**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, 2006




**OR**




**o**
            **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.)**311
                Rouser 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
o  No
x





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
o  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 o  No
x





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. o





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 o
            Accelerated
                filer o
            Non-accelerated
                filer x




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





The
      registrant completed its initial public offering in December 2006 and,
      therefore, there was no aggregate market value of common units as of June 30,
      2006. The aggregate market value of common units held by non-affiliates of
      the
      registrant on March 1, 2007 was approximately $176.5 million.





DOCUMENTS
      INCORPORATED BY REFERENCE: None









[THIS
      PAGE INTENTIONALLY LEFT BLANK]





Page
          2


**ATLAS
      ENERGY RESOURCES, LLC AND SUBSIDIARIES**


**INDEX
      TO ANNUAL REPORT**


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





Page**PART
                I**
            Item
                1:
            Business
            4Item
                1A:
            Risk
                Factors
            19Item
                1B:
            Unresolved
                Staff Comments
            33Item
                2:
            Properties
            33Item
                3:
            Legal
                Proceedings
            38Item
                4:
            Submission
                of Matters to a Vote of Security Holders
            38**PART
                II**
            Item
                5:
            Market
                for Registrant's Common Equity and Related Shareholder Mattersand Issuer Purchases of Equity Securities
            39Item
                6:
            Selected
                Financial Data
            40Item
                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
            64Item
                9:
            Changes
                in and Disagreements with Accountants on Accounting andFinancial
                Disclosure
            93Item
                9A:
            Controls
                and Procedures
            93Item
                9B:
            Other
                Information
            93**PART
                III**
            Item
                10:
            Directors
                and Executive Officers of the Registrant
            93Item
                11:
            Executive
                Compensation
            97Item
                12:
            Security
                Ownership of Certain Beneficial Owners and Management
            106Item
                13:
            Certain
                Relationships and Related Transactions
            107Item
                14:
            Principal
                Accounting Fees and Services
            108**PART
                IV**
            Item
                15:
            Exhibits
                and Financial Statement Schedules
            109**SIGNATURES**
            111






Page
          3




**PART
      I**





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





*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 years ended September 30, 2004 and 2005, the three month
      transition period ended December 31, 2005, and the year ended December 31,
      2006.*





**General**





We
      are a
      limited liability company focused on the development and production of natural
      gas and, to a lesser extent, oil in the Appalachian Basin region of the United
      States, principally in western New York, eastern Ohio, Western Pennsylvania
      and
      Tennessee. 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,
      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. ** In
      December 2006, we completed our initial public offering of 7,273,750 common
      units 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 our parent, Atlas America in the form of a non-taxable dividend
      and to repay debt.





We
      are
      managed by Atlas Energy Management, Inc., a wholly-owned subsidiary of Atlas
      America. Through our manager, Atlas America personnel are responsible for
      managing our assets and capital raising.





As
      of
      December 31, 2006, our principal assets consisted of:





·
            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;






Page
          4






·
            either
                directly or through our investment partnerships, interests in 7,252
                gross
                producing gas and oil wells, including overriding royalty interests
                in 634
                gross producing gas and oil wells;




·
            approximately
                601,400 gross (547,700 net) acres, primarily in the Appalachian Basin,
                over half of which, or approximately 336,700 gross (323,300 net)
                acres,
                are undeveloped; and




·
            an
                interest in a joint venture that gives us the right to drill up to
                200
                additional net wells before December 31, 2007 on approximately 212,000
                acres in Tennessee.





At
      December 31, 2006, we had proved reserves of 180.9 billion cubic feet of natural
      gas equivalents, or Bcfe, including the reserves net to our equity interest
      in
      our investment partnerships and our direct interests in producing
      wells.





For
      the
      year ended December 31, 2006, we produced 27.0 million cubic feet of natural
      gas
      equivalents per day, or Mmcfe/d, which includes our proportionate share of
      production from our investment partnerships as well as our direct interests
      in
      producing wells. This resulted in an average reserve life of approximately
      18
      years based on our proved reserves at December 31, 2006.





As
      of
      December 31, 2006, we had identified over 500 proved undeveloped drilling
      locations and approximately 2,600 additional potential drilling locations on
      our
      acreage and our Tennessee joint venture acreage.





We
      fund
      the drilling of natural gas and oil wells on our acreage by sponsoring and
      managing tax-advantaged investment partnerships. 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.





We
      derive
      substantially all of our revenues from our equity interest in the oil and gas
      produced by the investment partnerships as well as the fees paid by the
      partnerships to us for acting as the managing general partner as
      follows:





·
            **Gas
                and oil production.**We
                receive an interest in each investment partnership proportionate
                to the
                value of our coinvestment in it and the value of the acreage we contribute
                to it, typically 27% to 33% of the overall capitalization of a particular
                partnership. We also receive an incremental interest in each partnership,
                typically 7%, for which we do not make any additional capital
                contribution. Consequently, our equity interest in the reserves and
                production of each partnership is typically between 34% and
                40%.




·
            **Partnership
                management.**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**.
                Each 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.
                In
                addition, for each well drilled by an investment partnership, we
                receive a
                fixed administration fee of approximately
                $15,000.




·
            **Well
                services.**Each
                partnership pays us a monthly per well operating fee, currently $100
                to
                $457, 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.**Each partnership pays us a gathering fee for gathering services.
                Historically, this fee was typically insufficient to cover all of
                the
                gathering fees due to Atlas Pipeline Partners, L.P., under Atlas
                America’s
                master natural gas gathering agreement with it. After the closing
                of our
                initial public offering, 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.






Page
          5




**Recent
      Developments**





During
      the fourth quarter of 2006 and first quarter of 2007, we and one of our
      investment partnerships drilled three wells to multiple pay zones, including
      the
      Marcellus Shale of Southwest Pennsylvania. The Marcellus Shale is a black,
      organic rich shale formation located at depths between 7,000 and 8,500 feet
      and
      ranges in thickness from 100 to 150 feet on our acreage in Fayette, Westmoreland
      and Greene Counties. We currently hold approximately 157,500 acres of
      prospective Marcellus acreage in these counties. Most of this acreage is held
      by
      production, meaning that it is covered by a continuing lease due to production
      from the property.





**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, 2006, the average premium over NYMEX for natural gas delivered
      to
      our primary delivery points in the Appalachian Basin was $0.36 per million
      British thermal unit, or MMBtu. In addition, most of our natural gas production
      has a high Btu content, resulting in an additional premium to NYMEX natural
      gas
      prices.





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**





As
      of
      December 31, 2006, we owned interests in 7,252 gross wells, principally in
      the
      Appalachian Basin, of which we operated 6,155. In the year ended December 31,
      2006, we drilled 715 gross wells, 99% of which were successful in producing
      natural gas in commercial quantities.





In
      September 2004, we expanded operations into Tennessee through a joint venture
      with Knox Energy, LLC that gave us an exclusive right to drill up to 300 net
      wells through June 30, 2007 on approximately 212,000 acres owned by Knox Energy.
      This agreement was amended and extended, giving us the right to drill an
      additional 200 net wells from January 1, 2007 to December 31, 2007, provided
      that we commenced the drilling of a minimum of 75 wells before September 30,
      2007. As of December 31, 2006, we had drilled 141 net wells under this agreement
      and we have identified over 500 proved undeveloped drilling locations and
      approximately 2,600 additional potential drilling locations on our acreage
      and
      the Tennessee joint venture acreage.





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





**Partnership
      Management**





We
      generally fund our drilling activities 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 $218.5 million in the year ended December 31, 2006,
      and our investment partnerships invested $283.7 million in drilling and
      completing wells, of which we contributed $65.2 million.





Page
          6


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
      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, and 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.





**Natural
      Gas Sales**





We
      have a
      natural gas supply agreement with Hess Corporation which is valid through March
      31, 2009. Subject to certain exceptions, Hess 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 within 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.





Our
      agreement with Hess has the following exclusions:





·
            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.






Page
          7


Based
      on
      the most recent monthly production data available to us as of December 31,
      2006,
      we anticipate that we and our affiliates, including our investment partnerships,
      will sell approximately 30% of our natural gas production during the twelve
      months ending December 31, 2007 under the Hess agreement. The agreement also
      permits us to implement physical hedge transactions through Hess, as described
      below under “Business—Natural Gas Hedging.” The Hess agreement established an
      indexed price formula for each of the delivery points during an initial period
      of one to two years, and requires the parties to negotiate a new pricing
      arrangement at each delivery point for subsequent periods. 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 does not match this price, then we may sell the
      natural gas to the third-party. This process is repeated at the end of each
      contract period, which is usually one year. 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.





We
      expect
      that natural gas produced from wells drilled in areas of the Appalachian Basin
      other than 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.





**Crude
      Oil Sales**





Crude
      oil
      produced from our wells flows directly into storage tanks where it is picked
      up
      by oil companies, a common carrier, or pipeline companies acting for the oil
      companies which are purchasing the crude oil. We anticipate selling any oil
      produced by our wells to regional oil refining companies at the prevailing
      spot
      market price for Appalachian crude oil in spot sales.





**Natural
      Gas Hedging**





Pricing
      for natural gas and oil production has been volatile and unpredictable for
      many
      years. To limit our exposure to changing natural gas prices, we use financial
      and physical hedges for a portion of our natural gas production. Through our
      hedges, we seek to provide a measure of stability in the volatile environment
      of
      natural gas prices. 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 36 months in the future. To assure that the financial
      instruments will be used solely for hedging price risks and not for speculative
      purposes, our manager has 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, 2006, we had financial hedges and physical hedges
      in place for approximately 79% of our expected production for the twelve months
      ending December 31, 2007.





Hess
      and
      other third-party marketers to which we sell gas, such as Colonial Energy and
      UGI Energy Services, also use NYMEX-based financial instruments to hedge their
      pricing exposure and make price hedging opportunities available to us. We enter
      into physical hedge transactions which 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 Hess, Colonial Energy, UGI Energy Services, and any other
      third-party marketers for certain volumes of natural gas sold under these sales
      agreements may be significantly different from the underlying monthly spot
      market value. Fixed prices are defined as the price we have established with
      the
      related purchaser and are not subject to change in the future. For a description
      of our financial hedges, please read Item 7A: “Quantitative and Qualitative
      Disclosures About Market Risk” in this report.




Page
          8





**Natural
      Gas Gathering**





We
      conduct our natural gas transportation and processing operations through Atlas
      America’s affiliate, Atlas Pipeline Partners, L.P. (NYSE: APL). Atlas Pipeline
      owns approximately 1,600 miles of gathering systems located in eastern Ohio,
      western New York and western Pennsylvania serving approximately 5,865
      wells.





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 extend 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:




Page
          9





·
            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.





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. See Item 1A: Risk
      Factors. 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
                us and our investment partnerships, 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.






Page
          10


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





**Contribution
      Agreement**





*Contribution
      of assets by Atlas America.* The
      substantial majority of the 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 until December
      2007 against certain potential environmental liabilities associated with the
      operation of the assets and occurring before the closing date of the offering
      and against claims for covered environmental liabilities made before the fourth
      anniversary of the closing of the offering. The obligation of the indemnitors
      will not exceed $25.0 million, and they will not have any indemnification
      obligation until our losses exceed $500,000 in the aggregate, and then only
      to
      the extent such aggregate losses exceed $500,000. Additionally, 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.





*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.





Page
          11


Atlas
      Energy Management, its stockholders, directors, officers, employees and
      affiliates will not be liable to us, our directors or unitholders for acts
      or
      omissions performed in good faith and in accordance with and pursuant to the
      management agreement, except by reason 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 and 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 unitholders.





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.





**Operating
      Segment Information**





For
      financial information concerning our operating segments, including revenues
      from
      external customers, profit (loss) and total assets, see Note 9 to
      our Combined and Consolidated Financial Statements.





**Availability
      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 the year
      ended December 31, 2006, we faced no shortage of these goods and services.
      We
      cannot predict the duration of the current supply and demand situation for
      drilling rigs and other goods and services with any certainty due to numerous
      factors affecting the energy industry and the demand for natural gas and
      oil.





**Major
      Customers**





Our
      natural gas is sold under contract to various purchasers. During the year ended
      December 31, 2006, we did not have any customers that accounted for 10% or
      more
      of our revenues.





**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 oil and natural
      gas.




Page
          12





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 Item 1A:
“Risk
      Factors”. During the year ended December 31, 2006 we did not experience problems
      in selling our natural gas and oil, although prices have varied significantly
      during and after those periods.





**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.
      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 due to the
      fact that we have typically received the majority of funds from our investment
      partnerships during the fourth calendar quarter. Generally 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.





**Environmental
      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;




·
            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.






Page
          13





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 on the whole
      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 impact our properties or operations.
      For
      the year ended December 31, 2006, we did not incur any material capital
      expenditures for installation of remediation or pollution control equipment
      at
      any of our facilities. As of the date of this report, we are not aware of any
      environmental issues or claims that will require material capital expenditures
      during 2007 or that will otherwise have a material impact on our financial
      position or results of operations.





*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 impact 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 United States Environmental
      Protection Agency, or 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.




Page
          14


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, which
      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 impact 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
      impact our business.





Page
          15


**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 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.





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.




Page
          16





*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, Tennessee currently imposes a 3%
      severance tax on natural gas and oil production and Ohio imposes a severance
      tax
      of $0.025 per Mcf of natural gas and $0.10 per barrel, or 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.





**Credit
      Facility**





Simultaneously
      with the closing of our initial public offering, we entered into a $250 million
      senior secured credit facility with Wachovia Bank, National Association, as
      administrative agent, Wachovia Capital Markets LLC, 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 initial borrowing base is $155
      million. The borrowing base will be subject to redetermination on March 15,
      2007
      and on a semi-annual basis thereafter. The credit facility will mature on
      December 18, 2011.





Our
      obligations under the credit facility are secured by mortgages on our natural
      gas and oil properties as well as a pledge of all of our ownership interests
      in
      our operating subsidiaries, other than Anthem Securities, Inc. We are required
      to maintain mortgages on properties representing at least 80% of our natural
      gas
      and oil properties. Additionally, the obligations under the credit facility
      are
      guaranteed by all of our existing operating subsidiaries and by any future
      subsidiaries, other than Anthem Securities.





Borrowings
      under the new credit facility are available for development, exploitation and
      acquisition of natural gas and oil properties, working capital and general
      corporate purposes.





At
      our
      election, interest will be determined by reference to:





·
            the
                London interbank offered rate, or LIBOR, plus an applicable margin
                between
                1.00% and 1.75% per annum, depending on our usage of the facility;
                or




·
            the
                higher of (i) the federal funds rate plus 0.50% or (ii) the Wachovia
                prime
                rate, plus, in each case, an applicable margin between 0.00% and
                0.75% per
                annum, depending on our usage of the
                facility.





Interest
      is generally payable quarterly for domestic bank rate loans and at the end
      of
      each applicable interest period for LIBOR loans.





The
      credit facility contains covenants that, among other things, limit our ability
      to:





·
            incur
                indebtedness;




·
            grant
                certain liens;




·
            enter
                into certain leases;






Page
          17






·
            make
                certain loans, acquisitions, capital expenditures and
                investments;




·
            enter
                into hedging arrangements that exceed 85% of our proved
                reserves;




·
            make
                any change to the character of our business or the business of the
                investment partnerships;




·
            merge
                or consolidate; or




·
            engage
                in certain asset dispositions, including a sale of all or substantially
                all of our assets.





The
      credit facility requires us to maintain a current ratio (defined as the ratio
      of
      current assets to current liabilities excluding assets and liabilities under
      hedging agreements, deferred profit on advance payments received for the
      drilling and completion of oil and gas wells, and current maturity of any amount
      due under the credit facility, plus any unused amount under the borrowing base)
      of not less than 1.0 to 1.0; a funded debt to EBITDA ratio of not more than
      3.5
      to 1.0; and a minimum interest coverage ratio (defined as our EBITDA divided
      by
      our interest expense) of not less than 2.5 to 1.0. The credit facility defines
      EBITDA for any period of four quarters as the sum of consolidated net income
      for
      the period plus interest, income taxes, depreciation, depletion and
      amortization.





We
      have
      the ability to pay distributions to unitholders as long as there has not been
      an
      event of default and an event of default would not result from the
      distribution.





If
      an
      event of default exists under the credit facility, the lenders will be able
      to
      accelerate the maturity of the credit facility and exercise other customary
      rights and remedies. Each of the following is an event of default:





·
            failure
                to pay any principal when due or any interest, fees or other amounts
                in
                the credit facility;




·
            failure
                to pay any principal or interest on any of our other debt aggregating
                $2.5
                million or more;




·
            a
                representation, warranty or certification made under the loan documents
                or
                in any certificate furnished thereunder is false or misleading as
                of the
                time made or furnished in any material
                respect;




·
            failure
                to perform under any obligation set forth in the credit facility,
                subject
                to a grace period;




·
            an
                event having a material adverse effect on us, any of the guarantors
                or the
                collateral used to secure
                indebtedness;




·
            admission
                in writing the inability to, or being generally unable to, pay debts
                as
                they become due;




·
            bankruptcy
                or insolvency events;




·
            commencement
                of a proceeding or case in any court of competent jurisdiction, without
                application or consent, involving:




·
            liquidation,
                reorganization, dissolution or winding-up;
                or




·
            the
                appointment of a trustee, receiver, custodian, liquidator or the
                like;




·
            the
                entry of, and failure to pay, one or more judgments in excess of
                $2.5
                million;




·
            the
                loan documents cease to be in full force and effect or cease to create
                a
                valid, binding and enforceable
                lien;






Page
          18






·
            a
                change of control, generally defined as (i) a group or person acquiring
                35% or more of our outstanding voting units (other than Atlas America
                and
                its affiliates), (ii) our failure to own 85% or more of the outstanding
                shares of voting capital stock of any of our subsidiaries that is
                a
                guarantor under the credit facility, (iii) our failure to own 100%
                of
                Atlas Energy Operating Company or (iv) the failure of Atlas America
                or any
                of its wholly-owned subsidiaries to own at least 51% of the equity
                of our
                manager; and




·
            concealment
                of property with the intent to hinder, delay or defraud any lender
                with
                respect to their rights to such
                property.





**Employees**





We
      do not
      have any employees. To carry out our operations, our manager and its affiliates
      employed approximately 370 persons as of December 31, 2006.





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





Statements
      made by us in written or oral form to various persons, including statements
      made
      in filings with the SEC that are not strictly historical facts, are
“forward-looking” statements that are based on current expectations about our
      business and assumptions made by management. These statements are subject to
      risks and uncertainties that exist in our operations and business environment
      that could result in actual outcomes and results that are materially different
      than predicted. The following includes some, but not all, of those factors
      or
      uncertainties:





*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
      unitholders 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;






Page
          19






·
            fluctuations
                in our working capital needs;




·
            timing
                and collectibility of receivables;




·
            restrictions
                on distributions imposed by
                lenders;




·
            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
      unitholders 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 and we may have to lower our distribution or may not be able to pay
      distributions at all.* 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.






Page
          20


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, 2006, the NYMEX Henry Hub natural gas index price ranged from a high of
      $11.43 per MMBtu to a low of $4.20 per MMBtu, and West Texas Intermediate oil
      prices ranged from a high of $75.92 per Bbl to a low of $56.93 per
      Bbl.





At
      December 31, 2006, we owned interests in 7,252 gross wells. Producers with
      higher rates of production than ours are less sensitive to declining commodity
      prices due to the relatively fixed nature of well operating costs. Lower natural
      gas and oil prices may not only decrease our revenues, but also reduce the
      amount of natural gas and oil that we can produce economically, which would
      also
      decrease our revenues and cause us to shut in, and eventually plug and abandon,
      uneconomic wells.





*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
      distributions to our unitholders.* 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, 2006 reserve report, our average annual decline rate for proved
      developed producing reserves is approximately 12% during the first five years,
      approximately 7% in the next five years and less than 6% thereafter. Because
      total estimated proved reserves include proved undeveloped reserves at December
      31, 2006, 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, principally
      our sponsored investment partnerships, all of which are subject to the risks
      discussed elsewhere in this section.





*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. 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;






Page
          21






·
            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. Additionally, 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. Additionally, 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. Any of these negative effects on our
      reserves or PV-10 may decrease the value of our common units.





*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 unitholders 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. For the year ending December 31, 2007, we estimate these
      expenditures to be approximately $35.0 million. 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:





·
            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 unitholders. 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 unitholders
      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.




Page
          22





*We
      are required to make substantial capital expenditures to increase our asset
      base. If we are unable to obtain needed capital or financing on satisfactory
      terms, our ability to make cash distributions may be diminished.* The
      natural gas and oil industry is capital intensive. We intend to finance our
      future capital expenditures with capital raised through our sponsored investment
      partnerships, cash flow from operations and bank borrowings. In particular,
      our
      forecast of cash available for distribution for the year ending December 31,
      2007 assumes that we will raise $270.0 million from third parties through our
      investment partnerships. This amount of capital is significantly more than
      the
      $218.5 million we raised during the year ended December 31, 2006 and
      significantly more than the average annual amount of $152.0 million we raised
      for the three years ended September 30, 2006. If we are unable to obtain
      sufficient capital funds on satisfactory terms, we may be unable to increase
      or
      maintain our inventory of properties and reserve base, or be forced to curtail
      drilling or other activities. This would result in a decline in our revenues
      and
      our ability to increase cash distributions may be diminished. If we do not
      make
      sufficient or effective expansion capital expenditures, including with funds
      from third-party sources, we will be unable to expand our business operations
      and will be unable to raise the level of our future cash
      distributions.





*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. A recent change to federal tax law that
      may
      affect us is the Jobs and Growth Tax Relief Reconciliation Act of 2003, which
      reduced the maximum federal income tax rate on long-term capital gains and
      qualifying dividends to 15% through 2008. These changes may make investment
      in
      our investment partnerships relatively less attractive than investments in
      assets likely to yield capital gains or qualifying dividends.





