**SECURITIES
      AND EXCHANGE COMMISSION**


**WASHINGTON,
      D.C. 20549**




**FORM
      10-K**




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


For
      the
      fiscal year ended December 31, 2007




OR




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


Commission
      File Number 000-25170




**AURORA
      OIL & GAS CORPORATION**


(Exact
      Name of Registrant as Specified in its Charter)




Utah
            
            87-0306609(State
                or Other Jurisdiction ofIncorporation or Organization)
            
            (I.R.S.
                Employer
              Identification
                No.)4110
                Copper Ridge Dr, Suite 100, Traverse City, Michigan
            
            49684(Address
                of Principal Executive Offices)
            
            (Zip
                code)(231)
                941-0073(Issuer’s
                Telephone Number, Including Area
                Code.)




Securities
      registered pursuant to Section 12(b) of the Act:




Title
                of each class
            
            Name
                of each exchange on which registeredCommon
                stock, par value $0.01
            
            American
                Stock Exchange




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




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
      past 90 days.


Yes x No o




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, a non-accelerated filer, or a smaller reporting company.
      See
      the definitions of “large accelerated filer,” “accelerated filer,” and “smaller
      reporting company” in Rule 12b-2 of the Exchange Act (check one).


Large
                  accelerated filer o
              Accelerated
                  filer xNon-accelerated
                  filer o(Do
                  not check if a smaller reporting company)
              Smaller
                  reporting company o




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
      aggregate market value of common stock held by non-affiliates of the Registrant
      as of June 30, 2007, was $162,137,547. The number of outstanding shares of
      the
      Registrant’s common stock as of February 29, 2008, was 102,299,456.




**Documents
      Incorporated By Reference:**




Portions
      of the Proxy Statement for the annual shareholders’ meeting to be held on May
      30, 2008, are incorporated by reference into Part III.








**AURORA
      OIL & GAS CORPORATION**


**2007
      ANNUAL REPORT ON FORM 10-K**


**TABLE
      OF CONTENTS**




**PART
                    I**Item
                    1.
                Business
                2Item
                    1A.
                Risk
                    Factors
                15Item
                    1B.
                Unresolved
                    Staff Comments
                26Item
                    2.
                Properties
                26Item
                    3.
                Legal
                    Proceedings
                26Item
                    4.
                Submission
                    of Matters to a Vote of Security Holders
                26**PART
                    II**Item
                    5.
                Market
                    for the Registrant’s Common Stock, Related Shareholder Matters and Issuer
                    Purchases of Equity Securities
                27Item
                    6.
                Selected
                    Financial Data
                30Item
                    7.
                Management’s
                    Discussion and Analysis of Financial Condition and Results of
                    Operations
                32Item
                    7A.
                Quantitative
                    and Qualitative Disclosures About Market Risk
                48Item
                    8.
                Financial
                    Statements and Supplementary Data
                49Item
                    9.
                Changes
                    in and Disagreements with Accountants on Accounting and Financial
                    Disclosure
                91Item
                    9A.
                Controls
                    and Procedures
                91Item
                    9B.
                Other
                    Information
                92**PART
                    III**Item
                    10.
                Directors,
                    Executive Officers, and Corporate Governance
                92Item
                    11.
                Executive
                    Compensation
                92Item
                    12.
                Security
                    Ownership of Certain Beneficial Owners and Management and Related
                    Stockholder Matters
                92Item
                    13.
                Certain
                    Relationships, Related Transactions, and Director
                    Independence
                92Item
                    14.
                Principal
                    Accounting Fees and Services
                92**PART
                    IV**Item
                    15.
                Exhibits
                    and Financial Statement Schedules
                92Index
                    to Exhibits
                93Signatures
                95Exhibits
                96




i




**Cautionary
      Note Regarding Forward-Looking Statements**





This
      report contains forward-looking statements within the meaning of Section 27A
      of
      the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E
      of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All
      statements other than statements of historical facts are forward-looking
      statements. You can find many of these statements by looking for words such
      as
“believes,” “expects,” “anticipates,” “estimates,” “intends,” or similar
      expressions used in this report.





These
      forward-looking statements are subject to numerous assumptions, risks and
      uncertainties. Factors which may cause our actual results, performance or
      achievements to be materially different from any future results, performance
      or
      achievements expressed or implied by us in those statements include, among
      others, the following:





●
            the
                quality of our properties with regard to, among other things, the
                existence of reserves in economic
                quantities;


●
            uncertainties
                about the estimates of reserves;


●
            our
                ability to increase our production and oil and natural gas income
                through
                exploration and development;


●
            the
                number of well locations to be drilled and the time frame within
                which
                they will be drilled;


●
            the
                timing and extent of changes in commodity prices for natural gas
                and crude
                oil;


●
            domestic
                demand for oil and natural gas;


●
            drilling
                and operating risks;


●
            the
                availability of equipment, such as drilling rigs and transportation
                pipelines;


●
            changes
                in our drilling plans and related budgets;


●
            the
                adequacy of our capital resources and liquidity including, but not
                limited
                to, access to additional borrowing capacity;
                and


●
            other
                factors discussed under Item 1A Risk Factors with the heading “Risks
                Related To Our Business”.





Because
      such statements are subject to risks and uncertainties, actual results may
      differ materially from those expressed or implied by the forward-looking
      statements. You are cautioned not to place undue reliance on such statements,
      which speak only as of the date of this report.





**CERTAIN
      DEFINITIONS**





As
      used
      in this report, “mcf” means thousand cubic feet, “mmcf” means million cubic
      feet, “bcf” means billion cubic feet, “bbl” means barrel, “mbbls” means thousand
      barrels, and “mmbbls” means million barrels. Also in this report, “boe” means
      barrel of oil equivalent, “mcfe” means thousand cubic feet of natural gas
      equivalent, “mmcfe” means million cubic feet of natural gas equivalent, “mmbtu”
means million British thermal units, and “bcfe” means billion cubic feet of
      natural gas equivalent. Natural gas equivalents and crude oil equivalents are
      determined using the ratio of six mcf of natural gas to one bbl of crude oil,
      condensate, or natural gas liquids. All estimates of reserves and information
      related to production contained in this report, unless otherwise noted, are
      reported on a “net” basis. References to “us”, “we” and “our” in this report
      refer to Aurora Oil & Gas Corporation together with its
      subsidiaries.





**PART
      I**





**ITEM
      1.**  **DESCRIPTION
      OF BUSINESS**




**OVERVIEW**





We
      are a
      growing independent energy company focused on the exploration and development
      of
      unconventional natural gas reserves. Our projects target unconventional shale
      plays where large acreage blocks can be evaluated with a series of low cost
      test
      wells. Shale plays tend to be characterized by high drilling success and
      relatively low drilling costs when compared to conventional exploration and
      development plays. Our project areas are located in the Antrim shale of
      Michigan, the New Albany shale of Southern Indiana and Western Kentucky, and
      the
      Woodford shale in Oklahoma.





