **Volumes**
            
            **Floor
                and Cap**
            
            **Asset
                (Liability)****December
                31,**
            
            **Option
                Type**
            
            **(MMBtu)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands)********(1)**2008
            
            
            Puts
                purchased
            
            
            1,560,000
            
            $
            7.50
            
            $
            3682008
            
            
            Calls
                sold
            
            
            1,560,000
            
            
            9.40
            
            
            —2010
            
            
            Puts
                purchased
            
            
            2,880,000
            
            
            7.75
            
            
            —2010
            
            
            Calls
                sold
            
            
            2,880,000
            
            
            8.75
            
            
            (948
            )2011
            
            
            Puts
                purchased
            
            
            7,200,000
            
            
            7.50
            
            
            —2011
            
            
            Calls
                sold
            
            
            7,200,000
            
            
            8.45
            
            
            (3,495
            )2012
            
            
            Puts
                purchased
            
            
            720,000
            
            
            7.00
            
            
            —2012
            
            
            Calls
                sold
            
            
            720,000
            
            
            8.37
            
            
            (470
            )(4,545
            )Total
                net asset
            
            $
            5,503





(1)
            Fair
                value based on forward NYMEX natural gas
                prices.





64





**ITEM
      8:**  **FINANCIAL
      STATEMENTS AND SUPPLEMENTARY DATA**




**[THE
      REMAINDER OF THIS PAGE IS INTENTIONALLY LEFT BLANK]**




























65





**REPORT
      OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**





Board
      of
      Directors and Unitholders


Atlas
      Energy Resources, LLC





We
      have
      audited the accompanying consolidated balance sheets of Atlas Energy Resources,
      LLC and subsidiaries (a Delaware limited liability company) as of December
      31,
      2007 and 2006, and the related combined and consolidated statements of income,
      comprehensive income, equity, and cash flows for the years ended December 31,
      2007 and 2006, the three month period ended December 31, 2005 and the year
      ended
      September 30, 2005. These financial statements are the responsibility of the
      Company's management. Our responsibility is to express an opinion on these
      financial statements based on our audits.





We
      conducted our audits in accordance with the standards of the Public Company
      Accounting Oversight Board (United States). ** Those
      standards require that we plan and perform the audit to obtain reasonable
      assurance about whether the financial statements are free of material
      misstatement. ** An
      audit
      includes examining, on a test basis, evidence supporting the amounts and
      disclosures in the financial statements. ** An
      audit
      also includes assessing the accounting principles used and significant estimates
      made by management, as well as evaluating the overall financial statement
      presentation. ** We
      believe that our audits provide a reasonable basis for our opinion.





In
      our
      opinion, the combined and consolidated financial statements referred to above
      present fairly, in all material respects, the financial position of Atlas Energy
      Resources, LLC and subsidiaries as of December 31, 2007 and 2006, and the
      results of their operations and their cash flows for the years ended December
      31, 2007 and 2006, the three month period ended December 31, 2005 and the year
      ended September 30, 2005 in conformity with accounting principles generally
      accepted in the United States of America.





We
      also
      have audited, in accordance with the standards of the Public Company Accounting
      Oversight Board (United States), the effectiveness of Atlas Energy Resources,
      LLC’s internal control over financial reporting as of December 31, 2007, based
      on criteria established in Internal Control—Integrated Framework issued by the
      Committee of Sponsoring Organizations of the Treadway Commission
      (COSO *)* and
      our
      report dated February 27, 2008 expressed an unqualified opinion.




As
      also
      discussed in Note 2 to the combined and consolidated financial statements,
      the
      Company recorded a cumulative effect adjustment in 2006 in connection with
      the
      adoption of FASB Interpretation No. 47, “Accounting for Conditional Asset
      Retirement Obligations.”




/s/
      GRANT
      THORNTON LLP





Cleveland,
      Ohio


February
      27, 2008




66





**ATLAS
      ENERGY RESOURCES, LLC**


**CONSOLIDATED
      BALANCE SHEETS**


(in
      thousands)





**December
                31,****2007**
            
            **2006****ASSETS**Current
                assets:Cash
                and cash equivalents
            
            $
            25,258
            
            $
            8,833Accounts
                receivable
            
            
            57,524
            
            
            31,280Current
                portion of hedge asset
            
            
            38,181
            
            
            27,618Prepaid
                expenses and other
            
            
            8,265
            
            
            3,251Total
                current assets
            
            
            129,228
            
            
            70,982Property,
                plant and equipment, net
            
            
            1,693,467
            
            
            277,814Other
                assets, net
            
            
            28,312
            
            
            26,290Intangible
                assets, net
            
            
            5,061
            
            
            5,211Goodwill
            
            
            35,166
            
            
            35,166$
            1,891,234
            
            $
            415,463**LIABILITIES
                AND MEMBERS’ EQUITY**Current
                liabilities:Current
                portion of long-term debt
            
            $
            30
            
            $
            38Accounts
                payable
            
            
            55,051
            
            
            37,931Liabilities
                associated with drilling contracts
            
            
            132,517
            
            
            86,765Current
                portion of hedge liability
            
            
            356
            
            
            172Accrued
                liabilities
            
            
            34,535
            
            
            21,534Total
                current liabilities
            
            
            222,489
            
            
            146,440Long-term
                debt
            
            
            740,000
            
            
            30Other
                long-term liabilities
            
            
            2,372
            
            
            13,248Advances
                from affiliates
            
            
            8,696
            
            
            12,502Long-term
                hedge liability
            
            
            39,204
            
            
            3,835Asset
                retirement obligations
            
            
            42,358
            
            
            26,726Commitments
                and contingencies (Note 8)Members’
                equity:Class
                B common unit holders
            
            
            835,447
            
            
            187,769Class
                A unit holder
            
            
            5,770
            
            
            3,825Accumulated
                other comprehensive income (loss)
            
            
            (5,102
            )
            
            21,088Total
                members’ equity
            
            
            836,115
            
            
            212,682$
            1,891,234
            
            $
            415,463





**See
      accompanying notes to combined and consolidated financial statements**




67





**ATLAS
      ENERGY RESOURCES, LLC**


**COMBINED
      AND CONSOLIDATED STATEMENTS** **OF INCOME**


(in
      thousands, except per unit data)


**Three
                Months**
            
            **Year****Years
                Ended**
            
            **Ended**
            
            **Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2005**
            
            **2005****REVENUES**Gas
                and oil production
            
            $
            180,125
            
            $
            88,449
            
            $
            24,086
            
            $
            63,499Well
                construction and completion
            
            
            321,471
            
            
            198,567
            
            
            42,145
            
            
            134,338Administration
                and oversight
            
            
            18,138
            
            
            11,762
            
            
            2,964
            
            
            9,590Well
                services
            
            
            17,592
            
            
            12,953
            
            
            2,561
            
            
            9,552Gathering
            
            
            14,314
            
            
            9,251
            
            
            1,407
            
            
            4,359Gainon
                mark-to-market derivatives
            
            
            26,257
            
            
            —
            
            
            —
            
            
            —Total
                revenues
            
            
            577,897
            
            
            320,982
            
            
            73,163
            
            
            221,338**COSTS
                AND EXPENSES**Gas
                and oil production
            
            
            32,193
            
            
            13,881
            
            
            2,441
            
            
            8,165Well
                construction and completion
            
            
            279,540
            
            
            172,666
            
            
            36,648
            
            
            116,816Well
                services
            
            
            9,062
            
            
            7,337
            
            
            1,487
            
            
            5,167Gathering
            
            
            214
            
            
            —
            
            
            38
            
            
            52Gathering
                fee - Atlas Pipeline
            
            
            13,781
            
            
            29,545
            
            
            7,930
            
            
            21,929General
                and administrative
            
            
            39,414
            
            
            23,367
            
            
            5,818
            
            
            13,202Net
                expense reimbursement - affiliate
            
            
            —
            
            
            1,237
            
            
            163
            
            
            602Depreciation,
                depletion and amortization
            
            
            56,942
            
            
            22,491
            
            
            4,916
            
            
            14,061Total
                operating expenses
            
            
            431,146
            
            
            270,524
            
            
            59,441
            
            
            179,994**OPERATING
                INCOME**
            
            
            146,751
            
            
            50,458
            
            
            13,722
            
            
            41,344**OTHER
                INCOME (EXPENSE)**Interest
                expense
            
            
            (30,096
            )
            
            —
            
            
            —
            
            
            —Other
                - net
            
            
            849
            
            
            1,369
            
            
            57
            
            
            79Total
                other income (expense)
            
            
            (29,247
            )
            
            1,369
            
            
            57
            
            
            79Net
                income before cumulative effect of accounting change
            
            
            117,504
            
            
            51,827
            
            
            13,779
            
            
            41,423Cumulative
                effect of accounting change
            
            
            ─
            
            
            6,355
            
            
            —
            
            
            —Net
                income
            
            $
            117,504
            
            $
            58,182
            
            $
            13,779
            
            $
            41,423**Allocation
                of net income attributable to members’
                interests/owners:**Portion
                applicable to owner’s interest (period prior to the initial public
                offering on December 18, 2006)
            
            $
            —
            
            $
            55,375
            
            $
            13,779
            
            $
            41,423Portion
                applicable to members’ interests (period subsequent to the initial public
                offering on December 18, 2006)
            
            
            117,504
            
            
            2,807
            
            
            —
            
            
            —$
            117,504
            
            $
            58,182
            
            $
            13,779
            
            $
            41,423**Allocation
                of net income attributable to members’ interests:**Class
                A units
            
            $
            4,099
            
            
            56Class
                B common units
            
            
            113,405
            
            $
            2,751Net
                income attributable to members’ interests
            
            $
            117,504
            
            $
            2,807**Net
                income per Class B common unit:**Basic
            
            $
            2.32
            
            $
            .08Diluted
            
            $
            2.29
            
            $
            .08**Weighted
                average Class B common units outstanding:**Basic
            
            
            48,909
            
            
            36,627Diluted
            
            
            49,449
            
            
            36,638





**See
      accompanying notes to combined and consolidated financial statements**





68





**ATLAS
      ENERGY RESOURCES, LLC**


**COMBINED
      AND CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME**


(in
      thousands)





**Three
                Months****Years
                Ended**
            
            **Ended**
            
            **Year
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2005**
            
            **2005**Net
                income before taxes
            
            $
            117,504
            
            $
            58,182
            
            $
            13,779
            
            $
            41,423Other
                comprehensive income:Unrealized
                holding gains (losses) on hedging contracts
            
            
            (8,582
            )
            
            31,834
            
            
            (3,664
            )
            
            —Less:
                reclassification adjustment for gains realized in net
                income
            
            
            (17,608
            )
            
            (7,082
            )
            
            —
            
            
            —(26,190
            )
            
            24,752
            
            
            (3,664
            )
            
            —Comprehensive
                income
            
            $
            91,314
            
            $
            82,934
            
            $
            10,115
            
            $
            41,423




**See
      accompanying notes to combined and consolidated financial statements**




69





**ATLAS
      ENERGY RESOURCES, LLC**


**COMBINED
      AND CONSOLIDATED STATEMENTS OF EQUITY**


(in
      thousands, except unit data)


**Accumulated**
                
                
                
                **Total****Other**
                
                
                
                **Owner's****Comprehensive**
                
                **Net**
                
                **Equity/****Owner's**
                
                **Class
                    A Units**
                
                **Class
                    B**
                  **Common
                    Units**
                
                **Class
                    D Units**
                
                **Income**
                
                **Affiliate**
                
                **Members'****Equity**
                
                **Units**
                
                **Amount**
                
                **Units**
                
                **Amount**
                
                **Units**
                
                **Amount**
                
                **(Loss)**
                
                **Investment**
                
                **Equity****Balance,
                    October 1, 2004**
                
                $
                109,461
                
                
                —
                
                $
                —
                
                
                —
                
                $
                —
                
                
                —
                
                $
                —
                
                $
                —
                
                $
                109,461
                
                $
                109,461Net
                    change in affiliate advances
                
                
                (4,742
                )
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                (4,742
                )
                
                (4,742
                )Net
                    income
                
                
                41,423
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                41,423
                
                
                41,423**Balance,
                    September 30, 2005**
                
                $
                146,142
                
                
                —
                
                $
                —
                
                
                —
                
                $
                —
                
                
                —
                
                $
                —
                
                $
                —
                
                $
                146,142
                
                $
                146,142Net
                    change in affiliate advances
                
                
                (1,738
                )
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                (1,738
                )
                
                (1,738
                )Other
                    comprehensive income
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                (3,664
                )
                
                —
                
                
                (3,664
                )Net
                    income
                
                
                13,779
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                13,779
                
                
                13,779**Balance,
                    December 31, 2005**
                
                $
                158,183
                
                
                —
                
                $
                —
                
                
                —
                
                $
                —
                
                
                —
                
                $
                —
                
                $
                (3,664
                )
                $
                158,183
                
                $
                154,519Net
                    income attributable to ownerprior
                    to IPO on December 18,2006
                
                
                55,375
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                55,375
                
                
                55,375Net
                    assets retained by owner
                
                
                (25,108
                )
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                (25,108
                )
                
                (25,108
                )Net
                    assets contributed by owner
                
                
                (188,450
                )
                
                748,456
                
                
                3,769
                
                
                29,352,996
                
                
                184,681
                
                
                —
                
                
                —
                
                
                —
                
                
                (188,450
                )
                
                —Issuance
                    of common units in IPO
                
                
                —
                
                
                —
                
                
                
                
                
                7,273,750
                
                
                139,944
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                139,944Distribution
                    to owner
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                (139,944
                )
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                (139,944
                )Stock
                    option compensation
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                337
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                337Net
                    income attributable to unitholders
                    subsequent to IPO
                
                
                —
                
                
                —
                
                
                56
                
                
                —
                
                
                2,751
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                2,807Other
                    compensation income
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                24,752
                
                
                
                
                
                24,752**Balance,
                    December 31, 2006**
                
                $
                —
                
                
                748,456
                
                $
                3,825
                
                
                36,626,746
                
                $
                187,769
                
                
                —
                
                $
                —
                
                $
                21,088
                
                $
                —
                
                $
                212,682Units
                    issued
                
                
                —
                
                
                490,530
                
                
                —
                
                
                7,380,800
                
                
                181,179
                
                
                16,702,828
                
                
                416,316
                
                
                —
                
                
                —
                
                
                597,495Stock
                    based compensation
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                4,684
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                4,684Distributions
                    to members
                
                
                —
                
                
                —
                
                
                (2,154
                )
                
                —
                
                
                (57,941
                )
                
                —
                
                
                (9,187
                )
                
                —
                
                
                —
                
                
                (69,282
                )Distributions
                    paid on unissuedunits
                    under incentive plan
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                (778
                )
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                (778
                )Other
                    comprehensive income
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                (26,190
                )
                
                —
                
                
                (26,190
                )Conversion
                    of Class D units
                
                
                —
                
                
                —
                
                
                —
                
                
                16,702,828
                
                
                415,845
                
                
                (16,702,828
                )
                
                (415,845
                )
                
                —
                
                
                —
                
                
                —Net
                    income
                
                
                —
                
                
                —
                
                
                4,099
                
                
                
                
                
                104,689
                
                
                —
                
                
                8,716
                
                
                —
                
                
                —
                
                
                117,504**Balance,
                    December 31, 2007**
                
                $
                —
                
                
                1,238,986
                
                $
                5,770
                
                
                60,710,374
                
                $
                835,447
                
                $
                —
                
                $
                —
                
                $
                (5,102
                )
                $
                —
                
                $
                836,115





**See
      accompanying notes to combined and consolidated financial
      statements**





70




**ATLAS
      ENERGY RESOURCES, LLC**


**COMBINED
      AND CONSOLIDATED STATEMENTS OF CASH FLOWS**


(in
      thousands)





**Three
                Months****Years
                Ended**
            
            **Ended**
            
            **Year
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2005**
            
            **2005****CASH
                FLOWS FROM OPERATING ACTIVITIES:**Net
                income
            
            $
            117,504
            
            $
            58,182
            
            $
            13,779
            
            $
            41,423Adjustments
                to reconcile net income to net cash
              provided
                by operating activities:Amortization
                of deferred finance costs
            
            
            3,040
            
            
            ─
            
            
            ─
            
            
            ─Depreciation,
                depletion and amortization
            
            
            56,942
            
            
            22,491
            
            
            4,916
            
            
            14,061Write
                down of note receivable
            
            
            ─
            
            
            3
            
            
            ─
            
            
            487Non-cash
                compensation on long-term incentive plans
            
            
            4,684
            
            
            337
            
            
            393
            
            
            300Loss
                (gain) on asset dispositions
            
            
            111
            
            
            (39
            )
            
            (2
            )
            
            (52
            )Cumulative
                effect of accounting change
            
            
            ─
            
            
            (6,355
            )
            
            ─
            
            
            ─Non-cash
                gain on derivatives
            
            
            (14,000
            )
            
            ─
            
            
            ─
            
            
            ─Equity
                in loss of unconsolidated subsidiary
            
            
            158
            
            
            ─
            
            
            ─
            
            
            ─Minority
                interest
            
            
            32
            
            
            ─
            
            
            ─
            
            
            ─Changes
                in operating assets and liabilities:(Increase)
                decrease in accounts receivable and prepaid expenses
            
            
            3,239
            
            
            (8,862
            )
            
            (4,229
            )
            
            (2,550
            )Increase
                (decrease) in accounts payable
            
            
            6
            
            
            (3,229
            )
            
            16,940
            
            
            4,340Increase
                in liabilities associated with drilling contracts
            
            
            45,752
            
            
            16,251
            
            
            9,543
            
            
            31,596Increase
                in other operating assets and liabilities
            
            
            13,514
            
            
            1,757
            
            
            2,256
            
            
            920Net
                cash provided by operating activities
            
            
            230,982
            
            
            80,536
            
            
            43,596
            
            
            90,525**CASH
                FLOWS FROM INVESTING ACTIVITIES:**Net
                cash paid for acquisition
            
            
            (1,272,518
            )
            
            ─
            
            
            ─
            
            
            ─Capital
                expenditures
            
            
            (196,735
            )
            
            (75,635
            )
            
            (17,187
            )
            
            (59,124
            )Proceeds
                from sale of assets
            
            
            1,092
            
            
            47
            
            
            3
            
            
            111Increase
                in other assets
            
            
            (273
            )
            
            ─
            
            
            (1
            )
            
            (37
            )Net
                cash used in investing activities
            
            
            (1,468,434
            )
            
            (75,588
            )
            
            (17,185
            )
            
            (59,050
            )**CASH
                FLOWS FROM FINANCING ACTIVITIES:**Borrowings
            
            
            951,891
            
            
            ─
            
            
            91
            
            
            ─Principal
                payments on borrowings
            
            
            (211,929
            )
            
            (88
            )
            
            (17
            )
            
            (339
            )Distributions
                to unitholders
            
            
            (69,282
            )
            
            ─
            
            
            ─
            
            
            ─Distributions
                net of capital contributions to AAI
            
            
            ─
            
            
            (139,944
            )
            
            ─
            
            
            ─Net
                proceeds from issuance of units
            
            
            597,495
            
            
            139,944
            
            
            ─
            
            
            ─Advances
                to affiliates
            
            
            (3,806
            )
            
            (16,748
            )
            
            (11,813
            )
            
            (25,081
            )Increase
                in deferred financing costs
            
            
            (10,492
            )
            
            (197
            )
            
            ─
            
            
            ─Decrease
                in other assets
            
            
            ─
            
            
            ─
            
            
            ─
            
            
            19Net
                cash provided by (used in) financing activities
            
            
            1,253,877
            
            
            (17,033
            )
            
            (11,739
            )
            
            (25,401
            )Increase
                (decrease) in cash and cash equivalents
            
            
            16,425
            
            
            (12,085
            )
            
            14,672
            
            
            6,074Cash
                and cash equivalents at beginning of period
            
            
            8,833
            
            
            20,918
            
            
            6,246
            
            
            172Cash
                and cash equivalents at end of period
            
            $
            25,258
            
            $
            8,833
            
            $
            20,918
            
            $
            6,246





**See
      accompanying notes to combined and consolidated financial statements**





71





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS**





**NOTE
      1—DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION**





Atlas
      Energy Resources, LLC (“the Company”) is a publicly-traded Delaware limited
      liability company (NYSE: ATN). The Company is an independent developer and
      producer of natural gas and, to a lesser extent, oil in Northern Michigan's
      Antrim Shale and the Appalachian Basin. The Company is also a leading sponsor
      of
      and manages tax-advantaged direct investment partnerships, in which it coinvests
      to finance the exploitation and development of its acreage (“the Partnerships”).
      The Company's Northern Michigan operations are newly acquired (See Note
      3).





The
      Company was 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, Inc. (“AAI”) (NASDAQ: ATLS). AAI 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. ** In
      December 2006, the Company completed an initial public offering of 7,273,750
      units of its Class B common units, representing a 19.4% interest, at a price
      of
      $21.00 per common unit. The net proceeds of the offering of $139.9 million,
      after deducting underwriting discounts and costs, were distributed to AAI in
      the
      form of a non-taxable dividend and to repay debt. Concurrent with this
      transaction, Atlas America contributed all of the stock of its natural gas
      and
      oil development and production subsidiaries and its development and production
      assets in exchange for 29,352,996 common units and 748,456 Class A units. On
      June 29, 2007, Atlas Energy acquired DTE Gas and Oil Company from DTE Energy
      Company (“DTE”) for $1.273 billion in cash (See Note 3). On June 29, 2007, the
      Company also completed a private placement of 7,298,181 Class B common units
      and
      16,702,828 Class D units to a group of institutional investors to fund the
      acquisition of DTE Gas and Oil Company. After the completion of the offering
      and
      private placement, AAI owns 49.4% of the Company. For periods prior to the
      completion of the Company’s initial public offering, the combined and
      consolidated financial statements include the AAI subsidiaries which then held
      the Company’s assets.





**Principles
      of Combination and Consolidation**





The
      combined and consolidated financial statements of the Company before the date
      of
      its initial public offering have been prepared from the separate records
      maintained by AAI and may not necessarily be indicative of the conditions that
      would have existed or the results of operations if the Company had been operated
      as an unaffiliated entity. Because a direct ownership relationship did not
      exist
      among all the various entities comprising the Company, AAI’s net investment in
      the Company was shown as combined equity in the combined and consolidated
      financial statements. Transactions between the Company and other AAI operations
      have been identified in the combined and consolidated financial statements
      as
      transactions between affiliates (see Note 6). In accordance with
      established practice in the oil and gas industry, the Company includes its
      pro-rata share of assets, liabilities, revenues and costs and expenses of the
      investment partnerships in which it has an interest. Such interests typically
      range from 30% to 35%. All significant intercompany balances and transactions
      within the Company have been eliminated.