*Our
      credit facility has substantial restrictions and financial covenants. A default
      under these provisions could cause all of our debt to be immediately due and
      restrict our payment of distributions to our unitholders.* Our
      revolving credit facility restricts our ability to obtain additional financing,
      make investments, lease equipment, sell assets and engage in business
      combinations. We are also required to comply with specified financial covenants
      and ratios. Our ability to comply with these restrictions and covenants in
      the
      future is uncertain and will be affected by the levels of cash flow from our
      operations and events or circumstances beyond our control. Our failure to comply
      with any of the restrictions and covenants under the credit facility could
      result in a default, which could cause our existing indebtedness to be
      immediately due and restrict our payment of distributions to our
      unitholders.





*Our
      future debt levels may limit our flexibility to obtain additional financing
      and
      pursue other business opportunities.* We
      have
      the ability to borrow $155 million under our credit facility, subject to
      borrowing base limitations in the credit agreement. Our future indebtedness
      could have important consequences to us, including:





·
            our
                ability to obtain additional financing, if necessary, for working
                capital,
                capital expenditures, acquisitions or other purposes may be impaired
                or
                such financing may not be available on favorable
                terms;




·
            covenants
                contained in our credit arrangements require us to meet financial
                tests
                that may affect our flexibility in planning for and reacting to changes
                in
                our business, including possible acquisition
                opportunities;




·
            we
                will need a substantial portion of our cash flow to make principal
                and
                interest payments on our indebtedness, reducing the funds that would
                otherwise be available for operations, future business opportunities
                and
                distributions to unitholders; and




·
            our
                debt level will make us more vulnerable than our competitors with
                less
                debt to competitive pressures or a downturn in our business or the
                economy
                generally.






Page
          23


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.





*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. Accordingly, the amount of
      development activities we undertake 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 $107.7 million in fiscal 2004, $148.7 million
      in fiscal 2005, and $52.2 million in the three months ended December 31, 2005
      and $218.5 million in calendar 2006. Additionally, our forecast of cash
      available for distribution for the twelve month period ending December 31,
      2007
      assumes that we will raise $270.0 million from third parties through our
      investment partnerships. 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.





*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.





Page
          24




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 oil and natural gas. 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.





*Our
      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 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 a master gas gathering agreement 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, 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, 2006, this excess amount
      was
      approximately $30.3 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 distributions to unitholders.





*Shortages
      of drilling rigs, equipment and crews could delay our operations and reduce
      our
      cash available for distribution.* 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 oil and natural gas 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 and cash available for distribution.





*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;




·
            the
                federal Resource Conservation and Recovery Act, or RCRA, and comparable
                state laws that impose requirements for the handling and disposal
                of waste
                from our facilities; and






Page
          25






·
            the
                Comprehensive Environmental Response, Compensation and Liability
                Act of
                1980, or CERCLA, also known as “Superfund,” 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. Please read “Business — Environmental Matters and
      Regulation.”





*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 and, therefore, may impact our
      ability to pay distributions.* 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, 2006, we had identified approximately 500 proved undeveloped
      drilling locations and approximately 2,600 additional 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, Wright and Company, Inc. has not assigned any proved reserves to
      the
      over 2,600 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. Our forecast of
      estimated cash available for distribution to our unitholders is based on an
      assumption that we will drill 888 gross wells on behalf of investment
      partnerships during the year ending December 31, 2007, which number of wells
      exceeds the total number of currently identified proved undeveloped well
      locations. In the event that we are unable to continue to identify drilling
      locations that we believe will provide us attractive development opportunities
      in sufficient quantities to support our growth plans, we may be required to
      reduce the amount of funds raised through our investment partnerships, which
      in
      turn would result in a reduction in the fee-based revenue that we would
      otherwise realize and therefore would negatively impact our ability to make
      cash
      distributions to our unitholders at the initial quarterly distribution
      rate.





Page
          26


*Some
      of our undeveloped leasehold acreage is subject to leases that may expire in
      the
      near future.* Leases
      covering approximately 9,000 of our 547,700 net acres, or 2%, are scheduled
      to
      expire on or before December 31, 2007. If we are unable to renew these leases,
      or any leases scheduled for expiration beyond December 31, 2007, 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
      distributions.





*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. Additionally, our
      drilling and producing operations may be curtailed, delayed or canceled as
      a
      result of other factors, including:





·
            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 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 and impair
      our
      ability to make distributions to our unitholders.





Page
          27


*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 impact 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.
      Additionally, 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 36 months 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.





*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. Furthermore, investor partners in some of
      our investment partnerships have the right to present their interests for
      purchase by us, as managing general partner, up to 5% to 10% of the total
      limited partner interests in any calendar year.





*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 unitholders 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.





Page
          28


*If
      we
      fail to develop or maintain an effective system of internal controls, we may
      not
      be able to accurately report our financial results or prevent fraud. As a
      result, current and potential unitholders could lose confidence in our financial
      reporting, which would harm our business and the trading price of our common
      units.* Effective
      internal controls are necessary for us to provide reliable financial reports,
      prevent fraud and operate successfully as a public company. If we cannot provide
      reliable financial reports or prevent fraud, our reputation and operating
      results would be harmed. We cannot be certain that our efforts to develop and
      maintain our internal controls will be successful, that we will be able to
      maintain adequate controls over our financial processes and reporting in the
      future or that we will be able to comply with our obligations under Section
      404
      of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective
      internal controls, or difficulties encountered in implementing or improving
      our
      internal controls, could harm our operating results or cause us to fail to
      meet
      our reporting obligations. Ineffective internal controls could also cause
      investors to lose confidence in our reported financial information, which would
      likely have a negative effect on the trading price of our common
      units.





*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. Additionally, 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 that 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.





*Atlas
      America and its affiliates own a controlling interest in us.* Atlas
      America and its affiliates own approximately 80.0% of our common units and
      all
      of our Class A units. Accordingly, Atlas America possesses a controlling
      vote on all matters submitted to a vote of our unitholders, including election
      of our board of directors. As long as Atlas America owns a controlling interest
      in us, it will be able to approve or disapprove matters submitted to members
      for
      a vote irrespective of the vote of persons buying common units in this offering.
      Atlas America will be able to cause a change of control of our company. This
      concentration of ownership may have the effect of preventing or discouraging
      transactions involving an actual or a potential change of control of our
      company, regardless of whether a premium is offered over then-current market
      prices. Moreover, even if subsequent issuances result in Atlas America holding
      less than a majority of the common units, it will be able to determine matters
      requiring class voting so long as it controls the Class A
      units.





*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 us and our unitholders. For
      example, our limited liability company agreement provides that:




Page
          29





·
            our
                directors and officers will not have any liability to us or our
                unitholders 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 unitholders 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 unitholders 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:





·
            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
                unitholders.




·
            In
                some instances our board of directors may cause us to borrow funds
                in
                order to permit us to pay cash distributions to our unitholders,
                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.





*We
      are a “controlled company” within the meaning of NYSE rules and, as a result,
      qualify for, and intend to rely on, exemptions from some of the NYSE listing
      requirements with respect to independent directors.* Because
      Atlas America controls a majority of our outstanding common units, we are a
      controlled company within the meaning of NYSE rules which exempt controlled
      companies from the following corporate governance requirements:





·
            the
                requirement that a majority of the board of directors consist of
                independent directors;




·
            the
                requirement to have a nominating/corporate governance committee of
                the
                board of directors, composed entirely of members who are independent
                as
                defined by NYSE rules, that is responsible for identifying individuals
                qualified to become board members, consistent with criteria approved
                by
                the board, selection of board nominees for the next annual meeting
                of
                shareholders, development of corporate governance guidelines and
                oversight
                of the evaluation of the board and
                management;






Page
          30






·
            the
                requirement to have a compensation committee of the board of directors,
                composed entirely of independent directors, that is responsible for
                reviewing and approving corporate goals and objectives relevant to
                chief
                executive officer compensation, evaluation of the chief executive
                officer’s performance in light of the goals and objectives, determination
                and approval of the chief executive officer’s compensation, and making
                recommendations to the board with respect to compensation of other
                executive officers and incentive compensation and equity-based plans
                that
                are subject to board approval; and




·
            the
                requirement for an annual performance evaluation of the
                nominating/corporate governance and compensation
                committees.





For
      so
      long as we remain a controlled company, we do not intend to have a majority
      of
      independent directors or nominating/corporate governance or compensation
      committees. Accordingly, you will not have the same protections afforded to
      shareholders of companies that are subject to all of the NYSE corporate
      governance requirements.





*We
      may issue additional units without unitholder approval, which would dilute
      existing ownership interests.* We
      may
      issue an unlimited number of units of any type, including common units, without
      the approval of our unitholders. The issuance of additional units or other
      equity securities may have the following effects:





·
            a
                unitholder’s proportionate ownership interest in us may
                decrease;




·
            the
                amount of cash distributed on each common unit may
                decrease;




·
            the
                relative voting strength of each previously outstanding unit may
                be
                diminished; and




·
            the
                market price of the common units may
                decline.





*Our
      limited liability company agreement provides for a limited call right that
      may
      require unitholders 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 unitholders 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. Unitholders 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 unitholders. 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 unitholders 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.




Page
          31





*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.





*Expense
      reimbursements due to our manager under our management agreement will reduce
      cash available for distribution to our unitholders.* 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 unitholders 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 unitholders
      owning 20% or more of our common units.* Our
      limited liability company agreement restricts the voting rights of common
      unitholders 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 unitholders to call meetings or to acquire information about our
      operations, as well as other provisions limiting common unitholders’ 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.





Page
          32


*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 unitholders 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 unitholders 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.





*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 unitholders 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 unitholders receiving two Schedule K-1s, for one fiscal year and the
      cost of the preparation of these returns will be borne by all
      unitholders.





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





None





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





**Office
      Properties**





We
      own a
      24,000 square foot office building in Moon Township, Pennsylvania, a 17,000
      square foot field office and warehouse facility in Jackson Center, Pennsylvania
      and an office in Deerfield, Ohio. We lease a 1,400 square foot field office
      in
      Ohio under a lease expiring in 2009 and one 4,600 square foot field office
      in
      Pennsylvania under a lease expiring in 2009. We also rent 14,100 square feet
      of
      office space in Uniontown, Ohio under a lease expiring in August 30, 2008.
      We
      also lease other field offices in Ohio and New York on a month-to-month
      basis.





**Productive
      Wells**





The
      following table sets forth information as of December 31, 2006 regarding
      productive natural gas and oil wells in which we have a working
      interest:





Page
          33





**Number
                of productive wells****Gross**
            **(1)**
            **Net**
            **(1)**Oil
                wells
            
            
            504
            
            
            341Gas
                wells
            
            
            6,114
            
            
            2,927Total
            
            
            6,618
            
            
            3,268





(1)
            Includes
                our interest in wells owned by 92 investment partnerships for which
                we
                serve as general partner and various joint ventures. Does not include
                our
                royalty or overriding interests in 634
                wells.





**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, 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
            
            $
            .95Year
                ended September 30, 2004
            
            
            181,021
            
            
            7,285,281
            
            $
            32.85
            
            $
            5.84
            
            $
            .87





(1)
            Average
                sales price before the effects of financial hedging was $7.90 for
                the year
                ended December 31, 2006; 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.





**Developed
      and Undeveloped Acreage**





The
      following table sets forth information about our developed and undeveloped
      natural gas and oil acreage as of December 31, 2006. The information in this
      table includes our interest in acreage owned by our investment partnerships
      sponsored by us. 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
            
            
            -
            
            
            -Mississippi
            
            
            40
            
            
            3
            
            
            -
            
            
            -Montana
            
            
            -
            
            
            -
            
            
            2,650
            
            
            2,650New
                York
            
            
            20,517
            
            
            15,053
            
            
            38,172
            
            
            38,172North
                Dakota
            
            
            639
            
            
            96
            
            
            -
            
            
            -Ohio
            
            
            114,226
            
            
            95,054
            
            
            37,811
            
            
            34,287Oklahoma
            
            
            4,323
            
            
            468
            
            
            -
            
            
            -Pennsylvania
            
            
            107,495
            
            
            107,495
            
            
            233,538
            
            
            233,538Tennessee
            
            
            6,400
            
            
            4,265
            
            
            4,627
            
            
            4,627Texas
            
            
            4,520
            
            
            329
            
            
            -
            
            
            -West
                Virginia
            
            
            1,078
            
            
            539
            
            
            10,806
            
            
            5,403Wyoming
            
            
            -
            
            
            -
            
            
            80
            
            
            80264,701
            
            
            224,393
            
            
            336,744
            
            
            323,287


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




Page
          34






(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 is 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.





**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 an 87.5% net revenue interest to us for most leases
      directly acquired by us. In certain instances, this royalty amount may increase
      to 1/6 th (16.66%) when leases are taken from larger landowners or mineral owners
      such as coal and timber companies.





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
      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%.





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, 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.




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 $885,000
      in the year ended December 31, 2006 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.





Page
          35


Our
      properties are 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.





**Drilling
      Activity**





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 drilling was initiated.





**Development
                wells**
            
            **Exploratory
                wells****Productive**
            
            **Dry**
            
            **Productive**
            
            **Dry****Gross****(1)**
            
            **Net****(2)**
            
            **Gross****(1)**
            
            **Net****(2)**
            
            **Gross****(1)**
            
            **Net****(2)**
            
            **Gross****(1)**
            
            **Net****(2)**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
            
            
            —
            
            
            —
            
            
            —
            
            
            —Year
                ended September 30, 2004
            
            
            493.0
            
            
            160.5
            
            
            11.0
            
            
            3.8
            
            
            —
            
            
            —
            
            
            1.0
            
            
            1.0





(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.





**Natural
      Gas and Oil Reserves**





The
      following tables summarize information regarding our estimated proved natural
      gas and oil reserves at September 30, 2004 and 2005, and at December 31, 2005
      and December 31, 2006. 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 located in the United States.
      We
      base these estimated proved natural gas and oil reserves and future net revenues
      of natural gas and oil reserves upon reports prepared by Wright & Company,
      Inc., energy consultants. 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:




**At
                December 31,**
            
            **At
                December 31,**
            
            **At
                September 30,****2006**
            
            **2005**
            
            **2005**
            
            **2004**Natural
                gas (per Mcf)
            
            $
            6.33
            
            $
            10.84
            
            $
            14.75
            
            $
            6.91Oil
                (per Bbl)
            
            $
            57.26
            
            $
            57.54
            
            $
            63.29
            
            $
            46.00






Page
          36


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 Wright &
Company in preparing its 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 Item 1A: “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. We cannot
      assure you that these estimates are accurate predictions of future net cash
      flows from natural gas and oil reserves or their present value. For additional
      information concerning our natural gas and oil reserves and estimates of future
      net revenues, see Note 12 of our Notes to Combined and Consolidated Financial
      Statements.





**Proved
                natural****gas
                and oil****reserves
                for****Atlas
                Energy**
            
            **Proved
                natural gas and oil reserves for****Resources
                at**
            
            **Atlas
                America E&P Operations at****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**
            
            **2004**
            
            **2003**Natural
                gas reserves (Mmcf):Proved
                developed reserves
            
            
            107,683
            
            
            108,674
            
            
            104,786
            
            
            95,788
            
            
            87,760Proved
                undeveloped reserves (1)
            
            
            60,859
            
            
            49,250
            
            
            53,241
            
            
            46,345
            
            
            45,533Total
                proved reserves of natural gas
            
            
            168,542
            
            
            157,924
            
            
            158,027
            
            
            142,133
            
            
            133,293Oil
                reserves (Mbbl):Proved
                developed reserves
            
            
            2,064
            
            
            2,122
            
            
            2,116
            
            
            2,126
            
            
            1,825Proved
                undeveloped reserves
            
            
            4
            
            
            135
            
            
            143
            
            
            149
            
            
            30Total
                proved reserves of oil
            
            
            2,068
            
            
            2,257
            
            
            2,259
            
            
            2,275
            
            
            1,855Total
                proved reserves (Mmcfe)
            
            
            180,950
            
            
            171,466
            
            
            171,581
            
            
            155,782
            
            
            144,423PV-10
                estimate of cash flows of proved reserves (in thousands)
                (2):Proved
                developed reserves
            
            $
            279,330
            
            $
            465,459
            
            $
            617,445
            
            $
            265,516
            
            $
            164,617Proved
                undeveloped reserves
            
            
            4,111
            
            
            131,678
            
            
            228,206
            
            
            54,863
            
            
            26,802Total
                PV-10 estimate (3)
            
            $
            283,441
            
            $
            597,137
            
            $
            845,651
            
            $
            320,379
            
            $
            191,419Standardized
                measure of discounted future cash flows (in thousands) (2)
                (3)
            
            $
            283,441
            
            $
            429,272
            
            $
            606,697
            
            $
            232,998
            
            $
            144,351





(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.






Page
          37






(2)
            Amounts
                shown for September 30, 2003, 2004 and 2005 and December 31, 2005
                reflect
                values for Atlas America E&P Operations, which paid income taxes.
                Amounts shown for December 31, 2006 reflect values for our reserves.
                Since
                we are a limited liability company that allocates our taxable income
                to
                our unitholders, no provision for federal or state income taxes has
                been
                included in the December 31, 2006 calculation 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****Atlas
                Energy**
            
            **Proved
                natural gas and oil reserves for****Resources
                at**
            
            **Atlas
                America E&P Operations at****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**
            
            **2004**
            
            **2003**PV-10
                value
            
            $
            283,441
            
            $
            597,137
            
            $
            845,651
            
            $
            320,379
            
            $
            191,419Income
                tax effect
            
            
            —
            
            
            (167,865
            )
            
            (238,954
            )
            
            (87,381
            )
            
            (47,068
            )Standardized
                measure
            
            $
            283,441
            
            $
            429,272
            
            $
            606,697
            
            $
            232,998
            
            $
            144,351





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.





Projected
      natural gas and oil volumes for calendar 2007 and the remaining successive
      years
      are:





**Calendar**
            
            **Remaining****2007**
            
            **successive
                years**
            
            **Total**Natural
                gas (Mmcf)
            
            
            10,329
            
            
            158,213
            
            
            168,542Oil
                (Mbbl)
            
            
            141
            
            
            1,927
            
            
            2,068





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





One
      of
      our subsidiaries, Resource Energy, LLC, together with Resource America, Inc.
      (NASDAQ: REXI) is 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 alleges that we are not paying
      landowners the proper amount of royalty revenues with respect to natural gas
      produced from the leased properties. The complaint seeks 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 October 2006 we reached a tentative settlement of this lawsuit, the
      settlement terms are subject to final approval by the court. Pursuant to the
      tentative settlement terms, we have agreed to pay $300,000, upgrade certain
      gathering systems and cap certain transportation expenses chargeable to the
      land
      owners.





We
      are
      also a party to various routine legal proceedings arising out of 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**





Not
      applicable





Page
          38


**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.





**High**
            
            **Low****Fiscal
                2006**Fourth
                Quarter
            
            $
            22.88
            
            $
            21.80





As
      of
      February 28, 2007, there were 36,674,365 common units outstanding held by three
      holders of record.





**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 unitholders 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:




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




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




·
            provide
                funds for distributions (1) to our unitholders 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 unitholders.





On
      January 24, 2007, we declared an initial quarterly cash distribution for the
      fourth quarter of 2006 of $0.06 per common unit, which was paid on February
      14,
      2007 to common unitholders of record as of February 7, 2007. This distribution
      represents a pro-rated distribution of $0.42 per common unit for the period
      from
      December 18, 2006, the date of our initial public offering, through December
      31,
      2006.





For
      information concerning common units authorized for issuance under our incentive
      plan, see Note 10 to our Combined and Consolidated Financial
      Statements.





Page
          39


**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, as of and for the
      periods indicated. Atlas America E & P Operations represented 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 in December
      2006. We derived the historical financial data as of December 31, 2005 and
      2006
      and for the years ended September 30, 2004 and 2005, the three month transition
      period ended December 31, 2005 resulting from changing our year end from
      September 30 to December 31, and the year ended December 31, 2006 from
      financial statements, which were audited by Grant Thornton LLP, independent
      registered public accounting firm, and are included in this report. We derived
      the historical financial data as of September 30, 2002 and 2003 and for the
      years ended September 30, 2002 and 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.