In
      1969,
      we commenced operations to explore and mine natural resources under the name
      Royal Resources, Inc. In July 2001, we reorganized our business to pursue oil
      and natural gas exploration and development opportunities and changed our name
      to Cadence Resources Corporation. We acquired Aurora Energy, Ltd. ("Aurora")
      on
      October 31, 2005 through the merger of our wholly-owned subsidiary with and
      into
      Aurora. The acquisition of Aurora was accounted for as a reverse merger, with
      Aurora being the acquiring party for accounting purposes. The Aurora executive
      management team also assumed management control at the time the merger closed,
      and we moved our corporate offices to Traverse City, Michigan. On May 11, 2006,
      the name of Cadence Resources Corporation was changed to Aurora Oil & Gas
      Corporation (“AOG”).





As
      an
      early stage developer of properties, we have successfully accumulated a large
      acreage base of unconventional shale opportunities. As we develop these
      leaseholds, we anticipate reserve growth will be our initial focus followed
      by a
      more traditional balance between reserve and production growth. The following
      table sets forth our approximate leasehold acreage as of December 31,
      2007:





Developed
            
            Percentage
                DevelopedPlay/Trend
            
            Gross
            
            Net
            
            Gross
            
            NetMichigan
                Antrim
            
            
            310,141
            
            
            156,481
            
            
            28
            %
            
            34
            %New
                Albany
            
            
            833,365
            
            
            443,456
            
            
            2
            %
            
            1
            %Woodford
            
            
            37,325
            
            
            33,219
            
            
            -
            
            
            -Other
            
            
            102,352
            
            
            79,059
            
            
            1
            %
            
            1
            %Total
            
            
            1,283,183
            
            
            712,215
            
            
            8
            %
            
            8
            %





As
      of
      December 31, 2007 our proved reserves were approximately 166.6 bcfe, of which
      84% was in our Antrim shale properties and 70% was proved developed. The New
      Albany shale provided the largest increase in proved reserves during the year,
      adding a net 24 bcfe, which is a 900% increase over the 3.0 bcfe reported on
      December 31, 2006. The growth in the New Albany shale proved reserves was
      largely the result of 6 net wells drilled in 2007, which were 100% owned by
      Aurora. The Antrim shale proved reserves were reduced by a net 10.1 bcfe due
      to
      a 24.5 bcfe increase from positive drilling results in the Antrim shale and
      offset by 34.6 bcfe reduction in certain producing properties. This reduction
      reflected a lower production curve to be consistent with actual operating
      experience.





2




Unconventional
      shale plays tend to be characterized by high drilling success rates. For the
      12-month period ending December 31, 2007, we incurred $52.0 million to
      drill and participate in 101 (59 net) wells, with a 92% drilling success
      rate. In addition, we incurred $12.0 million on property and leasehold
      acquisitions. Average net daily production increased from 8,150 mcfe per day
      in
      2006 to 8,787 mcfe per day in 2007. The table below highlights our portfolio
      of
      producing wells as of December 31, 2007.





Play
                /Trend
            
            Gross Wells
              Producing
            
            Net Wells
              Producing
            
            Gross Wells Waiting
              Hook-Up
            
            Net Wells Waiting
              Hook-UpMichigan
                Antrim
            
            
            593.00
            
            
            287.39
            
            
            19.00
            
            
            7.00New
                Albany
            
            
            27.00
            
            
            3.25
            
            
            7.00
            
            
            5.36Other
            
            
            29.00
            
            
            14.53
            
            
            5.00
            
            
            2.30Total
            
            
            649.00
            
            
            305.17
            
            
            31.00
            
            
            14.66





Our
      revenue, profitability and future rate of growth are substantially dependent
      on
      our ability to find, develop and acquire gas reserves that are economically
      recoverable based on prevailing prices of natural gas and oil. Historically,
      the
      energy markets have been very volatile and it is likely that oil and natural
      gas
      prices will continue to be subject to wide fluctuations in the future. A
      substantial or extended decline in natural gas and oil prices could have a
      material adverse effect on our financial position, results of operations, cash
      flows, access to capital and on the quantities of natural gas and oil that
      can
      be economically produced.





**Our
      Strategy**




The
      objective of our business is to maximize shareholder value through the
      development of our substantial acreage base, which we expect to generate into
      significant increases in natural gas reserves and production growth. To achieve
      this objective, we employ the following strategies:





***Establish
      a base of lower risk development projects.*** We have
      established an extensive leasehold position in three plays - Antrim shale,
      New
      Albany shale and Woodford shale. All of these plays are at varying stages of
      their respective development life cycle. We believe the New Albany shale and
      Woodford shale represent emerging plays, as development activity has only been
      initiated within the last several years. As we invest capital into these plays,
      we believe that increased information resulting from drilling and production
      data by all operators will lower the risk profile, enhance results and provide
      opportunities for creating natural gas reserves and production
      growth.





***Improve
      financial flexibility.*** As
      an
      early-stage company with extensive development potential, we believe it is
      very
      important to have the right capital structure in place to facilitate our
      drilling activities. We expect to use a combination of internally-generated
      cash
      flow, project financing and reserve-based lending to achieve financial
      flexibility. Our financial structure will evolve as the company grows, fostering
      stable financing for our producing properties while providing flexibility for
      pursuing our growth development strategy.





***Generate
      growth through drilling*** .
      We
      expect to generate long-term reserve and production growth predominantly through
      our drilling activities. We believe the experience and expertise of our
      management and technical teams enables us to identify, evaluate and develop
      natural gas projects. We anticipate the majority of our future capital
      expenditures will be directed toward the drilling and production of wells,
      though we expect to continue acquiring additional leasehold interests to
      supplement our exploration and development strategy.





***Optimize
      our asset portfolio*** .
      With
      extensive leasehold positions in three shale plays, as well as several smaller
      targeted projects in other locations, we believe that we have created a diverse
      asset portfolio which must be carefully developed to limit our risk profile.
      We
      expect to regularly review our projects to optimize the value of this asset
      portfolio, the result of which will include appropriate joint ventures,
      farm-outs, equity partnerships, acquisitions, or divestitures.


3


**OPERATING
      AREAS**





***Antrim
      Shale***





Our
      Antrim shale properties are primarily located in northern Michigan and represent
      the majority of our production and proved reserves. At December 31, 2007, we
      owned working interests in 640 (320 net) Antrim wells which included 28 (26
      net)
      non-producing wells. In 2007, we drilled or participated in 56 gross (35 net)
      Antrim wells and completed 54 gross wells for a success rate of 96%. In 2006,
      we
      drilled 173 gross (98 net) Antrim wells and completed 164 gross wells for a
      success rate of 95%. We currently have 156,481 net acres leased, with
      approximately 52,603 acres developed in the Michigan Antrim shale
      play.