**Change
      in Year End**





On
      June 15, 2006, AAI’s Board of Directors changed the Company’s year end to
      December 31 from September 30. Accordingly, the Company’s combined and
      consolidated financial statements include its operations for the years ended
      December 31, 2007 and 2006, the three-month transition period ended
      December 31, 2005 and the year ended September 30, 2005.





72





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -
      (CONTINUED)**





**NOTE
      2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES**





**Use
      of Estimates**





Preparation
      of the combined and consolidated financial statements in conformity with
      accounting principles generally accepted in the United States of America
      requires management to make estimates and assumptions that affect the reported
      amounts of assets and liabilities and the disclosure of contingent assets and
      liabilities as of the date of the consolidated financial statements and the
      reported amounts of revenues and costs and expenses during the reporting period.
      Actual results could differ from these estimates.





**Reclassifications**





Certain
      reclassifications have been made to the combined and consolidated financial
      statements to conform to the 2007 presentation.





**Stock-Based
      Compensation**





The
      Company applies SFAS No. 123(R), “Share-Based Payment,” as revised (“SFAS No.
      123(R)”), to account for its Long-Term Incentive Plan (see Note 11). Generally,
      the approach to accounting for Statement 123(R) requires all unit-based payments
      to employees, including grants of employee stock options, to be recognized
      in
      the financial statements based on their fair values.





The
      Company did not have any unit-based payments outstanding prior to the adoption
      of SFAS No. 123(R), and has only granted restricted and phantom units and unit
      options in 2007 and 2006. The restricted and phantom units have no exercise
      price and, as such, the Company recognized compensation expense based upon
      the
      market price of the Company’s common units at the date of grant. The Company
      uses the Black Scholes option pricing model to estimate the weighted average
      fair value of the unit options to calculate compensation expense.





**Net
      Income Per Common Unit**





Basic
      earnings per unit for Class B units is computed by dividing net income, after
      the deduction of net income allocable to the Class A units and unit incentive
      awards, attributable to unit holders by the weighted average number of units
      outstanding during each period. The Class A unit holder’s allocable share of net
      income is calculated on a quarterly basis based upon AAI’s 2% interest and
      incentive distributions





Diluted
      earnings per unit is computed by adjusting the average number of units
      outstanding for the dilutive effect, if any, of the Company’s restricted unit
      and unit option awards, as calculated by the treasury stock method. Restricted
      units and unit options consist of common units issuable under the terms of
      the
      Company’s Long-Term Incentive Plan (See Note 11).





Prior
      to
      the closing of the Company’s initial public offering on December 18, 2006, there
      were no common units outstanding. As such, the Company’s 2006 net income
      attributable to common unit holders is only presented for the period from
      December 18, 2006 to December 31, 2006. The cumulative effect adjustment related
      to the adoption of FASB Interpretation No. 47, “Accounting for Conditional Asset
      Retirement Obligations” (“FIN 47”)  was allocated to the owner’s interest
      prior to the date of the Company’s initial public offering, as substantially all
      of the adjustment related to
      that
      period. The following table sets forth the reconciliation of the Company’s
      weighted average number of common units used to compute basic net income
      attributable to common unit holders per unit with those used to compute diluted
      net income attributable to common unit holders per unit (in
      thousands):





73





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**




**NOTE
                2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
                (Continued)**


**Period
                from****Year
                Ended**
            
            **December
                18, 2006****December
                31,****2007**
            
            **to
                December 31, 2006**Weighted
                average number of common unit holder units - basic
            
            
            48,909
            
            
            36,627Add
                effect of dilutive unit incentive awards
            
            
            540
            
            
            11Weighted
                average number of common unit holder units - diluted
            
            
            49,449
            
            
            36,638





**Comprehensive
      Income (Loss)**





Comprehensive
      income (loss) includes net income (loss) and all other changes in the equity
      of
      a business during a period from transactions and other events and circumstances
      from non-owner sources. These changes, other than net income (loss), are
      referred to as “other comprehensive income (loss)” and for the Company include
      only changes in the fair value of unrealized hedging gains and
      losses.





**Accounts
      Receivables and Allowance for Possible Losses**





In
      evaluating its allowance for possible losses, the Company performs ongoing
      credit evaluations of its customers and adjusts credit limits based upon payment
      history and the customer’s current creditworthiness, as determined by the
      Company’s review of its customer’s credit information. The Company extends
      credit on an unsecured basis to many of its customers. At December 31, 2007
      and
      2006, the Company’s credit evaluation indicated that it had no need for an
      allowance for possible losses.





**Property,
      Plant and Equipment**





Property,
      plant and equipment is stated at cost. Depreciation, depletion and amortization
      are based on cost less estimated salvage value primarily using the
      units-of-production or straight line method over the assets estimated useful
      lives. Maintenance and repairs are expensed as incurred. Major renewals and
      improvements that extend the useful lives of property are capitalized.





The
      estimated service lives of property, plant and equipment are as follows:





Buildings
                and improvements
            10-40
                yearsFurniture
                and equipment
            3-7
                yearsOther
            3-10
                years




74





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**


**NOTE
        2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
        (Continued)**


Property,
      plant and equipment consists of the following at the dates indicated (in
      thousands):




**December
                  31,****2007**
              
              **2006**Natural
                  gas and oil properties:Proved
                  properties:Leasehold
                  interests
              
              $
              1,043,687
              
              $
              11,302Wells
                  and related equipment
              
              
              752,184
              
              
              338,5801,795,871
              
              
              349,882Unproved
                  properties
              
              
              16,380
              
              
              1,002Support
                  equipment
              
              
              6,936
              
              $
              5,5411,819,187
              
              
              356,425Land,
                  buildings and improvements
              
              
              5,881
              
              
              4,169Other
              
              
              9,653
              
              
              4,8481,834,721
              
              
              365,442Accumulated
                  depreciation, depletion and amortization:
              
              
              (141,254
              )
              
              (87,628
              )$
              1,693,467
              
              $
              277,814





**Oil
      and Gas Properties**





The
      Company follows the successful efforts method of accounting for oil and gas
      producing activities. Exploratory drilling costs are capitalized pending
      determination of whether a well is successful. Exploratory wells subsequently
      determined to be dry holes are charged to expense. Costs resulting in
      exploratory discoveries and all development costs, whether successful or not,
      are capitalized. Geological and geophysical costs and delay rentals are
      expensed. Oil is converted to gas equivalent basis (“Mcfe”) at the rate one
      barrel equals 6 Mcf. Depletion is provided on the units-of-production
      method.





Upon
      the
      sale or retirement of a complete field of a proved property, the cost is
      eliminated from the property accounts, and the resultant gain or loss is
      reclassified to income. Upon the sale of an individual well the proceeds are
      credited to accumulated depreciation and depletion. Upon the sale of an entire
      interest in an unproved property where the property had been assessed for
      impairment individually, a gain or loss is recognized in the statements of
      income. If a partial interest in an unproved property is sold, any funds
      received are accounted for as a reduction of the cost in the interest
      retained.





**Goodwill**





The
      Company applies the provisions of SFAS No. 142 (“SFAS 142”) “Goodwill and
      Other Intangible Assets,” which requires that goodwill no longer be amortized,
      but instead evaluated for impairment at least annually. The evaluation of
      impairment under SFAS 142 requires the use of projections, estimates and
      assumptions as to the future performance of the Company’s operations, including
      anticipated future revenues, expected future operating costs and the discount
      factor used. Actual results could differ from projections, resulting in
      revisions to the Company’s assumptions and, if required, recognition of an
      impairment loss. The Company’s evaluation of goodwill at December 31, 2007
      indicated there was no impairment loss and no impairment indicators arose during
      the year ended December 31, 2007. The Company will continue to evaluate its
      goodwill at least annually or when impairment indicators arise, and will reflect
      the impairment of goodwill, if any, within the combined and consolidated
      statements of income in the period in which the impairment is indicated.





75





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**


**NOTE
        2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
        (Continued)**


**Impairment
      of Long-Lived Assets**





The
      Company’s long-lived assets are reviewed for impairment whenever events or
      changes in circumstances indicate that their carrying amounts may not be
      recoverable. Long-lived assets are reviewed for potential impairments at the
      lowest levels for which there are identifiable cash flows that are largely
      independent of other groups of assets.





The
      review of the Company’s oil and gas properties is done by determining if the
      historical cost of proved properties less the applicable accumulated
      depreciation, depletion and amortization and abandonment is less than the
      estimated expected undiscounted future cash flows. The expected future cash
      flows are estimated based on the Company’s plans to continue to produce and
      develop proved reserves. Expected future cash flow from the sale of production
      of reserves is calculated based on estimated future prices. The Company
      estimates prices based upon current contracts in place at December 31, 2007
      adjusted for basis differentials and market related information including
      published futures prices. The estimated future level of production is based
      on
      assumptions surrounding future levels of prices and costs, field decline rates,
      market demand and supply, and the economic and regulatory climates. If the
      carrying value exceeds such cash flows, an impairment loss is recognized for
      the
      difference between the estimated fair market value, (as determined by discounted
      future cash flows) and the carrying value of the assets.





Unproved
      properties are reviewed annually for impairment or whenever events or
      circumstances indicate that the carrying amount of an asset may not be
      recoverable. Impairment charges are recorded if conditions indicate the Company
      will not explore the acreage prior to expiration of the applicable leases or
      if
      it is determined that the carrying value of the properties is above their fair
      value.





**Capitalized
      Interest**





The
      Company capitalizes interest on borrowed funds related to its share of costs
      associated with the drilling and completion of new oil and gas wells and other
      capital projects. Interest is capitalized only during the periods in which
      these
      assets are brought to their intended use. The weighted average interest rate
      used to capitalize interest was 6.7% for the year ended December 31, 2007,
      which
      resulted in interest capitalized of $2.7 million. There was no interest
      capitalized for the year ended December 31, 2006.





**Asset
      Retirement Obligations**





The
      Company accounts for asset retirement obligations as required under SFAS
      No. 143, “Accounting for Retirement Asset Obligations” (“SFAS 143”). SFAS
      143 requires that the fair value of a liability for an asset retirement
      obligation be recognized in the period in which it is incurred, with the
      associated asset retirement costs being capitalized as a part of the carrying
      amount of the long-lived asset. The Company has asset retirement obligations
      related to the plugging and abandonment of its oil and gas wells. SFAS 143
      requires the Company to consider estimated salvage value in the calculation
      of
      depreciation, depletion and amortization.





In
      March
      2005, the Financial Accounting Standards Board (“FASB”) issued FIN 47. FIN 47
      clarified that the term “conditional asset retirement obligation” as used in FAS
      No. 143 refers to a legal obligation to perform an asset retirement
      activity in which the timing and/or method of settlement are conditional on
      a
      future event that may or may not be within the control of the entity. Since
      the
      obligation to perform the asset retirement activity is unconditional, FIN 47
      provides that a liability for the fair value of a conditional asset obligation
      should be recognized if that fair value can be reasonably estimated, even though
      uncertainty exists about the timing and/or method of settlement. FIN 47 also
      clarifies when an entity would have sufficient information to reasonably
      estimate the fair value of a conditional asset retirement obligation under
      FAS
      No. 143.





Under
      SFAS No.143, the Company had recorded its asset retirement obligation based
      on a
      probability factor which considered the Company’s history of selling its wells
      or otherwise disposing of them without incurring a disposal cost.





76





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**


**NOTE
        2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
        (Continued)**





FIN
      47
      requires the Company to record its retirement obligation without regard to
      its
      prior practice and accrue for obligations for all wells owned by the Company
      without regard to their probability of being sold or otherwise disposed of
      without incurring a disposal cost. Accordingly, the Company adopted FIN 47
      as of
      December 31, 2006 and recognized $6.4 million in 2006 as a cumulative
      effect of an accounting change. Additionally, the Company’s Consolidated Balance
      Sheet recognized an increase as of December 31, 2006 in its asset
      retirement obligation of $8.0 million, and a net increase in property and
      equipment of approximately $14.4 million.





Had
      the
      Company implemented FIN 47 retroactively to October 1, 2002, the following
      pro forma information summarizes the impact for the periods presented (in
      thousands):





**Year**
            
            **Three
                Months**
            
            **Year****Ended**
            
            **Ended**
            
            **Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**Net
                income as reported
            
            $
            51,827
            
            $
            13,779
            
            $
            41,423Proforma
                asset retirement obligation adjustment
            
            
            1,414
            
            
            576
            
            
            1,576Proforma
                net
                income as adjusted
            
            
            53,241
            
            
            14,355
            
            
            42,999Proforma
                asset retirement obligation
            
            $
            26,726
            
            $
            26,086
            
            $
            25,126





**Fair
      Value of Financial Instruments**





The
      Company used the following assumptions in estimating the fair value of each
      class of financial instrument for which it is practicable to estimate fair
      value:





·
            For
                receivables and payables, the carrying amounts approximate fair value
                because of the short maturity of these
                instruments.


·
            For
                derivatives the carrying value approximates fair
                value.


·
            For
                debt the carrying value approximates fair value because of the
                substantially short maturity of these instruments and variable interest
                rates in the related debt
                agreements.


**Derivative
        Instruments**
 
 The
        Company applies the provisions of SFAS No. 133, “Accounting for Derivative
        Instruments and Hedging Activities” (“SFAS 133”). SFAS 133 requires each
        derivative instrument to be recorded in the balance sheet as either an asset
        or
        liability measured at fair value. Changes in a derivative instrument’s fair
        value are recognized currently in earnings unless specific hedge accounting
        criteria are met (see Note 7).


**Concentration
      of Credit Risk**





Financial
      instruments, which potentially subject the Company to concentrations of credit
      risk, consist principally of periodic temporary investments of cash and cash
      equivalents. The Company places its temporary cash investments in high-quality
      short-term money market instruments and deposits with high-quality financial
      institutions and brokerage firms. At December 31, 2007 and 2006, the Company
      had
      $41.8 million and $13.5 million, respectively, in deposits at various banks,
      of
      which $40.9 million and $13.0 million, respectively, was over the insurance
      limit of the Federal Deposit Insurance Corporation. No losses have been
      experienced on such investments to date.




77





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**


**NOTE
        2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)**


**Environmental
      Matters**





The
      Company is subject to various federal, state and local laws and regulations
      relating to the protection of the environment. The Company has established
      procedures for the ongoing evaluation of its operations, to identify potential
      environmental exposures and to comply with regulatory policies and procedures.





The
      Company accounts for environmental contingencies in accordance with SFAS
      No. 5 “Accounting for Contingencies.” Environmental expenditures that
      relate to current operations are expensed as appropriate. Expenditures that
      relate to an existing condition caused by past operations, and do not contribute
      to current or future revenue generation, are also expensed. Liabilities for
      environmental contingencies are recorded when environmental assessments and/or
      clean-ups are probable and the costs can be reasonably estimated. The Company
      maintains insurance which may cover in whole or in part certain types of
      environmental contingencies. For the years ended December 31, 2007 and 2006,
      the
      three months ended December 31, 2005 and year ended September 30, 2006, the
      Company had no environmental contingencies requiring specific disclosure or
      the
      recording of a liability.





**Revenue
      Recognition**





The
      Company conducts certain energy activities through, and a portion of its
      revenues are attributable to, investment partnerships. The Company contracts
      with the investment partnerships to drill partnership wells. The contracts
      require that the investment partnerships must pay the Company the full contract
      price upon execution. The income from a drilling contract is recognized as
      the
      services are performed using the percentage of completion method. The contracts
      are typically completed in less than 60 days. On an uncompleted contract, the
      Company classifies the difference between the contract payments it has received
      and the revenue earned as a current liability.





The
      Company recognizes gathering revenues at the time the natural gas is delivered.





The
      Company recognizes well services revenues at the time the services are
      performed.





The
      Company is entitled to receive administration and oversight fees according
      to
      the respective partnership agreements. The Company recognizes such fees as
      income when services are performed.





The
      Company generally sells natural gas and crude oil at prevailing market prices.
      Revenue is recognized when produced quantities are delivered to a custody
      transfer point, persuasive evidence of a sales arrangement exists, the rights
      and responsibility of ownership pass to the purchaser upon delivery, collection
      of revenue from the sale is reasonably assured and the sales price is fixed
      or
      determinable. Revenues from the production of natural gas and crude oil in
      which
      the Company has an interest with other producers are recognized on the basis
      of
      the Company’s percentage ownership of working interest or overriding royalty.
      Generally, the Company’s sales contracts are based on pricing provisions that
      are tied to a market index, with certain adjustments based on proximity to
      gathering and transmission lines and the quality of its natural gas .





Because
      there are timing differences between the delivery of natural gas and oil and
      the
      Company’s receipt of a delivery statement, the Company has unbilled revenues.
      These revenues are accrued based upon volumetric data from the Company’s records
      and the Company’s estimates of the related transportation and compression fees
      which are, in turn, based upon applicable product prices. The Company had
      unbilled trade receivables at December 31, 2007 and 2006 of $44.9 million and
      $19.4 million, respectively, which are included in Accounts Receivable on its
      Consolidated Balance Sheets.





78





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**


**NOTE
        2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
        (Continued)**


**Supplemental
      Cash Flow Information**




The
      Company considers temporary investments with a maturity at the date of
      acquisition of 90 days or less to be cash equivalents. The Company did not
      pay
      cash for income taxes in any period presented.




Supplemental
      disclosure of cash flow information (in thousands):





**Years
                Ended**
            
            **Three
                Months Ended**
            
            **Year
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2005**
            
            **2005**Cash
                paid for interest(net of amount capitalized of $2.8 million in 2007)
            
            $
            23,151
            
            $
            ─
            
            $
            ─
            
            $
            ─Non-cash
                investing activities include the following:Current
                assets
            
            
            34,279
            
            
            ─
            
            
            ─
            
            
            ─Property,
                plant and equipment and other
            
            
            1,268,791
            
            
            ─
            
            
            ─
            
            
            ─Fair
                value of assets acquired
            
            
            1,303,070
            
            
            ─
            
            
            ─
            
            
            ─Liabilities
                assumed
            
            
            (30,552
            )
            
            ─
            
            
            ─
            
            
            ─Net
                cash paid
            
            $
            1,272,518
            
            $
            ─
            
            $
            ─
            
            $
            ─





**Income
      Taxes**




The
      Company is a limited liability company and has elected to be treated as a
      partnership for income tax purposes.  As a result, the Company is not
      subject to U.S. federal and most state income taxes.  The unit holders
      of the Company are liable for income taxes in regards to their distributive
      share of the Company’s taxable income.  Such taxable income may vary
      substantially from net income reported in the accompanying combined and
      consolidated financial statements.   Certain corporate subsidiaries of
      the Company are subject to federal and state income tax.  The federal and
      state income taxes related to the Company and these corporate subsidiaries
      were immaterial to the combined and consolidated financial statements and are
      recorded in pre-tax income on a current basis only.  Accordingly, no
      federal or state deferred income tax has been provided for in the accompanying
      combined and consolidated financial statements.




In
      June
      2006, the FASB released FASB Interpretation No. 48 “ Accounting
      for Uncertainty in Income Taxes ”,
      an
      Interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48
      provides guidance for how uncertain tax positions should be recognized,
      measured, presented and disclosed in the financial statements. FIN 48
      requires the evaluation of tax positions taken or expected to be taken in the
      course of preparing the Company’s tax returns to determine whether the tax
      positions have met a “more-likely-than-not” threshold of being sustained by the
      applicable tax authority. Tax benefits related to tax positions not deemed
      to
      meet the more-likely-than-not threshold are not permitted to be recognized
      in
      the financial statements.  The provisions of FIN 48 were adopted by the
      Company effective January 1, 2007.  Implementation of FIN 48 had no impact
      on the combined and consolidated financial statements of the Company for the
      year ended December 31, 2007.  The Company’s policy is to reflect
      interest and penalties related to uncertain tax positions as part of income
      tax
      expense, when and if they become applicable.




The
      Company files income tax returns in the U.S. federal and various state
      jurisdictions. With limited exceptions, the Company is no longer subject to
      income tax examinations by major tax authorities for years before 2006.





79





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**


**NOTE
        2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)**


**Recently
      Issued Financial Accounting Standards**





In
      December 2007, the Financial Accounting Standards Board, (“FASB”), issued
      Statement of Financial Accounting Standards No. 160, “Noncontrolling Interests
      in Consolidated Financial Statements” (“SFAS 160”). This statement amends
      Accounting Research Bulletin 51, “Consolidated Financial Statements”, to
      establish accounting and reporting standards for the noncontrolling (minority)
      interest in a subsidiary and for the deconsolidation of a subsidiary. It
      clarifies that a noncontrolling interest in a subsidiary is an ownership
      interest in the consolidated entity that should
      be
      reported as equity in the consolidated financial statements. .
      This
      statement is effective for fiscal periods beginning on or after December 15,
      2008. The Company does not expect the adoption of SFAS 160 to have a significant
      impact on its financial position or results of operations.





In
      December 2007, the FASB issued SFAS No 141(R), “Business Combinations” (“SFAS
      No. 141(R)”). SFAS No. 141(R) replaces SFAS No. 141, “Business Combinations”,
      however retains the fundamental requirements that the acquisition method of
      accounting be used for all business combinations and for an acquirer to be
      identified for each business combination. SFAS No. 141(R) requires an acquirer
      to recognize the assets acquired, liabilities assumed, and any noncontrolling
      interest in the acquiree at the acquisition date, be measured at their fair
      values as of that date, with specified limited exceptions. Changes subsequent
      to
      that date are to be recognized in earnings, not goodwill. Additionally, SFAS
      No.
      141 (R) requires costs incurred in connection with an acquisition be expensed
      as
      incurred. Restructuring costs, if any, are to be recognized separately from
      the
      acquisition. The acquirer in a business combination achieved in stages must
      also
      recognize the identifiable assets and liabilities, as well as the noncontrolling
      interests in the acquiree, at the full amounts of their fair values. SFAS No.
      141(R) is effective for business combinations occurring in fiscal years
      beginning on or after December 15, 2008. The Company will apply the requirements
      of SFAS No. 141(R) upon its adoption on January 1, 2009 and is currently
      evaluating whether SFAS No. 141(R) will have an impact on its financial position
      and results of operations.