Page
          40





**Three
                Months****Year
                Ended**
            
            **Ended**
            
            **Years
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**
            
            **2004**
            
            **2003**
            
            **2002****(in
                thousands)**Income
                statement data:Revenues:Gas
                and oil production
            
            $
            88,449
            
            $
            24,086
            
            $
            63,499
            
            $
            48,526
            
            $
            38,639
            
            $
            28,916Partnership
                management:Well
                construction and completion
            
            
            198,567
            
            
            42,145
            
            
            134,338
            
            
            86,880
            
            
            52,879
            
            
            55,736Administration
                and oversight
            
            
            11,762
            
            
            2,964
            
            
            9,590
            
            
            8,396
            
            
            5,090
            
            
            4,805Well
                services
            
            
            12,953
            
            
            2,561
            
            
            9,552
            
            
            8,430
            
            
            7,635
            
            
            7,585Gathering
                (1)
            
            
            9,251
            
            
            1,407
            
            
            4,359
            
            
            4,191
            
            
            3,898
            
            
            3,497Total
                revenues
            
            
            320,982
            
            
            73,163
            
            
            221,338
            
            
            156,423
            
            
            108,141
            
            
            100,539Expenses:Gas
                and oil production (1)
            
            
            13,881
            
            
            2,441
            
            
            8,165
            
            
            7,289
            
            
            6,770
            
            
            6,693Partnership
                management:Well
                construction and completion
            
            
            172,666
            
            
            36,648
            
            
            116,816
            
            
            75,548
            
            
            45,982
            
            
            48,443Well
                services
            
            
            7,337
            
            
            1,487
            
            
            5,167
            
            
            4,398
            
            
            3,773
            
            
            3,747Gathering
                (1)
            
            
            —
            
            
            38
            
            
            52
            
            
            53
            
            
            29
            
            
            48Gathering
                fee - Atlas Pipeline (1)
            
            
            29,545
            
            
            7,930
            
            
            21,929
            
            
            17,189
            
            
            14,564
            
            
            10,756General
                and administrative
            
            
            23,367
            
            
            5,818
            
            
            13,202
            
            
            11,708
            
            
            10,106
            
            
            10,616Compensation
                reimbursement - affiliate
            
            
            1,237
            
            
            163
            
            
            602
            
            
            1,050
            
            
            1,400
            
            
            1,181Depreciation,
                depletion and amortization
            
            
            22,491
            
            
            4,916
            
            
            14,061
            
            
            12,064
            
            
            9,938
            
            
            9,409Total
                operating expenses
            
            
            270,524
            
            
            59,441
            
            
            179,994
            
            
            129,299
            
            
            92,562
            
            
            90,893Operating
                income
            
            
            50,458
            
            
            13,722
            
            
            41,344
            
            
            27,124
            
            
            15,579
            
            
            9,646Other
                income (expenses):Interest
                income
            
            
            966
            
            
            32
            
            
            317
            
            
            250
            
            
            251
            
            
            686Other
                - net
            
            
            403
            
            
            25
            
            
            (238
            )
            
            194
            
            
            107
            
            
            865Total
                other income
            
            
            1,369
            
            
            57
            
            
            79
            
            
            444
            
            
            358
            
            
            1,551Net
                income before cumulative effect of accounting change
            
            
            51,827
            
            
            13,779
            
            
            41,423
            
            
            27,568
            
            
            15,937
            
            
            11,197Cumulative
                effect of
              accounting
                change (2)
            
            
            6,355
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Net
                income
            
            $
            58,182
            
            $
            13,779
            
            $
            41,423
            
            $
            27,568
            
            $
            15,937
            
            $
            11,197Cash
                flow data:Cash
                provided by operating activities
            
            $
            63,788
            
            $
            31,783
            
            $
            65,444
            
            $
            42,523
            
            $
            20,365
            
            $
            783Cash
                used in investing activities
            
            
            (75,588
            )
            
            (17,185
            )
            
            (59,050
            )
            
            (32,709
            )
            
            (22,112
            )
            
            (15,943
            )Cash
                provided by (used in) financing activities
            
            
            (285
            )
            
            74
            
            
            (320
            )
            
            (14,916
            )
            
            34
            
            
            2,289Capital
                expenditures
            
            
            75,635
            
            
            17,187
            
            
            59,124
            
            
            33,252
            
            
            22,607
            
            
            16,832Other
                financial information (unaudited):EBITDA
            
            $
            74,318
            
            $
            18,695
            
            $
            55,484
            
            $
            39,632
            
            $
            25,875
            
            $
            20,606Balance
                sheet data (at period end):Total
                assets
            
            $
            415,463
            
            $
            315,052
            
            $
            270,402
            
            $
            198,454
            
            $
            178,451
            
            $
            161,464Liabilities
                associated with drilling contracts
            
            
            86,765
            
            
            70,514
            
            
            60,971
            
            
            29,375
            
            
            22,157
            
            
            4,948Advances
                from affiliates
            
            
            12,502
            
            
            4,257
            
            
            13,897
            
            
            30,008
            
            
            34,776
            
            
            75,602Long-term
                debt, including current maturities
            
            
            68
            
            
            156
            
            
            81
            
            
            420
            
            
            194
            
            
            160Total
                debt
            
            
            12,570
            
            
            4,413
            
            
            13,978
            
            
            30,428
            
            
            34,970
            
            
            75,762Total
                equity
            
            
            212,682
            
            
            154,519
            
            
            146,142
            
            
            109,461
            
            
            102,031
            
            
            67,398





(1)
            We
                charge gathering fees to our investment partnership wells that are
                connected to Atlas Pipeline’s gathering systems. 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 4)






Page
          41




**EBITDA**





We
      define
      EBITDA as earnings before interest, taxes, depreciation, depletion and
      amortization. EBITDA is not a measure of performance calculated in accordance
      with GAAP. Although not prescribed under GAAP, we believe the presentation
      of
      EBITDA is relevant and useful because it helps our investors to understand
      our
      operating performance and makes it easier to compare our results with other
      companies that have different financing and capital structures or tax rates.
      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
      does
      not represent funds available for discretionary use. The following reconciles
      our net income before taxes to our EBITDA for the periods
      indicated:




**Three
                Months****Year
                Ended**
            
            **Ended**
            
            **Years
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**
            
            **2004**
            
            **2003**
            
            **2002****(in
                thousands)**Net
                income before cumulative effect of accounting change
            
            $
            51,827
            
            $
            13,779
            
            $
            41,423
            
            $
            27,568
            
            $
            15,937
            
            $
            11,197Plus
                interest expense
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Plus
                depreciation, depletion and amortization
            
            
            22,491
            
            
            4,916
            
            
            14,061
            
            
            12,064
            
            
            9,938
            
            
            9,409EBITDA
            
            $
            74,318
            
            $
            18,695
            
            $
            55,484
            
            $
            39,632
            
            $
            25,875
            
            $
            20,606




**ITEM
              7:**
            **MANAGEMENT’S
                DICUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
                OPERATIONS**





*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, Inc. which were contributed to us upon the closing of that 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 Atlas
      Energy Resources 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 Item 1A: “Risk Factors” for
      information regarding some of the risks inherent in our business*





**GENERAL**





We
      are a
      limited liability company focused on the development and production of natural
      gas and, to a lesser extent, oil principally 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.




Page
          42





We
      were
      formed in 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). We are managed by Atlas Energy Management, Inc., a wholly-owned
      subsidiary of Atlas America. Through our manager, Atlas America personnel are
      responsible for managing our assets and raising capital.





As
      of
      December 31, 2006, our principal assets consisted generally of:





·
            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;




·
            either
                directly or through our investment partnerhips, interests in 7,252
                gross
                producing gas and oil wells, including overriding royalty interests
                in 634
                gross producing gas and oil wells;




·
            approximately
                601,400 gross (547,700 net) acres, primarily in the Appalachian Basin,
                over half of which, or approximately 336,700 gross (323,300 net)
                acres,
                are undeveloped; and




·
            an
                interest in a joint venture that gives us the right to drill up to
                an
                additional 200 net wells before December 31, 2007 on approximately
                212,000
                acres in Tennessee.





At
      December 31, 2006, we had proved reserves of 180.9 Bcfe, including the reserves
      net to our equity interest in the investment partnerships and our direct
      interests in producing wells.





For
      the
      year ended December 31, 2006, we produced approximately 27.0 Mmcfe/d, which
      includes our proportionate share of production from our investment partnerships
      as well as our direct interests in producing wells. This resulted in an average
      reserve life of approximately 18 years based on our proved reserves at December
      31, 2006. As of December 31, 2006, we had identified over 500 proved undeveloped
      drilling locations and approximately 2,600 additional potential drilling
      locations on our acreage and our Tennessee joint venture acreage.





We
      fund
      the drilling of natural gas and oil wells on our acreage by sponsoring and
      managing tax-advantaged investment partnerships. 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.





We
      derive
      substantially all of our revenues from our equity interest in the oil and gas
      produced by the investment partnerships as well as the fees paid by the
      partnerships to us for acting as the managing general partner as
      follows:





·
            **Gas
                and oil production**.
                We receive an interest in each investment partnership proportionate
                to the
                value of our coinvestment in it and the value of the acreage we contribute
                to it, typically 27% to 33% of the overall capitalization of a particular
                partnership. We also receive an incremental interest in each partnership,
                typically 7%, for which we do not make any additional capital
                contribution. Consequently, our equity interest in the reserves and
                production of each partnership is typically between 34% and
                40%.




·
            **Partnership
                management**.
                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.






Page
          43






·
            **Administration
                and oversight**.
                Each 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.
                In
                addition, for each well drilled by an investment partnership, we
                receive a
                fixed administration fee of approximately
                $15,000.




·
            **Well
                services**.
                Each partnership pays us a monthly per well operating fee, currently
                $100
                to $457, 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**.
                Each partnership pays us a gathering fee for gathering services.
                Historically, this fee was typically insufficient to cover all of
                the
                gathering fees due to Atlas Pipeline Partners, L.P., under our master
                natural gas gathering agreement with it. After the closing, pursuant
                to
                the terms of our contribution agreement with Atlas America, our gathering
                revenues and costs will net to $0. Please read Item 1. “Business - Other
                Agreements with Atlas America and Its Affiliates - Contribution
                Agreement.”





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.





**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. The financial results now being reported
      by us
      relate to the twelve-month year ended December 31, 2006, and the three-month
      transitional period ended December 31, 2005. In order to compare the financial
      information for the year ended December 31, 2006 to a like period, we prepared
      financial information for the year ended December 31, 2005, which includes
      the
      three-month transitional period ended December 31, 2005, and the nine months
      ended September 30, 2005. Wherever practicable, the following discussion
      compares the consolidated financial statements for calendar year 2006 with
      the
      recast pro forma financial information for the year ended December 31, 2005.
      For
      purposes of Management’s Discussion and Analysis of Financial Condition and
      Results of Operations, we believe that this comparison provides a more
      meaningful analysis.





Throughout
      this discussion, data for all periods except for the year ended December 31,
      2005 and three months ended December 31, 2004, are derived from our consolidated
      financial statements, which appear in this report.





Page
          44


**Comparability
      of Financial Statements**





The
      historical financial statements of Atlas America E & P Operations included
      in this report may not be 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 10% 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 will incur indebtedness after the closing of our offering
                which will create interest expense.




·
            We
                will incur additional general and administrative expense estimated
                to be
                $500,000 per year for costs associated with Schedule K-1 preparation
                and
                distribution.




**BUSINESS
      SEGMENTS**





We
      operate two business segments:





·
            Our
                gas and oil production segment, which consists 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.





**Gas
      and Oil Production**





As
      of
      December 31, 2006, we owned interests in 7,252 gross wells, principally in
      the
      Appalachian Basin, of which we operated 6,155. Over the two years ended
      September 30, 2005, three months ended December 31, 2005 and year ended December
      31, 2006, we have drilled 2,074 gross (682 net) wells, 98% of which were
      successful in producing natural gas in commercial quantities. In September
      2004,
      we expanded our operations into Tennessee through a joint venture with Knox
      Energy, LLC that gave us an exclusive right to drill up to 300 net wells before
      June 30, 2007 on approximately 212,000 acres owned by Knox Energy. This
      agreement was amended and extended, giving us the right to drill an additional
      200 net wells from January 1, 2007 to December 31, 2007 provided that we
      commence the drilling of a minimum of 75 wells before September 30, 2007. As
      of
      December 31, 2006, we had drilled 141 net wells under this agreement. As of
      December 31, 2006, we had identified over 500 proved undeveloped drilling
      locations and approximately 2,600 additional potential drilling locations on
      our
      acreage and our Tennessee joint venture acreage.





Our
      results of operations for our gas and oil production segment are impacted by
      increases and decreases in the volume of natural gas that we produce, which
      we
      refer to as production volumes. Production volumes and pipeline capacity
      utilization rates generally are driven by wellhead production and the number
      of
      new wells drilled and connected in our areas of operation and more broadly,
      by
      demand for natural gas.





Page
          45


Our
      results of operations for our gas and oil production segment are also impacted
      by the prices we receive and the margins we generate. Because of the volatility
      of the prices for natural gas, as of December 31, 2006 we had financial hedges
      and physical hedges in place for approximately 79% of our expected production
      for the year ending December 31, 2007. Therefore, we have substantially reduced
      our exposure to commodity price movements with respect to those volumes under
      these types of contractual arrangements for this period. For additional
      information regarding our hedging activities, please read Item 7A:—“Quantitative
      and Qualitative Disclosures about Market Risk.”





**Partnership
      Management**





We
      generally fund our drilling activities 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. Historically, our fund-raising cycle has been on a calendar
      year basis. We raised $218.5 million in the year ended December 31, 2006. During
      the year ended December 31, 2006 our investment partnerships invested $283.7
      million in drilling and completing wells, of which we contributed $65.2 million.
      During the three months ended December 31, 2005, our investment partnerships
      invested $68.3 million in drilling and completing wells, of which we contributed
      $16.1 million. During fiscal 2005, our investment partnerships invested $206.0
      million in drilling and completing wells, of which we contributed $57.3
      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 general or
      managing partner. Additionally to provide 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 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.





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, 90% of the subscription proceeds
      received by each partnership are 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.





Our
      results of operations for our partnership management segment are impacted by
      increases and decreases in the number of wells that we drill and the number
      of
      wells we operate. Well construction activity is generally driven by commodity
      prices and demand for natural gas and oil. Additionally, the level of funds
      we
      raise through investment partnerships affects the number of wells we drill.
      Investor funds raised will be also dependent on commodity prices and tax laws
      associated with natural gas and oil.





**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.





*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.




Page
          46





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.





*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, 2006. 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.





**RESULTS
      OF OPERATIONS**





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





**Years
                Ended**
            
            **Three
                Months Ended**
            
            **Years
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**
            
            **2004**
            
            **2005**
            
            **2004**Production
                revenues (in thousands):Gas
                (1)
            
            $
            79,016
            
            $
            64,530
            
            $
            21,851
            
            $
            12,697
            
            $
            55,376
            
            $
            42,532Oil
            
            $
            9,384
            
            $
            8,324
            
            $
            2,227
            
            $
            1,942
            
            $
            8,039
            
            $
            5,947Production
                volumes:Gas
                (Mcf/d) (1) (2)
            
            
            24,511
            
            
            21,190
            
            
            21,468
            
            
            20,286
            
            
            20,892
            
            
            19,905Oil
                (Bbls/d)
            
            
            413
            
            
            429
            
            
            431
            
            
            447
            
            
            433
            
            
            495Total
                (Mcfe/d)
            
            
            26,989
            
            
            23,764
            
            
            24,054
            
            
            22,968
            
            
            23,490
            
            
            22,875Average
                sales prices:Gas
                (per Mcf) (3)
            
            $
            8.83
            
            $
            8.34
            
            $
            11.06
            
            $
            6.80
            
            $
            7.26
            
            $
            5.84Oil
                (per Bbl)
            
            $
            62.30
            
            $
            53.22
            
            $
            56.13
            
            $
            47.17
            
            $
            50.91
            
            $
            32.85Production
                costs (4):As
                a percent of production revenues
            
            
            16
            %
            
            12
            %
            
            10
            %
            
            12
            %
            
            13
            %
            
            15
            %Per
                Mcfe
            
            $
            1.41
            
            $
            1.02
            
            $
            1.10
            
            $
            0.83
            
            $
            0.95
            
            $
            0.87Depletion
                per Mcfe
            
            $
            2.08
            
            $
            1.61
            
            $
            2.01
            
            $
            1.28
            
            $
            1.42
            
            $
            1.22





(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 was $7.90
                for
                2006; 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 and gathering
                fees.







Page
          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, segment margins and number of net wells
      drilled during the periods indicated (in thousands):





**Years
                Ended**
            
            **Three
                Months Ended**
            
            **Years
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**
            
            **2004**
            
            **2005**
            
            **2004**Average
                construction and completion
              revenue
                per well
            
            $
            307
            
            $
            219
            
            $
            225
            
            $
            224
            
            $
            218
            
            $
            193Average
                construction and
              completion
                cost per well
            
            
            267
            
            
            191
            
            
            196
            
            
            195
            
            
            190
            
            
            168Average
                construction and completion segment margin per well
            
            $
            40
            
            $
            28
            
            $
            29
            
            $
            29
            
            $
            28
            
            $
            25Segment
                margin
            
            $
            25,901
            
            $
            19,034
            
            $
            5,497
            
            $
            3,985
            
            $
            17,552
            
            $
            11,332Net
                wells drilled
            
            
            647
            
            
            666
            
            
            187
            
            
            136
            
            
            615
            
            
            450





**Year
      ended December 31, 2006 compared to year ended December 31,
      2005**





*Gas
      and Oil Production*





Our
      natural gas revenues were $79.0 million in the year ended December 31, 2006,
      an
      increase of $14.5 million (22%) from $64.5 million in the year ended December
      31, 2005. The increase was attributable to a 6% increase in the average sales
      price of natural gas and a 16% increase in production volumes. The $14.5 million
      increase in natural gas revenues consisted of $3.8 million attributable to
      increases in natural gas sales prices and $10.7 million attributable to
      increased production volumes. The increase in our gas production volumes of
      3,321 Mcf/d resulted from production associated with new wells drilled for
      our
      investment partnerships. We believe that gas volumes will be favorably impacted
      in 2007 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 $9.4 million in the year ended December 31, 2006, an increase
      of
      $1.1 million (13%) from $8.3 million in the year ended December 31, 2005. The
      increase resulted from a 17% increase in the average sales price of oil,
      partially offset by a 4% decrease in production volumes. The $1.1 million
      increase consisted of $1.5 million attributable to increases in sales prices,
      partially offset by $400,000 attributable to volume decreases, as we drill
      primarily for natural gas rather than oil.





Our
      production costs were $13.9 million in the year ended December 31, 2006, an
      increase of $5.0 million (56%) from $8.9 million in the year ended December
      31,
      2005. This increase includes an increase in transportation charges, labor and
      maintenance costs associated with an increase in the number of wells we own
      from
      the prior year period. The transportation fees charged to our wells connected
      to
      Atlas Pipeline’s gathering system were generally increased from $0.29 to $0.35
      per mcf to 10% of the gas sales price beginning in January 2006.





Page
          48


*Well
      Construction and Completion*





Our
      well
      construction and completion segment margin was $25.9 million in the year ended
      December 31, 2006, an increase of $6.9 million (36%) from $19.0 million in
      the
      year ended December 31, 2005. During the year ended December 31, 2006, the
      increase of $6.9 million was attributable to an increase in the gross profit
      per
      well ($7.7 million) partially offset by a decrease in the number of wells
      drilled ($759,000). Since our drilling contracts are on a “cost plus” basis
      (typically cost plus 15%), an increase in our average cost per well also results
      in an increase in our average revenue per well. The increase in our average
      cost
      per well in the year ended December 31, 2006 resulted from an increase in the
      cost of tangible equipment, site preparation and reclamation expenses, as well
      as increased costs due to drilling to deeper formations.





It
      should
      be noted that “Liabilities associated with drilling contracts” on our balance
      sheet includes $71.6 million of funds raised in our investment programs that
      have not been applied to the completion of wells as of December 31, 2006 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 by March 31, 2007. During the year ended December 31, 2006, we raised
      $218.5 million. We anticipate raising $270.0 million in fiscal 2007. We
      anticipate oil and gas prices will continue to favorably impact our fundraising
      and therefore our drilling revenues in the year ending December 31,
      2007.





*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 $11.8 million in the year ended December
      31, 2006, an increase of $1.4 million (13%) from $10.4 million in the year
      ended
      December 31, 2005. This increase resulted from an increase in the number of
      wells managed for our investment partnerships in the year ended December 31,
      2006 as compared to the year ended December 31, 2005.





*Well
      Services*





Our
      well
      services revenues were $13.0 million in the year ended December 31, 2006, an
      increase of $3.1 million (31%) from $9.9 million in the year ended December
      31,
      2005. 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, 2006.





Our
      well
      services expenses were $7.3 million in year ended December 31, 2006, an increase
      of $1.8 million (33%) from $5.5 million in the year ended December 31, 2005.
      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, generally 10% of the gas sales
      price. Prior to our initial public offering, we 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 our gathering
      agreements with it. Our gathering fee to Atlas Pipeline was $29.5 million for
      the year ended December 31, 2006, an increase of $5.0 million (20%) from $24.5
      in the year ended December 31, 2005. The increase in the year ended December
      31,
      2006 is primarily a result of higher natural gas prices and increased volumes
      of
      gas transported due to additional volumes associated with wells we drilled
      in
      the past twelve months. We also pay our proportional 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 owned several small
      gathering systems before our initial public offering; the expenses associated
      with these are shown as gathering fees on our combined and consolidated
      statements of income. We do not own these gathering systems after the date
      of
      our initial public offering.





Page
          49




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 gathering revenues and expenses within our
      partnership management segment net to $0.




*General
      and Administrative*





Our
      general and administrative expenses were $23.4 million in the year ended
      December 31, 2006, an increase of $6.6 million (39%) from $16.8 million in
      the
      year ended December 31, 2005. These expenses include, among other things,
      salaries and benefits not allocated to a specific activity, costs of running
      our
      corporate office, partnership syndication activities and outside services.





The
      increase of $6.6 million in the year ended December 31, 2006 is principally
      attributed to the following:





·
            exploration
                costs increased $2.3 million due to the increase in activities of
                our land
                department as we acquire additional acreage and well
                sites;




·
            salaries
                and wages, including non-cash stock compensation, increased $3.0
                million
                due to the increase in executive salaries and in the number of employees
                as a result of Atlas America’s spin-off from Resource America;




·
            professional,
                legal and insurance expenses increased $470,000 due to higher audit
                fees
                and implementation of Sarbanes-Oxley Section 404 compliance;
                and




·
            directors’
                fees increased $770,000 as a result of Atlas America’s spin-off from
                Resource America.





*Net
      Expense Reimbursement—Affiliate*





Our
      net
      expense reimbursement—affiliate was $1.2 million in the year ended December 31,
      2006, an increase of $648,000 (117%) from $552,000 in the year ended December
      31, 2005. This increase resulted from an increase in allocations from Resource
      America for executive management and administrative services, including rent
      allocations for our offices in Philadelphia, PA and New York City.





*Depletion*





Our
      depletion of oil and gas properties as a percentage of oil and gas revenues
      was
      23% in the year ended December 31, 2006, compared to 19% in the year ended
      December 31, 2005. Depletion expense per Mcfe was $2.08 in the year ended
      December 31, 2006, an increase of $0.47 (29%) per Mcfe from $1.61 in the year
      ended December 31, 2005. Increases in our depletable basis and production
      volumes caused depletion expense to increase $6.6 million to $20.5 million
      in
      the year ended December 31, 2006 compared to $13.9 million in the year ended
      December 31, 2005. 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
      income*





Interest
      income was $966,000 in the year ended December 31, 2006, an increase of $618,000
      (178%) compared to $348,000 in the year ended December 31, 2005. The increase
      is
      from interest earned from investments on the proceeds received by Atlas America
      from the initial public offering of Atlas Pipeline Holdings, L.P., which was
      allocated to us.