The
      Antrim shale underlies the entire Michigan basin. The primary producing trend
      for the shale runs across the northern portion of the Michigan basin from Lake
      Michigan to Lake Huron (160 miles). In most situations, Antrim shale is
      encountered by vertical drilling, though on occasion, we may determine that
      horizontal drilling is preferred. A simple completion procedure is employed,
      using industry-proven hydraulic fracturing technology. These wells are produced
      with a production system that is specifically designed to minimize pressure
      on
      the wells, pipelines, facilities, and reservoir. This is expected to increase
      the recoverability of the shale gas production, thereby providing the maximum
      recovery of natural gas.





The
      Antrim shale exhibits a thick shale (140 to 200 feet), with a high organic
      content (up to 20%). Over 9,000 wells are currently producing in the Antrim
      shale and are expected to provide an average of 0.5 bcf of natural gas per
      well,
      with a productive life between 30 and 50 years.





A
      typical
      production curve for the shale suggests a peak rate of gas occurring within
      the
      first two years of production, after the shale reservoir has gone through a
      period of dewatering. Once the gas is able to fully release from the shale,
      the
      production will typically decline between 2% and 7% annually.





During
      the last several years, we have focused on development drilling in the Antrim
      shale, creating a stable base of production and proved reserves for the company.
      In 2008, drilling concentration will be directed to our largest undeveloped
      asset, the New Albany shale.





***New
      Albany shale***





Our
      New
      Albany shale properties are primarily located in southwestern Indiana and
      represent the majority of our developable acreage base. As with the Antrim
      shale, our New Albany shale operations are focused on the unconventional shale
      play. At December 31, 2007, we owned working interests in 61 (19 net) New Albany
      shale wells which included 27 (10 net) non-producing wells. In 2007, we drilled
      or participated in 27 gross (11 net) New Albany wells and completed 27 gross
      wells for a success rate of 100%. In 2006, we drilled or participated in 26
      gross (7.49 net) New Albany shale wells and completed 25 gross wells for a
      success rate of 96%. We currently have 443,456 net acres leased, with
      approximately 5,937 net acres developed in the New Albany shale.





The
      New
      Albany shale underlies a substantial portion of the Illinois basin. The most
      productive portion of the trend appears to run across the southeastern portion
      of Illinois, the southern portion of Indiana and the northwestern portion of
      Kentucky. Our acreage position is located primarily in the central portion
      of
      that trend, crossing approximately 12 counties.





Though
      the New Albany shale has been successfully drilled and produced using vertical
      wells, it has been determined that the most productive method of development
      is
      horizontal drilling. At this time, the completion methods are very simple,
      typically open-hole only. These wells are produced with a production system
      that
      is specifically designed to minimize pressure on the wells, pipelines,
      facilities and reservoir. This is expected to increase the recoverability of
      shale gas production, thereby providing the maximum recovery of natural
      gas.





The
      New
      Albany shale exhibits a thick shale (100 to over 200 feet), with high organic
      content (up to 25%). Over 200 vertical wells and less than 50 horizontal wells
      are currently producing in the New Albany shale. Horizontal wells are expected
      to provide an average of 1.2 bcf of natural gas per well with a productive
      life
      between 30 and 50 years.





4




A
      typical
      production curve for the shale suggests a peak rate of gas and water occurs
      within the first 60 days of production. Together, the natural gas and water
      decline an average of 2% to 7% annually.





While
      the
      New Albany shale is our primary target, our acreage also includes a variety
      of
      producible oil and natural gas formations, including those overlying silurian
      reefs and coalbed methane formations. Our New Albany shale drilling efforts
      will
      also provide useful information about these other producible formations for
      future evaluation strategies. In 2008, drilling concentration will be directed
      to certain properties in the New Albany shale, as it embodies the largest
      component of our undeveloped asset base. We believe this will provide further
      insight into our ability to predict the commerciality of the resource.





***Woodford
      shale***





Our
      Woodford shale properties are located in Oklahoma and are operated by our
      partner, West Star Operating Company. This is also an unconventional shale
      play
      which has recently emerged as a key onshore target of several large independent
      exploration and production companies. At December 31, 2007, we had 33,219 net
      acres leased, none of which has been developed.





The
      Woodford shale underlies most of Oklahoma, which includes the Anadarko, Arkoma,
      and Ardmore basins-a mature oil and gas area with more than 15 conventional
      producing reservoirs above and below the Woodford shale. Consequently, excellent
      well control data exists and was employed in our efforts to concentrate
      operations where the Woodford shale is the thickest (typically 200 feet thick).
      In addition, the shale boasts a high organic content and is highly siliceous,
      a
      property which lends itself to making the shale more productive.





In
      recent
      years, technological developments in completion and stimulation techniques
      have
      transformed this play. Horizontal wells and multi-stage fracturing technology
      will be utilized to provide the best rates of return. These wells are expected
      to provide an average of 3 bcf of natural gas per well with a productive life
      between 20 and 40 years.





In
      2008,
      we expect to pursue a testing drilling program which will evaluate the acreage
      and determine the profitability of our Woodford shale project and other
      potential formations.





***Drilling
      techniques and natural gas processing***





We
      are
      experienced at drilling both vertical and horizontal wells. In the Antrim,
      our
      first choice would typically be vertical drilling, although in some situations,
      we may determine that horizontal drilling is preferred. Our drilling technique
      in the New Albany shale continues to evolve as we seek to improve cost
      containment and producibility. Horizontal drilling has become our development
      method of first choice in the New Albany shale, primarily because of the high
      angled natural fractures. We seek to maximize intersections of the east-west
      natural fractures through horizontal drilling, as we believe that this will
      optimize production results.





For
      shale
      gas wells, we generally use a production system that is designed to achieve
      low
      pressure on the wells, pipelines, facilities and reservoir. This is done by
      keeping natural fractures open to the well bore and by using low-pressure gas
      processing near well sites. Using this low-pressure production approach, we
      seek
      to increase the recoverability of shale gas production through reduction of
      reservoir pressure, thereby enhancing dewatering and gas recovery.





In
      the
      Michigan Antrim, we use a simple proven completion procedure with industry
      proven hydraulic fracturing technology. This procedure involves drilling through
      several pay zones, setting and cementing casing, and drilling an extended
      rat-hole, which is used for gas-water separation. The wells are then
      hydraulically fractured with a specifically designed fracture procedure
      incorporating multiple stages with enhanced diversion methods to increase
      effective vertical coverage. Imaging logs are used to identify which zones
      are
      best fractured and will yield commercial gas production. For horizontal New
      Albany shale wells, minimal stimulation has been required to date to make
      economic gas wells. In exploratory areas of the New Albany and Antrim, shale
      log
      analysis is incorporated to enhance fracturing and completion
      design.