In
      September 2007, the Emerging Issues Task Force (“EITF”) reached consensus on
      EITF Issue No. 07-4, “Application of the two-class method under FASB Statement
      No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF No. 07-4”),
      an update of EITF No. 03-6. EITF No. 07-4 requires the calculation of a Master
      Limited Partnership’s (“MLPs”) net earnings per limited partner unit for each
      period presented according to distributions declared and participation rights
      in
      undistributed earnings as if all of the earnings for that period had been
      distributed. In periods with undistributed earnings above specified levels,
      the
      calculation per the two-class method results in an increased allocation of
      such
      undistributed earnings to the general partner and a dilution of earnings to
      the
      limited partners. EITF No. 07-4 is effective for fiscal years beginning after
      December 15, 2007. The application of EITF 07-4 is not expected to have an
      effect on the Company’s earnings per unit calculation.




In
      April
      2007, the FASB issued FASB
      Staff Position FIN 39-1, “Amendment of FASB Interpretation No. 39” (“FSP
      FIN
      39-1”), which refers to FASB Interpretation No. 39, “Offsetting of Amounts
      Related to Certain Contracts,” (“FIN 39”). FSP FIN 39-1 amends FIN
      39, which allows an entity to offset fair value amounts recognized for the
      right
      to reclaim cash collateral or the obligation to return cash collateral against
      fair value amounts recognized for derivative instruments executed with the
      same
      counterparty under the same master netting arrangement. FSP FIN 39-1 was
      effective for fiscal years beginning after November 15, 2007. The Company does
      not expect the adoption of FSP FIN 39-1 to have an impact on its financial
      position or results of operations.




In
      February 2007, the FASB issued Statement of Financial Accounting Standards
      No. 159, “The Fair Value Option for Financial Assets and Financial
      Liabilities” (“SFAS 159”). SFAS 159 permits entities to choose to measure
      eligible financial instruments and certain other items at fair value. The
      objective is to improve financial reporting by providing entities with the
      opportunity to mitigate volatility in reported earnings caused by measuring
      related assets and liabilities differently without having to apply complex
      hedge
      accounting provisions. The statement will be effective as of the beginning
      of an
      entity’s first fiscal year beginning after November 15, 2007. The Statement
      offers various options in electing to apply the provisions of this Statement.
      The Company does not expect the adoption of SFAS 159 to have an impact on
      its financial position or results of operations.





80





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**


**NOTE
        2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)**


In
      September 2006, the Financial Accounting Standards Board, or FASB, issued
      Statement of Financial Accounting Standards No. 157, “Fair Value
      Measurement,” (“SFAS 157”). SFAS 157 addresses the need for increased
      consistency in fair value measurements, defining fair value as the price that
      would be received to sell an asset or paid to transfer a liability in an orderly
      transaction between market participants at the measurement date. It also
      establishes a framework for measuring fair value and expands disclosure
      requirements. In February 2008, the FASB issued Final FASB Staff Position,
      or
      FSP No. FAS 157-2. The FSP, which was effective upon issuance, delays the
      effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities,
      except for items that are recognized or disclosed at fair value at least once
      a
      year, to fiscal years beginning after November 15, 2008. The FSP also covers
      interim periods within the fiscal years for items within its scope. The delay
      is
      intended to allow the FASB and its constituents the time to consider the various
      implementation issues associated with SFAS 157. The Company does not expect
      the
      adoption of SFAS 157 to have a significant impact on its financial position
      or
      results of operations.




**NOTE
      3 — ACQUISITION OF DTE GAS & OIL COMPANY**





On
      June
      29, 2007, the Company acquired all of the outstanding equity interests of DTE
      Gas & Oil Company (“DGO”) from DTE Energy Company (NYSE:DTE) and MCN Energy
      Enterprises for $1.273 billion, including adjustments for working capital of
      $15.0 million and current year capital expenditures of $19.0 million. Assets
      acquired include interests in approximately 2,150 natural gas wells with
      estimated proved reserves of approximately 613.7 billion cubic feet of natural
      gas equivalents located in the northern lower peninsula of Michigan, 228,000
      developed acres, and 66,000 undeveloped acres. With this acquisition, the
      Company increased its natural gas and oil production as well as entered into
      a
      new region that offers additional opportunities to expand its operations.
      Subsequent to the acquisition of DGO, the Company changed DGO’s name to Atlas
      Gas & Oil Company (“AGO”).





To
      fund
      the acquisition, the Company borrowed $713.9 million on its new credit facility
      (See Note 9) and received net proceeds of $597.5 million from a private
      placement of its Class B common and new Class D units (See Note 12). Proceeds
      of
      $52.5 million were used to pay the outstanding balance of the Company’s then
      existing credit facility. The acquisition was accounted for using the purchase
      method of accounting under SFAS No. 141, Business Combinations (“SFAS No. 141”).
      The table on the following page presents the purchase price allocation,
      including professional fees and other related acquisition costs, to the assets
      acquired and liabilities assumed based on their estimated fair market value
      at
      the date of acquisition (in thousands):





81





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**


****NOTE
      3 — ACQUISITION OF DTE GAS & OIL COMPANY
      (Continued)****


Accounts
                receivable
            
            $
            33,764Prepaid
                expenses
            
            
            515Other
                assets
            
            
            890Leaseholds,
                gas and wells and related equipment
            
            
            1,267,901Total
                assets acquired
            
            
            1,303,070Accounts
                payable and accrued liabilities
            
            
            (19,233
            )Other
                liabilities
            
            
            (210
            )Asset
                retirement obligations
            
            
            (11,109
            )(30,552
            )Net
                assets acquired
            
            $
            1,272,518





The
      purchase price allocation for the acquisition is based on a third-party
      valuation. It is subject to minor adjustments as management finalizes the
      allocation. AGO’s operations are included within the Company’s combined and
      consolidated financial statements beginning June 29, 2007.





The
      following data presents pro forma revenues, net income and basic and diluted
      net
      income per unit for the Company as if the AGO acquisition, Class B common unit
      and Class D unit equity offerings (See Note 12) and new revolving credit
      facility (See Note 9) had occurred on January 1, 2006. The Company has prepared
      these unaudited pro forma financial results for comparative purposes only;
      they
      may not be indicative of the results that would have occurred if the Company
      had
      completed the acquisition at January 1, 2006 or the results that will be
      attained in the future. Net income for the year ended December 31, 2006 includes
      periods prior to the Company’s initial public offering on December 18, 2006, and
      therefore, no earnings per unit has been presented (in thousands, except per
      unit amounts):





**Year
                Ended****December
                31, 2007****As**
              **Reported**
            
            **Pro
                Forma**
              **Adjustments**
            
            **Pro**
              **Forma**Revenues
            
            $
            577,897
            
            $
            15,888
            
            $
            593,785Net
                income
            
            $
            117,504
            
            $
            (57,877
            )
            $
            59,627Net
                income attributable to Class B unit holders
            
            $
            113,405
            
            $
            (54,971
            )
            $
            58,434Net
                income per Class B common unit outstanding - basic
            
            $
            2.32
            
            $
            (1.36
            )
            $
            0.96Weighted
                average Class B common units outstanding - basic
            
            
            48,909
            
            
            11,801
            
            
            60,710Net
                income per Class B common unit - diluted
            
            $
            2.29
            
            $
            (1.34
            )
            $
            0.95Weighted
                average Class B common units outstanding - diluted
            
            
            49,449
            
            
            11,740
            
            
            61,189





**Year
                Ended****December
                31, 2006****As**
              **Reported**
            
            **Pro
                Forma**
              **Adjustments**
            
            **Pro**
              **Forma**Revenues
            
            $
            320,982
            
            $
            291,346
            
            $
            612,328Net
                income before cumulative effect of accounting change
            
            
            51,827
            
            
            145,923
            
            
            197,750Net
                income
            
            
            58,182
            
            
            145,923
            
            
            204,105




82





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**  **NOTE
        3 — ACQUISITION OF DTE GAS & OIL COMPANY (Continued)**


Pro
      forma
      adjustments to revenues include substantial losses and gains on derivatives
      realized by AGO of $54.1 million and $149.5 million in fiscal 2007 and 2006,
      respectively. All existing derivatives were canceled upon the acquisition of
      AGO
      by the Company and the Company entered into new derivative contracts covering
      future AGO production. Pro forma adjustments include financial hedges between
      AGO and its affiliate. In addition, pro forma adjustments include depreciation,
      depletion and amortization related to assets acquired and interest expense
      associated with debt entered into to acquire such assets.





**NOTE
      4 - OTHER ASSETS AND INTANGIBLE ASSETS**





**Other
      Assets**





The
      following table provides information about other assets at the dates indicated
      (in thousands):





**At
                December 31,****2007**
            
            **2006**Long-term
                hedge receivable from Partnerships
            
            $
            13,542
            
            $
            2,131Long-term derivative
                asset
            
            
            6,882
            
            
            23,843Deferred
                finance costs,
                net of accumulated amortization of $2,708 and $0
            
            
            7,650
            
            
            194Other
            
            
            238
            
            
            122$
            28,312
            
            $
            26,290





Long-term
      hedge receivable from Partnerships represents the portion of the long-term
      unrealized hedge liability on contracts that has been allocated to them based
      on
      their share of total production volumes sold.





**Intangible
      Assets**





Included
      in intangible assets are partnership management and operating contracts acquired
      through previous acquisitions which were recorded at fair value on their
      acquisition dates. In addition, in 2007 the Company entered into a two-year
      non-compete agreement in connection with the acquisition of AGO. The Company
      amortizes these contracts on the declining balance and straight-line methods,
      over their respective estimated lives, ranging from two to thirteen years.
      Amortization expense for these contracts for the years ended December 31, 2007
      and 2006, three months ended December 31, 2005 and year ended September 30,
      2005
      was $1.0 million, $879,000, $220,000, and $933,000, respectively.





The
      aggregate estimated annual amortization expense of partnership management and
      operating contracts and the non-compete agreement for the next five years ending
      December 31 is as follows: 2008—$1.2 million; 2009—$964,000; 2010—$710,000;
      2011─$664,000 and 2012—$180,000.





The
      following table provides information about intangible assets at the dates
      indicated (in thousands):





**At
                December 31,****2007**
            
            **2006**Management
                and operating contracts
            
            $
            14,343
            
            $
            14,343Non-compete
                agreement
            
            
            890
            
            
            ―Total
                costs
            
            
            15,233
            
            
            14,343Accumulated
                amortization
            
            
            (10,172
            )
            
            (9,132
            )$
            5,061
            
            $
            5,211




83





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**





**NOTE
      5—ASSET RETIREMENT OBLIGATIONS**





The
      Company follows SFAS No 143 and FIN 47 “Accounting for Conditional Asset
      Retirement Obligations,” which require the Company to recognize an estimated
      liability for the plugging and abandonment of its oil and gas wells. Under
      SFAS
      143, the Company must currently recognize a liability for future asset
      retirement obligations if a reasonable estimate of the fair value of that
      liability can be made. The associated asset retirement costs are capitalized
      as
      part of the carrying amount of the long-lived asset. SFAS 143 requires the
      Company to consider estimated salvage value in the calculation of depreciation,
      depletion and amortization.





The
      estimated liability is based on historical experience in plugging and abandoning
      wells, estimated remaining lives of those wells based on reserve estimates,
      external estimates as to the cost to plug and abandon the wells in the future,
      and federal and state regulatory requirements. The liability is discounted
      using
      an assumed credit- **** adjusted
      risk- free
      interest rate. Revisions to the liability could occur due to changes in
      estimates of plugging and abandonment costs or remaining lives of the wells,
      or
      if federal or state regulators enact new plugging and abandonment requirements.
      The increase in asset retirement obligations in the year ended September 30,
      2005 was due to an upward revision in the estimated cost of plugging and
      abandoning wells.





The
      Company has no assets legally restricted for purposes of settling asset
      retirement obligations. Except for the item previously referenced, the Company
      has determined that there are no other material retirement obligations
      associated with tangible long-lived assets.





A
      reconciliation of the Company’s liability for well plugging and abandonment
      costs for the periods indicated is as follows (in thousands):





**Three
                Months****Years
                Ended**
            
            **Ended**
            
            **Year
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2005**
            
            **2005**Asset
                retirement obligations, beginning of period
            
            $
            26,726
            
            $
            18,499
            
            $
            17,651
            
            $
            4,889Cumulative
                effect of adoption of FIN 47
            
            
            —
            
            
            8,042
            
            
            —
            
            
            —Liabilities
                acquired
            
            
            11,109
            
            
            —
            
            
            —
            
            
            —Liabilities
                incurred
            
            
            2,582
            
            
            1,570
            
            
            725
            
            
            770Liabilities
                settled
            
            
            (91
            )
            
            (194
            )
            
            —
            
            
            (137
            )Revision
                in estimates
            
            
            —
            
            
            (2,411
            )
            
            —
            
            
            11,788Accretion
                expense
            
            
            2,032
            
            
            1,220
            
            
            123
            
            
            341Asset
                retirement obligations, end of period
            
            $
            42,358
            
            $
            26,726
            
            $
            18,499
            
            $
            17,651





The
      above
      accretion expense is included in depreciation, depletion and amortization in
      the
      Company’s Combined and Consolidated Statements of Income.





**NOTE
      6—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS**





In
      the
      ordinary course of its business operations, the Company has ongoing
      relationships with several related entities:





**Relationship
      with AAI.** The
      employees supporting the Company’s operations are employees of AAI. AAI provides
      centralized corporate functions on behalf of the Company, including legal,
      accounting, treasury, insurance administration and claims processing, risk
      management, health, safety and environmental, information technology, human
      resources, credit, payroll, internal audit, taxes and engineering. These costs
      are reflected in general and administrative expense in the Company’s
      combined and consolidated statements of income.





84





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**


**NOTE
        6—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
        (Continued)**


The
      Company participates in AAI’s cash management program. Any cash activity
      performed by AAI on behalf of the Company has been recorded as a long-term
      liability as parent advances and included in Advances from affiliates on the
      Company’s Consolidated Balance Sheets.





A
      reconciliation of the Company’s Advances from affiliates for the periods
      indicated is as follows (in thousands):





Balance,
                October 1, 2004
            
            $
            (30,008
            )Transportation
                expense due to affiliate
            
            
            (401
            )Payment
                on debt to affiliate
            
            
            17,000Net
                operational settlement
            
            
            (488
            )Balance,
                September 30, 2005
            
            
            (13,897
            )Transportation
                expense due to affiliate
            
            
            (720
            )Payment
                on debt to affiliate
            
            
            8,000Net
                operational settlement
            
            
            2,360Balance,
                December 31, 2005
            
            
            (4,257
            )Transportation
                expense due to affiliate
            
            
            (5,382
            )Payment
                on debt to affiliate
            
            
            —Net
                operational settlement
            
            
            (2,863
            )Balance,
                December 31, 2006
            
            $
            (12,502
            )





**Relationship
      with Company Sponsored Investment Partnerships.** The
      Company conducts certain activities through, and a substantial portion of its
      revenues are attributable to, the Partnerships. The Company serves as managing
      general partner of the Partnerships and assumes customary rights and obligations
      for the Partnerships. As a general partner, the Company is liable for
      Partnership liabilities and can be liable to limited partners if it breaches
      its
      responsibilities with respect to the operations of the Partnerships. The Company
      is entitled to receive management fees, reimbursement for administrative costs
      incurred, and to share in the Partnerships’ revenue, and costs and expenses
      according to the respective Partnership agreements.





**Relationship
      with Atlas Pipeline.** The
      Company has a master gas gathering agreement with Atlas Pipeline which governs
      the transportation of substantially all of the natural gas the Company produces
      from the wells it operates. This agreement generally provides for the Company
      to
      pay Atlas Pipeline 16% of the sales price received for natural gas produced
      from
      wells located on Atlas Pipeline’s gathering systems. These fees are shown as
      Gathering fee—Atlas Pipeline on the Company’s combined and consolidated
      statements of income. Atlas America agreed to assume the Company’s obligation to
      pay gathering fees to Atlas Pipeline after the Company’s initial public
      offering.





The
      Company charges rates to wells connected to these gathering systems,
      substantially all of which are owned by the Partnerships, generally ranging
      from
      $.35 per Mcf to 13% of the sales price received for the natural gas transported.
      Under the terms of its contribution agreement with AAI, the Company remits
      this
      amount to AAI. Therefore, after the closing of its initial public offering,
      the
      gathering revenues and costs within the partnership management segment net
      to
      $0.





**NOTE
      7—DERIVATIVE INSTRUMENTS**





From
      time
      to time, the Company enters into natural gas future option contracts, and collar
      contracts to hedge its exposure to changes in natural gas prices. At any point
      in time, such contracts may include regulated New York Mercantile Exchange
      (“NYMEX”) futures and options contracts and non-regulated over-the-counter
      futures contracts with qualified counterparties. NYMEX contracts are generally
      settled with offsetting positions, but may be settled by the delivery of natural
      gas.





85





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**


**NOTE
        7—DERIVATIVE INSTRUMENTS (Continued)**


The
      Company formally documents all relationships between hedging instruments and
      the
      items being hedged, including the risk management objective and strategy for
      undertaking the hedging transactions. This includes matching the natural gas
      futures and options contracts to the forecasted transactions. The Company
      assesses, both at the inception of the hedge and on an ongoing basis, whether
      the derivatives are highly effective in offsetting changes in the fair value
      of
      the hedged items. Historically these contracts have qualified and been
      designated as cash flow hedges and recorded at their fair values. Gains or
      losses on future contracts are determined as the difference between the contract
      price and a reference price, generally prices on NYMEX. Such gains and losses
      are charged or credited to accumulated other comprehensive income (loss).
      Realized gains and losses are recognized as a component of gas production
      revenues in the month the hedged gas is sold. If it is determined that a
      derivative is not highly effective as a hedge or it has ceased to be a highly
      effective hedge, the Company will discontinue hedge accounting for the
      derivative and subsequent changes in fair value for the derivative will be
      recognized immediately into earnings.





At
      December 31, 2007, the Company had 360 open natural gas futures contracts
      related to natural gas sales covering 130.6 million MMBtus of natural gas (which
      includes 72.6 million MMBtus covering natural gas production acquired from
      AGO)
      maturing through December 31, 2012 at a combined average settlement price
      of $8.32 per MMBtu. On May 18, 2007, the Company signed a definitive agreement
      to acquire AGO (see Note 3). In connection with the financing of this
      transaction, the Company agreed as a condition precedent to closing that it
      would hedge 80% of its projected natural gas volumes for no less than three
      years from the closing date of the transaction. During May 2007, the Company
      entered into derivative instruments to hedge 80% of the projected production
      of
      the assets to be acquired as required under the financing agreement. The
      production volume of the assets to be acquired was not considered to be
“probable forecasted production” under SFAS No. 133 at the date these
      derivatives were entered into because the acquisition of the assets had not
      yet
      been completed. Accordingly, the Company recognized the instruments as
      non-qualifying for hedge accounting at inception with subsequent changes in
      the
      derivative value recorded within revenues in its combined and consolidated
      statements of income. The Company recognized non-cash income of $26.3 million
      related to the change in value of these derivatives from May 22, 2007 to June
      28, 2007, which is shown as “Gain on mark-to-market derivatives” in the Combined
      and Consolidated Statements of Income for the year ended December 31, 2007.
      Upon
      closing of the acquisition on June 29, 2007, the production volume of the assets
      acquired was considered “probable forecasted production” under SFAS No. 133 and
      the Company evaluated these derivatives under the cash flow hedge criteria
      in
      accordance with SFAS No. 133. In addition, the Company recognized gains on
      settled contracts covering natural gas production of $17.6 million and $7.1
      million for the years ended December 31, 2007 and 2006,
      respectively.





As
      the
      underlying prices and
      terms
      in the Company’s hedge contracts were consistent with the indices used to sell
      its natural gas, there were no gains or losses recognized during the year ended
      December 31, 2006 for hedge ineffectiveness or as a result of the discontinuance
      of any cash flow hedges. The Company did not enter into any hedging contracts
      in
      the three months ended December 31, 2005 or year ended September 30,
      2005.




Of
      the
      $5.1 million net loss in accumulated other comprehensive income (loss) at
      December 31, 2007, the Company will reclassify $21.1 million of gains to its
      Combined and Consolidated Statements of Income over the next twelve month period
      as these contracts expire and $26.2 million of losses will be reclassified
      in
      later periods if the fair values of the instruments remain at current market
      values.




86





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**


**NOTE
        7—DERIVATIVE INSTRUMENTS (Continued)**


As
      of
      December 31, 2007, the Company had the following natural gas volumes
      hedged:





**Fixed
      Price Swaps**





**Twelve
                Month****Period
                Ending**
            
            
            
            
            
            **Average**
            
            **Fair
                Value****December
                31,**
            
            
            
            **Volumes**
            
            **Fixed
                Price**
            
            **Asset
                (Liability)****(MMBtu)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands)****(1)**2008
            
            
            
            
            
            35,960,000
            
            $
            8.86
            
            $
            37,4572009
            
            
            
            
            
            32,720,000
            
            $
            8.50
            
            
            1702010
            
            
            
            
            
            23,000,000
            
            $
            8.01
            
            
            (11,398
            )2011
            
            
            
            
            
            17,600,000
            
            $
            7.79
            
            
            (10,939
            )2012
            
            
            
            
            
            9,000,000
            
            $
            7.74
            
            
            (5,242
            )$
            10,048





**Costless
      Collars**





**Twelve
                Month****Period
                Ending**
            
            
            
            
            
            **Average**
            
            **Fair
                Value****December
                31,**
            
            **Option
                Type**
            
            **Volumes**
            
            **Floor
                and Cap**
            
            **Asset
                (Liability)****(MMBtu)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands)****(1)**2008
            
            
            Puts
                purchased
            
            
            1,560,000
            
            $
            7.50
            
            $
            3682008
            
            
            Calls
                sold
            
            
            1,560,000
            
            $
            9.40
            
            
            —2010
            
            
            Puts
                purchased
            
            
            2,880,000
            
            $
            7.75
            
            
            —2010
            
            
            Calls
                sold
            
            
            2,880,000
            
            $
            8.75
            
            
            (948
            )2011
            
            
            Puts
                purchased
            
            
            7,200,000
            
            $
            7.50
            
            
            —2011
            
            
            Calls
                sold
            
            
            7,200,000
            
            $
            8.45
            
            
            (3,495
            )2012
            
            
            Puts
                purchased
            
            
            720,000
            
            $
            7.00
            
            
            —2012
            
            
            Calls
                sold
            
            
            720,000
            
            $
            8.37
            
            
            (470
            )(4,545
            )Total
                Net Asset
            
            $
            5,503





(1)
            Fair
                value based on forward NYMEX natural gas prices, as
                applicable.