Page
          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 compared to three months ended December 31,
      2004**





*Gas
      and Oil Production*





Our
      natural gas revenues were $21.9 million in the three months ended December
      31,
      2005, an increase of $9.2 million (72%) from $12.7 million in the three months
      ended December 31, 2004. The increase in the three months ended December 31,
      2005 was attributable to an increase in the average sales price of natural
      gas
      of 63% for the three months ended December 31, 2005 and an increase of 6% in
      the
      volume of natural gas produced in the three months ended December 31, 2005.
      The
      $9.2 million increase in gas revenues in the three months ended December 31,
      2005 as compared to the prior period consisted of $8.0 million attributable
      to
      increases in natural gas sales prices, and $1.2 attributable to increased
      production volumes.





Our
      oil
      revenues were $2.2 million in the three months ended December 31, 2005, an
      increase of $285,000 (15%), from $1.9 million in the three months ended December
      31, 2004, primarily due to an increase in the average sales price of oil of
      19%
      for the three months ended December 31, 2005. The $285,000 increase in oil
      revenues in three months ended December 31, 2005 as compared to the prior year
      period consisted of $369,000 attributable to increases in sales prices,
      partially offset by $84,000 attributable to decreased production
      volumes.





Our
      production costs were $2.4 million in the three months ended December 31, 2005,
      an increase of $691,000 (40%) from $1.7 million in the three months ended
      December 31, 2004. This increase includes an increase in pumping labor and
      an
      increase in transportation expenses associated with increased production volumes
      and natural gas sales prices, as a portion of our wells are charged
      transportation based on the sales price of the gas transported. The decrease
      in
      production costs as a percent of production revenues in the three months ended
      December 31, 2005 as compared to December 31, 2004 was the result of an increase
      in our average sales price which more than offset the increase in production
      costs per mcfe.





*Well
      Construction and Completion*





Our
      well
      construction and completion segment margin was $5.5 million in the three months
      ended December 31, 2005, an increase of $1.5 million (38%) from $4.0 million
      in
      the three months ended December 31, 2004. The increase of $1.5 million was
      attributable to an increase in the number of wells drilled during the three
      months ended December 31, 2005. The slight increase in the revenue and cost
      per
      well was a result of increases in the cost of tangible equipment, site
      preparation and reclamation expenses, as well as increased costs due to drilling
      to deeper formations.





*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, an increase of $808,000 (37%) from $2.2 million in the three
      months ended December 31, 2004. This increase resulted from an increase in
      the
      number of wells managed for our investment partnerships in the three months
      ended December 31, 2005 as compared to the three months ended December 31,
      2004.





Page
          51


*Well
      Services*





Our
      well
      services revenues were $2.6 million in the three months ended December 31,
      2005,
      an increase of $313,000 (14%) from $2.3 million in the three months ended
      December 31, 2004. 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, 2005.





Our
      well
      services expenses were $1.5 million in three months ended December 31, 2005,
      an
      increase of $296,000 (25%) from $1.2 million in the three months ended December
      31, 2004. 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*





Our
      gathering fee to Atlas Pipeline was $7.9 million for the three months ended
      December 31, 2005, an increase of $2.6 million (49%) from $5.3 million in the
      three months ended December 31, 2004. The increase in the three months ended
      December 31, 2005 was primarily a result of higher natural gas prices and
      increased volumes of gas transported due to additional volumes associated with
      wells we drilled in the past twelve months. We also owned several small
      gathering systems; the expenses associated with these are shown as gathering
      fees on our combined and consolidated statements of income.





*General
      and Administrative*





Our
      general and administrative expenses were $5.8 million in the three months ended
      December 31, 2005, an increase of $3.6 million (164%) from $2.2 million in
      the
      three months ended December 31, 2004. These expenses include, among other
      things, salaries and benefits not allocated to a specific activity, costs of
      running our corporate office, partnership syndication activities and outside
      services.





The
      increase of $3.6 million in the three months ended December 31, 2005 is
      principally attributed to the following:





·
            net
                syndication costs increased $1.1 million due to an increase in expenses
                related to our increased fund raising in our public and private investment
                partnerships;




·
            professional
                and legal fees increased $680,000 primarily due to higher audit fees
                and
                implementation of Sarbanes-Oxley Section 404
                compliance;




·
            salaries
                and wages, including non-cash stock compensation, increased $1.2
                million
                due to an increase in executive salaries and in the number of employees
                as
                a result of Atlas America’s spin-off from Resource America;
                and




·
            directors’
                fees increased $250,000 as a result of Atlas America’s spin-off from
                Resource America.





*Net
      Expense Reimbursement—Affiliate*





Our
      net
      expense reimbursement—affiliate was $163,000 in the three months ended December
      31, 2005, a decrease of $50,000 (23%) from $213,000 in the three months ended
      December 31, 2004. This decrease resulted from a decrease in allocations from
      Resource America for executive management and administrative services, as we
      now
      directly employ many of the individuals previously allocated to us and therefore
      include their compensation in our general and administrative
      expenses.





Page
          52


*Depletion*





Our
      depletion of oil and gas properties as a percentage of oil and gas revenues
      was
      18% in the three months ended December 31, 2005 and December 31, 2004. Depletion
      expense per mcfe was $2.01 in the three months ended December 31, 2005, an
      increase of $.73 (57%) per mcfe from $1.28 in the three months ended December
      31, 2004. Increases in our depletable basis and production volumes caused
      depletion expense to increase $1.7 million (63%) to $4.4 million in the three
      months ended December 31, 2005 as compared to $2.7 million in the three months
      ended December 31, 2004. 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.





**Year
      ended September 30, 2005 compared to year ended September 30,
      2004**





*Gas
      and Oil Production*





Our
      natural gas revenues were $55.4 million in the year ended September 30, 2005,
      an
      increase of $12.9 million (30%) from $42.5 million in the year ended September
      30, 2004. The increase was due to a 24% increase in the average sales price
      of
      natural gas and a 5% increase in production volumes. The $12.9 million increase
      in natural gas revenues consisted of $10.4 million attributable to price
      increases and $2.5 million attributable to volume increases.





Our
      oil
      revenues were $8.0 million in the year ended September 30, 2005, an increase
      of
      $2.1 million (35%) from $5.9 million in the year ended September 30, 2004.
      The
      increase resulted from a 55% increase in the average sales price of oil,
      partially offset by a 13% decrease in production volumes. The $2.1 million
      increase in oil revenues consisted of $3.3 million attributable to price
      increases, partially offset by $1.2 million attributable to volume decreases,
      as
      we drill primarily for natural gas rather than oil.





Our
      production costs were $8.2 million in the year ended September 30, 2005, an
      increase of $900,000 (12%) from $7.3 million in the year ended September 30,
      2004. This increase includes normal operating expenses and coincides with the
      increased production volumes we realized from the increased number of wells
      we
      own. Additionally, there were increases in transportation expense as a result
      of
      increased natural gas prices as a portion of our wells are charged
      transportation based on the sales price of the gas transported. Rates charged
      to
      us for transportation vary based upon agreements put in place at the time the
      wells are drilled; some of these agreements have escalation clauses. Production
      costs as a percent of revenues decreased from 15% in 2004 to 13% in 2005 as
      a
      result of an increase in our average sales price which more than offset the
      increase in production costs per Mcfe.





*Well
      Construction and Completion*





Our
      well
      construction and completion segment margin was $17.5 million in the year ended
      September 30, 2005, an increase of $6.2 million (55%) from $11.3 million in
      year
      ended September 30, 2004. During the year ended September 30, 2005, the increase
      in segment margin was attributable to an increase in the number of wells drilled
      ($4.7 million) and an increase in the gross profit per well ($1.5 million).
      The
      increase in our average cost per well resulted from an increase in the cost
      of
      tangible equipment, site preparation and reclamation expenses, as well as
      increased costs due to drilling into deeper formations.





*Administration
      and Oversight*





Our
      administration and oversight fees were $9.6 million in the year ended September
      30, 2005, an increase of $1.2 million (14%) from $8.4 million in the year ended
      September 30, 2004. This increase resulted from an increase in the number of
      wells drilled and managed for our investment partnerships in 2005 as compared
      to
      the prior year.





Page
          53


*Well
      Services*





Our
      well
      services revenues were $9.6 million in the year ended September 30, 2005, an
      increase of $1.2 million (13%) from $8.4 million in the year ended September
      30,
      2004. This increase resulted from an increase in the number of wells operated
      for our investment partnerships due to additional wells drilled in
      2005.





Our
      well
      services expenses were $5.2 million in the year ended September 30, 2005, an
      increase of $769,000 (17%) from $4.4 million in the year ended September 30,
      2004. This increase resulted from an increase in wages, benefits, and field
      office expenses associated with an increase in employees due to the increase
      in
      number of wells operated for our investment partnerships in 2005 as compared
      to
      2004.





*Gathering*





Our
      gathering fee to Atlas Pipeline was $21.9 million in the year ended September
      30, 2005, an increase of $4.7 million (27%) from $17.2 million in the year
      ended
      September 30, 2004. This increase was primarily a result of higher natural
      gas
      prices and increased volumes of gas transported due to an increase in the number
      of wells drilled. We also pay our proportional share of gathering fees based
      on
      our percentage interest in the well, which are included in gas and oil
      production expense. We also owned several small gathering systems; the expenses
      associated with these are shown as gathering fees on our combined and
      consolidated statements of income.





*General
      and Administrative*





Our
      general and administrative expenses were $13.2 million in the year ended
      September 30, 2005, an increase of $1.5 million (13%) from $11.7 million in
      the
      year ended September 30, 2004. These expenses include, among other things,
      salaries and benefits not allocated to a specific activity, costs of running
      our
      corporate office, partnership syndication activities and outside services.
      The
      increase of $1.5 million in 2005 as compared to the prior year is attributable
      principally to increases in insurance and professional fees, including the
      implementation of Sarbanes-Oxley Section 404 compliance.





*Net
      Expense Reimbursement—Affiliate*





Our
      net
      expense reimbursement—affiliate was $602,000 in the year ended September 30,
      2005, a decrease of $448,000 (43%) from $1.1 million in the year ended September
      30, 2004. This decrease resulted from a decrease in allocations from Resource
      America for executive management and administrative services as we now directly
      employ many of the individuals previously being allocated to us and therefore
      include their compensation in our general and administrative
      expenses.





*Depletion*





Depletion
      of oil and gas properties as a percentage of oil and gas revenues was 19% in
      the
      year ended September 30, 2005 compared to 21% in the year ended September 30,
      2004. Depletion was $1.42 per Mcfe in 2005, an increase of $.20 per Mcfe (16%)
      from $1.22 per Mcfe in 2004. Increases in our depletable basis and production
      volumes caused depletion expense to increase $2.0 million to $12.2 million
      in
      2005 compared to $10.2 million in 2004. The variances from period to period
      are
      directly attributable to changes in our oil and gas reserve quantities, product
      prices and changes in the depletable cost basis of our oil and gas
      properties.





Page
          54


**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 and, in the past,
      advances from Atlas America. The following table sets forth our sources and
      uses of cash (in thousands):





**Three
                Months****Year
                Ended**
            
            **Ended**
            
            **Years
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**
            
            **2004**Provided
                by operations
            
            $
            63,788
            
            $
            31,783
            
            $
            65,444
            
            $
            42,523Used
                in investing activities
            
            
            (75,588
            )
            
            (17,185
            )
            
            (59,050
            )
            
            (32,709
            )Provided
                by (used in) financing activities
            
            
            (285
            )
            
            74
            
            
            (320
            )
            
            (14,916
            )Increase
                (decrease) in cash and cash equivalents
            
            $
            (12,085
            )
            $
            14,672
            
            $
            6,074
            
            $
            (5,102
            )





We
      had
      $8.8 million in cash and cash equivalents at December 31, 2006, compared to
      $20.9 million at December 31, 2005. We had a working capital deficit of
      $88.0 million at December 31, 2006, a decrease in working capital of $9.5
      million from a working capital deficit of $78.5 million at December 31,
      2005.





**Capital
      Requirements**





During
      the year ended December 31, 2006, our capital expenditures related
      primarily to investments in our investment partnerships, in which we invested
      $73.6 million. For the year ended December 31, 2006, we funded and expect
      to continue to fund these capital expenditures through cash on hand, from
      operations and amounts available under our credit facility. In fiscal 2005
      and
      2004 our capital expenditures related to investments in our investment
      partnerships totaled $57.9 million and $32.2 million, respectively.





The
      level
      of capital expenditures we must devote to our development and production
      operations depends upon the level of funds raised through our investment
      partnerships. In the year ended December 31, 2006, we had raised $218.5
      million. We believe cash flows from operations and amounts available under
      our credit facility will be adequate to fund our contributions to these
      partnerships. 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. During the years ended September 30, 2005
      and 2004 we raised $148.7 million and $107.7 million, respectively.





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 new credit facility and with the temporary use of funds
      raised in our investment partnerships in the period before we invest the funds.
      We estimate investment capital expenditures of $43.4 million during the twelve
      month period ending December 31, 2007, and no expansion capital expenditures,
      although that may change if opportunities are available to us in that period.
      We
      also 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 IQD to unitholders through December
      31,
      2007.





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.





Page
          55


**Credit
      Facility**





Simultaneously
      with the closing of our initial public offering, we entered into a $250 million
      senior secured credit facility (-0- outstanding at December 31, 2006) with
      Wachovia Bank, National Association, as administrative agent, Wachovia Capital
      Markets LLC, 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 initial borrowing base is $155 million. The borrowing base
      will
      be subject to redetermination on March 15, 2007 and on a semi-annual basis
      thereafter. The credit facility will mature in December 2011. For more
      information on the terms of our credit facility, please read Item 1: “Business—
Credit Facility.”





**CASH
      FLOWS**





**Year
      ended December 31, 2006**





**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 investment
      partnerships. Net ** cash
      provided by operating activities was $63.8 million in the year ended
      December 31, 2006, substantially as a result of the following:





·
            net
                income before depreciation and amortization was $80.7 million, principally
                as a result of higher natural gas and oil prices and increased drilling
                profits; and




·
            repayments
                to affiliates decreased operating cash flows by $16.7 million, principally
                due to an increase in cash generated by our
                operations.





**Investing
      activities.** Cash
      used
      in our investing activities was $75.6 million, primarily as a result of capital
      expenditures related to wells we drilled.





**Financing
      activities.** Cash
      used
      by our financing activities was $285,000 in the year ended December 31,
      2006, primarily as a result of cash spent on deferred finance costs and
      repayments of debt.





**Three
      months ended December 31, 2005**





**Operating
      activities.** Net cash
      provided by operating activities was $31.8 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;




·
            repayments
                to affiliates decreased operating cash flows by $11.8 million, principally
                due to an increase in cash generated by our operations;
                and




·
            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.





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





**Financing
      activities.** Cash
      provided by our financing activities was $74,000, as a result of net
      borrowings.





Page
          56


**Year
      ended September 30, 2005 compared to year ended September 30, 2004**





**Operating
      activities.** Net
      cash
      provided by operating activities increased $22.9 million in the year ended
      September 30, 2005 to $65.4 million from $42.5 million in the year ended
      September 30, 2004, substantially as a result of the following:





·
            an
                increase in net income before depreciation, depletion and amortization
                of
                $15.9 million in the year ended September 30, 2005 as compared to
                the
                prior fiscal year principally a result of higher natural gas prices
                and
                drilling profits;




·
            changes
                in operating assets and liabilities increased operating cash flows
                by
                $19.9 million in the year ended September 30, 2005, compared to the
                year
                ended September 30, 2004, primarily due to an increase in liabilities
                associated with our drilling contracts of $23.7 million related to
                an
                increase in advance payments received. This increase was partially
                offset
                by an increase of $5.3 million in accounts receivable related to
                increased
                gas and oil production revenues. Our level of liabilities is dependent
                in
                part upon the remaining amount of our drilling obligations at any
                balance
                sheet date, which is dependent upon the timing of funds raised through
                our
                investment partnerships; and




·
            an
                increase in repayments to affiliates decreased operating cash flows
                by
                $13.6 million in the year ended September 30, 2005 as compared to
                the
                prior year period principally as a result of an increase in cash
                generated
                by our operations.





**Investing
      activities.** Net
      cash
      used in our investing activities increased $26.3 million in the year ended
      September 30, 2005 to $59.0 million from $32.7 million in the year ended
      September 30, 2004 primarily from a $25.9 million increase in capital
      expenditures related to the increase in the number of wells drilled.





**Financing
      activities.** Net
      cash
      used in our financing activities decreased $14.6 million in the year ended
      September 30, 2005 to $320,000 from $14.9 million in the year ended September
      30, 2004, as a result of proceeds we received of $37.0 million in the year
      ended
      September 30, 2004 from Atlas America’s initial public offering of common stock;
      there were no such offerings in 2005.





**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, 2006 and 2005, we received an
      average of $8.83 and $8.34 per Mcf of natural gas and $62.30 and $53.22 per
      Bbl
      of oil, respectively. During the three months ended December 31, 2005 and 2004,
      we received an average of $11.06 and $6.80 per Mcf of natural gas and $56.13
      and
      $47.17 per Bbl of oil, respectively. During 2005, we received an average of
      $7.26 per Mcf of natural gas and $50.91 per Bbl of oil as compared to $5.84
      per
      Mcf and $32.85 per Bbl in 2004.





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.





Page
          57


**ENVIRONMENTAL
      REGULATION**





To
      date,
      compliance with environmental laws and regulations has not had a material impact
      on our capital expenditures, earnings or competitive position. For instance,
      we
      are evaluating the impact of spill prevention plan requirements on our
      operations, including pending changes by United Stated Environmental Protection
      Agency to the federal regulations that require 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. For more information on environmental regulation
      and
      our operations, please read Item 1: “Business—Environmental Matters and
      Regulation.”





**DISTRIBUTIONS**





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. Our limited
      liability company agreement requires that, within 45 days after the end of
      each
      quarter, we distribute all of our available cash to unitholders of record on
      the
      applicable record date. We intend to make cash distributions to our common
      units
      and Class A units at an initial distribution rate of $0.42 per unit
      per quarter ($1.68 per unit on an annualized basis). As a result of
      distributing all of our available cash, we expect that we will rely upon
      external financing sources, including commercial borrowings and other debt
      and
      common unit issuances, to fund any acquisitions or expansion capital
      expenditures.





On
      January 24, 2007, we declared our initial quarterly cash distribution for the
      fourth quarter 2006 of $0.06 per common unit, which represents a pro-rated
      distribution of $0.42 per common unit for the period from December 18, 2006,
      the
      date of our initial public offering, through December 31, 2006. The $2.2 million
      distribution was paid on February 14, 2007 to unit holders of record as of
      February 7, 2007.





**CONTRACTUAL
      OBLIGATIONS AND COMMERCIAL COMMITMENTS**





The
      following table summarizes our contractual obligations at December 31, 2006
      (in thousands):





**Payments
                due by period****Less
                Than**
            
            **2
                - 3**
            
            **4
                - 5**
            
            **After
                5****Total**
            
            **1
                Year**
            
            **Years**
            
            **Years**
            
            **Years**Contractual
                cash obligations:Total
                debt
            
            $
            68
            
            $
            38
            
            $
            30
            
            $
            —
            
            $
            —Secured
                revolving credit facilities
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Operating
                lease obligations
            
            
            1,770
            
            
            649
            
            
            865
            
            
            255
            
            
            1Capital
                lease obligations
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Unconditional
                purchase obligations
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Other
                long-term obligations
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Total
                contractual cash obligations
            
            $
            1,838
            
            $
            687
            
            $
            895
            
            $
            255
            
            $
            1





**Payments
                due by period****Less
                Than**
            
            **2
                - 3**
            
            **4
                - 5**
            
            **After
                5****Total**
            
            **1
                Year**
            
            **Years**
            
            **Years**
            
            **Years**Other
                commercial commitments:Standby
                letters of credit
            
            $
            495
            
            $
            495
            
            $
            —
            
            $
            —
            
            $
            —Guarantees
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Standby
                replacement commitments
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Other
                commercial commitments
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Total
                commercial commitments
            
            $
            495
            
            $
            495
            
            $
            —
            
            $
            —
            
            $
            —






Page
          58


**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, 2006 and 2005, our credit
      evaluation indicated that we have no need for an allowance for possible losses
      for our oil and gas receivables.





**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. Additionally, 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
      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.





Page
          59


**Dismantlement,
      Restoration, Reclamation and Abandonment Costs**





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, 2006 and 2005, 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.





**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.





Page
          60


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
      record
      the income from the working interests and overriding royalties of wells we
      own
      an interest in when the gas and oil are delivered.





**RECENTLY
      ISSUED FINANCIAL ACCOUNTING STANDARDS**





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
      are
      currently evaluating the impact of the adoption of SFAS 159 on our financial
      position and results of operations.





In
      September 2006, the SEC staff issued Staff Accounting Bulletin No. 108,
“Considering the Effects of Prior Year Misstatements When Quantifying
      Misstatements in Current Year Financial Statements”, or SAB 108. SAB 108
      was issued to provide consistency in how registrants quantify financial
      statement misstatements. We initially applied SAB 108 in connection with the
      preparation of our financial statements for the year ended December 31, 2006.
      The application of SAB 108 did not have a material effect 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. SFAS 157 is effective
      for us beginning January 1, 2008. We are currently evaluating the impact of
      the
      adoption of SFAS 157 on our financial position or results of
      operations.





In
      June
      2006, the FASB issued FASB Interpretation No. 48, Accounting for
      Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109,
      (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes
      recognized in an entity’s financial statements and provides guidance on the
      recognition, de-recognition and measurement of benefits related to an entity’s
      uncertain tax positions. FIN 48 is effective for us beginning January 1,
      2007. We do not expect the adoption of FIN 48 to have a significant impact
      on
      our financial position or results of operations.