5





In
      order
      to contain costs, we try to keep facilities for gas processing decentralized.
      Salt water disposal wells are drilled close to the compression facilities,
      near
      to each field’s wells. Skid mounted separators that can be easily upgraded or
      downsized are used at the site of the salt water disposal wells. The localized
      disposal of water reduces power demand. Different reservoirs contain different
      amounts of water. We cannot accurately predict the actual amount of time
      required for dewatering with respect to each well. The period of time during
      which the gas production rate is limited by the Antrim shale dewatering process
      is estimated to be two years or more, thereby delaying peak revenue production.





We
      use
      skid mounted booster compressors to maximize compression efficiencies from
      the
      well to the transportation line. We also seek to maintain low pressure in the
      gathering systems. Gas is usually drawn at low wellhead pressure using a five
      and one-half inch or seven inch production casing and up to 4-inch polypipe.





One
      strategy we use to minimize costs is to minimize the use of land surface. This
      is accomplished by using small well sites in open areas near roads using
      localized facilities as described above. We continue to explore innovations
      in
      technology and methodologies that will reduce production costs and increase
      efficiencies. We may use other drilling, completion and operating procedures
      than those described above if, in our opinion, alternative procedures will
      generate higher returns.





Our
      wells
      are drilled by outside drilling companies. We believe that there is currently
      enough capacity available in the areas in which we are working that we will
      not
      have a problem finding one or more drilling companies available to meet our
      time
      schedule for drilling wells. However, over time, circumstances could change
      as
      development activity in the industry accelerates.





***Oil
      and natural gas reserves***





The
      following table presents information as of December 31, 2007, with respect
      to
      our estimated proved reserves. Estimates of our future net revenues from proved
      reserves are discounted to present value using an annual discount rate of 10%
      (PV-10), using oil and natural gas prices in effect as of the dates of such
      estimates, held constant throughout the life of the properties. The information
      presented is based on a reserve report prepared by Data & Consulting
      Services Division of Schlumberger Technology Corporation (“Schlumberger”).
      According to this report, approximately 39% of our proved reserves are
      classified as either proved developed non-producing or proved
      undeveloped.




6





As
                of December 31, 2007Oil
                and Natural Gas Reserves(a)
            
            Oil
            
            Gas
            
            Total
            
            PV-10(d)
            
            Standardized
                Measure(e)(mbbls)
            
            (mmcf)
            
            (mmcfe)
            
            (In thousands)
            
            (In thousands)Proved
                developed producing
            
            
            74
            
            
            100,887
            
            
            101,331
            
            $
            127,723
            
            $
            110,036Proved
                developed non-producing
            
            
            66
            
            
            14,894
            
            
            15,290
            
            
            22,788
            
            
            17,332Proved
                undeveloped
            
            
            48
            
            
            49,686
            
            
            49,974
            
            
            39,425
            
            
            48,175Total
                proved (b) (c)
            
            
            188
            
            
            165,467
            
            
            166,595
            
            $
            189,936
            
            $
            175,543




Oil and Natural Gas Reserves by
              Play/Trend(a)
            
            Total
            
            Percent of
              Proved
              Reserves
            
            PV-10(d)(mmcfe)
            
            
            
            (In thousands)Michigan
                Antrim
            
            
            139,959
            
            
            84
            %
            $
            141,798New
                Albany
            
            
            24,982
            
            
            15
            %
            
            37,347Other
            
            
            1,654
            
            
            1
            %
            
            10,791Total
            
            
            166,595
            
            
            100
            %
            $
            189,936




Change
                in reserve quantity information
              for
                the year ended December 31, 2007(a)
            
            Oil
            
            Gas
            
            Total(mbbls)
            
            (mmcf)
            
            (mmcfe)Proved
                reserves as of December 31, 2006
            
            
            81
            
            
            152,964
            
            
            153,450Revisions
                of previous estimates
            
            
            20
            
            
            (34,651
            )
            
            (34,531
            )Purchases
                of minerals in place
            
            
            -
            
            
            2,943
            
            
            2,943Extensions
                and discoveries
            
            
            131
            
            
            47,256
            
            
            48,042Production
            
            
            (28
            )
            
            (3,034
            )
            
            (3,202
            )Sales
                of minerals in place
            
            
            (16
            )
            
            (11
            )
            
            (107
            )Proved
                reserves as of December 31, 2007
            
            
            188
            
            
            165,467
            
            
            166,595





(a)
            The
                information presented for reserves is based on reserve reports prepared
                by
                Schlumberger. Consistent with Schlumberger’s standard engineering
                practices, these reports and such reserves excluded the impact of
                the
                financial hedges.





(b)
            Proved
                reserves are those quantities of gas which, by analysis of geological
                and
                engineering data, can be estimated with reasonable certainty to be
                commercially recoverable from known reservoirs and under current
                economic
                conditions, operating methods, and government regulations.





(c)
            Developed
                reserves are expected to be recovered from existing wells. Undeveloped
                reserves are expected to be recovered: (i) from new wells on undrilled
                acreage; (ii) from deepening existing wells to a different reservoir;
                or
                (iii) where relatively large expenditure is required to recomplete
                an
                existing well or install production or transportation facilities
                for
                primary or improved recovery
                projects.





(d)
            Represents
                the present value, discounted at 10% per annum (PV-10), of estimated
                future net revenue before income tax of our estimated proved reserves.
                The
                estimated future net revenues were determined by using reserve quantities
                of proved reserves and the periods in which they are expected to
                be
                developed and produced based on economic conditions prevailing at
                December
                31, 2007. The estimated future production is priced at December 31,
                2007,
                without escalation, using $90.18 per bbl and $7.18 per mmbtu, in
                each case
                adjusted for transportation fees and regional price differentials.
                PV-10
                is a non-GAAP financial measure because it excludes income tax effects.
                Management believes that the presentation of the non-GAAP financial
                measure of PV-10 provides useful information because it is widely
                used by
                professional analysts and sophisticated investors in evaluating oil
                and
                natural gas companies. PV-10 is not a measure of financial or operating
                performance under GAAP. PV-10 should not be considered as an alternative
                to the standardized measure as defined under GAAP. We have included
                a
                reconciliation of PV-10 to the most directly comparable GAAP measure
                -
                standardized measure of discounted future net cash flow - in the
                following
                table:




7




As
                of December 31,2007
            
            2006
            
            2005Standardized
                measure of discounted future net cash flows
            
            $
            175,543,140
            
            $
            130,461,821
            
            $
            152,868,240Add:
                Present value of future income tax discounted at 10%
            
            
            14,392,640
            
            
            28,320,989
            
            
            46,639,204PV-10
            
            $
            189,935,780
            
            $
            158,782,810
            
            $
            199,507,444





(e)
            The
                standardized measure represents the present value of estimated future
                cash
                inflows from proved oil and natural gas reserves, less future development,
                abandonment, production and income tax expenses, discounted at 10%
                per
                annum to reflect timing of future cash flows and using the same pricing
                assumptions as were used to calculate PV-10. Standardized measure
                differs
                from PV-10 because standardized measure includes the effect of future
                income taxes. As noted in footnote (a) above, this excludes the impact
                of
                our hedges. If the impact of our hedges were included, the standardized
                measure would have been increased by $7,214,670 to
                $182,757,810.