The
      fair
      value of the derivatives is included in the Consolidated Balance Sheets as
      follows (in thousands):





**December
                31,****2007**
            
            **2006**Current
                portion of hedge asset
            
            $
            38,181
            
            $
            27,618Long-term
                hedge asset
            
            
            6,882
            
            
            23,843Current
                portion of hedge liability
            
            
            (356
            )
            
            (172
            )Long-term
                hedge liability
            
            
            (39,204
            )
            
            (3,835
            )$
            5,503
            
            $
            47,454





87








**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**




**NOTE
      7—DERIVATIVE INSTRUMENTS (Continued)**





In
      addition, $3.4 million of unrealized losses and $26.4 million of unrealized
      hedge gains have been allocated to the Partnerships at December 31, 2007 and
      2006, respectively, based on the Partnerships share of estimated future gas
      production related to the hedges not yet settled and is included in the
      Consolidated Balance Sheets as follows (in thousands):





**December
                31,****2007**
            
            **2006**Unrealized
                hedge loss - short-term
            
            $
            213
            
            $
            96Other
                assets - long-term
            
            
            13,542
            
            
            2,131Accrued
                liabilities - short-term
            
            
            (9,013
            )
            
            (15,345
            )Unrealized
                hedge gain - long-term
            
            
            (1,348
            )
            
            (13,248
            )$
            3,394
            
            $
            (26,366
            )





**NOTE
      8—COMMITMENTS AND CONTINGENCIES**





The
      Company leases office space and equipment under leases with varying expiration
      dates through 2014. Rental expense was $980,000, $670,000, $136,000 and $1.2
      million for the years ended December 31, 2007 and 2006, three months ended
      December 31, 2005, and year ended September 30, 2005, respectively. Future
      minimum rental commitments for the next five annual periods are as follows
      (in
      thousands):





2008
            
            $
            1,2822009
            
            
            1,1712010
            
            
            9272011
            
            
            6112012
            
            
            611





The
      Company is the managing general partner of the Partnerships, and has agreed
      to
      indemnify each investor partner from any liability that exceeds such partner’s
      share of Partnership assets. Subject to certain conditions, investor partners
      in
      certain Partnerships have the right to present their interests for purchase
      by
      the Company, as managing general partner. The Company is not obligated to
      purchase more than 5% to 10% of the units in any calendar year. Based on past
      experience, the Company believes that any liability incurred would not be
      material.





The
      Company may be required to subordinate a part of its net partnership revenues
      from the Partnerships to the receipt by investor partners of cash distributions
      from the investment partnerships equal to at least 10% of their subscriptions
      determined on a cumulative basis, in accordance with the terms of the
      partnership agreements.





AAI
      is
      party to employment agreements with certain executives that provide
      compensation, severance and certain other benefits. Some of these obligations
      may be allocable to the Company.





One
      of
      the Company’s subsidiaries, Resource Energy, LLC, together with Resource
      America, Inc., (the former parent of AAI), was a defendant in a class action
      originally filed in February 2000 in the New York Supreme Court, Chautauqua
      County, by individuals, putatively on their own behalf and on behalf of
      similarly situated individuals, who leased property to the Company. The
      complaint alleged that the Company was not paying landowners the proper amount
      of royalty revenues with respect to natural gas produced from the leased
      properties. The complaint was seeking damages in an unspecified amount for
      the
      alleged difference between the amount of royalties actually paid and the amount
      of royalties that allegedly should have been paid. In April 2007, a settlement
      of this lawsuit was approved by the court. Pursuant to the settlement terms,
      the
      Company paid $300,000 in May 2007, upgraded certain gathering systems and capped
      certain transportation expenses chargeable to the landowners. The Company was
      indemnified by AAI for this matter .





88




**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**




**NOTE
      8—COMMITMENTS AND CONTINGENCIES (Continued)**





Atlas
      Gas
& Oil Company LLC, as successor to DTE Gas & Oil Company, was one of
      four defendants in a personal injury action filed in Antrim County Circuit
      Court
      in northern Michigan in August 2006.  The complaint alleged that plaintiff
      suffered serious personal injuries as a result of the defendants’ negligence.
      The Company paid $125,000 to the plaintiff in October 2007 in full settlement
      of
      this action.





The
      Company is also a party to various routine legal proceedings arising in
      of the
      ordinary course of its business. Management believes that none of these actions,
      individually or in the aggregate, will have a material adverse effect on the
      Company’s financial condition or results of operations.





**NOTE
      9—LONG-TERM DEBT**





Total
      debt consists of the following at the dates indicated (in
      thousands):





**December
                31,****2007**
            
            **2006**Revolving
                credit facility
            
            $
            740,000
            
            $
            —Other
                debt
            
            
            30
            
            
            68740,030
            
            
            68Less
                current maturities
            
            
            (30
            )
            
            (38
            )$
            740,000
            
            $
            30





**Revolving
      Credit Facility** .
      Upon
      the closing of its acquisition of DTE Gas & Oil (See Note 3), the Company
      replaced its credit facility with a new 5-year credit facility with an initial
      borrowing base of $850.0 million with J.P. Morgan Chase Bank, N.A. (“J.P.
      Morgan”) as administrative agent, Wachovia Bank, N. A. as syndication agent, and
      other lenders. The borrowing base will be redetermined semiannually on April
      1
      and October 1 subject to changes in the Company’s oil and gas reserves. The
      initial borrowing base was reduced to $672.5 million in January 2008, upon
      the
      issuance by the Company of $250.0 million in senior unsecured notes. See Note
      14
      for a discussion of the Company’s sale of these notes. Up to $50.0 million of
      the facility may be in the form of standby letters of credit. The facility
      is
      secured by substantially all of the Company’s assets and is guaranteed by each
      of the company’s subsidiaries and bears interest at either the base rate plus
      the applicable margin or at adjusted LIBOR plus the applicable margin, elected
      at the Company’s option. At December 31, 2007, the weighted average interest
      rate on outstanding borrowings was 7.2%.





The
      base
      rate for any day equals the higher of the federal funds rate plus 0.50% or
      the
      J.P. Morgan 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 1.25% for base rate loans and 1.00% to 2.25% for LIBOR loans.





The
      credit facility requires the Company to maintain specified financial ratios
      of
      current assets to current liabilities and debt to earnings before interest,
      taxes, depreciation, depletion and amortization (“EBITDA”) as disclosed in the
      agreement. In addition, the agreement limits sales, leases or transfers of
      assets and the incurrence of additional indebtedness. The agreement limits
      the
      distributions payable by the Company if an event of default has occurred and
      is
      continuing or would occur as a result of such distribution. The Company is
      in
      compliance with these covenants as of December 31, 2007. The facility terminates
      in June 2012, when all outstanding borrowings must be repaid. At December 31,
      2007 and 2006, $740.0 million and $0 million, respectively, were outstanding
      under this facility and the previous credit facility. In addition, letters
      of
      credit of $1.1 million and $495,000 were outstanding at each date, which are
      not
      reflected as borrowings on the Company’s Consolidated Balance
      Sheets.




89





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**





**December
      31, 2007**




**NOTE
        9—LONG-TERM DEBT (Continued)**





Annual
      principal debt payments over the next five years ending December 31 are as
      follows (in thousands)





2008
            
            $
            302009
            
            
            ―2010
            
            
            ―2011
            
            
            ―2012
            
            
            740,000$
            740,030





**NOTE
      10—OPERATING SEGMENT INFORMATION**





The
      Company’s operations include three reportable operating segments. These
      operating segments reflect the way the Company manages its operations and makes
      business decisions.





The
      Company organizes its oil and gas production segments by geographic location.
      The Appalachia segment represents the Company’s well interests in the states of
      Pennsylvania, Ohio, New York, West Virginia and Tennessee. The Michigan segment
      represents the Company’s well interests in the Antrium Shale, located in
      Michigan’s northern, lower peninsula.





90





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**


**NOTE
        10—OPERATING SEGMENT INFORMATION (Continued)**


Operating
      segment data for the periods indicated are as follows (in thousands):




**Three
                Months****Years
                Ended**
            
            **Ended**
            
            **Year
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2005**
            
            **2005****Gas
                and oil production****Appalachia****:**Revenues
            
            $
            99,015
            
            $
            88,449
            
            $
            24,086
            
            $
            63,499Costs
                and expenses
            
            
            17,638
            
            
            13,881
            
            
            2,441
            
            
            8,165Segment
                profit
            
            $
            81,377
            
            $
            74,568
            
            $
            21,645
            
            $
            55,334**Michigan:**Revenues
            
            $
            107,367(2
            )Costs
                and expenses
            
            
            14,555Segment
                profit
            
            $
            92,812**Partnership
                management**Revenues
            
            $
            370,053
            
            $
            232,533
            
            $
            49,077
            
            $
            157,839Costs
                and expenses
            
            
            302,382
            
            
            209,548
            
            
            46,103
            
            
            143,964Segment
                profit
            
            $
            67,671
            
            $
            22,985
            
            $
            2,974
            
            $
            13,875





**Three
                Months****Years
                Ended**
            
            **Ended**
            
            **Year
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2005**
            
            **2005**Reconciliation
                of segment profit to net incomeSegment
                profitGas
                and oil production-Appalachia
            
            $
            81,377
            
            $
            74,568
            
            $
            21,645
            
            $
            55,334Gas
                and oil production-Michigan
            
            
            92,812Partnership
                management
            
            
            67,671
            
            
            22,985
            
            
            2,974
            
            
            13,875Total
                segment profit
            
            
            241,860
            
            
            97,553
            
            
            24,619
            
            
            69,209General
                and administrative
            
            
            (39,414
            )
            
            (23,367
            )
            
            (5,818
            )
            
            (13,202
            )Compensation
                reimbursement - affiliate
            
            
            ─
            
            
            (1,237
            )
            
            (163
            )
            
            (602
            )Depreciation,
                depletion and amortization
            
            
            (56,942
            )
            
            (22,491
            )
            
            (4,916
            )
            
            (14,061
            )Interest
                expense
            
            
            (30,096
            )
            
            ─
            
            
            ─
            
            
            ─Other
                − net(1)
            
            
            2,096
            
            
            1,369
            
            
            57
            
            
            79Net
                income before cumulative effect of accounting change
            
            $
            117,504
            
            $
            51,827
            
            $
            13,779
            
            $
            41,423





(1) Includes
      revenues and expenses for AGO well services and transportation of $1.2 million
      that do not meet the quantitative threshold for reporting segment information
      for the year ended December 31, 2007.


(2) Includes
      ineffective derivative gains of $26.3 million.




91





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**


**NOTE
        10—OPERATING SEGMENT INFORMATION (Continued)**


**Three
                Months****Years
                Ended**
            
            **Ended**
            
            **Year
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2005**
            
            **2005**Capital
                expendituresGas
                and oil productionAppalachia
            
            $
            146,605
            
            $
            74,075
            
            $
            16,610
            
            $
            57,894Michigan
            
            
            40,878
            
            
            ─
            
            
            ─
            
            
            ─Partnership
                management
            
            
            4,499
            
            
            1,042
            
            
            445
            
            
            747Corporate
            
            
            4,753
            
            
            518
            
            
            132
            
            
            483$
            196,735
            
            $
            75,635
            
            $
            17,187
            
            $
            59,124Balance
                sheetsGoodwillGas
                and oil production - Appalachia
            
            $
            21,527
            
            $
            21,527
            
            $
            21,527
            
            $
            21,527Partnership
                management
            
            
            13,639
            
            
            13,639
            
            
            13,639
            
            
            13,639$
            35,166
            
            $
            35,166
            
            $
            35,166
            
            $
            35,166Total
                assetsGas
                and oil productionAppalachia
            
            $
            491,199
            
            $
            377,807
            
            $
            254,831
            
            $
            233,855Michigan
            
            
            1,330,432
            
            
            ─
            
            
            ─
            
            
            ─Partnership
                management
            
            
            30,359
            
            
            26,474
            
            
            37,050
            
            
            27,115Corporate
            
            
            39,244
            
            
            11,182
            
            
            23,171
            
            
            9,432$
            1,891,234
            
            $
            415,463
            
            $
            315,052
            
            $
            270,402





For
      the
      year ended September 30, 2005, gas sales to Hess Corporation (formerly
      FirstEnergy Solutions Corp.) accounted for 13% of total revenues. No other
      fiscal periods or operating segments had revenues from a single customer which
      exceeded 10% of total revenues.





**NOTE
      11 - BENEFIT PLANS**





**Stock
      Incentive Plan.** ** In
      December 2006, the Company adopted a Long-Term Incentive Plan (“ATN LTIP”),
      which provides performance incentive awards to officers, employees and board
      members and employees of its affiliates, consultants and joint-venture partners.
      The ATN LTIP is administered by AAI’s compensation committee, which may grant
      awards of either restricted stock units, phantom units or unit options for
      an
      aggregate of
      3,742,000 common units.
      Awards granted in 2007 vest 25% after three years and 100% upon the four year
      anniversary of grant, except for awards of 1,500 units to board members which
      vest 25% per year over four years. Awards granted in 2006 vest 25% per year
      over
      four years. Upon termination of service by a grantee, all unvested awards are
      forfeited. A restricted stock or phantom unit entitles a grantee to receive
      a
      common unit of the Company upon vesting of the unit or, at the discretion of
      AAI’s compensation committee, cash equivalent to the then fair market value of
      a
      common unit of the Company. In
      tandem
      with phantom unit grants, AAI’s compensation committee may grant a distribution
      equivalent right (“DER”), which is the right to receive cash per restricted unit
      in an amount equal to, and at the same time as, the cash distributions the
      Company makes on a common unit during the period such phantom unit is
      outstanding.





*Restricted
      Stock and Phantom Units.* Under
      the ATN LTIP, 590,950 and 47,619 units of restricted stock and phantom units
      were awarded in 2007 and 2006, respectively. The fair value of the grants is
      based on the closing stock price on the grant date, and is being charged to
      operations over the requisite service periods using a straight-line attribution
      method.





92





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**


**NOTE
        11 - BENEFIT PLANS (Continued)**


The
      following table summarizes the activity of restricted stock and phantom units
      for the periods indicated:





**Weighted****Average****Grant
                Date****Units**
            
            **Fair
                Value**Non-vested
                shares outstanding atDecember
                31,
                2005
            
            
            —
            
            $
            —Granted
            
            
            47,619
            
            $
            21.00Non-vested
                shares outstanding atDecember
                31,
                2006
            
            
            47,619
            
            $
            21.00Granted
            
            
            590,950
            
            $
            24.63Vested
            
            
            (11,904
            )
            $
            21.00Forfeited
            
            
            (2,000
            )
            $
            23.06Non-vested
                shares outstanding at December 31, 2007
            
            
            624,665
            
            $
            24.42





*Unit Options* .
      In
      fiscal 2007 and 2006, 1,532,000 and 373,752 unit options, respectively, were
      awarded under the ATN LTIP. Option awards expire 10 years from the date of
      grant
      and are generally granted with an exercise price equal to the market price
      of
      the Company’s stock at the date of grant. The Company uses the Black-Scholes
      option pricing model to estimate the weighted average fair value per option
      granted with the following assumptions:




**Years
                  Ended December 31,****2007**
              
              **2006**Expected
                  life (years)
              
              
              6.25
              
              
              6.25Expected
                  volatility
              
              
              25
              %
              
              25
              %Risk-free
                  interest rate
              
              
              4.7
              %
              
              4.4
              %Expected
                  dividend yield
              
              
              5.1-8.0
              %
              
              8.0
              %Weighted
                  average fair value of stock options granted
              
              $
              2.96
              
              $
              2.14





The
      following table sets forth option activity for the periods
      indicated:





**Weighted****Average****Weighted**
            
            **Remaining**
            
            **Aggregate****Average**
            
            **Contractual**
            
            **Intrinsic****Exercise**
            
            **Term**
            
            **Value****Shares**
            
            **Price**
            
            **(in
                years)**
            
            **(in
                thousands)**Outstanding
                at December 31, 2005
            
            
            —
            
            $
            —Granted
            
            
            373,752
            
            $
            21.00Outstanding
                at December 31, 2006
            
            
            373,752
            
            $
            21.00Granted
            
            
            1,532,000
            
            $
            24.84Exercised
            
            
            —
            
            
            —Forfeited
                or expired
            
            
            (10,700
            )
            $
            23.06Outstanding
                at December 31, 2007
            
            
            1,895,052
            
            $
            24.09
            
            
            8.9
            
            $
            13,256Options
                exercisable at December 31, 2007
            
            
            93,438
            
            $
            21.00
            
            
            9.0Available
                for grant at December 31, 2007
            
            
            1,210,379




93





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**


**NOTE
        11 - BENEFIT PLANS (Continued)**


The
      following tables summarize information about stock options outstanding and
      exercisable at December 31, 2007:




**Options
                  Outstanding**
              
              **Options
                  Exercisable****Range
                  of**
                **Exercise
                  Prices**
              
              **Number
                  of Shares Outstanding**
              
              **Weighted
                  -Average**
                **Remaining**
                **Contractual**
                **Life
                  in Years**
              
              **Weighted-**
                **Average**
                **Exercise
                  Price**
              
              **Number
                  of Shares Exercisable**
              
              **Weighted
                  - Average Exercise Price**$21.00-$23.06
              
              
              1,659,452
              
              
              9.0
              
              $
              22.60
              
              
              93,438
              
              $
              21.00$34.18-$35.00
              
              
              235,600
              
              
              9.5
              
              $
              34.65
              
              
              —
              
              
              —1,895,052
              
              
              8.9
              
              $
              24.09
              
              
              93,438
              
              $
              21.00





The
      Company recognized $4.7 million and $337,000 in compensation expense related
      to
      restricted stock units, phantom units and stock options for the years ended
      December 31, 2007 and 2006, respectively. There was no such expense for the
      three months ended December 31, 2005 or the ended September 30, 2005. The
      Company paid $778,000 with respect to its LTIP DERs for the year ended December
      31, 2007. This amount was recorded as a reduction of members’ equity on the
      Company’s Consolidated Balance Sheet. At December
      31, 2007, the Company had approximately $15.8 million of unrecognized
      compensation expense related to the unvested portion of the restricted stock
      units, phantom units and options.





**NOTE
      12 - PRIVATE PLACEMENT OF CLASS B COMMON AND CLASS D UNITS**




To
      partially fund the acquisition of AGO, the Company completed a private placement
      of 7,298,181 Class B common units and 16,702,828 Class D units to a group of
      institutional investors at a weighted average price of $25.00 per unit for
      net
      proceeds of $597.5 million. The private placement of the Class B common and
      Class D units was exempt from registration under Section 4(2) of the Securities
      Act of 1933, as amended.
      The Class D units were a new class of equity security, which automatically
      converted to common units on a one-to-one basis upon the receipt of the consent
      of the Company’s unit holders, which the Company obtained in November 2007. The
      Company entered into a registration rights agreement in connection with the
      sale
      of the units. The agreement required the Company to prepare and file a
      registration statement covering the resale of such units by January 31, 2008
      and
      have such registration statement declared effective by May 30, 2008. The Company
      filed this registration statement, which was declared effective on February
      20,
      2008.





94





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**




**NOTE
      13 - CASH DISTRIBUTIONS**




The
      Company is required to distribute, within 45 days after the end of each quarter,
      all of its available cash (as defined in its limited liability agreement) for
      that quarter. Distributions declared by the Company from inception are as
      follows:




**Cash****Distribution**
            
            **Total
                Cash**
            
            **Total**
            
            **Manager****Date
                Cash**
            
            
            
            **Per**
            
            **Distribution**
            
            **Cash**
            
            **Incentive****Distribution**
            
            
            
            **Common**
            
            **to
                Common**
            
            **Distribution**
            
            **Distribution****Paid
                or Payable**
            
            **For
                Quarter Ended**
            
            **Unit**
            
            **Unitholders****(2)**
            
            **to
                the Manager**
            
            **Payable****(in
                thousands)**
            
            **(in
                thousands)**
            
            **(in
                thousands)**February
                14, 2007
            
            
            December
                31, 2006
            
            $
            0.06(1
            )
            $
            2,231
            
            $
            45May
                15, 2007
            
            
            March
                31, 2007
            
            $
            0.43
            
            $
            15,989
            
            $
            322August
                14, 2007
            
            
            June
                30, 2007
            
            $
            0.43
            
            $
            15,989
            
            $
            322November
                14, 2007
            
            
            September
                30, 2007
            
            $
            0.55
            
            $
            33,697
            
            $
            681
            
            $
            784February
                14 , 2008
            
            
            December
                31, 2007
            
            $
            0.57
            
            $
            34,921
            
            $
            706
            
            $
            965




(1)
            Represents
                a prorated distribution of $0.42 per unit for the period from December
                18,
                2006, the date of the Company’s initial public offering through December
                31, 2006.




(2)
            Includes
                distributions paid on unissued units under the Company’s employee
                incentive plan.




**NOTE
      14 - SUBSEQUENT EVENTS**





**Private
      debt offering** . In
      January 2008, the Company issued $250.0 million of senior unsecured notes
      due 2018 in a private placement at a coupon rate of 10.75%. The Company used
      the
      proceeds of the note offering to reduce the balance outstanding on its senior
      secured 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 certain redemption prices, together with accrued
      and
      unpaid interest to the date of redemption. In addition, before February 1,
      2011,
      the Company 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 the
      Company 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
      the
      Company does not reinvest the net proceeds within 360 days. The senior notes
      are
      junior in right of payment to the Company’s secured debt, including its
      obligations under its credit facility. The indenture governing the senior notes
      contains covenants, including limitations of the Company’s ability to: incur
      certain liens; engage in sale/leaseback transactions; incur additional
      indebtedness; declare or pay distributions if an event of default has occurred;
      redeem, repurchase or retire equity interests or subordinated indebtedness;
      make
      certain investments; or merge, consolidate or sell substantially all of its
      assets.