Page
          61


**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 interest rate cap 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, 2006. Only the potential impacts of hypothetical assumptions are analyzed.
      The analysis does not consider other possible effects that could impact our
      business.





**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 use physical hedges. These transactions are
      similar to NYMEX-based futures contracts, swaps and options, but also require
      firm delivery of the hedged quantity. Thus, we limit these arrangements to
      much smaller quantities than those projected to be available at any delivery
      point.





We
      also
      negotiate with certain purchasers for delivery of a portion of natural gas
      we
      will produce for the upcoming year. The prices under most of our gas sales
      contracts are negotiated on an annual basis and are index-based. 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 physical
      or
      financial hedge agreements for the year ending December 31, 2007, 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 $1.4 million.





We
      also
      enter into natural gas futures 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. A portion of the future sales is
      periodically hedged through the use of swaps and collar contracts.





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 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. 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.




Page
          62





As
      of
      December 31, 2006, we had financial and physical hedges in place for
      approximately 79% of our expected production volumes for the twelve months
      ending December 31, 2007. At December 31, 2006, we had 234 open natural gas
      futures contracts related to natural gas sales covering 54.9 million MMBtus
      of
      natural gas, maturing through December 31, 2010 at an average settlement
      price of $8.48 per MMBtu. We recognized gains of $7.1 million on settled
      contracts covering natural gas production for the year ended December 31, 2006.
      There were no gains or losses recognized during this period for hedge
      ineffectiveness or as a result of the discontinuance of these cash flow hedges.
      There were no gains or losses recognized on hedging for the three months ended
      December 31, 2005, or for the years ended September 30, 2005 and 2004.





Of
      the
      $47.5 million net unrealized hedge gain, our portion is $21.1 million and $26.4
      million has been allocated to our investment partnerships. Of the $21.1 million
      net gain in accumulated other comprehensive income at December 31, 2006, we
      will
      reclassify $12.2 million of gains to our consolidated statements of income
      over
      the next twelve month period as these contracts expire, and $8.9 million of
      gains will be reclassified in later periods if the fair values of the
      instruments remain at current market values.





As
      of
      December 31, 2006, we had the following natural gas volumes hedged:





**Fixed
      Price Swaps**




**Twelve
                Month****Period
                Ending**
            
            
            
            **Average****December
                31,**
            
            **Volumes**
            
            **Fixed
                Price**
            
            **Fair
                Value Asset****(MMBtu)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands) (1)**2007
            
            
            14,650,000
            
            $
            8.60
            
            $
            25,9352008
            
            
            15,800,000
            
            $
            8.91
            
            
            11,4502009
            
            
            15,720,000
            
            $
            8.31
            
            
            7,6902010
            
            
            5,400,000
            
            $
            7.53
            
            
            587$
            45,662





**Costless
      Collars**




**Twelve
                Month****Period
                Ending**
            
            
            
            
            
            **Average****December
                31,**
            
            **Option
                Type**
            
            **Volumes**
            
            **Floor
                and Cap**
            
            **Fair
                Value Asset****(MMBtu)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands) (1)**2007
            
            
            Puts
                purchased
            
            
            1,800,000
            
            $
            7.50
                - 8.60
            
            $
            1,5112007
            
            
            Calls
                sold
            
            
            1,800,000
            
            $
            7.50
                - 8.60
            
            
            -2008
            
            
            Puts
                purchased
            
            
            1,560,000
            
            $
            7.50
                - 9.40
            
            
            2812008
            
            
            Calls
                sold
            
            
            1,560,000
            
            $
            7.50
                - 9.40
            
            
            -$
            1,792Total
                Net Asset
            
            
            
            
            
            
            
            
            
            
            $
            47,454





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








Page
          63




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


**REPORT
      OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**








Board
      of
      Directors


Atlas
      Energy Resources, LLC




We
      have
      audited the accompanying combined and consolidated balance sheets of Atlas
      Energy Resources, LLC (a Delaware limited liability company) as of December
      31,
      2006 and 2005, and the related combined and consolidated statements of income,
      comprehensive income, equity, and cash flows for the year ended December 31,
      2006, the three month period ended December 31, 2005 and the years ended
      September 30, 2005 and 2004. 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. The Company is not required to
      have, nor were we engaged to perform an audit of its internal control over
      financial reporting. Our audit included consideration of internal control over
      financial reporting as a basis for designing audit procedures that are
      appropriate in the circumstances, but not for the purpose of expressing an
      opinion on the effectiveness of the Company’s internal control over financial
      reporting. Accordingly, we express no such opinion. An audit also includes
      examining, on a test basis, evidence supporting the amounts and disclosures
      in
      the financial statements, 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 as of December 31, 2006 and 2005, and the results of its
      operations and its cash flows the year ended December 31, 2006, the three month
      period ended December 31, 2005 and the years ended September 30, 2005 and 2004
      in conformity with accounting principles generally accepted in the United States
      of America.




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







Cleveland,
      Ohio


February
      28, 2007




Page
          64




**ATLAS
      ENERGY RESOURCES, LLC**




**COMBINED
      AND CONSOLIDATED BALANCE SHEETS**


(in
      thousands)





**December
                31,**
            
            **December
                31,****2006**
            
            **2005****ASSETS**Current
                assets:Cash
                and cash equivalents
            
            $
            8,833
            
            $
            20,918Accounts
                receivable
            
            
            31,280
            
            
            22,092Unrealized
                hedge gain
            
            
            27,618
            
            
            3,190Prepaid
                expenses
            
            
            3,251
            
            
            3,318Total
                current assets
            
            
            70,982
            
            
            49,518Property
                and equipment, net
            
            
            277,814
            
            
            214,701Other
                assets
            
            
            26,290
            
            
            9,577Intangible
                assets, net
            
            
            5,211
            
            
            6,090Goodwill
            
            
            35,166
            
            
            35,166$
            415,463
            
            $
            315,052**LIABILITIES
                AND COMBINED EQUITY**Current
                liabilities:Current
                portion of long-term debt
            
            $
            38
            
            $
            88Accounts
                payable
            
            
            37,931
            
            
            41,160Liabilities
                associated with drilling contracts
            
            
            86,765
            
            
            70,514Advances
                from affiliates
            
            
            12,502
            
            
            4,257Accrued
                liabilities
            
            
            21,706
            
            
            11,991Total
                current liabilities
            
            
            158,942
            
            
            128,010Long-term
                debt
            
            
            30
            
            
            68Partnership
                hedge payable
            
            
            13,248
            
            
            —Unrealized
                hedge loss
            
            
            3,835
            
            
            13,956Asset
                retirement obligations
            
            
            26,726
            
            
            18,499Commitments
                and contingencies (Note 7)Owner’s
                equity/Members’ equity:Owner’s
                equity
            
            
            —
            
            
            158,183Common
                unitholders’ interests
            
            
            187,769
            
            
            —Class
                A unitholder’s interests
            
            
            3,825
            
            
            —Accumulated
                other comprehensive income (loss)
            
            
            21,088
            
            
            (3,664
            )Total
                equity
            
            
            212,682
            
            
            154,519$
            415,463
            
            $
            315,052





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





Page
          65


**ATLAS
      ENERGY RESOURCES, LLC**




**COMBINED
      AND CONSOLIDATED STATEMENTS OF INCOME**


(in
      thousands except per unit data)





**Three
                Months****Year
                Ended**
            
            **Ended**
            
            **Years
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**
            
            **2004****REVENUES**Gas
                and oil production
            
            $
            88,449
            
            $
            24,086
            
            $
            63,499
            
            $
            48,526Well
                construction and completion
            
            
            198,567
            
            
            42,145
            
            
            134,338
            
            
            86,880Administration
                and oversight
            
            
            11,762
            
            
            2,964
            
            
            9,590
            
            
            8,396Well
                services
            
            
            12,953
            
            
            2,561
            
            
            9,552
            
            
            8,430Gathering
            
            
            9,251
            
            
            1,407
            
            
            4,359
            
            
            4,191Total
                revenues
            
            
            320,982
            
            
            73,163
            
            
            221,338
            
            
            156,423**COSTS
                AND EXPENSES**Gas
                and oil production
            
            
            13,881
            
            
            2,441
            
            
            8,165
            
            
            7,289Well
                construction and completion
            
            
            172,666
            
            
            36,648
            
            
            116,816
            
            
            75,548Well
                services
            
            
            7,337
            
            
            1,487
            
            
            5,167
            
            
            4,398Gathering
            
            
            —
            
            
            38
            
            
            52
            
            
            53Gathering
                fee - Atlas Pipeline
            
            
            29,545
            
            
            7,930
            
            
            21,929
            
            
            17,189General
                and administrative
            
            
            23,367
            
            
            5,818
            
            
            13,202
            
            
            11,708Net
                expense reimbursement - affiliate
            
            
            1,237
            
            
            163
            
            
            602
            
            
            1,050Depreciation,
                depletion and amortization
            
            
            22,491
            
            
            4,916
            
            
            14,061
            
            
            12,064Total
                operating expenses
            
            
            270,524
            
            
            59,441
            
            
            179,994
            
            
            129,299Operating
                income
            
            
            50,458
            
            
            13,722
            
            
            41,344
            
            
            27,124**OTHER
                INCOME (EXPENSES)**Interest
                income
            
            
            966
            
            
            32
            
            
            317
            
            
            250Other
                - net
            
            
            403
            
            
            25
            
            
            (238
            )
            
            194Total
                other income
            
            
            1,369
            
            
            57
            
            
            79
            
            
            444Net
                income before cumulative effect of accounting change
            
            
            51,827
            
            
            13,779
            
            
            41,423
            
            
            27,568Cumulative
                effect of accounting change
            
            
            6,355
            
            
            —
            
            
            —
            
            
            —Net
                income
            
            $
            58,182
            
            $
            13,779
            
            $
            41,423
            
            $
            27,568**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
            
            $
            41,423
            
            $
            27,568Portion
                applicable to members’ interests (period subsequent to the initial public
                offering on December 18, 2006)
            
            
            2,807
            
            
            —
            
            
            —
            
            
            —Net
                income
            
            $
            58,182
            
            $
            13,779
            
            $
            41,423
            
            $
            27,568**Allocation
                of net income attributable to members’ interests:**Common
                units
            
            $
            2,751Class
                A units
            
            
            56$
            2,807**Basic
                and diluted net income**
              **per
                common unit**
            
            $
            .08**Weighted
                average common units outstanding:**Basic
            
            
            36,627Diluted
            
            
            36,638
            
            
            —
            
            
            —
            
            
            —





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





Page
          66


**ATLAS
      ENERGY RESOURCES, LLC**




**COMBINED
      AND CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME**


(in
      thousands)





**Three
                Months****Year
                Ended**
            
            **Ended**
            
            **Years
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**
            
            **2004**Net
                income before taxes
            
            $
            58,182
            
            $
            13,779
            
            $
            41,423
            
            $
            27,568Other
                comprehensive income:Unrealized
                holding gains (losses) on hedging contracts
            
            
            31,834
            
            
            (3,664
            )
            
            —
            
            
            —Less:
                reclassification adjustment for gains realized in net
                income
            
            
            (7,082
            )
            
            —
            
            
            —
            
            
            —24,752
            
            
            (3,664
            )
            
            —
            
            
            —Comprehensive
                income
            
            $
            82,934
            
            $
            10,115
            
            $
            41,423
            
            $
            27,568





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




Page
          67


**ATLAS
      ENERGY RESOURCES, LLC**




**COMBINED
      AND CONSOLIDATED STATEMENTS OF EQUITY**


(in
      thousands, except unit data)





**Total****Accumulated**
            
            
            
            **Owner’s****Other**
            
            **Net**
            
            **Equity/****Owner’s**
            
            **Class
                A Units**
            
            **Common
                Units**
            
            **Comprehensive**
            
            **Affiliate**
            
            **Members’****Equity**
            
            **Units**
            
            **Amount**
            
            **Units**
            
            **Amount**
            
            **Income
                (Loss)**
            
            **Investment**
            
            **Equity****Balance,
                September 30, 2003**
            
            $
            102,031
            
            
            -
            
            $
            -
            
            
            -
            
            $
            -
            
            $
            -
            
            $
            102,031
            
            $
            102,031Net
                change in affiliate advances
            
            
            (20,138
            )
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            (20,138
            )
            
            (20,138
            )Net
                income
            
            
            27,568
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            27,568
            
            
            27,568**Balance,
                September 30, 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 owner prior 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 unit holders subsequent to IPO
            
            
            -
            
            
            -
            
            
            56
            
            
            -
            
            
            2,751
            
            
            -
            
            
            -
            
            
            2,807Other
                comprehensive income
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            24,752
            
            
            -
            
            
            24,752**Balance,
                December 31, 2006**
            
            $
            -
            
            
            748,456
            
            $
            3,825
            
            
            36,626,746
            
            $
            187,769
            
            $
            21,088
            
            $
            -
            
            $
            212,682





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





Page
          68


**ATLAS
      ENERGY RESOURCES, LLC**




**COMBINED
      AND CONSOLIDATED STATEMENTS OF CASH FLOWS**


(in
      thousands)





**Three
                Months****Year
                Ended**
            
            **Ended**
            
            **Years
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**
            
            **2004****CASH
                FLOWS FROM OPERATING ACTIVITIES:**Net
                income before taxes
            
            $
            58,182
            
            $
            13,779
            
            $
            41,423
            
            $
            27,568Adjustments
                to reconcile net income to net cash provided by operating
                activities:Depreciation,
                depletion and amortization
            
            
            22,491
            
            
            4,916
            
            
            14,061
            
            
            12,064Write
                down of note receivable
            
            
            3
            
            
            —
            
            
            487
            
            
            —Non-cash
                compensation on long-term incentive plans
            
            
            337
            
            
            393
            
            
            300
            
            
            64Gain
                on asset dispositions
            
            
            (39
            )
            
            (2
            )
            
            (52
            )
            
            (43
            )Cumulative
                effect of accounting change
            
            
            (6,355
            )
            
            —
            
            
            —
            
            
            —Advances
                to affiliates
            
            
            (16,748
            )
            
            (11,813
            )
            
            (25,081
            )
            
            (11,517
            )Changes
                in operating assets and liabilities:(Increase)
                decrease in accounts receivable
            
            
            (9,092
            )
            
            (4,378
            )
            
            (4,942
            )
            
            377Decrease
                in prepaid expenses
            
            
            230
            
            
            149
            
            
            2,392
            
            
            2,576Increase
                (decrease) in accounts payable
            
            
            (3,229
            )
            
            16,940
            
            
            4,340
            
            
            4,460Increase
                in liabilities associated with drilling contracts
            
            
            16,251
            
            
            9,543
            
            
            31,596
            
            
            7,922Increase
                (decrease) in other operating assets and liabilities
            
            
            1,757
            
            
            2,256
            
            
            920
            
            
            (948
            )Net
                cash provided by operating activities
            
            
            63,788
            
            
            31,783
            
            
            65,444
            
            
            42,523**CASH
                FLOWS FROM INVESTING ACTIVITIES:**Capital
                expenditures
            
            
            (75,635
            )
            
            (17,187
            )
            
            (59,124
            )
            
            (33,252
            )Proceeds
                from sale of assets
            
            
            47
            
            
            3
            
            
            111
            
            
            218Decrease
                (increase) in other assets
            
            
            —
            
            
            (1
            )
            
            (37
            )
            
            325Net
                cash used in investing activities
            
            
            (75,588
            )
            
            (17,185
            )
            
            (59,050
            )
            
            (32,709
            )**CASH
                FLOWS FROM FINANCING ACTIVITIES:**Borrowings
            
            
            —
            
            
            91
            
            
            —
            
            
            282Principal
                payments on borrowings
            
            
            (88
            )
            
            (17
            )
            
            (339
            )
            
            (56
            )Issuance
                of common stock by AAI
            
            
            —
            
            
            —
            
            
            —
            
            
            36,991Distributions
                net of capital contributions to AAI
            
            
            (139,944
            )
            
            —
            
            
            —
            
            
            —Net
                proceeds from issuance of common units
            
            
            139,944
            
            
            —
            
            
            —
            
            
            —Dividend
                to Resource America, Inc.
            
            
            —
            
            
            —
            
            
            —
            
            
            (52,133
            )Increase
                in deferred financing costs
            
            
            (197
            )
            
            —
            
            
            —
            
            
            —Decrease
                in other assets
            
            
            —
            
            
            —
            
            
            19
            
            
            —Net
                cash provided by (used in) financing activities
            
            
            (285
            )
            
            74
            
            
            (320
            )
            
            (14,916
            )Increase
                (decrease) in cash and cash equivalents
            
            
            (12,085
            )
            
            14,672
            
            
            6,074
            
            
            (5,102
            )Cash
                and cash equivalents at beginning of period
            
            
            20,918
            
            
            6,246
            
            
            172
            
            
            5,274Cash
                and cash equivalents at end of period
            
            $
            8,833
            
            $
            20,918
            
            $
            6,246
            
            $
            172





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




Page
          69




**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 limited liability company engaged
      primarily in the development and production of natural gas and, to a lesser
      extent, oil in the western New York, eastern Ohio, western Pennsylvania and
      Tennessee region of the Appalachian Basin. The Company sponsors and manages
      tax-advantaged investment partnerships, in which it coinvests to finance the
      exploitation and development of its acreage (“the Partnerships”).





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 common stock, 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. 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.





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 5). 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. 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 from
      September 30 to December 31. The combined and consolidated statements of
      income, comprehensive income, equity and cash flows reflect audited results
      for
      the year ended December 31, 2006, the three-month transition period ended
      December 31, 2005 and the years ended September 30, 2005 and 2004. The
      combined and consolidated balance sheets reflect the audited financial position
      of the Company at December 31, 2006 and 2005.





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





**Use
      of Estimates**





Preparation
      of the combined 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.





Page
          70


**ATLAS
      ENERGY RESOURCES, LLC**


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





**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 10). 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 units and unit options.
      The
      restricted 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**





The
      Company’s basic net income attributable to common unit holders per unit is
      computed by dividing the Company’s net income attributable to common unit
      holders, which is determined after the deduction of the net income allocable
      to
      AAI Class A units, by the Company’s weighted average number of common unit
      holder units outstanding during the period. The Company’s diluted net income
      attributable to common unit holders per unit is calculated by dividing the
      Company’s net income attributable to common unit holders by the sum of the
      weighted average number of the Company’s common unit holder units outstanding
      and the dilutive effect 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 10). Prior to the closing of the Company’s initial
      public offering on December 18, 2006, there were no common unit holder units
      outstanding. As such, the Company’s net income attributable to common unit
      holders per unit is only presented for the period from December 18, 2006 to
      December 31, 2006. The cumulative effect adjustment 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):





**Period
                from****December
                18, 2006 to****December
                31, 2006**Weighted
                average number of common unit holder units - basic
            
            
            36,627Add
                effect of dilutive unit incentive awards
            
            
            11Weighted
                average number of common unit holder units - diluted
            
            
            36,638





**Comprehensive
      Income**





Comprehensive
      income includes net income 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, are referred to as
      “other comprehensive income” and for the Company include only changes in the
      fair value of unrealized hedging gains and losses.





Page
          71


**ATLAS
      ENERGY RESOURCES, LLC**


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





**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, 2005
      and
      2006, the Company’s credit evaluation indicated that it had no need for an
      allowance for possible losses.





**Property
      and Equipment**





Property
      and equipment is stated at cost. Depreciation, depletion and amortization is
      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 and equipment are as follows:





Land,
                buildings and improvements
            
            
            10-40
                yearsFurniture
                and equipment
            
            
            3-7
                yearsOther
            
            
            3-10
                years





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





**December
                31,****2006**
            
            **2005**Mineral
                interests:Proved
                properties
            
            $
            1,290
            
            $
            2,308Unproved
                properties
            
            
            1,002
            
            
            1,002Wells
                and related equipment
            
            
            348,742
            
            
            273,855Land,
                building and improvements
            
            
            4,169
            
            
            4,146Support
                equipment
            
            
            5,541
            
            
            4,173Other
            
            
            4,698
            
            
            4,173365,442
            
            
            289,657Accumulated
                depreciation, depletion and amortization:Oil
                and gas properties
            
            
            (83,216
            )
            
            (71,059
            )Other
            
            
            (4,412
            )
            
            (3,897
            )(87,628
            )
            
            (74,956
            )$
            277,814
            
            $
            214,701





**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. 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.





Page
          72


**ATLAS
      ENERGY RESOURCES, LLC**


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





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 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 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.





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.





**Asset
      Retirement Obligations**





The
      Company accounts for asset retirement obligations as required under FAS
      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 FASB
      Interpretation No. 47, “Accounting for Conditional Asset Retirement
      Obligations” (“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
      FASB 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. 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 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.





Page
          73


**ATLAS
      ENERGY RESOURCES, LLC**


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





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):





**Three
                Months****Year
                Ended**
            
            **Ended**
            
            **Years
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**
            
            **2004**Net
                income as reported
            
            $
            51,827
            
            $
            13,779
            
            $
            41,423
            
            $
            27,568Proforma
                asset retirement obligation adjustment
            
            
            1,414
            
            
            576
            
            
            1,576
            
            
            1,338Proforma
                net income
            
            $
            53,241
            
            $
            14,355
            
            $
            42,999
            
            $
            28,906Proforma
                asset retirement obligation at year end
            
            $
            26,726
            
            $
            26,086
            
            $
            25,126
            
            $
            11,357





**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 because the
                Company
                marks to market all derivatives.




·
            For
                debt the carrying value approximates fair value because of the
                substantially short maturity of these
                instruments.





**Derivative
      Instruments**





The
      Company applies the provisions of SFAS No. 133, “Accounting for Derivative
      Instruments and Hedging Activities” and its various amendments (“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. All derivative activity reflected in the
      combined financial statements prior to the Company’s initial public offering was
      transacted by AAI with third parties and allocated to the Company. At the date
      of the initial public offering, all open derivative contracts were assumed
      by
      the Company.





**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, 2006 and 2005, the Company
      had
      $13.5 million and $27.4 million, respectively in deposits at various banks,
      of
      which $13.0 million and $26.7 million, respectively, was over the insurance
      limit of the Federal Deposit Insurance Corporation. No losses have been
      experienced on such investments to date.