Management
      uses present value of future net revenue, which is calculated without deducting
      estimated future income tax expense, and the present value thereof as one
      measure of the value of our current proved reserves and to compare relative
      values among peer companies without regard to income taxes. We also understand
      that securities analysts use this measure in similar ways.





***Acreage***





The
      following table sets forth as of December 31, 2007, the gross and net acres
      of
      both developed and undeveloped oil and gas leases which we hold. “Gross” acres
      are the total number of acres in which we own a working interest. “Net” acres
      refer to gross acres multiplied by our fractional working interest. Acreage
      numbers do not include our options to acquire additional leaseholds which have
      not been exercised.





Developed(a)
            
            Undeveloped(b)
            
            TotalPlay/Trend
            
            Gross
            
            Net
            
            Gross
            
            Net
            
            Gross
            
            NetMichigan
                Antrim
            
            
            87,860
            
            
            52,603
            
            
            222,281
            
            
            103,878
            
            
            310,141
            
            
            156,481New
                Albany
            
            
            13,120
            
            
            5,937
            
            
            820,245
            
            
            437,519
            
            
            833,365
            
            
            443,456Woodford
            
            
            -
            
            
            -
            
            
            37,325
            
            
            33,219
            
            
            37,325
            
            
            33,219Other
            
            
            1,330
            
            
            830
            
            
            101,022
            
            
            78,229
            
            
            102,352
            
            
            79,059Total
            
            
            102,310
            
            
            59,370
            
            
            1,180,873
            
            
            652,845
            
            
            1,283,183
            
            
            712,215





(a)
            Developed
                refers to the number of acres which are allocated or assignable to
                producing wells or wells capable of production. Developed acreage
                includes
                acreage having wells shut-in awaiting the addition of
                infrastructure.





(b)
            Undeveloped
                refers to lease acreage on which wells have not been developed or
                completed to a point that would permit the production of commercial
                quantities of oil or natural gas regardless of whether such acreage
                contains proved reserves.




8




***Production
      and price information***





The
      following table summarizes sales volumes, sales prices, and production cost
      information for the periods indicated:





Year
                Ended December 31Production
            
            2007
            
            2006
            
            2005Oil
                (bbls)
            
            
            27,907
            
            
            22,588
            
            
            10,628Natural
                gas (mcf)
            
            
            3,039,714
            
            
            2,517,897
            
            
            687,271Natural
                gas equivalent (mcfe)
            
            
            3,207,155
            
            
            2,653,427
            
            
            751,039Oil
                and natural gas salesOil
                sales
            
            $
            1,939,160
            
            $
            1,399,445
            
            $
            558,455Natural
                gas sales
            
            
            24,784,658
            
            
            20,192,366
            
            
            6,184,989Total
            
            $
            26,723,818
            
            $
            21,591,811
            
            $
            6,743,444Average
                sales price (including realized gains or losses from
                hedging)Oil
                ($ per bbl)
            
            $
            69.49
            
            $
            61.96
            
            $
            52.55Natural
                gas ($ per mcf)
            
            
            8.15
            
            
            8.02
            
            
            9.00Natural
                gas equivalent ($ per mcfe)
            
            
            8.33
            
            
            8.14
            
            
            8.98Average
                production expenses ($ per mcfe)Production
                taxes
            
            $
            0.35
            
            $
            0.33
            
            $
            0.67Post-production
                expenses
            
            
            0.59
            
            
            0.55
            
            
            0.50Leasing
                operating expenses
            
            
            2.14
            
            
            1.82
            
            
            1.62Total
            
            $
            3.08
            
            $
            2.70
            
            $
            2.79





***Productive
      wells***





The
      following table sets forth as of December 31, 2007, information relating to
      the
      productive wells in which we owned a working interest. Productive wells consist
      of producing wells and wells capable of production, including natural gas wells
      awaiting pipeline connections to commence deliveries and oil wells awaiting
      connection to production facilities. Gross wells are the total number of
      productive wells in which we have an interest, and net wells are the sum of
      our
      fractional working interests owned in gross wells.





Natural
                Gas
            
            OilPlay/Trend
            
            Gross
                Wells
            
            Net
                Wells
            
            Gross
                Wells
            
            Net
                WellsMichigan
                Antrim
            
            
            612
            
            
            294.39
            
            
            -
            
            
            -New
                Albany
            
            
            34
            
            
            8.61
            
            
            -
            
            
            -Woodford
            
            
            -
            
            
            -
            
            
            -
            
            
            -Other
            
            
            1
            
            
            0.10
            
            
            33
            
            
            16.71Total
            
            
            647
            
            
            303.10
            
            
            33
            
            
            16.71





***Drilling
      activities***





The
      following table sets forth information with respect to wells drilled and
      completed during the periods indicated. The information should not be considered
      indicative of future performance, nor should it be assumed that there is
      necessarily any correlation between the number of productive wells drilled,
      quantities of reserves found or economic value. Productive wells are those
      that
      produce commercial quantities of hydrocarbons, whether or not they produce
      a
      reasonable rate of return.




9





Gross
                Wells
            
            Net
                WellsType
                of Well
            
            Productive(b)
            
            Dry(c)
            
            Total
            
            Productive(b)
            
            Dry(c)
            
            TotalYear
                Ended 12/31/07(d)Exploratory(a)Michigan
                Antrim
            
            
            1
            
            
            -
            
            
            1
            
            
            0.22
            
            
            -
            
            
            0.22New
                Albany
            
            
            15
            
            
            -
            
            
            15
            
            
            10.57
            
            
            -
            
            
            10.57Woodford
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Other
            
            
            7
            
            
            6
            
            
            13
            
            
            5.51
            
            
            5.00
            
            
            10.51Total
            
            
            23
            
            
            6
            
            
            29
            
            
            16.30
            
            
            5.00
            
            
            21.30Development(a)Michigan
                Antrim
            
            
            50
            
            
            2
            
            
            52
            
            
            29.43
            
            
            2.00
            
            
            31.43New
                Albany
            
            
            12
            
            
            -
            
            
            12
            
            
            0.60
            
            
            -
            
            
            0.60Woodford
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Other
            
            
            8
            
            
            -
            
            
            8
            
            
            5.80
            
            
            -
            
            
            5.80Total
            
            
            70
            
            
            2
            
            
            72
            
            
            35.83
            
            
            2.00
            
            
            37.83Year
                Ended 12/31/06Exploratory(a)Michigan
                Antrim
            