**New
      interest rate swap** .
      In
      January 2008, the Company entered into an interest rate swap contract for $150
      million, swapping the floating rate incurred on a portion of its existing senior
      secured credit facility for a fixed rate of approximately 4.36%, which includes
      an initial margin of 1.25% over the three year fixed swap rate of 3.11%. The
      interest rate swap contract will mature in January 2011.


95





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**





**NOTE
      15—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)**





Results
      of operations from oil and gas producing activities for the periods indicated
      are as follows (in thousands):





**Three
                Months****Years
                Ended**
            
            **Ended**
            
            **Year
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2005**
            
            **2005**Revenues
            
            $
            206,382(1
            )
            $
            88,449
            
            $
            24,086
            
            $
            63,499Production
                costs
            
            
            (32,193
            )
            
            (13,881
            )
            
            (2,441
            )
            
            (8,165
            )Exploration
                expenses
            
            
            (4,065
            )
            
            (3,016
            )
            
            (17
            )
            
            (904
            )Depreciation,
                depletion and amortization
            
            
            (54,383
            )
            
            (20,600
            )
            
            (4,477
            )
            
            (12,288
            )Results
                of operations from oil and gas producing activities
            
            $
            115,741
            
            $
            50,952
            
            $
            17,151
            
            $
            42,142


____________________


( 1) Includes
      gains from mark-to-market derivatives of $26.3 million **.**





*Capitalized
      Costs Related to Oil and Gas Producing Activities.* The
      components of capitalized costs related to the Company’s oil and gas producing
      activities at the dates indicated are as follows (in thousands):





**At
                December 31,****2007**
            
            **2006**Natural
                gas and oil properties:Proved
                properties
            
            $
            1,795,871
            
            $
            349,882Unproved
                properties
            
            
            16,380
            
            
            1,002Support
                equipment
            
            
            6,936
            
            
            5,5411,819,187
            
            
            356,425Accumulated
                depreciation, depletion and amortization(1)
            
            
            (136,603
            )
            
            (83,182
            )Net
                capitalized costs
            
            $
            1,682,584
            
            $
            273,243


_____________


(1) Costs
      related to unproved properties are excluded from amortization as they are
      assessed for impairment.





*Costs
      Incurred in Oil and Gas Producing Activities* .
      The
      costs incurred by the Company in its oil and gas activities for the periods
      indicated are as follows (in thousands):





**Three
                Months****Years
                Ended**
            
            **Ended**
            
            **Year
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2005**
            
            **2005**Property
                acquisition costs:Proved
                properties
            
            $
            1,243,877
            
            $
            1,322
            
            $
            —
            
            $
            308Unproved
                properties
            
            
            50,100
            
            
            —
            
            
            —
            
            
            —Exploration
                costs
            
            
            4,065
            
            
            6,847
            
            
            1,312
            
            
            904Development
                costs
            
            
            168,253
            
            
            76,687
            
            
            17,380
            
            
            72,308$
            1,466,295
            
            $
            84,856
            
            $
            18,692
            
            $
            73,520





The
      development costs above were substantially all incurred for the development
      of
      proved undeveloped properties.





96





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**




**NOTE
      15—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
      (Continued)**




*Oil
      and Gas Reserve Information* .
      The
      estimates of the Company’s proved and unproved gas and oil reserves are based
      upon evaluations made by management and verified by an independent petroleum
      engineering firm. All reserves are generally located in
      the
      Appalachian Basin and in Michigan’s Lower Peninsula. Reserves
      are estimated in accordance with guidelines established by the Securities and
      Exchange Commission and the Financial Accounting Standards Board which require
      that reserve estimates be prepared under existing economic and operating
      conditions with no provisions for price and cost escalation except by
      contractual arrangements.





Proved
      oil and gas reserves are the estimated quantities of natural gas which
      geological and engineering data demonstrate with reasonable certainty to be
      recoverable in future years from known reservoirs under existing economic and
      operating conditions, i.e. prices and costs as of the date the estimate is
      made.
      Prices include consideration of changes in existing prices provided only by
      contractual arrangements, but not on escalations based upon future conditions.





·
            Reservoirs
                are considered proved if economic producibility is supported by either
                actual production or conclusive formation tests. The area of a reservoir
                considered proved includes (a) that portion delineated by drilling
                and defined by gas-oil and/or oil-water contacts, if any; and (b) the
                immediately adjoining portions not yet drilled, but which can be
                reasonably judged as economically productive on the basis of available
                geological and engineering data. In the absence of information on
                fluid
                contacts, the lowest known structural occurrence of hydrocarbons
                controls
                the lower proved limit of the
                reservoir.


·
            Reserves
                which can be produced economically through application of improved
                recovery techniques (such as fluid injection) are included in the
“proved”
                classification when successful testing by a pilot project, or the
                operation of an installed program in the reservoir, provides support
                for
                the engineering analysis on which the project or program was
                based.


·
            Estimates
                of proved reserves do not include the following: (a) oil that may
                become available from known reservoirs but is classified separately
                as
                “indicated additional reservoirs”; (b) crude oil and natural gas, the
                recovery of which is subject to reasonable doubt because of uncertainty
                as
                to geology, reservoir characteristics or economic factors; (c) crude
                oil and natural gas, that may occur in undrilled prospects; and natural
                gas, that may be recovered from oil shales, coal, gilsonite and other
                such
                sources.





Proved
      developed oil and gas reserves are reserves that can be expected to be recovered
      through existing wells with existing equipment and operation methods. Additional
      oil and gas expected to be obtained through the application of fluid injection
      or other improved recovery techniques for supplementing the natural forces
      and
      mechanisms of primary recovery should be included as “proved developed reserves”
only after testing by a pilot project or after the operation of an installed
      program has confirmed through production response that increased recovery will
      be achieved.





There
      are
      numerous uncertainties inherent in estimating quantities of proven reserves
      and
      in projecting future net revenues and the timing of development expenditures.
      The reserve data presented represents estimates only and should not be construed
      as being exact. Additionally, the standardized measure of discounted future
      net
      cash flows may not represent the fair market value of the Company’s oil and gas
      reserves or the present value of future cash flows of equivalent reserves,
      due
      to anticipated future changes in oil and gas prices and in production and
      development costs and other factors for effects have not been proved. The
      increase in the Company’s reserves for the year ended December 31, 2007, is
      primarily due to the purchase of reserves in-place as a result of the
      acquisition of DTE Gas and Oil Company on June 29, 2007.




97





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**


**NOTE
        15—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
        (Continued)**


The
      Company’s reconciliation of changes in proved reserve quantities is as follows:





**Gas**
            
            **Oil****(Mcf)**
            
            **(Bbls)**Balance
                September 30, 2004
            
            
            142,133,365
            
            
            2,274,712Extensions,
                discoveries and other additions
            
            
            33,364,097
            
            
            95,552Sales
                of reserves in-place
            
            
            (226,237
            )
            
            (1,010
            )Purchase
                of reserves in-place
            
            
            116,934
            
            
            575Transfers
                to limited partnerships
            
            
            (7,104,731
            )
            
            (148,899
            )Revisions
            
            
            (2,631,044
            )
            
            196,263Production
            
            
            (7,625,695
            )
            
            (157,904
            )Balance
                September 30, 2005
            
            
            158,026,689
            
            
            2,259,289Extensions,
                discoveries and other additions
            
            
            8,357,940
            
            
            36,931Sales
                of reserves in-place
            
            
            (59,873
            )
            
            —Purchase
                of reserves in-place
            
            
            6,132
            
            
            16Transfers
                to limited partnerships
            
            
            (4,740,605
            )
            
            —Revisions
            
            
            (1,690,863
            )
            
            653Production
            
            
            (1,975,070
            )
            
            (39,678
            )Balance
                December 31, 2005
            
            
            157,924,350
            
            
            2,257,211Extensions,
                discoveries and other additions
            
            
            46,205,382
            
            
            12,920Sales
                of reserves in-place
            
            
            (127,472
            )
            
            (703
            )Purchase
                of reserves in-place
            
            
            305,433
            
            
            1,675Transfers
                to limited partnerships
            
            
            (6,671,754
            )
            
            (19,235
            )Revisions
            
            
            (20,147,989
            )
            
            (33,594
            )Production
            
            
            (8,946,376
            )
            
            (150,628
            )Balance
                December 31, 2006
            
            
            168,541,574
            
            
            2,067,646Extensions,
                discoveries and other additions
            
            
            126,613,549
            
            
            23,358Sales
                of reserves in-place
            
            
            (62,699
            )
            
            (625
            )Purchase
                of reserves in-place
            
            
            622,851,730
            
            
            48,634Transfers
                to limited partnerships
            
            
            (11,507,307
            )
            
            —Revisions
            
            
            (714,501
            )
            
            (2,517
            )Production
            
            
            (20,963,436
            )
            
            (153,465
            )Balance
                December 31, 2007
            
            
            884,758,910
            
            
            1,983,031Proved
                developed reserves at:September
                30, 2004
            
            
            95,788,656
            
            
            2,125,813September
                30, 2005
            
            
            104,786,047
            
            
            2,116,412December
                31, 2005
            
            
            108,674,675
            
            
            2,122,568December
                31, 2006
            
            
            107,683,343
            
            
            2,064,276December
                31, 2007
            
            
            594,708,965
            
            
            1,977,446




98





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**




**NOTE
      15—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
      (Continued)**




The
      following schedule presents the standardized measure of estimated discounted
      future net cash flows relating to proved oil and gas reserves. The estimated
      future production is priced at year-end prices, adjusted only for fixed and
      determinable increases in natural gas and oil prices provided by contractual
      agreements. The resulting estimated future cash inflows are reduced by estimated
      future costs to develop and produce the proved reserves based on year-end cost
      levels and includes the effect on cash flows of settlement of asset retirement
      obligations on gas and oil properties. The future net cash flows are reduced
      to
      present value amounts by applying a 10% discount factor. The standardized
      measure of future cash flows was prepared using the prevailing economic
      conditions existing at September 30, 2005 and December 31, 2005, 2006 and 2007
      and such conditions continually change. Accordingly, such information should
      not
      serve as a basis in making any judgment on the potential value of recoverable
      reserves or in estimating future results of operations. Amounts shown for
      December 31, 2005 and September 30, 2005 reflect values for Atlas America
      E&P Operations, which were subject to federal and state income taxes.
      Amounts shown for December 31, 2006 and 2007 reflect values for the Company.
      Since it is a limited liability company that allocates taxable income to the
      individual unit holders, no provisions for federal or state income taxes have
      been included in the December 31, 2006 and 2007 calculation of standardized
      measure.





**Three
                Months****Years
                Ended**
            
            **Ended**
            
            **Year
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2005**
            
            **2005****(in
                thousands)**Future
                cash inflows
            
            $
            6,408,367
            
            $
            1,262,161
            
            $
            1,874,432
            
            $
            2,503,644Future
                production costs
            
            
            (1,804,199
            )
            
            (334,062
            )
            
            (290,600
            )
            
            (296,015
            )Future
                development costs
            
            
            (388,111
            )
            
            (149,610
            )
            
            (107,784
            )
            
            (117,256
            )Future
                income tax expense
            
            
            —
            
            
            —
            
            
            (445,004
            )
            
            (607,624
            )Future
                net cash flows
            
            
            4,216,057
            
            
            778,489
            
            
            1,031,044
            
            
            1,482,749Less
                10% annual discount for estimating timing of cash flows
            
            
            (2,734,879
            )
            
            (495,048
            )
            
            (601,772
            )
            
            (876,052
            )Standardized
                measure of discounted future net cash flows
            
            $
            1,481,178
            
            $
            283,441
            
            $
            429,272
            
            $
            606,697





The
      future cash flows estimated to be spent to develop proved undeveloped properties
      in the years ended December 31, 2008, 2009, 2010, 2011 and 2012 are $112.2
      million, $113.1 million, $108.5 million, $37.0 million and $17.3 million,
      respectively.




99





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**




**NOTE
      15—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
      (Continued)**





The
      following table (in thousands) summarizes the changes in the standardized
      measure of discounted future net cash flows from estimated production of proved
      oil and gas reserves after income taxes for the three months ended December
      31,
      2005 and the year ended September 30, 2005. Since the Company allocates taxable
      income to unit holders, no recognition has been given to income taxes for the
      years ended December 31, 2007 and 2006, and the balance at the beginning of
      the
      period has been adjusted to exclude income taxes.




**Three****Months****Years
                Ended**
            
            **Ended**
            
            **Year
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2005**
            
            **2005**Balance,
                beginning of period
            
            $
            283,441
            
            $
            597,137
            
            $
            606,697
            
            $
            232,998Increase
                (decrease) in discounted future net cash flows:Sales
                and transfers of oil and gas, net of related costs
            
            
            (147,982
            )
            
            (74,567
            )
            
            (21,645
            )
            
            (55,333
            )Net
                changes in prices and production costs
            
            
            45,261
            
            
            (273,631
            )
            
            (245,838
            )
            
            417,798Revisions
                of previous quantity estimates
            
            
            (1,208
            )
            
            (30,058
            )
            
            (4,571
            )
            
            (6,073
            )Development
                costs incurred
            
            
            98,424
            
            
            3,426
            
            
            2,727
            
            
            4,224Changes
                in future development costs
            
            
            (14,128
            )
            
            (8,505
            )
            
            (1,159
            )
            
            (1,577
            )Transfers
                to limited partnerships
            
            
            (13,998
            )
            
            (8,449
            )
            
            (8,563
            )
            
            (24,750
            )Extensions,
                discoveries, and improved recovery less related costs
            
            
            170,349
            
            
            44,820
            
            
            22,597
            
            
            154,215Purchases
                of reserves in place
            
            
            957,137
            
            
            660
            
            
            24
            
            
            596Sales
                of reserves in place, net of tax effect
            
            
            (105
            )
            
            (572
            )
            
            (243
            )
            
            (672
            )Accretion
                of discount
            
            
            74,685
            
            
            59,714
            
            
            21,141
            
            
            32,038Net
                changes in future income taxes
            
            
            —
            
            
            —
            
            
            71,614
            
            
            (151,882
            )Estimated
                settlement of asset retirement obligations
            
            
            (4,523
            )
            
            (8,226
            )
            
            (848
            )
            
            (12,763
            )Estimated
                proceeds on disposals of well equipment
            
            
            5,168
            
            
            10,007
            
            
            998
            
            
            12,740Other
            
            
            28,657
            
            
            (28,315
            )
            
            (13,659
            )
            
            5,138Balance,
                end of period
            
            $
            1,481,178
            
            $
            283,441
            
            $
            429,272
            
            $
            606,697




100





**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS —
(CONTINUED)**





**NOTE
      16 - QUARTERLY RESULTS (UNAUDITED)**




**March
                  31,**
              
              **June
                  30,**
              
              **September
                  30,**
              
              **December
                  31,****(in
                  thousands, except unit data)****Year
                  ended December 31, 2007**Revenues
              
              $
              105,191
              
              $
              128,055
              
              $
              180,269
              
              $
              164,382Net
                  income
              
              $
              19,941
              
              $
              41,665
              
              $
              31,612
              
              $
              24,286Net
                  income per common unit:Basic
              
              $
              .53
              
              $
              1.10
              
              $
              .50
              
              $
              .38Diluted
              
              
              .53
              
              $
              1.08
              
              $
              .49
              
              $
              .37**Year
                  ended December 31, 2006**Revenues
              
              $
              82,111
              
              $
              63,608
              
              $
              81,193
              
              $
              94,070Income
                  from continuing operations before cumulative effect of accounting
                  changePortion
                  applicable to owner’s interest
              
              $
              12,469
              
              $
              12,599
              
              $
              11,466
              
              $
              12,486Portion
                  applicable to common unit holders
              
              
              —
              
              
              —
              
              
              —
              
              
              2,751Portion
                  applicable to Class A unit holder
              
              
              —
              
              
              —
              
              
              —
              
              
              56Net
                  income before cumulative effect of accounting change
              
              $
              12,469
              
              $
              12,599
              
              $
              11,466
              
              $
              15,293Net
                  income before cumulative effect ofaccounting
                  change per common unit - basicand
                  diluted
              
              $
              —
              
              $
              —
              
              $
              —
              
              $
              0.08Cumulative
                  effect of accounting change
              
              
              —
              
              
              —
              
              
              —
              
              
              6,355Net
                  income
              
              $
              12,469
              
              $
              12,599
              
              $
              11,466
              
              $
              21,648




101





**ITEM
      9.**  **CHANGES
      IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
      DISCLOSURE**




None.





**ITEM
      9A. CONTROLS AND PROCEDURES**





**Conclusion
      Regarding the Effectiveness of Disclosure Controls and
      Procedures**





We
      maintain disclosure controls and procedures that are designed to ensure that
      information required to be disclosed in our Securities Exchange Act of 1934
      reports is recorded, processed, summarized and reported within the time periods
      specified in the SEC’s rules and forms, and that such information is accumulated
      and communicated to our management, including our Chief Executive Officer and
      Chief Financial Officer, as appropriate, to allow timely decisions regarding
      required disclosure. In designing and evaluating the disclosure controls and
      procedures, our management recognized that any controls and procedures, no
      matter how well designed and operated, can provide only reasonable assurance
      of
      achieving the desired control objectives, and our management necessarily was
      required to apply its judgment in evaluating the cost-benefit relationship
      of
      possible controls and procedures.





Under
      the
      supervision of our Chief Executive Officer and Chief Financial Officer, we
      have
      carried out an evaluation of the effectiveness of our disclosure controls and
      procedures as of the end of the period covered by this report. Based upon that
      evaluation, our Chief Executive Officer and Chief Financial Officer concluded
      that, as of December 31, 2007, our disclosure controls and procedures were
      effective at the reasonable assurance level.





**Management’s
      Report on Internal Control over Financial Reporting**





Our
      management is responsible for establishing and maintaining adequate internal
      control over financial reporting, as such term is defined in Exchange Act Rule
      13a-15(f). Under the supervision and with the participation of management,
      including our Chief Executive Officer and Chief Financial Officer, we conducted
      an evaluation of the effectiveness of internal control over financial reporting
      based upon criteria set forth by the Committee of Sponsoring Organizations
      of
      the Treadway Commission in Internal Control - Integrated Framework (COSO
      framework).





An
      effective internal control system, no matter how well designed, has inherent
      limitations, including the possibility of human error and circumvention or
      overriding of controls and therefore can provide only reasonable assurance
      with
      respect to reliable financial reporting. Furthermore, effectiveness of an
      internal control system in future periods cannot be guaranteed because the
      design of any system of internal controls is based in part upon assumptions
      about the likelihood of future events. There can be no assurance that any
      control design will succeed in achieving its stated goals under all potential
      future conditions. Over time certain controls may become inadequate because
      of
      changes in business conditions, or the degree of compliance with policies and
      procedures may deteriorate. As such, misstatements due to error or fraud may
      occur and not be detected.





In
      conducting management’s evaluation of the effectiveness of its internal control
      over financial reporting, management has excluded, due to the
      transaction size and complexity and timing of the acquisition ,
      the
      operations of Atlas Gas and Oil, LLC (AGO), which we acquired in June 2007,
      from
      its December 31, 2007 Sarbanes-Oxley 404 review. AGO constituted approximately
      72% of our total assets as of December 31, 2007 and 16% of our total revenues
      for the year ended December 31, 2007.





Based
      on
      our evaluation under the COSO framework, management concluded that our internal
      control over financial reporting as of December 31, 2007 was
      effective.





Grant
      Thornton, LLP, an independent registered public accounting firm, has issued
      an
      attestation report on our internal control over financial reporting as of
      December 31, 2007.




102


**REPORT
        OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**
 
 
 Board
        of
        Directors and Unitholders
 Atlas
        Energy Resources, LLC
 
 We
        have
        audited Atlas Energy Resources, LLC’s (a Delaware limited liability company)
        internal control over financial reporting as of December 31, 2007, based
        on
        criteria established in *Internal
        Control—Integrated Framework* issued
        by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
        Atlas Energy Resources, LLC’s management is responsible for maintaining
        effective internal control over financial reporting and for its assessment
        of
        the effectiveness of internal control over financial reporting, included
        in the
        accompanying *Management’s
        Report on Internal Control over Financial Reporting* .
        Our
        responsibility is to express an opinion on Atlas Energy Resources, LLC’s
        internal control over financial reporting based on our audit.
 
 We
        conducted our audit in accordance with the standards of the Public Company
        Accounting Oversight Board (United States). Those standards require that
        we plan
        and perform the audit to obtain reasonable assurance about whether effective
        internal control over financial reporting was maintained in all material
        respects. Our audit included obtaining an understanding of internal control
        over
        financial reporting, assessing the risk that a material weakness exists,
        testing
        and evaluating the design and operating effectiveness of internal control
        based
        on the assessed risk, and performing such other procedures as we considered
        necessary in the circumstances. We believe that our audit provides a reasonable
        basis for our opinion.
 
 As
        indicated in the accompanying *Management’s Report on Internal Control over
        Financial Reporting*, in conducting management’s assessment of and
        conclusion on the effectiveness of internal controls over financial reporting,
        management has excluded Atlas Energy Resources, LLC’s subsidiary Atlas Gas &
Oil Company, which was acquired on June 29, 2007. Atlas Gas & Oil Company
        represented approximately 72% of Atlas Energy Resources, LLC’s total assets and
        approximately 16% of its total revenues at December 31, 2007. Management
        did not
        assess the effectiveness of internal controls over financial reporting at
        this
        subsidiary due to the transaction size and complexity and timing of the
        acquisition. Our audit of internal controls over financial reporting of Atlas
        Energy Resources, LLC did not include an evaluation of the internal control
        over
        financial reporting of Atlas Gas & Oil Company.
 
 A
        company’s internal control over financial reporting is a process designed to
        provide reasonable assurance regarding the reliability of financial reporting
        and the preparation of financial statements for external purposes in accordance
        with generally accepted accounting principles. A company’s internal control over
        financial reporting includes those policies and procedures that (1) pertain
        to
        the maintenance of records that, in reasonable detail, accurately and fairly
        reflect the transactions and dispositions of the assets of the company; (2)
        provide reasonable assurance that transactions are recorded as necessary
        to
        permit preparation of financial statements in accordance with generally accepted
        accounting principles, and that receipts and expenditures of the company
        are
        being made only in accordance with authorizations of management and directors
        of
        the company; and (3) provide reasonable assurance regarding prevention or
        timely
        detection of unauthorized acquisition, use, or disposition of the company’s
        assets that could have a material effect on the financial
        statements.
 