**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.





Page
          74


**ATLAS
      ENERGY RESOURCES, LLC**


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





The
      Company accounts for environmental contingencies in accordance with SFAS
      No. 5 “Accounting for Contingencies.” Environmental expenditures that
      relate to current operations are expensed or capitalized as appropriate.
      Expenditures that relate to an existing condition caused by past operations,
      and
      do not contribute to current or future revenue generation, are 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 year ended December 31,
      2006, the three months ended December 31, 2005 and two years ended
      September 30, 2005, 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 records the income from the working interests and overriding royalties
      of wells in which it owns an interest when the gas and oil are delivered.





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, 2006 and 2005 of $19.4 million and
      $19.5 million, respectively, which are included in Accounts Receivable on its
      Combined and Consolidated Balance Sheets.





**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. Amounts paid for interest in
      all
      periods was not material.




Page
          75


**ATLAS
      ENERGY RESOURCES, LLC**


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





**Income
      Taxes**





The
      Company is a limited liability company and has elected to be treated as a
      partnership for federal income tax reporting. As a result, the Company’s income
      for federal income tax purposes is reportable on the tax returns of the
      individual unitholders. Accordingly, no recognition has been given to income
      taxes in the accompanying combined and consolidated financial statements of
      the
      Company.





Net
      income, for financial statement purposes, may differ significantly from taxable
      income reportable to unitholders as a result of differences between the tax
      bases and financial reporting bases of assets and liabilities and the taxable
      income allocation requirements under the limited liability company agreement.
      These different allocations can and usually will result in significantly
      different tax capital account balances in comparison to the capital accounts
      on
      the combined and consolidated financial statements.





The
      following table reconciles net income before taxes to pro forma federal taxable
      income for the periods indicated (in thousands, unaudited):





**Three
                Months****Year
                Ended**
            
            **Ended**
            
            **Year
                Ended****December
                31, 2006**
            
            **December
                31, 2005**
            
            **September
                30, 2005**Net
                income before taxes
            
            $
            51,827
            
            $
            13,779
            
            $
            41,423Depreciation,
                depletion and amortization for tax reporting purposes
            
            
            16,886
            
            
            (3,206
            )
            
            (10,981
            )Deferred
                revenues
            
            
            3,964
            
            
            (130
            )
            
            3,061Accrued
                expenses
            
            
            (3,884
            )
            
            (255
            )
            
            (29
            )Other
            
            
            490
            
            
            257
            
            
            32Pro
                forma federal taxable income
            
            $
            69,283
            
            $
            10,445
            
            $
            33,506





The
      Company’s financial reporting bases of its net assets exceeded the tax bases of
      its net assets by $122.3 million (unaudited) and $108.3 million
      (unaudited) at December 31, 2006 and 2005, respectively.





**Recently
      Issued Financial Accounting Standards**





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,
      and at this time the Company has not made any decision as to its application
      and
      is evaluating the impact of the adoption of SFAS 159 on the Company’s financial
      position and results of operations.





In
      September 2006, the 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. SFAS 157 is effective for the Company beginning January 1,
      2008. The Company is currently evaluating the impact of the adoption of SFAS
      157
      on its financial position and results of operations.




Page
          76


**ATLAS
      ENERGY RESOURCES, LLC**


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





In
      September 2006, the SEC staff issued Staff Accounting Bulletin No. 108,
“Considering the Effects of Prior Year Misstatements When Quantifying
      Misstatements in Current Year Financial Statements”, or SAB 108. SAB 108
      was issued to provide consistency in how registrants quantify financial
      statement misstatements. The Company initially applied SAB 108 in connection
      with the preparation of its financial statements for the year ended December
      31,
      2006. The application of SAB 108 did not have a material impact on the Company’s
      financial position or results of operations.





In
      June
      2006, the FASB issued FASB Interpretation No. 48, Accounting for
      Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109,
      (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes
      recognized in an entity’s financial statements and provides guidance on the
      recognition, de-recognition and measurement of benefits related to an entity’s
      uncertain tax positions. FIN 48 is effective for the Company beginning
      January 1, 2007. The Company does not expect the adoption of FIN 48 to have
      a significant impact on its financial position or results of operations.





**NOTE
      3—OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL**





**Other
      Assets**





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





**At
                December 31,**
            
            **At
                December 31,****2006**
            
            **2005**Long-term
                hedge receivable from Partnerships
            
            $
            2,131
            
            $
            9,340Long-term
                hedge receivable
            
            
            23,843
            
            
            —Other
            
            
            316
            
            
            237$
            26,290
            
            $
            9,577





Long-term
      hedge receivable from Partnerships represents the portion of the long-term
      unrealized hedge loss on contracts that has been reallocated to the
      Partnerships.





**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. The Company amortizes contracts acquired on the declining
      balance and straight-line methods, over their respective estimated lives,
      ranging from five to thirteen years. Amortization expense for these contracts
      for the year ended December 31, 2006, three months ended December 31, 2005
      and
      years ended September 30, 2005 and 2004 was $879,000, $220,000, $933,000, and
      $1.0 million, respectively.





The
      aggregate estimated annual amortization expense of partnership management and
      operating contracts for the next five years ending December 31 is as
      follows: 2007—$819,000; 2008—$778,000; 2009—$742,000; 2010—$710,000 and
      2011—$664,000.





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





**At
                December 31,**
            
            **At
                December 31,****2006**
            
            **2005**Cost
            
            $
            14,343
            
            $
            14,343Accumulated
                amortization
            
            
            (9,132
            )
            
            (8,253
            )$
            5,211
            
            $
            6,090






Page
          77


**ATLAS
      ENERGY RESOURCES, LLC**


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





**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, 2006
      indicated there was no impairment loss and no impairment indicators arose during
      the year ended December 31, 2006. 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 consolidated statements of income
      in the period in which the impairment is indicated.





**NOTE
      4—ASSET RETIREMENT OBLIGATIONS**





The
      Company follows SFAS No 143 “Accounting for Asset Retirement Obligations” (“SFAS
      143”) and FASB Interpretation No. 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 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****Year
                Ended**
            
            **Ended**
            
            **Years
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**
            
            **2004**Asset
                retirement obligations, beginning of period
            
            $
            18,499
            
            $
            17,651
            
            $
            4,889
            
            $
            3,131Cumulative
                effect of adoption of FIN 47
            
            
            8,042
            
            
            —
            
            
            —
            
            
            —Liabilities
                incurred
            
            
            1,570
            
            
            725
            
            
            770
            
            
            1,725Liabilities
                settled
            
            
            (194
            )
            
            —
            
            
            (137
            )
            
            (58
            )Revision
                in estimates
            
            
            (2,411
            )
            
            —
            
            
            11,788
            
            
            (205
            )Accretion
                expense
            
            
            1,220
            
            
            123
            
            
            341
            
            
            296Asset
                retirement obligations, end of period
            
            $
            26,726
            
            $
            18,499
            
            $
            17,651
            
            $
            4,889






Page
          78


**ATLAS
      ENERGY RESOURCES, LLC**


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





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





**NOTE
      5—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. The Company
      comprises substantially all of AAI’s operations, other than Atlas Pipeline
      Partners, L.P. (“Atlas Pipeline”), and therefore the Company bears substantially
      all of those costs which are reflected in general and administrative
      expense in the Company’s combined and consolidated Statements of Income.





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





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





Balance,
                October 1, 2003
            
            $
            (34,776
            )Transportation
                expense due to affiliates
            
            
            (1,687
            )Payment
                on debt to affiliate
            
            
            6,000Net operational
                settlement
            
            
            455Balance,
                September 30, 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.





Page
          79


**ATLAS
      ENERGY RESOURCES, LLC**


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





**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 10% 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
      6—DERIVATIVE INSTRUMENTS**





From
      time
      to time, the Company enters into natural gas futures and option 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.





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) and
      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, due to the loss of
      correlation between changes in gas reference prices under a hedging instrument
      and actual gas prices, the Company will discontinue hedge accounting for the
      derivative and subsequent changes in fair value for the derivative will be
      recognized immediately into earnings.





A
      portion
      of the Company’s future natural gas sales is periodically hedged through the use
      of swaps and collar contracts. Realized gains and losses on these derivative
      instruments that are classified as effective hedges are reflected in the
      contract month being hedged as an adjustment to revenue.





At
      December 31, 2006, the Company had 234 open natural gas futures contracts
      related to natural gas sales covering 54.9 million MMBtus of natural gas,
      maturing through December 31, 2010 at a combined average settlement price
      of $8.48 per MMBtu. The Company recognized a gain of $7.1 million on settled
      contracts covering natural gas production for the year ended December 31, 2006.
      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 these cash
      flow hedges. There were no gains or losses recognized on hedging in the years
      ended September 30, 2004 and 2005 and the three months ended December 31, 2005.





Of
      the
      $21.1 million net gain in accumulated other comprehensive income at December
      31,
      2006, the Company will reclassify $12.2 million of gains to its Combined and
      Consolidated Statements of Income over the next twelve month period as these
      contracts expire and $8.9 million of gains will be reclassified in later periods
      if the fair values of the instruments remain at current market values.





Page
          80


**ATLAS
      ENERGY RESOURCES, LLC**


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





As
      of
      December 31, 2006, the Company had the following natural gas volumes
      hedged:





**Fixed
      Price Swaps**




**Twelve
                Month****Period
                Ending**
            
            
            
            **Average****December
                31**
            
            **Volumes**
            
            **Fixed
                Price**
            
            **Fair
                Value Asset****(MMBtu)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands) (1)**2007
            
            
            14,650,000
            
            $
            8.60
            
            $
            25,9352008
            
            
            15,800,000
            
            $
            8.91
            
            
            11,4502009
            
            
            15,720,000
            
            $
            8.31
            
            
            7,6902010
            
            
            5,400,000
            
            $
            7.53
            
            
            587$
            45,662





**Costless
      Collars**




**Twelve
                Month****Period
                Ending**
            
            
            
            
            
            **Average****December
                31**
            
            **Option
                Type**
            
            **Volumes**
            
            **Floor
                and Cap**
            
            **Fair
                Value Asset****(MMBtu)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands) (1)**2007
            
            
            Puts
                purchased
            
            
            1,800,000
            
            $
            7.50
                - 8.60
            
            $
            1,5112007
            
            
            Calls
                sold
            
            
            1,800,000
            
            $
            7.50
                - 8.60
            
            
            -2008
            
            
            Puts
                purchased
            
            
            1,560,000
            
            $
            7.50
                - 9.40
            
            
            2812008
            
            
            Calls
                sold
            
            
            1,560,000
            
            $
            7.50
                - 9.40
            
            
            -$
            1,792Total
                Net Asset
            
            
            
            
            
            
            
            
            
            
            $
            47,454





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





The
      following table sets forth the book and estimated fair values of derivative
      instruments (in thousands):





**December
                31, 2006****Book
                Value**
            
            **Fair
                Value**AssetsDerivative
                instruments
            
            $
            51,461
            
            $
            51,461$
            51,461
            
            $
            51,461LiabilitiesDerivative
                instruments
            
            $
            (4,007
            )
            $
            (4,007
            )$
            (4,007
            )
            $
            (4,007
            )$
            47,454
            
            $
            47,454





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





Unrealized
                hedge gain - short-term
            
            $
            27,618Other
                assets - long-term
            
            
            23,843Accrued
                liabilities - short-term
            
            
            (172
            )Unrealized
                hedge loss - long-term
            
            
            (3,835
            )$
            47,454






Page
          81


**ATLAS
      ENERGY RESOURCES, LLC**


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





Of
      the
      $47.5 million net unrealized hedge gain at December 31, 2006, the Company’s
      retained portion of $21.1 million is included in accumulated other comprehensive
      income and $26.4 million has been allocated to the Partnerships and included
      in
      the Combined and Consolidated Balance Sheets as follows (in thousands):





Unrealized
                hedge gain - short-term
            
            $
            96Other
                assets - long-term
            
            
            2,131Accrued
                liabilities - short-term
            
            
            (15,345
            )Unrealized
                hedge loss - long-term
            
            
            (13,248
            )$
            (26,366
            )





**NOTE
      7—COMMITMENTS AND CONTINGENCIES**





The
      Company leases office space and equipment under leases with varying expiration
      dates through 2014. Rental expense was $670,000, $136,000, $1.2 million and
      $479,000 for the year ended December 31, 2006, three months ended December
      31,
      2005, and years ended September 30, 2005 and 2004, respectively. Future
      minimum rental commitments for the next five annual periods are as follows
      (in
      thousands):





2007
            
            $
            6492008
            
            
            5362009
            
            
            3292010
            
            
            1482011
            
            
            107





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
      and certain other benefits. The agreements also provide for severance payments
      under certain circumstances in which some of these obligations may be allocable
      to the Company.





One
      of
      the Company’s subsidiaries, Resource Energy, LLC, together with Resource
      America, is 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 alleges that the defendants are not paying
      landowners the proper amount of royalty revenues with respect to natural gas
      produced from the leased properties. The complaint seeks 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 October 2006 a tentative settlement of this lawsuit was reached, the terms
      of
      which are subject to final approval by the court. Pursuant to the tentative
      settlement terms, AAI has agreed to pay $300,000, upgrade certain gathering
      systems and cap certain transportation expenses chargeable to the land owners.
      The Company is indemnified by AAI for this legal action pursuant to the
      contribution agreement.





The
      Company is also a party to various routine legal proceedings arising out 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.





Page
          82


**ATLAS
      ENERGY RESOURCES, LLC**


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





**NOTE
      8—LONG-TERM DEBT**





Upon
      the
      closing of its initial public offering in December 2006, the Company entered
      into a $250 million senior secured credit facility, which is led by Wachovia
      Bank, N.A. (“Wachovia”). The revolving credit facility has a current borrowing
      base of $155.0 million which may be redetermined subject to changes in the
      Company’s oil and gas reserves. Up to $50.0 million of the facility may be in
      the form of standby letters of credit ($495,000 outstanding at December 31,
      2006). The facility is secured by the Company’s assets 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.





The
      base
      rate for any day equals the higher of the federal funds rate plus 0.50% or
      the
      Wachovia 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 Euro currency funding. The applicable margin ranges from 0.0%
      to
      0.75% for base rate loans and 1.00% to 1.75% for LIBOR loans.





The
      Wachovia credit facility requires the Company to maintain specified ratios
      of
      current assets to current liabilities, interest coverage (as defined), and
      debt
      to earnings before interest, taxes, depreciation, depletion and amortization
      (“EBITDA”). In addition, the facility limits sales, leases or transfers of
      assets and the incurrence of additional indebtedness. The Company is in
      compliance with these covenants as of December 31, 2006. The facility terminates
      in December 2011, when all outstanding borrowings must be repaid.





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





**At
                December 31,**
            
            **At
                December 31,****2006**
            
            **2005**Loans
                secured by vehicles and equipment
            
            $
            68
            
            $
            156Less
                current maturities
            
            
            (38
            )
            
            (88
            )Long-term
                debt
            
            $
            30
            
            $
            68





Maturities
      of long-term debt are as follows (in thousands):





Years
                ended December 31,2007
            
            $
            382008
            
            
            30$
            68





**NOTE
      9—OPERATING SEGMENT INFORMATION**





The
      Company’s operations include two reportable operating segments. These operating
      segments reflect the way the Company manages its operations and makes business
      decisions. Operating segment data for the periods indicated are as follows
      (in
      thousands):





Page
          83


**ATLAS
      ENERGY RESOURCES, LLC**


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





**Three
                Months****Year
                Ended**
            
            **Ended**
            
            **Years
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**
            
            **2004**Gas
                and oil productionRevenues
            
            $
            88,449
            
            $
            24,086
            
            $
            63,499
            
            $
            48,526Costs
                and expenses
            
            
            13,881
            
            
            2,441
            
            
            8,165
            
            
            7,289Segment
                profit
            
            $
            74,568
            
            $
            21,645
            
            $
            55,334
            
            $
            41,237Partnership
                managementRevenues
            
            $
            232,533
            
            $
            49,077
            
            $
            157,839
            
            $
            107,897Costs
                and expenses
            
            
            209,548
            
            
            46,103
            
            
            143,964
            
            
            97,188Segment
                profit
            
            $
            22,985
            
            $
            2,974
            
            $
            13,875
            
            $
            10,709





**Three
                Months****Year
                Ended**
            
            **Ended**
            
            **Years
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**
            
            **2004**Reconciliation
                of segment profit to net incomeSegment
                profitGas
                and oil production
            
            $
            74,568
            
            $
            21,645
            
            $
            55,334
            
            $
            41,237Partnership
                management
            
            
            22,985
            
            
            2,974
            
            
            13,875
            
            
            10,709Total
                segment profit
            
            
            97,553
            
            
            24,619
            
            
            69,209
            
            
            51,946General
                and administrative
            
            
            (23,367
            )
            
            (5,818
            )
            
            (13,202
            )
            
            (11,708
            )Compensation
                reimbursement - affiliate
            
            
            (1,237
            )
            
            (163
            )
            
            (602
            )
            
            (1,050
            )Depreciation,
                depletion and amortization
            
            
            (22,491
            )
            
            (4,916
            )
            
            (14,061
            )
            
            (12,064
            )Other
                income - net
            
            
            1,369
            
            
            57
            
            
            79
            
            
            444Net
                income before cumulative effect of accounting change
            
            $
            51,827
            
            $
            13,779
            
            $
            41,423
            
            $
            27,568Capital
                expendituresGas
                and oil production
            
            $
            74,075
            
            $
            16,610
            
            $
            57,894
            
            $
            32,172Partnership
                management
            
            
            1,042
            
            
            445
            
            
            747
            
            
            599Corporate
            
            
            518
            
            
            132
            
            
            483
            
            
            481$
            75,635
            
            $
            17,187
            
            $
            59,124
            
            $
            33,252Balance
                sheetsGoodwillGas
                and oil production
            
            $
            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 production
            
            $
            377,807
            
            $
            254,831
            
            $
            233,855
            
            $
            168,715Partnership
                management
            
            
            26,474
            
            
            37,050
            
            
            27,115
            
            
            28,563Corporate
            
            
            11,182
            
            
            23,171
            
            
            9,432
            
            
            1,176$
            415,463
            
            $
            315,052
            
            $
            270,402
            
            $
            198,454






Page
          84


**ATLAS
      ENERGY RESOURCES, LLC**


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





For
      the
      years ended September 30, 2004 and 2005, gas sales to Hess Corporation (formerly
      FirstEnergy Solutions Corp.) accounted for 18% and 13%, respectively, of total
      revenues. No other operating segments had revenues from a single customer which
      exceeded 10% of total revenues.





**NOTE
      10 - 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 or unit options for an aggregate of
      3,742,000 common units.





*Restricted
      Stock Units.* Under
      the ATN LTIP, 47,619 restricted stock units were awarded in 2006, each unit
      representing the right to receive one share of the Company’s common units upon
      vesting. Units will vest 25% per year over a four year service period. The
      fair
      value of the grants is based on the price of closing stock price on the grant
      date, and is being charged to operations over the requisite service periods.
      Upon termination of service by a grantee, all unvested units are forfeited.
      The
      Company recognized $187,000 in compensation expense related to restricted stock
      units for the year ended December 31, 2006. At December 31, 2006, the Company
      had approximately $813,000 million of unrecognized compensation expense related
      to the unvested portion of the restricted stock units.





The
      following table summarizes the activity of restricted stock units for the year
      ended December 31, 2006:





**Weighted****Weighted**
            
            **Average**
            
            **Aggregate****Average**
            
            **Remaining**
            
            **Intrinsic****Grant
                Date**
            
            **Contractual**
            
            **Value****Units**
            
            **Fair
                Value**
            
            **Term
                (in years)**
            
            **(in
                thousands)**Non-vested
                shares outstanding atDecember
                31,
                2005
            
            
            -
            
            $
            -
            
            
            -Granted
            
            
            47,619
            
            $
            21.00
            
            
            3.3Vested
            
            
            -
            
            $
            -
            
            
            -Forfeited
            
            
            -
            
            $
            -
            
            
            -Non-vested
                shares outstanding at December 31, 2006
            
            
            47,619
            
            $
            21.00
            
            
            3.3
            
            $
            1,080





*Stock
      Options* .
      In
      December 2006, 373,752 unit options were awarded under the ATN LTIP. Unit option
      awards expire 10 years from the date of grant, and will vest 25% each year
      from
      the date of grant. The Black-Scholes option pricing model was used to estimate
      the weighted average fair value of $2.14 per unit option granted with the
      following assumptions (a) expected dividend yield of 8.0%, (b) risk-free
      interest rate of 4.4%, (c) expected volatility of 25.0%, and (d) an expected
      life of 6.25 years. The Company recognized $150,000 in compensation expense
      related to options granted for the year ended December 31, 2006. At December
      31,
      2006, the Company had approximately $650,000 of unrecognized compensation
      expense related to the unvested portion of the option units.





Page
          85


**ATLAS
      ENERGY RESOURCES, LLC**


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





The
      following table sets forth ATN LTIP’s option unit activity for the year ended
      December 31, 2006:





**Weighted****Average**
            
            **Aggregate****Weighted**
            
            **Remaining**
            
            **Intrinsic****Average**
            
            **Contractual**
            
            **Value****Shares**
            
            **Exercise
                Price**
            
            **Term
                (in years)**
            
            **(in
                thousands)**Outstanding
                at December 31, 2005
            
            
            -
            
            $
            -
            
            
            -Granted
            
            
            373,752
            
            $
            21.00
            
            
            9.3Exercised
            
            
            -
            
            $
            -
            
            
            -Forfeited
                or expired
            
            
            -
            
            $
            -
            
            
            -Outstanding
                at December 31, 2006
            
            
            373,752
            
            $
            21.10
            
            
            9.3
            
            $
            624Options
                exercisable at December 31, 2006
            
            
            0Available
                for grant
            
            
            3,320,629





**NOTE
      11 - DISTRIBUTIONS**





On
      January 24, 2007, the Company declared its initial quarterly cash distribution
      for the fourth quarter 2006 of $0.06 per common unit, which represents a
      pro-rated distribution of $0.42 per common unit for the period from December
      18,
      2006, the date of its initial public offering, through December 31, 2006. The
      $2.2 million distribution was paid on February 14, 2007 to unit holders of
      record as of February 7, 2007.