            
            2
            
            
            -
            
            
            2
            
            
            2.00
            
            
            -
            
            
            2.00New
                Albany
            
            
            13
            
            
            1
            
            
            14
            
            
            6.39
            
            
            0.50
            
            
            6.89Other
            
            
            1
            
            
            3
            
            
            4
            
            
            0.38
            
            
            1.25
            
            
            1.63Total
            
            
            16
            
            
            4
            
            
            20
            
            
            8.77
            
            
            1.75
            
            
            10.52Development(a)Michigan
                Antrim
            
            
            162
            
            
            9
            
            
            171
            
            
            91.53
            
            
            4.93
            
            
            96.46New
                Albany
            
            
            12
            
            
            -
            
            
            12
            
            
            0.60
            
            
            -
            
            
            0.60Other
            
            
            6
            
            
            -
            
            
            6
            
            
            3.95
            
            
            -
            
            
            3.95Total
            
            
            180
            
            
            9
            
            
            189
            
            
            96.08
            
            
            4.93
            
            
            101.01Year
                Ended 12/31/05Exploratory(a)Michigan
                Antrim
            
            
            1
            
            
            1
            
            
            2
            
            
            0.20
            
            
            0.20
            
            
            0.40New
                Albany
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Other
            
            
            3
            
            
            -
            
            
            3
            
            
            1.17
            
            
            -
            
            
            1.17Total
            
            
            4
            
            
            1
            
            
            5
            
            
            1.37
            
            
            0.20
            
            
            1.57Development(a)Michigan
                Antrim
            
            
            136
            
            
            5
            
            
            141
            
            
            101.37
            
            
            3.40
            
            
            104.77New
                Albany
            
            
            3
            
            
            -
            
            
            3
            
            
            0.15
            
            
            -
            
            
            0.15Other
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Total
            
            
            139
            
            
            5
            
            
            144
            
            
            101.52
            
            
            3.40
            
            
            104.92





(a)
            An
                exploratory well is a well drilled either in search of a new, as
                yet
                undiscovered, oil or natural gas reservoir or to greatly extend the
                known
                limits of a previously discovered reservoir. A development well is
                a well
                drilled within the presently proved productive area of an oil or
                natural
                gas reservoir, as indicated by reasonable interpretation of available
                data, with the objective of being completed in that reservoir.





(b)
            A
                productive well is an exploratory or development well found to be
                capable
                of producing either oil or natural gas in sufficient quantities to
                justify
                completion as an oil or natural gas well.





(c)
            A
                dry well is an exploratory or development well that is not a producing
                well or a well that has either been plugged or has been converted
                to
                another use.





(d)
            At
                December 31, 2007, we had 3 gross (1 net) wells in the process of
                being
                drilled.




10


***Sale
      of production***





We
      market
      natural gas and oil production on a competitive basis for our operated
      properties. In most cases, we connect to nearby high pressure transmission
      pipelines and utilizes a gas marketing firm for the sale of production.
      Effective June 1, 2007, we entered into a firm sales contact with Integrys
      Energy Services, Inc. (formerly WPS) for 5,000 mmbtu per day at MichCon
      city-gate for the period June 1, 2007, through December 31, 2008. Our average
      daily production for operated Antrim was 6,277 mmbtu per day for 2007. Integrys
      Energy Services, Inc. is our primary marketing partner for the majority of
      our
      Michigan operated properties. In addition, we have established other base
      contracts primarily for future natural gas sales in Indiana and Michigan. We
      set
      the firm delivery volume obligation under these contracts on either a monthly
      or
      a daily basis with the amount of the obligation varying from month to month
      or
      day to day. As new wells come online and production volume increases, new
      production will be sold under the base contracts on a spot market pricing
      structure.





Prices
      for oil and natural gas fluctuate fairly widely based on supply and demand.
      Supply and demand are influenced by weather, foreign policy and industry
      practices. Nonetheless, in light of historical fluctuations in prices, there
      can
      be no assurance at what price we will be able to sell our oil and natural gas.
      It is possible that prices will be low at the time periods in which the wells
      are most productive, thereby reducing overall returns.





***Hedging***





Our
      results of operations and operating cash flows are impacted by the fluctuations
      in the market prices of natural gas. To mitigate a portion of the exposure
      to
      adverse market changes, we will periodically enter into various derivative
      instruments with a major financial institution. The purpose of the derivative
      instrument is to provide a measure of stability to our cash flow in meeting
      financial obligations while operating in a volatile natural gas market
      environment. The derivative instrument reduces our exposure on the hedged
      production volumes to decreases in commodity prices and limits the benefit
      we
      might otherwise receive from any increases in commodity prices on the hedged
      production volumes.




***Other
      properties***




On
      October 4, 2005, we purchased office space in the Copper Ridge Professional
      Center Five, located in Traverse City, Michigan. Our unit contains approximately
      14,645 square feet on the second floor of a three story **** building,
      plus common areas and 15 covered parking spaces. We moved our corporate offices
      into this space on December 5, 2005.




We
      also
      own non-oil and natural gas mineral rights in several properties, although
      we do
      not presently consider them to be material to our business.




***Employees***




As
      of
      December 31, 2007, we had 67 full-time employees and 1 part-time employee.
      We
      are not a party to any collective bargaining agreements. We believe that our
      relations with our employees are good.





***Executive
      Officers***





The
      following table sets forth the name, age and position of each of our executive
      officers.


Name
              
              Age
              
              Position(s)
                  with the CompanyWilliam
                  W. Deneau
              
              63
              
              Director,
                  Chairman, and Chief Executive OfficerJohn
                  E. McDevitt
              
              61
              
              Director,
                  President, and Chief Operating OfficerBarbara
                  E. Lawson
              
              49
              
              Chief
                  Financial OfficerGilbert
                  A. Smith
              
              60
              
              Vice
                  President, Business DevelopmentJohn
                  C. Hunter
              
              56
              
              Vice
                  President, Exploration and
                  Production




11




***William
      W. Deneau*** has
      served on our Board of Directors and as our President and Chairman of the Board
      of Directors since November 1, 2005. Mr. Deneau became an employee of Aurora
      at
      the time he sold his interest in Jet/LaVanway Exploration, L.L.C. to Aurora
      in
      exchange for Aurora’s stock on April 22, 1997. Since April 1997, Mr. Deneau has
      been responsible for managing Aurora’s affairs. He officially became a Director
      of Aurora on June 25, 1997 and the President of Aurora on July 17, 1997,
      positions he continued to hold until Aurora was merged into AOG effective
      January 1, 2008. William W. Deneau is the brother of Richard M. Deneau, another
      one of our Directors.





***John
      E. McDevitt*** has
      served as our Director, President and Chief Operating Officer since January
      22,
      2008. Since 2006, Mr. McDevitt has been a Manager and President of Acadian
      Energy, LLC ,
      a
      private company focused on unconventional natural gas exploration and production
      in the New Albany shale. From
      2003 to 2007, Mr. McDevitt was President of CDX Resources LLC, a rig fleet
      and
      directional services company that was owned by CDX Gas, LLC. Prior to that,
      he
      held positions with CDX Gas, LLC as Chief Financial Officer and Senior Vice
      President of Strategic Planning. CDX Gas, LLC was an
      independent oil and gas company focused on the onshore exploration and
      production of unconventional natural gas, which was sold
      in 2006.