 Because
        of its inherent limitations, internal control over financial reporting may
        not
        prevent or detect misstatements. Also, projections of any evaluation of
        effectiveness to future periods are subject to the risk that controls may
        become
        inadequate because of changes in conditions, or that the degree of compliance
        with the policies or procedures may deteriorate.
 
 In
        our
        opinion, Atlas Energy Resources, LLC maintained, in all material respects,
        effective internal control over financial reporting as of December 31, 2007,
        based on criteria established in *Internal
        Control—Integrated Framework* issued
        by COSO *.*
 
 We
        also
        have audited, in accordance with the standards of the Public Company Accounting
        Oversight Board (United States), the accompanying consolidated balance sheets
        of
        Atlas Energy Resources, LLC and subsidiaries (a Delaware limited liability
        company) as of December 31, 2007 and 2006, and the related combined and
        consolidated statements of income, comprehensive income, equity, and cash
        flows
        for the years ended December 31, 2007 and 2006, the three month period ended
        December 31, 2005 and the year ended September 30, 2005 and our report dated
        February 27, 2008 expressed an unqualified opinion.
 
 /s/
        GRANT
        THORNTON LLP
 
 Cleveland,
        Ohio
 February
        27, 2008


103




**ITEM
      9B.**  **OTHER
      INFORMATION**





None.





**PART
      III**





**ITEM
      10.**  **DIRECTORS
      AND EXECUTIVE OFFICERS OF THE REGISTRANT**





As
      set
      forth in our Company Governance Guidelines and in accordance with NYSE listing
      standards, the non-management members of the board of directors will meet in
      executive session regularly without management. The director who presides at
      these meetings will rotate each meeting. The purpose of these executive sessions
      is to promote open and candid discussion among the non-management directors.
      Interested parties wishing to communicate directly with the non-management
      directors may contact the chairman of the audit committee, Walter Jones.
      Correspondence to Mr. Jones should be marked “Confidential” and sent to Mr.
      Jones’s attention, c/o Atlas Energy Resources, LLC, 1845 Walnut Street, 10th
      Floor, Philadelphia, PA 19103.





The
      independent directors comprise all of the members of all of the board of
      directors’ committees: the conflicts committee, the audit committee, the
      nominating and corporate governance committee and the compensation committee.
      The conflicts committee has the authority to review specific matters as to
      which
      the board believes there may be a conflict of interest to determine if the
      resolution of the conflict is fair and reasonable to us. Any matters approved
      by
      the conflicts committee are conclusively judged to be fair and reasonable to
      us,
      approved by all our unit holders and not a breach of obligation to us or to
      our
      unit holders. The audit committee reviews the external financial reporting
      by
      our management, the audit by our independent public accountants, the procedures
      for internal auditing and the adequacy of our internal accounting controls.
      The
      nominating and corporate governance committee assists the company and the board
      by identifying qualified candidates for director positions and in developing
      recommendations to improve the company’s corporate governance. Starting with the
      2008 calendar year, the compensation committee will assist the board in carrying
      out its responsibilities with respect to the compensation allocated to those
      individuals who perform services for us.





We
      have
      entered into a management agreement with our manager, Atlas Energy Management,
      Inc., pursuant to which it is responsible for managing our day-to-day
      operations, subject to the supervision and direction of our board of directors.
      Neither we nor our manager directly employ any of the persons responsible for
      our operations. Rather, personnel of Atlas America manage and operate our
      business. Our officers and those of our manager may spend a substantial amount
      of time managing the business and affairs of Atlas America and its affiliates
      and may face a conflict regarding the allocation of their time between our
      business and affairs and their other business interests.





**Board
      of Directors and Executive Officers**





Our
      board
      of directors is comprised of seven directors, each serving a one year term.
      There are no family relationships among the directors and executive officers
      except that Edward E. Cohen, our Chairman and Chief Executive Officer, is the
      father of Jonathan Z. Cohen, the Vice Chairman of our Board of Directors. The
      following table sets forth information regarding our executive officers and
      directors:





**Name**
            
            **Age**
            
            **Title**Edward
                E. Cohen
            
            69
            
            Chairman
                of the Board and Chief Executive OfficerJonathan
                Z. Cohen
            
            37
            
            Vice
                Chairman of the BoardMatthew
                A. Jones
            
            46
            
            Chief
                Financial Officer and DirectorRichard
                D. Weber
            
            44
            
            President,
                Chief Operating Officer and DirectorNancy
                J. McGurk
            
            52
            
            Chief
                Accounting OfficerLisa
                Washington
            
            40
            
            Chief
                Legal Officer and SecretaryDaniel
              C. Herz
            
            31
            
            Senior
              Vice President, Corporate DevelopmentWalter
                C. Jones
            
            45
            
            DirectorEllen
                F. Warren
            
            51
            
            DirectorBruce
                M. Wolf
            
            59
            
            Director




104




**Edward
      E. Cohen** has been
      our Chairman of the Board and Chief Executive Officer since our formation in
      2006 and Chairman of the Board and Chief Executive Officer of Atlas Energy
      Management since its formation in 2006. He has been the Chief Executive Officer
      and President of Atlas America since its formation in September 2000.
      Mr. Cohen has been Chairman of the managing board of Atlas Pipeline
      Partners GP, LLC, the general partner of Atlas Pipeline Partners, L.P., since
      its formation in 1999, and Chairman of the Board and Chief Executive Officer
      of
      Atlas Pipeline Holdings GP, LLC, the general partner of Atlas Pipeline Holdings,
      L.P., since its formation in January 2006. In addition, he has been Chairman
      of
      the board of directors of Resource America, Inc. (a publicly-traded specialized
      asset management company) since 1990 and was its Chief Executive Officer from
      1988 until 2004; Chairman of the Board of Resource Capital Corp. (a
      publicly-traded real estate investment trust) since its formation in September
      2005; a director of TRM Corporation (a publicly-traded consumer services
      company) from 1998 to July 2007; and Chairman of the Board of Brandywine
      Construction & Management, Inc. (a property management company) since
      1994. Mr. Cohen is the father of Jonathan Z. Cohen.





**Jonathan
      Z. Cohen** has been
      Vice Chairman of the Board since our formation in 2006 and Vice Chairman of
      Atlas Energy Management since its formation in 2006. He has been the Vice
      Chairman of Atlas America since its formation in September 2000. Mr. Cohen
      has been Vice Chairman of the managing board of Atlas Pipeline Partners GP
      since
      its formation in 1999, and Vice Chairman of the Board of Atlas Pipeline Holdings
      GP since its formation in January 2006. In addition, he has been a senior
      officer of Resource America since 1998, serving as the Chief Executive Officer
      since 2004, President since 2003 and a director since 2002, Chief Executive
      Officer, President and a director of Resource Capital Corp. since its formation
      in 2005. Mr. Cohen was a trustee and secretary of RAIT Financial Trust (a
      publicly-traded real estate investment trust) from 1997, and its Vice Chairman
      from 2003, until December 2006. Mr. Cohen is a son of Edward E.
      Cohen.





**Matthew
      A. Jones** has been
      our Chief Financial Officer and a director since our formation and Chief
      Financial Officer of Atlas Energy Management since its formation. He has been
      the Chief Financial Officer of Atlas America and of Atlas Pipeline Partners
      GP
      since March 2005. He has been the Chief Financial Officer of Atlas Pipeline
      Holdings GP since January 2006 and a director since February 2006. From 1996
      to
      2005, Mr. Jones worked in the Investment Banking group at Friedman Billings
      Ramsey, which we refer to as FBR, concluding as Managing Director.
      Mr. Jones worked in FBR’s Energy Investment Banking Group from 1999 to 2005
      and in FBR’s Specialty Finance and Real Estate Group from 1996 to 1999.
      Mr. Jones is a Chartered Financial Analyst.





**Richard
      D. Weber** has been
      our President, Chief Operating Officer and a director since our formation in
      2006 and President, Chief Operating Officer and a director of Atlas Energy
      Management since its formation in 2006. Mr. Weber served from June 1997
      until March 2006 as Managing Director and Group Head of the Energy Group of
      KeyBanc Capital Markets, a division of KeyCorp, and its predecessor,
      McDonald & Company Securities, Inc. As part of his duties, he oversaw
      the bank’s activities with oil and gas producers, pipeline companies and
      utilities.





**Nancy
      J. McGurk** has been
      our Chief Accounting Officer since our formation in 2006 and Chief Accounting
      Officer of Atlas Energy Management since its formation. She has been the Chief
      Accounting Officer of Atlas America since January 2001 and Senior Vice President
      since January 2002. Ms. McGurk was a Vice President of Resource America
      from 1992 until May 2004, and its Treasurer and Chief Accounting Officer from
      1989 until May 2004. Ms. McGurk has been Senior Vice President since
      January 2002, and Chief Financial Officer and Chief Accounting Officer since
      January 2001, of Atlas Resources.





**Lisa
      Washington** has been
      our Chief Legal Officer and Secretary since our formation in 2006 and Chief
      Legal Officer and Secretary of Atlas Energy Management since its formation.
      Ms. Washington has been the Vice President, Chief Legal Officer and
      Secretary of Atlas America and Atlas Pipeline Partners GP since November 2005.
      She has been the Chief Legal Officer and Secretary of Atlas Pipeline Holdings
      GP
      since January 2006. From 1999 to November 2005, Ms. Washington was an
      attorney in the business department of the law firm of Blank Rome
      LLP.


**Daniel
        C. Herz** has been
        our Senior Vice President of Corporate Development since August 2007. He
        has
        also been the Senior Vice President of Corporate Development of Atlas America,
        Atlas Pipeline Partners GP and Atlas Pipeline Holdings GP since August 2007.
        Before that, he was Vice President of Corporate Development of Atlas America
        and
        Atlas Pipeline Partners GP from December 2004 and of Atlas Pipeline Holdings
        GP
        from its formation in January 2006. Mr. Herz joined Atlas America and Atlas
        Pipeline Partners GP in January 2004. He was an Associate Investment Banker
        with
        Banc of America Securities from 2002 to 2003 and an Analyst from 1999 to
        2002.





**Independent
      Directors**





**Walter
      C. Jones** has been
      a member of the Board of Directors since December 2006. Since June 2007, Mr.
      Jones has been an advisor to GRAVITAS Capital Advisors, LLC, an independent
      advisory firm where from May 2005, he was the General Counsel and Senior
      Director of Private Equity for the firm. From May 1994 to May 2005,
      Mr. Jones was at the Overseas Private Investment Corporation, where he
      served as Manager for Asia, Africa, the Middle East, Latin America and the
      Caribbean, as well as a Senior Investment Officer in the Finance Department.
      Prior to that, Mr. Jones was an International Consultant at the Washington,
      DC
      firm of Neill & Co. Mr. Jones began his career at the law firm of Sidley
& Austin.




105





**Ellen
      F. Warren** has been
      a member of the Board of Directors since December 2006. Ms. Warren is founder
      and President of OutSource Communications, a marketing communications firm
      that
      services corporate and nonprofit clients. Prior to founding OutSource
      Communications in August 2005, she was President of Levy Warren Marketing Media,
      a public relations and marketing firm she co-founded in March 1998. Before
      that,
      she was Vice President of Marketing/Communications for Jefferson Bank, a
      Philadelphia-based financial institution from September 1992 to February
      1998.





**Bruce
      M. Wolf** has been
      a member of the Board of Directors since December 2006. Mr. Wolf has been
      President of Homard Holdings, LLC, a wine manufacturer and distributor, since
      September 2003. Mr. Wolf has been of counsel with Picadio, Sneath,
      Miller & Norton, P.C., Pittsburgh, PA, since May 2003. Additionally,
      since June 1999, Mr. Wolf has been a consultant in connection with energy
      and securities matters, conducting research and providing expert testimony
      and
      litigation support. Mr. Wolf was a Senior Vice President of Atlas America
      from October 1998 to May 1999 and, before that, Secretary and General Counsel
      of
      Atlas Energy Group from 1980.





**Information
      Concerning the Audit Committee**





Our
      board
      of directors has a standing audit committee. All of the members of the audit
      committee are independent directors as defined by NYSE rules. The members of
      the
      audit committee are Messrs. W. Jones and Wolf, and Ms. Warren, with Mr. Jones
      acting as the chairman. Our Board of Directors has determined that Mr. Jones
      is
      an “audit committee financial expert,” as defined by SEC rules. The audit
      committee reviews the scope and effectiveness of audits by the independent
      accountants, is responsible for the engagement of independent accountants and
      reviews the adequacy of our internal controls.





**Section
      16(a) Beneficial Ownership Reporting Compliance**





Section
      16(a) of the Securities Exchange Act of 1934 requires our officers, directors
      and persons who own more than ten percent of a registered class of our equity
      securities to file reports of ownership and changes in ownership with the SEC
      and to furnish us with copies of all such reports.





Based
      solely on our review of the reports we have received, written representations
      from certain reporting persons that no filings were required for those persons,
      we believe that during 2007, our executive officers, directors and greater
      than
      10% stockholders complied with all applicable filing requirements of Section
      16(a) of the Securities Exchange Act.





**Compensation
      Committee Interlocks and Insider Participation**





We
      did
      not have a compensation committee in 2007. Compensation of the personnel of
      Atlas America and its affiliates who provide us with services was set by Atlas
      America.





Mr.
      Wolf
      was a Senior Vice President of Atlas America from October 1998 to May 1999.
      On
      December 12, 2006, the Board determined Mr. Wolf to be an independent board
      member pursuant to NYSE listing standards and Rule 10A-3(b) promulgated under
      the Securities Exchange Act of 1934. None of the other independent directors
      is
      an employee or former employee of ours or of our parent. No executive officer
      of
      ours is a director or executive officer of any entity in which an independent
      director is a director or executive officer.





**Code
      of Business Conduct and Ethics, Company Governance Guidelines and Committee
      Charters**





We
      have
      adopted a code of business conduct and ethics that applies to the principal
      executive officer, principal financial officer and principal accounting officer,
      as well as to persons performing services for us generally. We have also adopted
      Company Governance Guidelines and charters for each of the audit, compensation
      and nominating and corporate governance committees. We will make a printed
      copy
      of our code of ethics, our Company Governance Guidelines, our audit committee
      charter, our compensation committee charter and our nominating and corporate
      governance charter available to any unit holder who so requests. Requests for
      print copies may be directed to us as follows: Atlas Energy Resources, LLC, 1550
      Coraopolis Heights Road—2 nd Floor,
      Moon Township, Pennsylvania 15108 ,
      Attention: Secretary. Each of the code of business conduct and ethics, the
      Company Governance Guidelines, the audit committee charter, the compensation
      committee charter and the nominating and corporate governance charter are
      posted, and any waivers we grant under our code of business conduct and ethics
      will be posted, on our website at www.atlasenergyresources.com .





106





**ITEM
      11.**  **EXECUTIVE
      COMPENSATION**





**COMPENSATION
      DISCUSSION AND ANALYSIS**




We
      are
      required to provide information regarding the compensation program in place
      as
      of December 31, 2007, for our CEO, CFO and the three other most
      highly-compensated executive officers. In this report, we refer to our CEO,
      CFO
      and the other three most highly-compensated executive officers as our “Named
      Executive Officers” or “NEOs.” This section should be read in conjunction with
      the detailed tables and narrative descriptions below.




Through
      the end of 2007, the compensation committee of Atlas America, our parent, has
      been responsible for formulating and presenting recommendations to its Board
      of
      Directors and our board with respect to the compensation of our named executive
      officers. We do not directly compensate our named executive officers. Rather,
      Atlas America allocates the compensation of the executive officers between
      activities on behalf of us and activities on behalf of itself and its affiliates
      based upon an estimate of the time spent by such persons on activities for
      us
      and for Atlas America and its affiliates. We reimburse Atlas America for the
      compensation allocated to us. The compensation committee is also responsible
      for
      administering our employee benefit plans, including incentive plans. The
      compensation committee is comprised solely of independent directors of Atlas
      America.




Compensation
      Objectives




We
      believe that our compensation program must support our business strategy, be
      competitive, and provide both significant rewards for outstanding performance
      and clear financial consequences for underperformance. We also believe that
      a
      significant portion of the NEOs’ compensation should be “at risk” in the form of
      annual and long-term incentive awards that are paid, if at all, based on
      individual and company accomplishment.




The
      compensation awarded to our NEOs for fiscal 2007 specifically was intended:




•  To
      encourage and reward strong performance; and




•  To
      motivate our NEOs by providing them with a meaningful equity stake in our
      company and our publicly-traded subsidiaries, as appropriate.




Accounting
      and cost implications of compensation programs are considered in program design;
      however, the essential consideration is that a program is consistent with our
      business needs.




Compensation
      Methodology




The
      compensation committee makes recommendations to the Atlas America board on
      compensation amounts during the month after the close of its (and our) fiscal
      year. In the case of base salaries, it recommends the amounts to be paid for
      that year. In the case of annual bonus and long-term incentive compensation,
      the
      committee recommends the amount of awards based on the then concluded fiscal
      year. We typically pay cash awards and issue equity awards in February of the
      following fiscal year. The compensation committee has the discretion to
      recommend the issuance of equity awards at other times during the fiscal year.
      In addition, some of our NEOs who also perform services for Atlas America and
      its other publicly-traded subsidiaries, Atlas Pipeline Partners and Atlas
      Pipeline Holdings, may receive stock-based awards from these subsidiaries,
      each
      of which have delegated compensation decisions to the compensation committee
      since neither we, nor the other subsidiaries, have employees.




107




Each
      year, Atlas America’s (and our) Chief Executive Officer provides the
      compensation committee with key elements of Atlas America’s performance and the
      NEOs’ performance as well as recommendations to assist it in determining
      compensation levels. The compensation committee focuses on Atlas America’s
      equity performance, market capitalization, corporate developments, business
      performance (including production of energy and replacement of reserves) and
      financial position in recommending the compensation for those NEOs who provided
      services to both Atlas America and to us.




In
      June
      2006, the compensation committee retained Mercer Human Resource Consulting
      to
      analyze and review the competitiveness and appropriateness of all elements
      of
      the compensation paid by Atlas America to its executive officers, including
      our
      NEOs, individually and as a group, for fiscal 2006. The purpose of retaining
      Mercer was to determine whether Atlas America’s compensation practices were
      within the norm for companies of similar size and focus. Because of the
      importance to Atlas America and to us of our direct-placement energy investment
      programs and Atlas America’s creation of new initiatives entities, Mercer looked
      not only to the energy industry in evaluating our compensation levels but also
      to the financial services and alternative asset industries. Mercer’s analysis
      established that Atlas America’s fiscal 2006 compensation amounts fell between
      the median and the 75 th percentile of the peer group it used, which the compensation committee found
      acceptable in the context of its evaluation of the performance of the
      NEOs.




Ultimately,
      the decisions regarding executive compensation are made by the compensation
      committee after extensive discussion regarding appropriate compensation and
      are
      approved by the Atlas America board of directors.




Elements
      of our Compensation Program




Our
      executive officer compensation package includes a combination of annual cash
      and
      long-term incentive compensation. Annual cash compensation is comprised of
      base
      salary plus cash bonus. Long-term incentives consist of a variety of equity
      awards. Both the annual
      cash incentives and long-term incentives may be performance-based.




Base
      Salary




Base
      salary is intended to provide fixed compensation to the NEOs for their
      performance of core duties that contributed to the success of Atlas America
      and
      us as measured by the elements of corporate performance mentioned above. Base
      salaries are not intended to compensate individuals for extraordinary
      performance or for above average company performance.




Annual
      Incentives




Annual
      incentives are intended to tie a significant portion of each of the NEO’s
      compensation to Atlas America’s annual performance and /or that of one of Atlas
      America’s subsidiaries or divisions for which the officer is responsible.
      Generally, the higher the level of responsibility of the executive within Atlas
      America, the greater is the incentive component of that executive’s target total
      cash compensation. The compensation committee may recommend awards of
      performance-based bonuses and discretionary bonuses.




*Performance-Based
      Bonuses* —
The
      Atlas America Annual Incentive Plan for Senior Executives, which we refer to
      as
      the Senior Executive Plan, provides awards for the achievement of predetermined,
      objective performance measures over a specified 12-month performance period,
      generally Atlas America’s fiscal year. Awards under the Senior Executive Plan
      are paid in cash. Notwithstanding the existence of the Senior Executive Plan,
      the compensation committee believes that stockholder interests are best served
      by not restricting its discretion and flexibility in crafting compensation,
      even
      if the compensation amounts result in non-deductible compensation expense.
      Therefore, the committee reserves the right to approve compensation that is
      not
      fully deductible.




In
      February 2007, the compensation committee set the performance goals for the
      Atlas America’s executive offers, some of whom are also our NEOs. Specifically,
      the committee decided that if Atlas America’s 2007 net income, which was defined
      as net income before income taxes and compensatory bonuses paid, exceeded
      $18,000,000, a bonus pool equal to 15% of the 2007 net income would be
      established, from which bonus awards would be made. Pursuant to the terms of
      the
      Senior Executive Plan, in determining whether and to what extent the performance
      target was achieved, the compensation committee relies on information contained
      in the Atlas America’s audited financial statements and other objectively
      determinable information. If the performance target was not achieved, no annual
      incentives would be awarded. Pursuant to the terms of the Senior Executive
      Plan,
      the compensation committee has the discretion to recommend the reduction, but
      not the increase, of the annual incentive awards.




108




*Discretionary
      Bonuses* —Discretionary
      bonuses may be awarded to recognize individual and group performance.




Long-Term
      Incentives




We
      believe that our long-term success depends upon aligning our executives’ and
      stockholders’ interests. To support this objective, we provide our executives
      with various means to become significant stockholders, including our long-term
      incentive programs. These awards are usually a combination of stock options,
      restricted units and phantom units which vest over four years to support
      long-term retention of executives and reinforce our longer-term goals. Our
      NEOs
      are eligible to receive awards under our Long-Term Incentive Plan, which we
      refer to as our Plan, the Atlas America Stock Incentive Plan, which we refer
      to
      as the Atlas Plan, the Atlas Pipeline Partners Long-Term Incentive Plan, which
      we refer to as the APL Plan, and the Atlas Pipeline Holdings Long-Term Incentive
      Plan, which we refer to as the AHD Plan, as appropriate.