**NOTE
      12—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****Year
                Ended**
            
            **Ended**
            
            **Years
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**
            
            **2004**Revenues
            
            $
            88,449
            
            $
            24,086
            
            $
            63,499
            
            $
            48,526Production
                costs
            
            
            (13,881
            )
            
            (2,441
            )
            
            (8,165
            )
            
            (7,289
            )Exploration
                expenses
            
            
            (3,016
            )
            
            (17
            )
            
            (904
            )
            
            (1,549
            )Depreciation,
                depletion and amortization
            
            
            (20,600
            )
            
            (4,477
            )
            
            (12,288
            )
            
            (10,319
            )Results
                of operations from oil and gas producing activities
            
            $
            50,952
            
            $
            17,151
            
            $
            42,142
            
            $
            29,369






Page
          86


**ATLAS
      ENERGY RESOURCES, LLC**


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





*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,**
            
            **At
                December 31,****2006**
            
            **2005**Mineral
                interests:Proved
                properties
            
            $
            1,290
            
            $
            2,308Unproved
                properties
            
            
            1,002
            
            
            1,002Wells
                and related equipment
            
            
            348,691
            
            
            273,804Support
                equipment
            
            
            5,541
            
            
            4,173Uncompleted
                well equipment and facilities
            
            
            51
            
            
            51356,575
            
            
            281,338Accumulated
                depreciation, depletion and amortization
            
            
            (83,216
            )
            
            (71,059
            )Net
                capitalized costs
            
            $
            273,359
            
            $
            210,279





*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****Year
                Ended**
            
            **Ended**
            
            **Years
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**
            
            **2004**Property
                acquisition costs:Proved
                properties
            
            $
            1,322
            
            $
            —
            
            $
            308
            
            $
            1,700Unproved
                properties
            
            
            —
            
            
            —
            
            
            —
            
            
            439Exploration
                costs
            
            
            6,847
            
            
            1,312
            
            
            904
            
            
            1,549Development
                costs
            
            
            76,687
            
            
            17,380
            
            
            72,308
            
            
            39,978$
            84,856
            
            $
            18,692
            
            $
            73,520
            
            $
            43,666





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





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 Wright & Company, Inc., an independent petroleum
      engineering firm, as of September 30, 2004 and 2005 and as of December 31,
      2005 and 2006. All reserves are located within the United States. 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.





Page
          87


**ATLAS
      ENERGY RESOURCES, LLC**


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





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.





Page
          88


**ATLAS
      ENERGY RESOURCES, LLC**


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





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





**Gas**
            
            **Oil****(Mcf)**
            
            **(Bbls)**Balance
                September 30, 2003
            
            
            133,292,755
            
            
            1,854,674Current
                additions
            
            
            28,761,902
            
            
            245,509Sales
                of reserves in-place
            
            
            (3,439
            )
            
            (1,669
            )Purchase
                of reserves in-place
            
            
            232,429
            
            
            4,000Transfers
                to limited partnerships
            
            
            (10,132,616
            )
            
            (29,394
            )Revisions
            
            
            (2,732,385
            )
            
            382,613Production
            
            
            (7,285,281
            )
            
            (181,021
            )Balance
                September 30, 2004
            
            
            142,133,365
            
            
            2,274,712Current
                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
            
            
            2,259,289Current
                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
            
            
            2,257,211Current
                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
            
            
            2,067,646Proved
                developed reserves at:September
                30, 2003
            
            
            87,760,113
            
            
            1,825,280September
                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
            
            
            2,064,276






Page
          89




**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (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, 2004 and 2005 and December 31, 2005
      and 2006 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, September 30, 2005 and 2004 reflect values for
      Atlas America E&P Operations, which were subject to Federal and state income
      taxes. Amounts shown for December 31, 2006 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 calculation of standardized
      measure.





**Three
                Months****Year
                Ended**
            
            **Ended**
            
            **Years
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**
            
            **2004****(in
                thousands)**Future
                cash inflows
            
            $
            1,262,161
            
            $
            1,874,432
            
            $
            2,503,644
            
            $
            1,096,047Future
                production costs
            
            
            (334,062
            )
            
            (290,600
            )
            
            (296,015
            )
            
            (227,738
            )Future
                development costs
            
            
            (149,610
            )
            
            (107,784
            )
            
            (117,256
            )
            
            (92,079
            )Future
                income tax expense
            
            
            −
            
            
            (445,004
            )
            
            (607,624
            )
            
            (227,862
            )Future
                net cash flows
            
            
            778,489
            
            
            1,031,044
            
            
            1,482,749
            
            
            548,368Less
                10% annual discount for estimating timing of cash flows
            
            
            (495,048
            )
            
            (601,772
            )
            
            (876,052
            )
            
            (315,370
            )Standardized
                measure of discounted future net cash flows
            
            $
            283,441
            
            $
            429,272
            
            $
            606,697
            
            $
            232,998





The
      future cash flows estimated to be spent to develop proved undeveloped properties
      in the years ended December 31, 2007, 2008 and 2009 are $48.1 million, $50.8
      million and $50.7 million, respectively.





Page
          90


**ATLAS
      ENERGY RESOURCES, LLC**


**NOTES
      TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (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 years ended September 30, 2005 and 2004. Since the Company
      allocates taxable income to unitholders, no recognition has been given to income
      taxes for the year ended December 31, 2006, and the balance at the beginning
      of
      the period has been adjusted to exclude income taxes.





**Three
                Months****Year
                Ended**
            
            **Ended**
            
            **Years
                Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,****2006**
            
            **2005**
            
            **2005**
            
            **2004**Balance,
                beginning of period
            
            $
            597,137
            
            $
            606,697
            
            $
            232,998
            
            $
            144,351Increase
                (decrease) in discounted future net cash flows:Sales
                and transfers of oil and gas, net of related costs
            
            
            (74,567
            )
            
            (21,645
            )
            
            (55,333
            )
            
            (41,237
            )Net
                changes in prices and production costs
            
            
            (273,631
            )
            
            (245,838
            )
            
            417,798
            
            
            97,161Revisions
                of previous quantity estimates
            
            
            (30,058
            )
            
            (4,571
            )
            
            (6,073
            )
            
            6,265Development
                costs incurred
            
            
            3,426
            
            
            2,727
            
            
            4,224
            
            
            4,838Changes
                in future development costs
            
            
            (8,505
            )
            
            (1,159
            )
            
            (1,577
            )
            
            (1,033
            )Transfers
                to limited partnerships
            
            
            (8,449
            )
            
            (8,563
            )
            
            (24,750
            )
            
            (9,499
            )Extensions,
                discoveries, and improved recovery less related costs
            
            
            44,820
            
            
            22,597
            
            
            154,215
            
            
            54,979Purchases
                of reserves in place
            
            
            660
            
            
            24
            
            
            596
            
            
            594Sales
                of reserves in place, net of tax effect
            
            
            (572
            )
            
            (243
            )
            
            (672
            )
            
            (33
            )Accretion
                of discount
            
            
            59,714
            
            
            21,141
            
            
            32,038
            
            
            19,142Net
                changes in future income taxes
            
            
            −
            
            
            71,614
            
            
            (151,882
            )
            
            (40,504
            )Estimated
                settlement of asset retirement obligations
            
            
            (8,226
            )
            
            (848
            )
            
            (12,763
            )
            
            (1,757
            )Estimated
                proceeds on disposals of well equipment
            
            
            10,007
            
            
            998
            
            
            12,740
            
            
            2,055Other
            
            
            (28,315
            )
            
            (13,659
            )
            
            5,138
            
            
            (2,324
            )Balance,
                end of period
            
            $
            283,441
            
            $
            429,272
            
            $
            606,697
            
            $
            232,998






Page
          91


**ATLAS
      ENERGY RESOURCES, LLC**


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


**NOTE
      13 - QUARTERLY RESULTS (Unaudited)**





**March
                31,**
            
            **June
                30**
            
            **September
                30,**
            
            **December
                31,****(in
                thousands, except unit data)****Year
                ended December 31, 2006**Revenues
            
            $
            80,320
            
            $
            65,036
            
            $
            81,556
            
            $
            94,070Income
                from continuing operations before cumulative effect of accounting
                change:Portion
                applicable to owner’s interest
            
            $
            12,509
            
            $
            12,559
            
            $
            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
            
            $
            12,509
            
            $
            12,559
            
            $
            11,466
            
            $
            15,293Net
                income before cumulative effect of accounting change per common unit
                -
                basic and diluted
            
            $
            —
            
            $
            —
            
            $
            —
            
            $
            0.08Cumulative
                effect of accounting change
            
            
            —
            
            
            —
            
            
            —
            
            
            6,355Net
                income
            
            $
            12,509
            
            $
            12,559
            
            $
            11,466
            
            $
            21,648








**December
                31**
            
            **March
                31**
            
            **June
                30**
            
            **September
                30****(in
                thousands)****Year
                ended September 30, 2005**Revenues
            
            $
            50,780
            
            $
            60,431
            
            $
            49,737
            
            $
            60,390Net
                income
            
            $
            10,388
            
            $
            9,519
            
            $
            11,191
            
            $
            10,325






Page
          92





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





None.





**ITEM
              9A.**
            **CONTROLS
                AND PROCEDURES**





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




As
        of the
        end of the period covered by this annual report on Form 10-K, our chief
        executive officer and chief financial officer conducted an evaluation of
        our
        disclosure controls and procedures (as defined in Rules 13a-15(e) of the
        Securities Exchange Act). Based upon this evaluation, our chief executive
        officer and chief financial officer concluded that our disclosure controls
        and
        procedures are effective in alerting them in a timely manner of any material
        information relating to us that is required to be disclosed by us in the
        reports
        we file or submit under the Securities Exchange Act.
 
 This
        annual report does not include a report of management's assessment regarding
        internal control over financial reporting or attestation report of our
        registered public accounting firm due to a transition period established
        by
        rules of the Securities and Exchange Commission for newly public
        companies.


**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 both of the board of
      directors’ committees: the conflicts committee and the audit 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 unitholders and not a breach of obligation to us or to
      our
      unitholders. 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.




Page
          93





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
            
            68
            
            Chairman
                of the Board and Chief Executive OfficerJonathan
                Z. Cohen
            
            36
            
            Vice
                Chairman of the BoardMatthew
                A. Jones
            
            45
            
            Chief
                Financial Officer and DirectorRichard
                D. Weber
            
            43
            
            President,
                Chief Operating Officer and DirectorNancy
                J. McGurk
            
            51
            
            Chief
                Accounting OfficerLisa
                Washington
            
            39
            
            Chief
                Legal Officer and SecretaryWalter
                C. Jones
            
            43
            
            DirectorEllen
                F. Warren
            
            50
            
            DirectorBruce
                M. Wolf
            
            58
            
            Director





**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) since 1998; 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.




Page
          94


**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.





**Independent
      Directors**





**Walter
      C. Jones** has been
      the General Counsel and Senior Director of Private Equity for GRAVITAS Capital
      Advisors, LLC, an independent investment advisory firm since May 2005. 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 for seven years a senior officer in the
      Finance Department.





**Ellen
      F. 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
      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.




Page
          95





**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 2006, our executive officers, directors and greater
      than
      10% stockholders complied with all applicable filing requirements of Section
      16(a) of the Securities Exchange Act, except Messrs. M. Jones, Weber and Wolf
      and Ms. Washington inadvertently each filed one Form 4 late.





**Compensation
      Committee Interlocks and Insider Participation**





We
      do not
      have a compensation committee. Compensation of the personnel of Atlas America
      and its affiliates who provide us with services is 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.





Page
          96


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





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 a charter for the audit committee. We will
      make a printed copy of our code of ethics, our Company Governance Guidelines
      and
      our audit committee charter available to any unitholder who so requests.
      Requests for print copies may be directed to us as follows: Atlas Energy
      Resources, LLC, 311 Rouser Road, Moon Township, Pennsylvania 15108, Attention:
      Secretary. Each of the code of business conduct and ethics, the Company
      Governance Guidelines and the audit committee charter are posted on our website
      at www.atlasenergyresources.com .





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





Compensation
      Discussion and Analysis





The
      compensation committee of Atlas America, our parent, is 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 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 our named executive officers’ 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 named executive officers for fiscal 2006
      specifically was intended:





·
            to
                encourage and reward strong performance;
                and




·
            to
                motivate our named executive officers by providing them with a meaningful
                equity stake in our company.





Accounting
      and cost implications of compensation programs are considered in program design;
      however, the main driver of design is alignment with our business
      needs.





Overview
      of Compensation Process





The
      compensation committee retained Mercer Human Resource Consulting in June 2006
      to
      analyze and review the competitiveness and appropriateness of all elements
      of
      the total compensation (base salary and annual and long-term incentives) paid
      by
      Atlas America to its executive officers, including our named executive officers,
      individually and as a group. Mercer was asked to review compensation Atlas
      America awarded during 2005 and to assist the compensation committee in its
      analysis of 2006 awards. Mercer and the compensation committee looked not only
      to the oil and energy industry (adjusted for scope by position) in evaluating
      Atlas America’s compensation levels but also, as appropriate, to the financial
      services industry.





The
      compensation committee focused on Atlas America’s equity performance, market
      capitalization, corporate developments, business performance and financial
      position in determining the compensation for those executive officers who
      provided services to both Atlas America and to us.




Page
          97





Our
      chief
      executive officer provided the compensation committee with statistical data
      and
      recommendations to assist it in determining compensation levels. While the
      compensation committee utilized this information and valued Mr. E. Cohen’s
      observations with regard to Atlas America’s performance, our performance and the
      performance of the named executive officers, the compensation committee also
      considered the analysis, recommendations, and review provided by Mercer.
      Ultimately the decisions regarding executive compensation were made by the
      compensation committee after extensive discussion regarding appropriate
      compensation and were approved by Atlas America’s Board of Directors and our
      board.





In
      addition to making decisions regarding compensation for the named executive
      officers, during 2006, the compensation committee also developed and articulated
      a compensation philosophy based on Atlas America’s and our business strategy,
      significant growth, organizational structure, and future objectives. The
      compensation philosophy includes a frame of reference for compensation
      comparisons, target positioning, and objectives by pay element.





Additionally,
      the compensation committee established a formalized process for approving future
      compensation decisions, including base salary increases and annual and long-term
      incentive awards.





Elements
      of our Compensation Program





Base
      Salary





Base
      salary is intended to provide fixed compensation to the named executive officers
      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. Mercer’s analysis of compensation of executive officers within the energy
      industry (adjusted for scope by position) confirmed that the base salaries
      paid
      to the named executive officers in fiscal 2006 fall between the median and
      the
      75 th percentile of the energy industry. Mercer also referenced financial services
      data where appropriate.




Salary
      allocations to us by Atlas America for 2006 reflect the fact that we completed
      our initial public offering in December 2006.





Annual
      Incentives





Annual
      incentives are intended to tie a significant portion of each of the named
      executive officer’s compensation to Atlas America’s annual performance and, our
      annual performance and/or to the performance of one of Atlas America’s
      subsidiaries or divisions for which he or she is responsible. Additionally,
      the
      annual incentive allows Atlas America to recognize an individual’s performance
      in relation to Atlas America’s performance or that of one of its subsidiaries or
      divisions. 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.





Long-Term
      Incentives





We
      believe that our long term success depends upon aligning executives’ and
      unitholders’ interests. To support this objective, we will provide our
      executives with the opportunity to become significant shareholders, through
      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 named executive officers who do not work full time for us also are eligible
      to receive awards under 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.





Historically,
      the date upon which equity awards have been granted has not been fixed. If
      we do
      grant equity awards in the future, we shall do so in February of each
      year.





Page
          98


Supplemental
      Benefits, Deferred Compensation and Perquisites





We
      do not
      emphasize supplemental benefits for executives, and perquisites are discouraged.
      None of our named executive officers have deferred any portion of their
      compensation.





Compensation
      Determination





In
      determining compensation amounts awarded, the compensation committee focused
      on
      specific contributions by the named executive officers to the overall
      performance of Atlas America and its subsidiaries, including us during
      2006.





The
      following table sets forth the compensation allocation for fiscal year 2006
      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, the APL Plan and the AHD Plan.





**2006
      Summary Compensation Table**





**Stock**
            
            
            
            **Option**
            
            
            
            **All
                Other****Name
                and**
            
            
            
            **Salary**
            
            **Awards**
            
            
            
            **Awards**
            
            
            
            **Compensation**
            
            
            
            **Total****Principal
                Position**
            
            **Year**
            
            **($)**
            
            **($)**
            
            
            
            **($)**
            
            
            
            **($)**
            
            
            
            **($)**Edward
                E. Cohen, Chairman of the Board and Chief Executive
                Officer
            
            
            2006
            
            $
            27,391
            
            $
            674,625
            
            
            (1)
            
            $
            84,861
            
            
            (2)
            
            $
            32,300
            
            
            (3)
            
            $
            819,177Matthew
                A. Jones, Chief Financial Officer
            
            
            2006
            
            $
            13,696
            
            $
            276,546
            
            
            (1)
            
            $
            324,172
            
            
            (2)
            
            $
            7,650
            
            
            (4)
            
            $
            622,064Richard
                D. Weber, President and Chief Operating Officer
            
            
            2006
            
            $
            15,217
            
            $
            187,504
            
            
            (5)
            
            $
            347,779
            
            
            (6)
            
            $
            —
            
            
            
            
            $
            550,500





(1)
            Represents
                the dollar amount of (i) expense recognized by Atlas Pipeline Holdings
                for
                financial statement reporting purposes with respect to phantom units
                granted under the AHD Plan, and (ii) expense recognized by Atlas
                Pipeline
                for financial statement reporting purposes with respect to phantom
                units
                granted under the APL Plan, all in accordance with FAS
                123R.(2)
            Represents
                the dollar amount of (i) expense recognized for financial statement
                reporting purposes by Atlas Pipeline Holdings for options granted
                under
                the AHD Plan and (ii) for Mr. Jones, also includes expense recognized
                for
                financial reporting purposes by Atlas America for options granted
                under
                the Atlas Plan, all in accordance with FAS 123R.(3)
            Represents
                payments on distribution equivalent rights (“DERs”) of $17,000 with
                respect to the phantom units awarded under the APL Plan and $15,300
                with
                respect to phantom units awarded under the AHD Plan.(4)
            Represents
                payments on DERs of $4,250 with respect to the phantom units awarded
                under
                the APL Plan and $3,400 with respect to phantom units awarded under
                the
                AHD Plan.(5)
            Represents
                the dollar amount of expense we recognized for financial statement
                reporting purposes with respect to restricted units granted under
                our Plan
                (see Note 10 to our combined and consolidated financial
                statements), in accordance with FAS 123R.(6)
            Represents
                the dollar amount of (i) expense we recognized for financial statement
                reporting purposes with respect to options granted under our Plan
                (see Note 10 to our combined and consolidated financial statements)
                and (ii) expense recognized by Atlas America for financial statement
                reporting purposes with respect to options granted under the Atlas
                Plan,
                all in accordance with FAS 123R.




As
      required by SEC guidance, the following table discloses awards under the Atlas
      Plan, the APL Plan , and the AHD Plan.





Page
          99





**2006
      GRANTS OF PLAN-BASED AWARDS TABLE**





**All
                Other**
            
            
            
            **All
                Other****Stock
                Awards:**
            
            
            
            **Option
                Awards:****Number
                of Shares**
            
            
            
            **Number
                of Securities**
            
            
            
            **Exercise
                  or**
                **Base**
            
            **Grant
                  Date**
                **Fair
                  Value of****Grant**
            
            **Approval**
            
            **Of
                Stock or Units**
            
            
            
            **Underlying
                Options**
            
            
            
            **Price
                of**
              **Option
                Awards**
            
            **Stock
                and Option Awards****Name**
            
            **Date**
            
            **Date**
            
            **(#)**
            
            
            
            **(#)**
            
            
            
            **($
                / unit)**Edward
                E. Cohen
            
            
            11/01/06
            
            
            10/31/06
            
            
            20,000
            
            
            (1)
            
            
            —
            
            
            
            
            
            —
            $
            943,800
            (1)11/10/06
            
            
            10/31/06
            
            
            90,000
            
            
            (2)
            
            
            500,000
            
            
            (3)
            
            $
            22.56
            $
            2,030,400
            (2)$
            1,880,000
            (3)Matthew
                A. Jones
            
            
            11/01/06
            
            
            10/31/06
            
            
            5,000
            
            
            (1)
            
            
            —
            
            
            
            
            
            —
            $
            235,950
            (1)11/10/06
            
            
            10/31/06
            
            
            20,000
            
            
            (2)
            
            
            100,000
            
            
            (3)
            
            $
            22.56
            $
            451,200
            (2)$
            376,000
            (3)Richard
                D. Weber
            
            
            4/17/06
            
            
            4/03/06
            
            
            —
            
            
            
            
            
            50,000
            
            
            (4)
            
            $
            47.86
            $
            1,055,000
            (4)





(1)
            Represents
                grants of phantom units under the APL Plan, which vest 25% per year
                on the
                anniversary of the grant, valued in accordance with FAS 123R at the
                closing price of Atlas Pipeline’s common units on the grant date of
                $47.19.(2)
            Represents
                grants of phantom units under the AHD 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 Atlas Pipeline Holdings’
                common units on the grant date of $22.56.(3)
            Represents
                grants of stock options under the AHD Plan, which vest 25% on the
                third
                anniversary and 75% on the fourth anniversary of the grant valued
                at $3.76
                per option usingthe 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 4.0%, (b) risk-free interest rate
                of
                4.5%, (c) expected volatility of 20.0%, and (d) an expected life
                of 6.9
                years.(4)
            Represents
                grants of stock options under the Atlas 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, except as described below under “—Richard D. Weber
                Employment Agreement”, valued at $21.10, per share using the Black-Scholes
                option pricing model to estimate the weighted average fair value
                of each
                option granted for 50,000 shares with weighted average assumptions
                for (a)
                expected dividend yield of $-0-, (b) risk-free interest rate of 4.8%,
                (c)
                expected volatility of 35%, and (d) an expected life of 6.25 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:




·
            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:




Page
          100




·
            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
      reason for the change of control triggering events relating to the
      disaffiliation of Messrs. Cohen from our company or Atlas America is that
      Mr. Weber believed that Messrs. Cohen effectively controlled us at the time
      of his employment and their separation from us 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 our 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 Atlas
      America’s 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.