***Barbara
      E. Lawson*** has
      served as our Chief Financial Officer since January 22, 2008. Ms. Lawson has
      worked for us since March 2006 as SEC Reporting Manager. From 2005 to 2006,
      Ms.
      Lawson was Vice President of Simple Financial Solutions, Inc. providing
      consulting services that covered public equity offerings and Sarbanes-Oxley
      Section 404 implementation. From 1988 to 2004, Ms. Lawson was employed with
      Midland Cogeneration Venture, LLP, an independent power producer, where her
      last
      position was Treasurer and Manager of Internal Audit.





***Gilbert
      A. Smith*** has
      served as a Vice President since February 1, 2008. Since January 2007, Mr.
      Smith
      has been a Manager and Chief Operating Officer of Acadian Energy, LLC. From
      2002
      to 2006, Mr. Smith was Vice President of Land and Contract Administration for
      CDX Gas, LLC. From 1999 to 2001, Mr. Smith worked as an independent
      consultant ,
      performing international strategic contract negotiation and business
      development.  Mr.
      Smith
      worked for Sun Exploration and Production Company (subsequently named Oryx
      Energy Company) from 1978 through 1999 where he served in various senior
      management positions.





***John
      C. Hunter*** ** has
      served as a Vice President since May 30, 2007. He has worked for us since 2005
      as Senior Petroleum Engineer. From 2004 to 2005, Mr. Hunter was Executive Vice
      President of Wellstream Energy Services providing petroleum engineering
      consulting services. From 2000 to 2004, Mr. Hunter was President of Terra
      Drilling Services, LLC and TerraFluids, LLC, which provides short radius
      horizontal drilling services, as well as drilling and completion fluids in
      the
      United States. From 1995 to 2004, Mr. Hunter was Director of Exploitation of
      Torch Energy Advisors, Inc. located in Houston, Texas, where he managed a staff
      of 15 employees dedicated to the development of oil and natural gas
      properties.




***Competition
      and markets***




We
      face
      competition from other oil and natural gas companies in all aspects of our
      business, including acquisition of producing properties and oil and natural
      gas
      leases, marketing of oil and natural gas, and obtaining goods, services and
      labor. Many of our competitors have substantially larger financial and other
      resources than we have. Factors that affect our ability to acquire producing
      properties include available funds, available information about prospective
      properties and our limited number of employees. Gathering systems are the only
      practical method for the intermediate transportation of natural gas. Therefore,
      competition for natural gas delivery is presented by other pipelines and gas
      gathering systems. Competition is also presented by alternative fuel sources,
      including heating oil and other fossil fuels. Renewable energy sources may
      become more competitive in the future.


12




The
      availability of a ready market for and the price of any hydrocarbons produced
      will depend on many factors beyond our control including, but not limited to,
      the amount of domestic production and imports of foreign oil and liquefied
      natural gas, the marketing of competitive fuels, the proximity and capacity
      of
      natural gas pipelines, the availability of transportation and other market
      facilities, the demand for hydrocarbons, the effect of federal and state
      regulation of allowable rates of production, taxation, the conduct of drilling
      operations and federal regulation of natural
      gas. In addition, the restructuring of the
      natural gas pipeline industry virtually eliminated the gas purchasing activity of traditional
      interstate gas transmission pipeline buyers. Producers of natural gas have
      therefore been required to develop new markets among gas marketing companies,
      end users of natural gas and local distribution companies. All of these
      factors, together with economic factors in the marketing arena, generally affect
      the supply of and/or demand for oil and natural gas and thus the prices
      available for sales of oil and natural gas.




***Regulatory*** ***considerations***




Proposals
      and proceedings that might affect the oil and gas industry are periodically
      presented to Congress, the Federal Energy Regulatory Commission (“FERC”), the
      Minerals Management Service (“MMS”), state legislatures and commissions and the
      courts. We cannot predict when or whether any such proposals may become
      effective. The natural gas industry is heavily regulated. There is no assurance
      that the regulatory approach currently pursued by various agencies will continue
      indefinitely. Notwithstanding the foregoing, we currently do not anticipate
      that
      compliance with existing federal, state and local laws, rules and regulations,
      will have a material or significantly adverse effect upon our capital
      expenditures, earnings or competitive position. No material portion of our
      business is subject ** to
      renegotiation of profits or termination of contracts or subcontracts at the
      election of the federal government.




Our
      operations are subject to various types of regulation at the federal, state
      and
      local levels. This regulation includes requiring permits for drilling wells,
      maintaining bonding requirements in order to drill or operate wells and
      regulating 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 the disposal of fluids used or generated
      in
      connection with operations. Our operations are also subject to various
      conservation laws and regulations. These include the regulation of the size
      of
      drilling and spacing units or proration units and the density of wells which
      may
      be drilled and the unitization or pooling of oil and natural gas properties.
      In
      addition, state conservation laws sometimes establish maximum rates of
      production from oil and natural gas wells, generally prohibit the venting or
      flaring of natural gas and impose certain requirements regarding the ratability
      of production. The effect of these regulations may limit the amount of
      oil and
      natural gas we can produce from our wells in a given state and may limit the
      number of wells
      or
      the locations at which we can drill.




Currently,
      there are no federal, state or local laws that regulate the price for our sales of natural
      gas, natural gas liquids, crude oil or condensate. However, the rates charged
      and terms and conditions for the movement of gas in interstate commerce through
      certain intrastate pipelines and production area hubs are subject to regulation
      under the Natural Gas Policy Act of 1978, as amended. Pipeline and hub
      construction activities are, to a limited extent, also subject ** to
      regulations under the Natural Gas Act of 1938, as amended. While these controls
      do not apply directly to us, their effect on natural gas markets can be
      significant in terms of competition and cost of transportation services, which
      in turn can have a substantial impact on our profitability and costs of ** doing
      business. Additional proposals and proceedings that might affect the natural
      gas
      and crude oil extraction industry are considered from time to time by Congress,
      FERC, state regulatory bodies and the courts. We cannot predict when or if
      any
      such proposals might become effective and their effect, if any, on our
      operations. We do not believe that we will be affected by any action taken
      in
      any materially different respect from other crude oil and natural gas producers,
      gatherers and marketers with whom we compete.




State
      regulation of gathering facilities generally includes various safety,
      environmental and in some circumstances, nondiscriminatory take requirements.
      This regulation has not generally been applied against producers and gatherers
      of natural gas to the same extent as processors, although natural gas gathering
      may receive greater regulatory scrutiny in the future.