*Grants
      under our Plan:* The
      compensation committee may recommend grants of equity awards in the form of
      options, restricted units, and/or phantom units. In May 2007, our Plan was
      amended to meet the deductibility requirements of Section 162(m) when the awards
      are granted pursuant to pre-established performance goals.




Options —Options
      have a ten-year term and, in general, vest 25% on the third anniversary of
      the
      grant date and 75% on the fourth anniversary of the grant date.




Phantom
      Units —A
      phantom unit is a notional unit which, upon vesting, converts into a common
      unit
      in our company. Phantom units may be granted with or without tandem distribution
      equivalent rights, which we refer to as DERs. In general, grants of our phantom
      units vest 25% on the third anniversary of the grant date and 75% on the fourth
      anniversary of the grant date.




Restricted
      Units —From
      time to time, restricted units of our company may be granted to selected NEOs
      or
      employees.




*Grants
      under Other Plans* :
      As
      described above, our NEOs who perform services for us and one or more of Atlas
      America’s publicly-traded subsidiaries may receive stock-based awards under the
      Atlas Plan, the APL Plan or the AHD Plan.




Supplemental
      Benefits, Deferred Compensation and Perquisites




We
      do not
      emphasize supplemental benefits for executives other than Mr. E. Cohen, and
      perquisites are discouraged. None of our NEOs have deferred any portion of
      their
      compensation.




Determination
      of 2007 Compensation Amounts




As
      described above, after the end of our 2007 fiscal year, the compensation
      committee set the base salaries of the Atlas America executives for the 2008
      fiscal year and recommended incentive awards based on the prior year’s
      performance. In carrying out its function, the compensation committee acted
      in
      consultation with Mercer.




In
      determining the actual amounts to be paid to the Atlas America executives,
      the
      compensation committee looked to both the individual’s performance as well as to
      the overall performance of our company and our publicly-held subsidiaries during
      fiscal 2007. As described above, Atlas America allocates the cash compensation
      for our NEOs to us based upon an estimate of the time spent by such persons
      on
      activities for us and for Atlas America and its affiliates.




109




Base
      Salary .
      Consistent with its preference for having a significant portion of our NEOs’
overall compensation package be incentive compensation, the compensation
      committee decided to recommend that base salaries for 2008 be maintained at
      the
      same levels as 2007.




Annual
      Incentives .




*Performance-Based
      Bonuses* .
      The
      compensation committee reviewed Atlas America’s financial statements and
      determined that the 2007 net income exceeded the pre-determined minimum
      threshold. It accordingly recommended for approval awards under the Senior
      Executive Plan. The amount of these awards that were allocated to us were as
      follows: Edward E. Cohen, $2,250,000; Jonathan Z. Cohen, $1,434,783; Matthew
      A.
      Jones, $900,000; and Richard D. Weber, $1,500,000.




*Discretionary
      Bonuses* .
      Based
      on the record-breaking performance of our direct-placement energy investment
      programs, the compensation committee recommended that Atlas America award Mr.
      Kotek a cash bonus of which $750,000 was allocable to us.




Long-Term
      Incentives .
      Additionally, the compensation committee recognized the importance of a
      long-term incentive component as a part of the 2007 compensation. The
      compensation committee recommended the award of Atlas America stock options
      as
      follows: Mr. E. Cohen—200,000 options; Mr. J. Cohen—160,000 options; Mr. M.
      Jones—80,000 options; Mr. Weber—60,000 options; and Mr. Kotek—40,000 options.
      These awards are not reflected in the Summary Compensation Table because we
      did
      not recognize expense for them in fiscal 2007. The compensation committee
      determined that it would not recommend that awards be made to our NEOs under
      our
      Plan, the APL Plan or the AHD Plan because it felt that previous awards were
      adequate.




The
      following table sets forth the compensation allocation for fiscal year 2007
      for
      our Chief Executive Officer and Chief Financial Officer, and each of our other
      most highly compensated executive officers whose allocated total compensation
      exceeded $100,000. As required by SEC guidance, the table also discloses awards
      under the Atlas Plan.




110




**2007
      Summary Compensation Table**





**Name
                and Principal Position**
            
            **Year**
            
            **Salary ($)**
            
            **Bonus ($)**
            
            **Stock**
              **Awards**
              **($)****(1)**
            
            **Option**
              **Awards**
              **($)****(2)**
            
            **Non-Equity
                Incentive Plan Compensation**
              **($)**
            
            **All
                Other**
              **Compensation**
              **($)**
            
            **Total**
              **($)**Edward
                E. Cohen,
              Chairman
                of the Board and Chief Executive Officer
            
            
            2007
            
            $
            405,000
            
            
            —
            
            $
            1,153,000
            
            $
            301,250
            
            $
            2,250,000
            
            $
            294,000(3)
            
            $
            4,403,2502006
            
            $
            27,391
            
            
            —
            
            $
            674,625
            
            $
            84,861
            
            
            —
            
            $
            32,300
            
            $
            819,177Matthew
                A. Jones,
              Chief
                Financial Officer
            
            
            2007
            
            $
            135,000
            
            
            —
            
            $
            115,300
            
            $
            337,295
            
            $
            900,000
            
            $
            29,400(3)
            
            $
            1,516,9952006
            
            $
            13,696
            
            
            —
            
            $
            276,546
            
            $
            324,172
            
            
            —
            
            $
            7,600
            
            $
            622,064Jonathan
                Z. Cohen,
              Vice
                Chairman
            
            
            2007
            
            $
            33,750
            
            
            —
            
            $
            576,500
            
            $
            120,500
            
            $
            1,434,783
            
            $
            147,000(3)
            
            $
            2,312,533Richard
                D. Weber,
              President
                and Chief Operating Officer of Atlas Energy Resources, LLC
            
            
            2007
            
            $
            300,000
            
            
            —
            
            $
            250,000
            
            $
            463,770
            
            $
            1,500,000
            
            $
            2,857
            
            $
            2,516,6272006
            
            $
            15,217
            
            
            —
            
            $
            187,504
            
            $
            347,779
            
            
            —
            
            
            —
            
            $
            550,500Freddie
                M. Kotek,
              Executive
                Vice President of Atlas America
            
            
            2007
            
            $
            225,000
            
            $
            750,000
            
            $
            115,300
            
            $
            183,710
            
            
            —
            
            $
            29,400(3)
            
            $
            1,303,410




(1)
            Represents
                the dollar amount of expense we recognized for financial statement
                reporting purposes with respect to phantom units and/or restricted
                units
                granted under our Plan, all in accordance with FAS 123R. See Note
                11 to
                our combined and consolidated financial statements for an explanation
                of
                the assumptions we make for this
                valuation.




(2)
            Represents
                the dollar amount of (i) expense recognized by Atlas for financial
                statement reporting purposes with respect to options granted under
                the
                Atlas Plan; and/or (ii) expense we recognized for financial statement
                reporting purposes for options granted under our Plan, all in accordance
                with FAS 123R. See Note 11 to our combined and consolidated financial
                statements for an explanation of the assumptions we make for this
                valuation.


(3)
            Represents
                payments on DERs with respect to the phantom units awarded under
                our Plan,
                as reported in the Stock Awards column.




111





The following
      table discloses awards under our Plan.





**2007
      GRANTS OF PLAN-BASED AWARDS TABLE**




**Name**
              
              **Grant**
                **Date**
              
              **Approval**
                **Date**
              
              **All Other**
                **Stock Awards:**
                **Number of Shares**
                **Of
                  Stock or Units**
                **(#)**
              
              **All
                  Other**
                **Option Awards:**
                **Number of Securities**
                **Underlying
                  Options**
                **(#)**
              
              **Exercise or**
                **Base
                  Price of**
                **Option Awards**
                **($ / Sh)**
              
              **Grant
                  Date**
                **Fair
                  Value of**
                **Stock
                  and**
                **Option
                  Awards**Edward
                  E. Cohen
              
              
              1/24/07
              
              
              1/22/07
              
              
              200,000(1)
              
              
              500,000(2)
              
              $
              23.06
              
              $
              4,612,000(1)$
              1,250,000(2)Matthew
                  A. Jones
              
              
              1/24/07
              
              
              1/22/07
              
              
              20,000(1)
              
              
              50,000(2)
              
              $
              23.06
              
              $
              461,200(1)$
              120,500(2)Jonathan
                  Z. Cohen
              
              
              1/24/07
              
              
              1/22/07
              
              
              100,000(1)
              
              
              200,000(2)
              
              $
              23.06
              
              $
              2,306,000(1)$
              482,000(2)Richard
                  D. Weber
              
              
              1/24/07(3)
              
              
              4/3/06
              
              
              47,
                  619(4)
              
              
              373,752(5)
              
              $
              21.00
              
              $
              999,999(1)$
              900,742(2)Freddie
                  Kotek
              
              
              1/24/07
              
              
              1/22/07
              
              
              20,000(1)
              
              
              50,000(2)
              
              $
              23.06
              
              $
              461,200(1)$
              120,500(2)




(1)
            Represents
                grants of phantom units under our Plan, which vest 25%  on the third
                anniversary and 75% on the fourth anniversary of the grant, valued
                in
                accordance with FAS 123R at the closing price of our common units
                on the
                grant date of $23.06.




(2)
            Represents
                grants of stock options under our Plan, which vest 25% on the third
                anniversary and 75% on the fourth anniversary of the grant, valued
                at $
                2.41 per option using the Black-Scholes option pricing model to estimate
                the weighted average fair value of each unit option granted with
                weighted
                average assumptions for (a) expected dividend yield of 8.0%, (b)
                risk-free
                interest rate of 4.7%, (c) expected volatility of 25.0%, and (d)
                an
                expected life of 6.3 years.




(3)
            Pursuant
                to Mr. Weber’s employment agreement entered into on April 17, 2006, upon
                the completion of our initial public offering we were obligated to
                award
                him the restricted units and options shown in the table. However,
                we did
                not grant the awards until our registration statement on Form S-8,
                covering unit awards was declared effective by the SEC.




(4)
            Represents
                grants of phantom units under our Plan, in accordance with Mr. Weber’s
                employment agreement, which vest 25% per year on the anniversary of
                the commencement of Mr. Weber’s employment, valued in accordance with FAS
                123R at the closing price of our common units on the grant date of
                $21.00.




(5)
            Represents
                grants of options under our Plan, in accordance with Mr. Weber’s
                employment agreement, which vest 25% per year on the anniversary of
                the commencement of Mr. Weber’s employment on April 17, 2006, valued at $
                2.41 per option using the Black-Scholes option pricing model to estimate
                the weighted average fair value of each unit option granted with
                weighted
                average assumptions for (a) expected dividend yield of 8.0%, (b)
                risk-free
                interest rate of 4.7%, (c) expected volatility of 25.0%, and (d)
                an
                expected life of 6.3 years.





Richard
      D. Weber Employment Agreement





Atlas
      America entered into an employment agreement in April 2006 with Richard Weber,
      who serves as President and Chief Operating Officer of us and of our manager,
      Atlas Energy Management. The agreement has a two year term and, after the first
      year, the term automatically renews daily so that on any day that the agreement
      is in effect, the agreement will have a remaining term of one year.
      Mr. Weber is required to devote substantially all of his working time to
      Atlas Energy Management and its affiliates. The agreement provides for an annual
      base salary of not less than $300,000 and a bonus of not less than $700,000
      during the first year. After that, bonuses will be awarded solely at the
      discretion of the compensation committee. The agreement provides for equity
      compensation as follows:





112




•
            Upon
                execution of the agreement, Mr. Weber was granted options to purchase
                50,000 shares of Atlas America stock at
                $47.86.




•
            In
                January 2007, Mr. Weber was granted 47,619 shares of our restricted
                units with a value of $1,000,000.




•
            In
                January 2007, Mr. Weber was granted options to purchase 373,752 of
                our common units at $21.00.





All
      of
      the securities described above vest 25% per year on each anniversary of the
      date Mr. Weber commenced his employment, April 17, 2006. All
      securities will vest immediately upon a change of control or termination by
      Mr. Weber for good reason or by Atlas Energy Management other than for
      cause. Change of control is defined as:




•
            the
                acquisition of beneficial ownership, as defined in the Securities
                Exchange
                Act, of 50% or more of Atlas America’s or our voting securities or all or
                substantially all of Atlas America’s or our assets by a single person or
                entity or group of affiliated persons or entities, other than an
                entity of
                which either Mr. E. Cohen or Mr. J. Cohen is an officer,
                manager, director or participant;




•
            we
                or Atlas America consummate a merger, consolidation, combination,
                share
                exchange, division or other reorganization or transaction with an
                unaffiliated entity after which Atlas Energy Management is not our
                manager; or




•
            our
                or Atlas America’s shareholders approve a plan of complete liquidation of
                winding up, or agreement of sale of all or substantially all of our
                or
                Atlas America’s assets other than an entity of which either Mr. E.
                Cohen or Mr. J. Cohen is an officer, manager, director or
                participant.




The
      change of control triggering events relating to the possible absence of Messrs.
      Cohen reflects that Mr. Weber’s belief that Messrs. Cohen effectively
      controlled us at the time of his employment and their separation would therefore
      constitute a change of control.





Good
      reason is defined as a material breach of the agreement, reduction in his base
      pay, a demotion, a material reduction in his duties or his failure to be elected
      to the Atlas Energy Resources Board of Directors. Cause is defined as fraud
      in
      connection with his employment, conviction of a crime other than a traffic
      offense, material failure to perform his duties after written demand by our
      Board or breach of the representations made by Mr. Weber in the employment
      agreement if the breach impacts his ability to fully perform his duties.
      Disability is defined as becoming disabled by reason of physical or mental
      disability for more than 180 days in the aggregate or a period of 90 consecutive
      days during any 365-day period and the good faith determination by our Board
      based upon medical evidence that Mr. Weber is unable to perform his duties
      under
      his employment agreement.





Atlas
      Energy Management may terminate Mr. Weber without cause upon 45 days
      written notice or for cause upon written notice. Mr. Weber may terminate
      his employment for good reason or for any other reason upon 30 days’ written
      notice. Key termination benefits are as follows:




•
            If
                Mr. Weber’s employment is terminated due to death, (a) Atlas Energy
                Management will pay to Mr. Weber’s designated beneficiaries a lump sum
                cash payment in an amount equal to the bonus that Mr. Weber received
                from
                the prior fiscal year pro rated for the time employed during the
                current
                fiscal year, (b) Mr. Weber’s family will receive health insurance coverage
                for one year; and (c) all Atlas Energy Resources stock and option
                awards
                will automatically vest.




•
            If
                Mr. Weber’s employment is terminated by Mr. Weber other than for
                good reason, all stock and option awards will automatically vest.




•
            If
                Atlas Energy Management terminates Mr. Weber’s employment other than for
                cause (including termination by reason of disability), or Mr. Weber
                terminates his employment for good reason, (a) Atlas Energy Management
                will pay amounts and benefits otherwise payable to Mr. Weber as if
                Mr.
                Weber remained employed for one year, except that the bonus amount
                shall
                be prorated and based on the bonus awarded in the prior fiscal year,
                and
                (b) all stock and option awards will automatically
                vest.




113





Mr. Weber
      is entitled to a gross-up payment if any payments made to him would constitute
      an excess parachute payment under Section 280G of the Code such that the
      net amount Mr. Weber receives after the deduction of any excise tax, any
      federal, state and local income tax, and any FICA and Medicare withholding
      tax
      is the same amount he would have received had such taxes not been deducted.
      The
      agreement includes standard restrictive covenants for a period of two years
      following termination, including non-compete and non-solicitation provisions.





If
      a
      termination event had occurred as of December 31, 2007, we estimate that
      the value of the benefits to Mr. Weber would have been as follows:





**Lump
                Sum**
            
            
            
            **Accelerated
                Vesting of****Severance**
            
            
            
            **Stock
                Awards and****Reason
                for Termination**
            
            **Payment**
            
            **Benefits****(1)**
            
            **Option
                Awards****(2)**Death
            
            $
            1,500,000(3)
            
            $
            17,193
            
            $
            —Disability
            
            
            —
            
            
            19,719
            
            
            —Termination
                by us other than for cause (including for disability) or by Mr. Weber
                for good reason
            
            
            1,800,000(4)
            
            
            19,719
            
            
            5,472,900Change
                of control
            
            
            —
            
            
            —
            
            
            5,472,900Termination
                by Mr. Weber without cause
            
            
            —
            
            
            —
            
            
            —





(1)
            Represents
                rates currently in effect for COBRA insurance benefits for 12
                months.


(2)
            Represents
                the value of unvested and accelerated option awards disclosed in
                the
                “Outstanding Equity Awards at Fiscal Year-End Table,” calculated by
                multiplying the number of accelerated options by the difference between
                the exercise price and the closing price of our stock on December
                31,
                2007.


(3)
            Represents
                Mr. Weber’s 2007 bonus.


(4)
            Calculated
                as the sum of Mr. Weber’s 2007 base salary and
                bonus.





Our
      Long-Term Incentive Plan





Our
      Plan
      provides performance incentive awards to our officers and directors, and the
      employees, directors and consultants of our manager and its affiliates,
      consultants and joint-venture partners who perform services for us. Our Plan
      is
      administered by Atlas America’s compensation committee under delegation from our
      board. The compensation committee may grant awards of common units, restricted
      units, phantom units, unit options for an aggregate of 3,742,000 common
      units.





*Restricted
      Units and Phantom Units.* A
      restricted unit is a common unit that is subject to forfeiture prior to the
      vesting of the award. ** A
      phantom
      unit entitles a participant to receive a common unit upon vesting of the phantom
      unit or, at the discretion of the compensation committee, cash equivalent to
      the
      then fair market value of a common unit. In
      tandem
      with phantom unit grants, the compensation committee may grant a DER. The
      compensation committee determines the vesting period for both restricted units
      and phantom units.





*Unit
      Options.* A
      unit
      option entitles a participant to receive a common unit upon payment of the
      exercise price for the option after completion of vesting of the unit option.
      The exercise price of the unit option may be equal to or more than the fair
      market value of a common unit as determined by the compensation committee on
      the
      date of grant of the option. The
      compensation committee determines the vesting and exercise period for unit
      options. Unit option awards expire 10 years from the date of grant.







The
      vesting of these types of awards mentioned above may also be contingent upon
      the
      attainment of predetermined performance targets, which could increase or
      decrease the actual award settlement, as determined by the compensation
      committee, although no awards currently outstanding contain any such provision.
      Awards will automatically vest upon a change of control, as defined in our
      Plan.
      In May 2007, the
      Atlas
      America stockholders approved an amendment to our Plan which provides for
      performance-based awards criteria for purposes of complying with Section 162(m)
      of the Internal Revenue Code (“Section 162(m)”).




114




Atlas
      Plan





The
      Atlas
      Plan authorizes the granting of up to 3.0 million shares of Atlas America common
      stock to its employees, affiliates, consultants and directors in the form of
      incentive stock options, non-qualified stock options, stock appreciation rights
      (“SARs”), restricted stock and deferred units. SARs represent a right to receive
      cash in the amount of the difference between the fair market value of a share
      of
      Atlas America common stock on the exercise date and the exercise price, and
      may
      be free-standing or tied to grants of options. A deferred unit represents the
      right to receive one share of Atlas common stock upon vesting. Awards under
      the
      Atlas Plan generally become exercisable as to 25% each anniversary after the
      date of grant, except that deferred units awarded to our non-executive board
      members vest 33 1/3% on the second, third and fourth anniversaries of the grant,
      and expire not later than ten years after the date of grant. Options and units
      will vest sooner upon a change in control of Atlas America or death or
      disability of a grantee, provided the grantee has completed at least six months
      service from the date of grant.





As
      required by SEC guidelines, the following table discloses awards under our
      Plan
      as well as under the Atlas Plan.