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, Atlas Energy Management
                will (a) 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 and (b) Mr. Weber’s family will receive
                health insurance coverage for one year.




·
            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, 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.





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, 2006, we estimate that
      the value of the benefits to Mr. Weber would have been as follows:





**Accelerated****Lump
                Sum**
            
            
            
            **Vesting
                of Stock****Severance**
            
            
            
            **Awards
                and**
            
            **Tax****Reason
                for Termination**
            
            **Payment**
            
            **Benefits****(1)**
            
            **Option
                Awards****(2)**
            
            **Gross-up**Death
            
            $
            800,000
            (3)
            $
            18,185
            
            $
            —
            
            $
            —Disability
            
            
            —
            
            
            22,131
            
            
            —
            
            
            —Termination
                by us without cause (including for disability) or by Mr. Weber for
                good reason
            
            
            1,923
            (4)
            
            22,131
            
            
            1,055,000
            
            
            —Change
                of control
            
            
            —
            
            
            —
            
            
            1,055,000
            
            
            —Termination
                by Mr. Weber without cause
            
            
            —
            
            
            —
            
            
            —
            
            
            —




(1)
              Represents
                  rates currently in effect for COBRA insurance benefits for 12
                  months.




Page
          101




(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
                29,
                2006.





(3)
            Calculated
                as the sum of Mr. Weber’s 2006 base salary and
                bonus.





(4)
            Represents
                Mr. Weber’s 2006 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.





Atlas
      Plan





The
      Atlas
      Plan authorizes the granting of up to 2.0 million shares of Atlas 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.





AHD
      Plan





The
      AHD
      Plan provides performance incentive awards to officers, employees and board
      members and employees of its affiliates, consultants and joint-venture partners
      who perform services for Atlas Pipeline Holdings. The AHD Plan is administered
      by Atlas America’s compensation committee under delegation from Atlas Pipeline
      Holding’s board. The compensation committee may grant awards of either phantom
      units or unit options for an aggregate of 2.1 million common limited partner
      units.




Page
          102





*Partnership
      Phantom Units.* 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 phantom units. Through
      December 31, 2006, phantom units granted under the AHD Plan generally vest
      25%
      three years from the date of grant and 100% four years from the date of grant.





*Partnership
      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. Through
      December 31, 2006, unit options granted generally will vest 25% three years
      from
      the date of grant and 100% four years from the date of grant.





The
      vesting of both types of awards 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 the AHD Plan. This
      year, the compensation committee approved grants under the AHD Plan conditioned
      upon the filing of a Registration Statement on Form S-8.





APL
      Plan





The
      APL
      Plan provides incentive awards to officers, employees and non-employee managers
      of its general partner and officers and employees of its general partner’s
      affiliates, consultants and joint venture partners who perform services for
      APL
      or in furtherance of its business. The APL Plan is administered by the Atlas
      America compensation committee, under delegation from APL’s general partner’s
      managing board. Under the APL Plan, the compensation committee may make awards
      of either phantom units or options covering an aggregate of 435,000 common
      units.





*APL
      Phantom Units.* A
      phantom unit entitles the participant to receive a common unit upon the vesting
      of the phantom unit or, at the discretion of the compensation committee, cash
      equivalent to the 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 phantom units. Through December 31, 2006,
      phantom units granted under the APL Plan generally vested over a 4-year period
      at the rate of 25% per year.





*APL
      Unit Options.* A unit
      option entitles the participant to purchase APL common units at an exercise
      price determined by the compensation committee, which may be less than, equal
      to
      or more than the fair market value of APL common units on the date of grant.
      The
      compensation committee will also have discretion to determine how the exercise
      price may be paid. No unit options have been granted under the APL
      Plan.





Each
      non-employee manager of APL’s general partner is awarded the lesser of 500
      phantom units, with DERs, or that number of phantom units, with DERs, equal
      to
      $15,000 divided by the then fair market value of a common unit for each year
      of
      service on the managing board. Up to 10,000 phantom units may be awarded to
      non-employee managers. Except for phantom units awarded to non-employee managers
      of APL’s general partner, the compensation committee will determine the vesting
      period for phantom units and the exercise period for options. Phantom units
      awarded to non-employee managers will generally vest over a 4-year period at
      the
      rate of 25% per year. Both types of awards will automatically vest upon a change
      of control, as defined in the APL Plan.





As
      required by SEC guidelines, the following table discloses awards under our
      Plan
      as well as under each of the Atlas Plan, the APL Plan and the AHD
      Plan.





Page
          103





**OUTSTANDING
      EQUITY AWARDS AT FISCAL YEAR-END TABLE**





**Option
                Awards**
            
            **Stock
                Awards****Market****Number
                of**
            
            **Value
                of****Shares
                or**
            
            **Shares
                or****Number
                of**
            
            
            
            
            
            **Units
                of**
            
            **Units
                of****Securities
                Underlying**
            
            **Option**
            
            
            
            **Stock
                That**
            
            **Stock
                That****Unexercised
                Options**
            
            **Exercise**
            
            **Option**
            
            **Have
                Not**
            
            **Have
                Not****(#)**
            
            **Price**
            
            **Expiration**
            
            **Vested**
            
            **Vested****Name**
            
            **Exercisable**
            
            **Unexercisable**
            
            **($)**
            
            **Date**
            
            **(#)**
            
            **($)**Edward
                E. Cohen
            
            
            450,000
            (1)
            
            —
            
            $
            25.47
            
            
            7/1/2015
            
            
            47,500
            (2)
            $
            2,280,000
            (3)—
            
            
            —
            
            
            500,000
            (4)
            $
            22.56
            
            
            11/10/2016
            
            
            90,000
            (5)
            $
            2,149,200
            (6)Matthew
                A. Jones
            
            
            30,000
            (7)
            
            90,000
            (8)
            $
            25.47
            
            
            7/1/2015
            
            
            16,250
            (9)
            $
            780,000
            (3)—
            
            
            —
            
            
            100,000
            (10)
            $
            22.56
            
            
            11/10/2016
            
            
            20,000
            (11)
            $
            472,600
            (6)Richard
                D. Weber
            
            
            —
            
            
            50,000
            (12)
            $
            47.86
            
            
            4/17/2016
            
            
            —
            
            
            —





(1)
            Represents
                options to purchase Atlas America stock, granted on 7/1/05, which
                vested
                immediately.(2)
            Represents
                APL phantom units, which vest as follows: 3/16/07 - 5,000; 6/8/07
                - 6,250;
                11/1/07 - 5,000; 3/16/08 - 5,000; 6/8/08 - 6,250; 11/1/08 - 5,000;
                3/16/09
                - 5,000; 11/1/09 - 5,000 and 11/1/10 - 5,000; includes 20,000 units
                reported in “2006 Grants of Plan-Based Awards Table.”(3)
            Based
                on closing market price of APL common units on December 29, 2006
                of
                $48.00.(4)
            Represents
                options to purchase AHD units (all of which are reported in “2006 Grants
                of Plan-Based Awards Table”), which vest as follows: 11/10/09 - 125,000
                and 11/10/10 - 375,000.(5)
            Represents
                AHD phantom units (all of which are reported in “2006 Grants of Plan-Based
                Awards Table”), which vest as follows: 11/10/09 - 22,500 and 11/10/10 -
                67,500.(6)
            Based
                on closing market price of AHD common units on December 29, 2006
                of
                $23.88.(7)
            Represents
                options to purchase Atlas America stock.(8)
            Represents
                options to purchase Atlas America stock, which vest as follows: 7/1/07
                -
                30,000; 7/1/08 - 30,000 and 7/1/09 - 30,000.(9)
            Represents
                APL phantom units, which vest as follows: 3/16/07 - 3,750; 11/1/07
                -
                1,250; 3/16/08 - 3,750; 11/1/08 - 1,250; 3/16/09 - 3,750; 11/1/09
                - 1,250
                and 11/1/10 - 1,250; includes 5,000 units reported in “2006 Grants of
                Plan-Based Awards Table.”(10)
            Represents
                AHD options (all of which are reported in “2006 Grants of Plan-Based
                Awards Table”), which vest as follows: 11/10/09 - 25,000 and 11/10/10 -
                75,000.(11)
            Represents
                AHD phantom units (all of which are reported in “2006 Grants of Plan-Based
                Awards Table”), which vest as follows: 11/10/09 - 5,000 and 11/10/10 -
                15,000.(12)
            Represents
                options to purchase Atlas America stock (all of which are reported
                in
                “2006 Grants of Plan-Based Awards Table”), which vest as follows: 4/17/07
                - 12,500; 4/17/08 - 12,500; 4/17/09 - 12,500 and 4/17/10 - 12,500.






Page
          104





**2006
      OPTION EXERCISES AND STOCK VESTED TABLE**





**Stock
                Awards**(1)**Number of Units**
            
            **Value
                Realized****Name**
            
            **Acquired on Vesting**
            
            **on
                Vesting****(#)**
            
            **($)**Edward
                E. Cohen
            
            
            11,250
            
            $
            454,612Matthew
                A. Jones
            
            
            3,750
            
            $
            151,537




(1) Awards
      under the APL Plan.





**DIRECTOR
      COMPENSATION TABLE**





**Name**
            
            **Fees Earned or**
              **Paid in Cash****($)**Walter
                C. Jones
            
            $
            1,342Ellen
                F. Warren
            
            $
            1,342Bruce
                M. Wolf
            
            $
            1,342





**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 2006, a pro-rated portion of the annual retainer of $35,000
      in
      cash and, in January 2007, an annual grant of phantom units with DERs in an
      amount equal to the lesser of 500 units or $15,000 worth of units (based upon
      the market price of our common units) 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.





Page
          105


**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 March 12, 2007. The address for each director and executive officer
      and Atlas America is 311 Rouser Road, P.O. Box 611, Moon Township, Pennsylvania
      15108.





**Beneficial
                Owner**
            
            Common
                    Unit
                  Amount
                    and Nature of
                  Beneficial
                    Ownership
            
            
            
            Percent
                  of
                Class**Directors**Edward
                E. Cohen
            
            
            —
            
            
            
            
            
            —Jonathan
                Z. Cohen
            
            
            —
            
            
            
            
            
            —Matthew
                A. Jones
            
            
            1,100
            
            
            
            
            
            *Walter
                C. Jones
            
            
            —
            
            
            
            
            
            —Ellen
                F. Warren
            
            
            —
            
            
            
            
            
            —Richard
                D. Weber
            
            
            1,100
            
            
            
            
            
            *Bruce
                M. Wolf
            
            
            3,000
            
            
            
            
            
            ***Non-Director
                Executive Officers**Nancy
                J. McGurk
            
            
            —
            
            
            
            
            
            —Lisa
                Washington
            
            
            100
            
            
            
            
            
            *All
                executive officers and directors as a group (9 persons)
            
            
            5,300
            
            
            
            
            
            ***Other
                Owners of More Than 5% of Outstanding Shares**Atlas
                America, Inc.
            
            
            29,352,996
            
            
            (1
            )
            
            80.04
            %







*
      Less
      than 1%





(1)
            This
                information is based upon a Schedule 13D which was filed with SEC
                on
                December 27, 2006. The address for Atlas America, Inc. is 311 Rouser
                Road,
                Moon Township, Pennsylvania 15108.




**Equity
      Compensation Plan Information**





The
      following table contains information about our Plan as of December 31,
      2006:





**(a)**
            
            **(b)**
            
            **(c)****Plan
                category**
            
            **Number
                of securities to be issued upon exercise of outstanding options,
                warrants
                and rights**
            
            **Weighted
                average exercise price of outstanding options, warrants and
                rights**
            
            **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
            
            
            -0-
            
            
            
            
            
            3,742,000
            (1)




(1)
              Includes
                  47,619 restricted units and 373,752 unit options granted in January,
                  2007.




Page
          106


The
      following table contains information about the AHD Plan as of December 31,
      2006:


**(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
                  units
              
              
              220,492
              
              $
              0.00Equity
                  compensation plans not approved by security holders - unit
                  options
              
              
              1,215,000
              
              $
              22.56Equity
                  compensation plans not approved by security holders -
                  Total
              
              
              1,435,492
              
              
              
              
              
              664,508




The
      following table contains information about the APL Plan as of December 31,
      2006:


**(a)**
              
              **(b)**
              
              **(c)****Plan
                  category**
              
              **Number
                  of securities to be issued upon exercise of phantom
                  units**
              
              **Weighted
                  Average exercise price of outstanding phantom
                  units**
              
              **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
              
              
              159,067
              
              $
              0.00
              
              
              275,933




The
      following table contains information about the Atlas Plan as of December 31,
      2006:


**(a)**
              
              **(b)**
              
              **(c)****Plan
                  category**
              
              **Number
                  of securities to be issued upon exercise of outstanding options,
                  warrants
                  and rights**
              
              **Weighted
                  Average exercise price of outstanding options, warrants and
                  rights**
              
              **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
              
              
              1,241,511
              
              $
              26.59
              
              
              754,348




**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 2006, Resource America paid $1.3 million toward such operating
      costs of Anthem and Anthem reimbursed it $2.7 million.





Page
          107


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.





**ITEM
              14.**
            **PRINCIPAL
                ACCOUNTING FEES AND
                SERVICES**





For
      the
      year ended December 31, 2006, Grant Thornton LLP’s accounting fees and services
      were as follows (in thousands) (4) :





Audit
                fees(1)
            
            $
            100Audit-related
                fees
            
            
            -Tax
                fees(2)
            
            
            -All
                other fees(3)
            
            
            -Total
                accounting fees and services
            
            $
            100





(1)
            Audit
                fees include professional services rendered for the annual audit
                of our
                financial statements.





(2)
            There
                were no fees for tax services rendered to us during the year ended
                December 31, 2006.





(3)
            There
                were no other fees rendered to us during the year ended December
                31,
                2006.





(4)
            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.




**Audit
      Committee Pre-Approval Policies and Procedures**





The
      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 during 2005 and
      2004.





Page
          108





**PART
      IV**





**ITEM
      15.**  **EXHIBITS,
      FINANCIAL STATEMENT SCHEDULES**





**(a)**  **(1)**  **Financial
      Statements**





Report
                of Independent Registered Public Accounting FirmCombined
                and Consolidated Balance Sheets at December 31, 2006 and
                2005Combined
                and Consolidated Statements of Income for the year ended December
                31,
                2006, three months ended December 31, 2005 and years ended September
                30,
                2005 and 2004Combined
                and Consolidated Statements of Comprehensive Income for the year
                ended
                December 31, 2006, three months ended December 31, 2005 and years
                ended
                September 30, 2005 and 2004Combined
                and Consolidated Statements of Equity for the year ended December
                31,
                2006, three months ended December 31, 2005 and years ended September
                30,
                2005 and 2004Combined
                and Consolidated Statements of Cash Flows for the year ended December
                31,
                2006, three months ended December 31, 2005 and years ended September
                30,
                2005 and 2004Notes
                to Combined and Consolidated Financial Statements − December 31,
                2006





**(2)**  **Financial
      Statement Schedules**





**(3)**  **Exhibits:**





Exhibit
                No.
            
            Description3.1
            
            Amended
                and Restated Limited Liability Company Agreement of Atlas Energy
                Resources, LLC(1)3.2
            
            Certificate
                of Formation of Atlas Energy Resources, LLC(2)4.1
            
            Form
                of common unit certificate (included as Exhibit A to the Amended
                and
                Restated Limited Liability Company Agreement of Atlas Energy Resources,
                LLC)(1)10.1
            
            Contribution,
                Conveyance and Assumption Agreement, dated as of December 18, 2006,
                among
                Atlas America, Inc., Atlas Energy Resources, LLC and Atlas Energy
                Operating Company, LLC(1)10.2
            
            Omnibus
                Agreement, dated as of December 18, 2006, between Atlas America,
                Inc. and
                Atlas Energy Resources, LLC(1)10.3
            
            Management
                Agreement, dated as of December 18, 2006, among Atlas Energy Resources,
                LLC, Atlas Energy Operating Company, LLC and Atlas Energy Management,
                Inc.(1)10.4(a)
            
            Master
                Natural Gas Gathering Agreement, dated February 2, 2000, among Atlas
                Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P.,
                Atlas
                America, Inc., Resource Energy, Inc. and Viking Resources
                Corporation(2)10.4(b)
            
            Natural
                Gas Gathering Agreement, dated January 1, 2002, among Atlas Pipeline
                Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas
                Resources, Inc., Atlas Energy Group, Inc., Atlas Noble Corporation,
                Resource Energy, Inc. and Viking Resources Corporation(2)10.4(c)
            
            Amendment
                to Master Natural Gas Gathering Agreement and Natural Gas Gathering
                Agreement, dated October 25, 2005, among Atlas Pipeline Partners,
                L.P.,
                Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc.,
                Resource
                Energy, Inc., Viking Resources Corporation, Atlas Noble Corp. and
                Atlas
                Resources, Inc.(2)10.4(d)
            
            Amendment
                and Joinder to Gas Gathering Agreements, dated as of December 18,
                2006,
                among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership,
                L.P., Atlas America, Inc., Resource Energy, LLC, Viking Resources,
                LLC,
                Atlas Noble, LLC, Atlas Resources, LLC, Atlas America, LLC, Atlas
                Energy
                Resources, LLC and Atlas Energy Operating Company, LLC(1)






Page
          109





10.5(a)
            
            Omnibus
                Agreement, dated February 2, 2000, among Atlas America, Inc., Resource
                Energy, Inc., Viking Resources Corporation, Atlas Pipeline Partnership,
                L.P., and Atlas Pipeline Partners, L.P.(2)10.5(b)
            
            Amendment
                and Joinder to Omnibus Agreement, dated as of December 18, 2006 among
                Atlas Pipeline, Atlas America, Resource Energy, LLC, Viking Resources,
                LLC, Atlas Energy Resources, LLC and Atlas Energy Operating Company,
                LLC(1)10.6
            
            Agreement
                for Services among Atlas America, Inc. and Richard Weber, dated April
                5,
                2006(2)10.7
            
            Atlas
                Energy Resources Long-Term Incentive Plan(3)10.8
            
            Drilling
                and Operating Agreement, dated September 15, 2004, between Atlas
                America,
                Inc. and Knox Energy, LLC(2)10.9(a)
            
            Revolving
                Credit Agreement, dated as of December 18, 2006, among Atlas Energy
                Operating Company, LLC, its subsidiaries, Wachovia National Bank,
                as
                Administrative Agent and the other lenders signatory thereto(1)10.9(b)
            
            Guaranty,
                dated as of December 18, 2006, from Atlas Energy Resources, LLC in
                favor
                of Wachovia Bank, National Association, as administrative
                agent(1)10.10
            
            Services
                Agreement, dated as of December 18, 2006, between Anthem Securities,
                Inc.
                and Atlas America, Inc.(1)10.11(a)
            
            Gas
                Purchase Agreement, dated March 31, 1999, between Northeast Ohio
                Gas
                Marketing, Inc. and Atlas Energy Group, Inc.(2)10.11(b)
            
            Amendment
                to Gas Purchase Agreement, dated February 1, 2001, between FirstEnergy
                Services Corp., an assign of Northeast Ohio Gas Marketing, Inc.,
                Atlas
                Energy Group, Inc. and Resource Energy Inc.(2)10.11(c)
            
            Second
                Amendment to Base Gas Purchase Agreement, dated July 16, 2003, between
                FirstEnergy Solutions Corp. and Atlas Energy Group, Inc., Atlas Resources,
                Inc. and Resource Energy, Inc.(2)10.11(d)
            
            Assignment
                and Novation of Transactions, dated April 1, 2005, between FirstEnergy
                Solutions Corp., Amerada Hess Corporation and the Atlas parties named
                therein(2)10.11(e)
            
            Third
                Amendment to Base Gas Purchase Agreement(4)10.12
            
            Form
                of Unit Award Agreement(5)10.13
            
            Limited
                Liability Company Agreement of Atlas Energy Operating Company, LLC
                dated
                June 29, 2006(2)10.14
            
            Form
                of Non-Employee Director Grant Agreement(5)10.15
            
            Form
                of Phantom Unit Grant Agreement(5)10.16
            
            Form
                of Option Grant Agreement(5)21.1
            
            Subsidiaries
                of Atlas Energy Resources, LLC(2)23.1
            
            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 December 22,
                2006(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 18,
                2006(4)
            Previously
                filed as an exhibit to our Form 8-K filed January 10,
                2007(5)
            Previously
                filed as an exhibit to our Form 8-K filed January 22,
                2007





Page
          110




**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 27, 2007
            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
                27, 2007Edward
                E. Cohen*/s/
                Richard D. Weber*
            
            President
                and Chief Operating Officer
            
            March
                27, 2007Richard
                D. Weber*/s/
                Matthew A. Jones*
            
            Chief
                Financial Officer
            
            March
                27, 2007Matthew
                A. Jones*/s/
                Nancy J. McGurk*
            
            Chief
                Accounting Officer
            
            March
                27, 2007Nancy
                J. McGurk*/s/
                Jonathan Z. Cohen*
            
            Director
            
            March
                27, 2007Jonathan
                Z. Cohen*/s/
                Walter C. Jones*
            
            Director
            
            March
                27, 2007Walter
                C. Jones*/s/
                Ellen F. Warren*
            
            Director
            
            March
                27, 2007Ellen
                F. Warren*/s/
                Bruce M. Wolf*
            
            Director
            
            March
                27, 2007Bruce
                M. Wolf





Page
          111