**2007** **OUTSTANDING
      EQUITY AWARDS AT FISCAL YEAR-END TABLE**






**Option
                Awards**
            
            **Stock
                Awards**


**Number
                    of**
                  **Securities**
                  **Underlying**
                  **Unexercised**
                  **Options**
                  **(#)**
                
                **Number
                    of**
                  **Securities**
                  **Underlying**
                  **Unexercised**
                  **Options**
                  **(#)**
                
                **Option**
                  **Exercise**
                  **Price**
                  **($)**
                
                **Option**
                  **Expiration**
                  **Date**
                
                **Number of**
                  **Shares
                    or**
                  **Units
                    of**
                  **Stock That**
                  **Have
                    Not**
                  **Vested**
                  **(#)**
                
                **Market**
                  **Value of**
                  **Shares or**
                  **Units
                    of**
                  **Stock That**
                  **Have
                    Not**
                  **Vested**
                  **($)****Name**
                
                **Exercisable**
                
                **Unexercisable**Edward
                    E. Cohen
                
                
                675,000(1)
                
                
                —
                
                $
                16.98
                
                
                7/1/2015—
                
                
                500,000(2)
                
                $
                23.06
                
                
                1/24/2017
                
                
                200,000(3)
                
                $
                6,218,000(4)Matthew
                    A. Jones
                
                
                90,000(5)
                
                
                90,000(6)
                
                $
                16.98
                
                
                7/1/2015—
                
                
                50,000(7)
                
                $
                23.06
                
                
                1/24/2017
                
                
                20,000(8)
                
                $
                621,800(4)Jonathan
                    Z. Cohen
                
                
                450,000(9)
                
                
                —
                
                $
                16.98
                
                
                7/1/2015—
                
                
                200,000(10)
                
                $
                23.06
                
                
                1/24/2017
                
                
                100,000(11)
                
                $
                3,109,000(4)Richard
                    D. Weber
                
                
                18,750(12)
                
                
                56,250(13)
                
                $
                31.91
                
                
                4/17/201693,438(14)
                
                
                280,314(15)
                
                $
                21.00
                
                
                4/17/2016
                
                
                35,715(16)
                
                $
                1,110,379(4)Freddie
                    M. Kotek
                
                
                45,000(17)
                
                
                45,000(18)
                
                $
                16.98
                
                
                7/1/2015—
                
                
                50,000(19)
                
                $
                23.06
                
                
                1/24/2017
                
                
                20,000(20)
                
                $
                621,800(4)


(1)
              Represents
                  675,000 options to purchase Atlas America stock, granted on 7/1/05
                  in
                  connection with its spin-off from Resource America, which vested
                  immediately. Reflects a 3-for-2 stock split which was effected
                  on May 29,
                  2007.
  (2)
              Represents
                  options to purchase our common units, which vest as follows: 1/24/10
                  -
                  125,000 and 1/24/11 - 375,000.
  (3)
              Represents
                  our phantom units, which vest as follows: 1/24/10 - 50,000 and
                  1/24/17 -
                  150,000.
  (4)
              Based
                  upon closing price of our common units on December 31, 2007 of
                  $31.09.
  (5)
              Represents
                  90,000 options to purchase Atlas America stock, granted on 7/1/05
                  in
                  connection with its spin-off from Resource America. Reflects a
                  3-for-2
                  stock split which was effected on May 29,
                  2007.
  (6)
              Represents
                  options to purchase Atlas America stock, which vest as follows:
                  7/1/08 -
                  45,000 and 7/1/09 - 45,000.
  (7)
              Represents
                  options to purchase our common units, which vest as follows: 1/24/10
                  -
                  12,500 and 1/24/11 - 37,500.
  (8)
              Represents
                  our phantom units, which vest as follows: 1/24/10—5,000 and
                  1/24/11—15,000.
  (9)
              Represents
                  450,000 options to purchase Atlas America stock, granted on 7/1/05
                  in
                  connection with its spin-off from Resource America, which vested
                  immediately. Reflects a 3-for-2 stock split which was effected
                  on May 29,
                  2007.
  115
  (10)
              Represents
                  options to purchase our common units, which vest as follows: 1/24/10
                  -
                  50,000 and 1/24/11 - 150,000.
  (11)
              Represents
                  our phantom units, which vest as follows: 1/24/10—25,000 and
                  1/24/11—75,000.
  (12)
              Represents
                  18,750 options to purchase Atlas America stock. Reflects a 3-for-2
                  stock
                  split which was effected on May 29,
                  2007.
  (13)
              Represents
                  options to purchase Atlas America stock, which vest as follows:
                  4/17/08 -
                  18,750; 4/17/09 - 18,750 and 4/17/10 - 18,750.
  (14)
              Represents
                  93,438 options to purchase our common
                  units.
  (15)
              Represents
                  options to purchase our common units, which vest as follows:
                  4/17/08—93,438; 4/17/09—93,438 and 4/17/10—93,438.
  (16)
              Represents
                  our restricted units, which vest as follows: 4/17/08—11,905;
                  4/17/09—11,905 and 4/17/10—11,905.
  (17)
              Represents
                  45,000 options to purchase Atlas America stock, granted on 7/1/05
                  in
                  connection with its spin-off from Resource America. Reflects a
                  3-for-2
                  stock split which was effected on May 29,
                  2007.
  (18)
              Represents
                  options to purchase Atlas America stock, which vest as follows:
                  7/1/08 -
                  22,500 and 7/1/09 - 22,500.
  (19)
              Represents
                  options to purchase our common units, which vest as follows: 1/24/10
                  -
                  12,500 and 1/24/11 - 37,500.
  (20)
              Represents
                  our phantom units, which vest as follows: 1/24/10—5,000 and
                  1/24/11—15,000.


**2007
      OPTION EXERCISES AND STOCK VESTED TABLE**





**Stock
                Awards****Name**
            
            **Number of Shares**
              **Acquired on Vesting**
            
            **Value Realized**
              **on
                Vesting**
              **($)**Richard
                D. Weber
            
            
            11,904(1)
            
            $
            330,574




(1)
            Represents
                awards under our Plan.




**2007
      DIRECTOR COMPENSATION TABLE**





**Fees
                Earned or**
            
            **Stock
                Awards**
            
            **All
                Other**
            
            **Total****Paid
                in Cash**
            
            **($)**
            
            **Compensation**
            
            **($)****Name**
            
            **($)**
            
            **(1)**
            
            **($)(2)**Walter
                C. Jones
            
            $35,000
            
            $2,883
            
            $735
            
            $38,618Ellen
                F. Warren
            
            $35,000
            
            $2,883
            
            $735
            
            $38,618Bruce
                M. Wolf
            
            $35,000
            
            $2,883
            
            $735
            
            $38,618





(1)
            Represents
                the dollar amount of expense we recognized for financial statement
                reporting purposes with respect to phantom units granted under our
                Plan in
                accordance with FAS 123R. Represents 500 phantom units granted to
                each of
                Messrs. Jones and Wolf and Ms. Warren, which vest 25% on each of
                the first
                through fourth anniversaries of the date of grant. The vesting schedule
                for the phantom units is as follows: 1/24/08 -125; 1/24/09 -125;
                1/24/10
                -125; and 1/24/11 -125.





(2)
            Represents
                payments on DERs of $735 with respect to the phantom units awarded
                under
                our Plan.




116




**Director
      Compensation**





We
      do not
      pay additional remuneration to officers or employees of Atlas America who also
      serve as members of our board of directors. Each non-employee director received
      in fiscal year 2007, an annual retainer of $35,000 in cash and, in January
      2007,
      a grant of 500 phantom units with DERs pursuant to our Plan. In addition, we
      reimburse each non-employee director for out-of-pocket expenses in connection
      with attending meetings of the board or committees. We reimburse Atlas America
      for these expenses and indemnify our directors for actions associated with
      serving as directors to the extent permitted under Delaware law.





**ITEM
      12.**  **SECURITY
      OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT**





The
      following table sets forth the number and percentage of our common units owned
      by beneficial owners of 5% or more of our common units, by our executive
      officers and directors and by all of the executive officers and directors as
      a
      group as of February 25, 2008. The address for each director and executive
      officer and Atlas America is 1550 Coraopolis Heights Road—2nd Floor, Moon
      Township, Pennsylvania 15108.


**Class
                  B**
                **Common
                  Units****Amount
                  and Nature of**
              
              **Percent
                  of****Beneficial
                  Owner**
              
              **Beneficial
                  Ownership**
              
              **Class
                  B Units****Directors**Edward
                  E. Cohen
              
              700,000
              
              (1)
              
              1.15%Jonathan
                  Z. Cohen
              
              300,000
              
              (2)
              
              *Matthew
                  A. Jones
              
              71,100
              
              (3)
              
              *Walter
                  C. Jones
              
              1,000
              
              (4)
              
              *Ellen
                  F. Warren
              
              1,000
              
              (4)
              
              *Richard
                  D. Weber
              
              422,471
              
              (5)
              
              *Bruce
                  M. Wolf
              
              4,000
              
              (4)
              
              ***Non-Director
                  Executive Officers**Nancy
                  J. McGurk
              
              25,000
              
              (6)
              
              *Lisa
                  Washington
              
              13,100
              
              (7)
              
              *Daniel
                C. Herz
              
              40,000
              
              (8)
              
              *All
                  executive officers and directors as a group (10 persons)
              
              1,577,671
              
              
              
              2.60%**Other
                  Owners of More Than 5% of Outstanding Shares**Atlas
                  America, Inc.
              
              29,352,996
              
              (9)
              
              48.35%Cobalt
                  Capital Management, Inc.
              
              3,094,930
              
              (10)
              
              5.10%Lehman
                  Brothers Holdings Inc.
              
              3,940,161
              
              (11)
              
              6.49%




*
            Less
                than 1%(1)
            Includes
                200,000 phantom units and 500,000 unit options granted pursuant to
                our
                Plan on January 24, 2007. Each phantom unit represents the right
                to
                receive, upon vesting, one common unit. Each unit option represents
                the
                right to purchase, upon vesting, one common unit. The phantom units
                and
                unit options vest 25% on the third anniversary of the grant and 75%
                on the
                fourth anniversary of the grant.(2)
            Includes
                100,000 phantom units and 200,000 unit options granted pursuant to
                our
                Plan on January 24, 2007. Each phantom unit represents the right
                to
                receive, upon vesting, one common unit. Each unit option represents
                the
                right to purchase, upon vesting, one common unit. The phantom units
                and
                unit options vest 25% on the third anniversary of the grant and 75%
                on the
                fourth anniversary of the grant.(3)
            Includes
                20,000 phantom units and 50,000 unit options granted pursuant to
                our Plan
                on January 24, 2007. Each phantom unit represents the right to receive,
                upon vesting, one common unit. Each unit option represents the right
                to
                purchase, upon vesting, one common unit. The phantom units and unit
                options vest 25% on the third anniversary of the grant and 75% on
                the
                fourth anniversary of the grant.




117




(4)
            Includes
                875 phantom units granted pursuant to our Plan. Each phantom unit
                represents the right to receive, upon vesting, either one common
                unit or
                its then fair market value in cash. The phantom units vest as follows:
                1/24/09—250; 1/24/10—250; 1/24/11—250; and 1/24/12—125.(5)
            Includes35,715phantom
                units and 280,314 unit options granted pursuant to the terms of Mr.
                Weber’s employment agreement dated April 17, 2006. Each phantom unit
                represents the right to receive, upon vesting, one common unit. Each
                unit
                option represents the right to purchase, upon vesting, one common
                unit.
                The phantom units and the unit options vest as follows: 4/17/08—11,905
                phantom units and 93,438 unit options; 4/17/09—11,905 phantom units and
                93,438 unit options; and 4/17/10—11,905 phantom units and 93,438 unit
                options.(6)
            Includes
                10,000 phantom units and 15,000 unit options granted pursuant to
                our Plan
                on January 24, 2007. Each phantom unit represents the right to receive,
                upon vesting, one common unit. Each unit option represents the right
                to
                purchase, upon vesting, one common unit. The phantom units and unit
                options vest 25% on the third anniversary of the grant and 75% on
                the
                fourth anniversary of the grant.(7)
            Includes
                5,000 phantom units and 8,000 unit options granted pursuant to our
                Plan on
                January 24, 2007. Each phantom unit represents the right to receive,
                upon
                vesting, one common unit. Each unit option represents the right to
                purchase, upon vesting, one common unit. The phantom units and unit
                options vest 25% on the third anniversary of the grant and 75% on
                the
                fourth anniversary of the grant.(8)
            Includes
              10,000 phantom units and 30,000 unit options granted pursuant to our
              Plan on January 24, 2007. Each phantom unit represents the right to
              receive, upon vesting, one common unit. Each unit option represents
              the
              right to purchase, upon vesting, one common unit. The phantom units
              and
              unit options vest 25% on the third anniversary of the grant and 75%
              on the
              fourth anniversary of the grant.(9)
            This
                information is based upon a Schedule 13D/A which was filed with SEC
                on
                February 15, 2008. The address for Atlas America, Inc. is 1550 Coraopolis
                Heights Road—2nd Floor, Moon Township, Pennsylvania 15108.(10)
            This
                information is based upon a Schedule 13G/A which was filed with the
                SEC on
                February 14, 2008. The address for Cobalt Capital Management, Inc.
                is 237
                Park Avenue, Suite 900, New York, NY 10012.(11)
            This
                information is based upon a Schedule 13G/A which was filed with the
                SEC on
                February 13, 2008. The address for Lehman Brothers Holdings, Inc.
                is 745
                Seventh Avenue, New York, NY 10019.





As
      of
      February 25, 2008, 100% of our outstanding Class A units were owned by our
      manager, Atlas Energy Management, Inc. (the “Manager”).




**Equity
      Compensation Plan Information**





The
      following table contains information about our Plan as of December 31,
      2007:





**(a)**
            
            **(b)**
            
            **(c)****Plan
                category**
            
            **Number
                of securities to be issued upon exercise of****equity
                instruments**
            
            **Weighted-average
                exercise price of outstanding**
              **equity
                instruments**
            
            **Number
                of securities remaining available for future issuance under equity
                compensation plans (excluding securities reflected in column
                (a))**Equity
                compensation plans not approved by security holders - phantom and
                restricted units
            
            
            624,665
            
            
            n/aEquity
                compensation plans not approved by security holders - unit
                options
            
            
            1,895,052
            
            $
            24.09Equity
                compensation plans not approved by security holders -
                Total
            
            
            2,519,717
            
            
            
            
            
            1,210,379




The
      following table contains information about the Atlas Plan as of December 31,
      2007:





**(a)**
            
            **(b)**
            
            **(c)****Plan
                category**
            
            **Number
                of securities to be issued upon exercise of****equity
                instruments**
            
            **Weighted-average
                exercise price of outstanding**
              **equity
                instruments**
            
            **Number
                of securities remaining available for future issuance under equity
                compensation plans (excluding securities reflected in column
                (a))**Equity
                compensation plans approved by
              security
                holders - restricted units
            
            
            4,263
            
            
            n/aEquity
                compensation plans approved by
              security
                holders - options
            
            
            1,810,254
            
            $
            18.15Equity
                compensation plans approved by
              security
                holders - Total
            
            
            1,814,517
            
            
            
            
            
            1,112,565




118




The
      following table contains information about the AHD Plan as of December 31,
      2007:





**(a)**
            
            **(b)**
            
            **(c)****Plan
                category**
            
            **Number
                of securities to be issued upon exercise of**
              **equity
                instruments**
            
            **Weighted-average
                exercise price of outstanding**
              **equity
                instruments**
            
            **Number
                of securities remaining available for future issuance under equity
                compensation plans (excluding securities reflected in column
                (a))**Equity
                compensation plans approved by
              security
                holders - phantom units
            
            
            220,825
            
            
            n/aEquity
                compensation plans approved by
              security
                holders - unit options
            
            
            1,215,000
            
            $
            22.56Equity
                compensation plans approved by
              security
                holders - Total
            
            
            1,435,825
            
            
            
            
            
            663,800





The
      following table contains information about the APL Plan as of December 31,
      2007:





**(a)**
            
            **(b)**
            
            **(c)****Plan
                category**
            
            
            **Number
                of securities to be issued upon exercise of**
              **equity
                instruments**
            
            
            **Weighted-average
                exercise price of outstanding**
              **equity
                instruments**
            
            
            **Number
                of securities remaining available for future issuance under equity
                compensation plans (excluding securities reflected in column
                (a)**
            **)**Equity
                compensation plans approved by
              security
                holders - phantom units
            
            
            129,746
            
            
            n/a
            
            
            208,055




**ITEM
      13.**  **CERTAIN
      RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR**  **INDEPENDENCE**





Anthem
      Securities, our wholly-owned subsidiary is a registered broker-dealer which
      serves as the dealer-manager of investment programs sponsored by Resource
      America’s real estate and equipment finance segments **.** Salaries
      of the personnel performing services for Anthem are paid by Resource America
      and
      Anthem reimburses Resource America for the allocable costs of such personnel.
      In
      addition, Resource America agreed to cover some of the operating costs for
      Anthem’s office of supervisory jurisdiction, principally licensing fees and
      costs. In fiscal 2007, Resource America paid $5.2 million toward such operating
      costs of Anthem and Anthem reimbursed it $3.2 million.





Our
      board
      of directors has determined that Messrs. W. Jones and Wolf, and Ms. Warren
      each
      satisfy the requirement for independence set out in Section 303A.02 of the
      rules
      of the New York Stock Exchange (the “NYSE”) including those set forth in Rule
      10A-3(b)(1) of the Securities Exchange Act, and meet the definition of an
      independent member set forth in our Governance Guidelines. In making theses
      determinations, the board of directors reviewed information from each of these
      non-management directors concerning all their respective relationships with
      us
      and analyzed the materiality of those relationships.




119





**ITEM
      14.**  **PRINCIPAL
      ACCOUNTING FEES AND SERVICES**





For
      the
      years ended December 31, 2007 and 2006, Grant Thornton LLP’s accounting fees and
      services were as follows (in thousands) :





**2007**
            
            **2006**(1)Audit
                fees(2)
            
            $
            1,180
            
            $
            100Audit-related
                fees(3)
            
            
            372
            
            
            —Tax
                fees
            
            
            —
            
            
            —All
                other fees
            
            
            —
            
            
            —Total
                accounting fees and services
            
            $
            1,552
            
            $
            100





(1)
            Prior
                to our initial public offering on December 18, 2006, all Grant Thornton
                audit, audit-related and tax fees were billed to, paid by, and reported
                by
                Atlas America, Inc.


(2)
            Audit
                fees include professional services rendered for the annual audit
                of our
                financial statements and the reviews of the financial statements
                included
                in our quarterly reports of Form
                10-Q.


(3)
            Represents
                fees related to the historical audits of DTE Gas & Oil
                Company.





**Audit
      Committee Pre-Approval Policies and Procedures**





Our
      audit
      committee, on at least an annual basis, reviews audit and non-audit services
      performed by Grant Thornton, LLP as well as the fees charged by Grant Thornton,
      LLP for such services. Our policy is that all audit and non-audit services
      must
      be pre-approved by the audit committee. All of such services and fees were
      pre-approved by Atlas America’s audit committee before December 18, 2006 and by
      our audit committee after that date.




120





**PART
      IV**





**ITEM
      15.**  **EXHIBITS,
      FINANCIAL STATEMENT SCHEDULES**





**(a)**  **(1)**  **Financial
      Statements**





Report
                of Independent Registered Public Accounting FirmConsolidated
                Balance Sheets at December 31, 2007 and 2006Combined
                and Consolidated Statements of Income for the years ended December
                31,
                2007 and 2006, three months ended December 31, 2005 and year ended
                September 30, 2005Combined
                and Consolidated Statements of Comprehensive Income for the years
                ended
                December 31, 2007 and 2006, three months ended December 31, 2005
                and year
                ended September 30, 2005Combined
                and Consolidated Statements of Equity for the years ended December
                31,
                2007 and 2006, three months ended December 31, 2005 and year ended
                September 30, 2005Combined
                and Consolidated Statements of Cash Flows for the years ended December
                31,
                2007 and 2006, three months ended December 31, 2005 and year ended
                September 30, 2005Notes
                to Combined and Consolidated Financial Statements − December 31,
                2007





**(2)**  **Financial
      Statement Schedules**





**(3)**  **Exhibits:**





Exhibit
              No.
            
            Description2.1
            
            Purchase
                Agreement dated as of May 18, 2007 among MCN Energy Enterprises,
                Inc., DTE Energy Company, ATN Michigan, Inc. and Atlas Energy Resources,
                LLC13.1
            
            Certificate
                of Formation of Atlas Energy Resources, LLC23.2
            
            Amended
                and Restated Limited Liability Company Agreement of Atlas Energy
                Resources, LLC33.2(a)
            
            Amendment
                No. 1 to Amended and Restated Operating Agreement of Atlas Energy
                Resources, LLC44.1
            
            Form
                of common unit certificate (included as Exhibit A to the Amended
                and
                Restated Limited Liability Company Agreement of Atlas Energy Resources,
                LLC)310.1
            
            Revolving
                Credit Agreement, dated as of June 29, 2007, among Atlas Energy Operating
                Company, LLC, its subsidiaries, J.P. Morgan Chase Bank, N.A., as
                Administrative Agent and the other lenders signatory thereto410.1(a)
            
            First
                Amendment to Credit Agreement, dated as of October 25,
                2007510.2
            
            Employment
                Agreement, dated May 18, 2007, by and between Atlas America, Inc.
                and
                Richard L. Redmond Jr.410.3
            
            Voting
                Agreement dated as of June 29, 2007 between Atlas America, Inc. and
                Atlas
                Energy Management, Inc.410.4
            
            Registration
                Rights Agreement dated as of June 29, 2007 by and among Atlas Energy
                Resources, LLC ad the purchasers named therein410.5
            
            Class
                D and Common Unit Purchase Agreement1




121




10.6
            
            Atlas
                Energy Resources Long-Term Incentive Plan610.6(a)
            
            Form
                of Unit Award Agreement710.6(b)
            
            Form
                of Non-Employee Director Grant Agreement710.6(c)
            
            Form
                of Phantom Unit Grant Agreement710.6(d)
            
            Form
                of Option Grant Agreement710.7
            
            Third
                Amendment to Base Gas Purchase Agreement814.1
            
            Pre-Clearance
                Procedures Memorandum, as amended on October 23, 2007521.1
            
            Subsidiaries
                of Atlas Energy Resources, LLC23.1
            
            Consent
                of Grant Thornton LLP31.1
            
            Rule
                13(a)-14(a)/15d-14(a) Certification31.2
            
            Rule
                13(a)-14(a)/15d-14(a) Certification32.1
            
            Section
                1350 Certification32.2
            
            Section
                1350 Certification




1
      Previously filed as an exhibit to our Form 8-K filed May 21, 2007.


2 Previously filed as an exhibit to our registration statement on Form S-1
      (Registration No. 333-136094).


3 Previously filed as an exhibit to our Form 8-K filed December 22,
      2006.


4 Previously filed as an exhibit to our Form 8-K filed June 29, 2007.


5 Previously filed as an exhibit to our Form 8-K filed October 26,
      2007.


6 Previously filed as an exhibit to our Form 8-K filed December 18,
      2006.


7 Previously filed as an exhibit to our Form 8-K filed January 22,
      2007.


8 Previously filed as an exhibit to our Form 8-K filed January 10,
      2007.




122





**SIGNATURES**





Pursuant
      to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
      1934, the registrant has duly caused this report to be signed on its behalf
      by
      the undersigned, thereunto duly authorized.





**ATLAS
                ENERGY RESOURCES, LLC.****(Registrant)**Date: March
                6, 2008
            By:*/s/
                Edward E. Cohen*Edward
                E. CohenChairman
                and Chief Executive Officer








Pursuant
      to the requirements of the Securities Exchange Act of 1934, this report has
      been
      signed below by the following persons on behalf of the registrant in the
      capacities and on the dates indicated.





*/s/
                Edward E. Cohen*
            Chairman
                and Chief Executive Officer
            March
                6, 2008Edward
                E. Cohen*/s/
                Richard D. Weber*
            President
                and Chief Operating Officer
            March
                  6, 2008Richard
                D. Weber*/s/
                Matthew A. Jones*
            Chief
                Financial Officer
            March
                  6, 2008Matthew
                A. Jones*/s/
                Nancy J. McGurk*
            Chief
                Accounting Officer
            March
                  6, 2008Nancy
                J. McGurk*/s/
                Jonathan Z. Cohen*
            Director
            March
                  6, 2008Jonathan
                Z. Cohen*/s/
                Walter C. Jones*
            Director
            March
                  6, 2008Walter
                C. Jones*/s/
                Ellen F. Warren*
            Director
            March
                  6, 2008Ellen
                F. Warren*/s/
                Bruce M. Wolf*
            Director
            March
                  6, 2008Bruce
                M. Wolf




123