13




Our
      oil
      and natural gas production and saltwater disposal operations and our processing,
      handling and disposal of hazardous materials, such as hydrocarbons and naturally
      occurring radioactive materials (“NORM”) are subject to stringent environmental
      regulation. Compliance with environmental regulations is generally required
      as a
      condition to obtaining drilling permits. State inspectors frequently inspect
      regulated facilities and review records required to be maintained for document
      compliance. We could incur significant costs, including cleanup costs resulting
      from a release of hazardous material, third-party claims for property damage
      and
      personal injuries, fines and sanctions, as a result of any violations or
      liabilities under environmental or other laws. Changes in or more stringent
      enforcement of environmental laws could also result in additional operating
      costs and capital expenditures.




Various
      federal, state and local laws regulating the discharge of materials into the
      environment, or otherwise relating to the protection of the environment,
      directly impact oil and natural gas exploration, development and production
      operations, and consequently may impact our operations and costs. These
      regulations include, among others, (i) regulations by the Environmental
      Protection Agency (“EPA”), and various state agencies regarding approved methods
      of disposal for certain hazardous and non-hazardous wastes; (ii) the
      Comprehensive Environmental Response, Compensation and Liability Act, and
      analogous state laws, which regulate the removal or remediation of previously
      disposed wastes (including wastes disposed of or released by prior owners or
      operators), property contamination (including groundwater contamination), and
      remedial plugging operations to prevent future contamination; (iii) the Clean
      Air Act and comparable state and local requirements, which may require certain
      pollution controls with respect to air emissions from our operations; (iv)
      the
      Oil Pollution Act of 1990, which contains numerous requirements relating to
      the
      prevention of and response to oil spills into waters of the United States;
      (v)
      the Resource Conservation and Recovery Act, which is the principal federal
      statute governing the treatment, storage and disposal of hazardous wastes;
      and
      (vi) state regulations and statutes governing the handling, treatment, storage
      and disposal of NORM.




A
      permit
      from the EPA and the Michigan Department of Environmental Quality or a state
      regulatory agency (Indiana) must be obtained before we may drill a salt water
      disposal well. The amount of time required to obtain such a permit varies from
      state to state, but can take as much as six or more months in Michigan. Since
      many gas wells can only be produced if a salt water disposal well is available,
      the salt water disposal well permit requirement may delay the commencement
      of
      production.




In
      the
      course of our routine oil and natural gas operations, surface spills and leaks,
      including casing leaks of oil or other materials may occur, and we may incur
      costs for waste handling and environmental compliance. It is also possible
      that
      our oil and natural gas operations may require us to manage NORM. NORM are
      present in varying concentrations in sub-surface formations, including
      hydrocarbon reservoirs, and may become concentrated in scale, film and sludge
      in
      equipment that comes in contact with crude oil and natural gas production and
      processing streams. Some states, including Michigan and Texas, have enacted
      regulations governing the handling, treatment, storage and disposal of NORM.
      Moreover, we are able to control directly the operations of only those wells
      for
      which we act as the operator. Despite our lack of control over wells owned
      by us
      but operated by others, the failure of the operator to comply with the
      applicable environmental regulations may, in certain circumstances, be
      attributed to us under applicable state, federal or local laws or
      regulations.




We
      believe that we are in substantial compliance with all currently applicable
      environmental laws and regulations. To date, compliance with such laws and
      regulations has not required the expenditure of any material amount of money,
      and we do not currently anticipate that future compliance with environmental
      laws will have a materially adverse effect on our consolidated financial
      position or results of operations. Since these laws and regulations are
      periodically amended, however, we are unable to predict the ultimate cost of
      compliance. To our knowledge, there are currently no material adverse
      environmental conditions that exist on any of our properties and there are
      no
      current or threatened actions or claims by any local, state or federal agency,
      or by any private landowner against us pertaining to such a condition. Further,
      we are not aware of any currently existing condition or circumstance that may
      give rise to such actions or claims in the future.


14




***Where
      you can find more information***




We
      are
      subject to the information and reporting requirements of the Exchange Act and
      are therefore required to file annual, quarterly, and current reports, proxy
      statements, and other information with the Securities and Exchange Commission
      (“SEC”). You may read any materials we file with the SEC free of charge at the
      SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC
      20549. Copies of all or any part of these documents may be obtained from such
      office upon the payment of the fees prescribed by the SEC. The public may obtain
      information on the operation of the public reference room by calling the SEC
      at
      1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy
      and information statements, and other information regarding registrants that
      file electronically with the SEC. The address of the site is www.sec.gov .
      The
      report, including all exhibits thereto and amendments thereof, has been filed
      electronically with the SEC.





Our
      principal executive offices are located at 4110 Copper Ridge Drive, Suite 100,
      Traverse City, Michigan 49684, and our telephone number is 231-941-0073. Our
      website is www.auroraogc.com .
      Our
      report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
      8-K, and amendments to these reports filed or furnished pursuant to Section
      13(a) or 15(d) of the Securities Exchange Act of 1934 are posted on our website
      as soon as reasonably possible after they are electronically filed with the
      SEC
      and are available to you through our website free of charge. You may also
      request a copy of our SEC filings at no cost by writing or telephoning us at
      the
      above address attention investor relations. Information contained on our website
      does not constitute a part of this report.





**ITEM
      1A. RISK FACTORS**




**RISKS
      RELATED TO OUR BUSINESS**





***Natural
      gas prices are volatile. A substantial decrease in natural gas prices
      would***  ***significantly
      affect our business and impede our growth.***





Our
      revenues, profitability and future growth depend upon prevailing natural gas
      prices. Prices also affect the amount of cash flow available for capital
      expenditures and our ability to borrow and raise additional capital. Lower
      prices may also reduce the amount of natural gas that we can economically
      produce. It is possible that prices will be low at the time periods in which
      the
      wells are most productive, thereby reducing overall returns. It is possible
      that
      prices will drop so low that production will become uneconomical. Ongoing
      production costs that will continue include equipment maintenance, compression
      and pumping costs. If production becomes uneconomical, we may decide to
      discontinue production until prices improve.





Prices
      for natural gas fluctuate widely. For example, from January 1, 2006, through
      December 31, 2007, natural gas prices quoted for the near month NYMEX contract
      have ranged from a low of $4.40 per mmbtu to a high of $11.00 per mmbtu. The
      prices for natural gas are subject to a variety of factors beyond our control,
      including:





●
            the
                level of consumer product demand;


●
            weather
                conditions;


●
            domestic
                and foreign governmental regulations;


●
            the
                price and availability of alternative fuels;


●
            political
                conditions in oil and natural gas producing
                regions;


●
            the
                domestic and foreign supply of oil and natural gas;


●
            speculative
                trading and other market uncertainty; and


●
            worldwide
                economic conditions.




15


***The
      failure to develop reserves could adversely affect our production and cash
      flows.***





Our
      success depends upon our ability to find, develop or acquire natural gas
      reserves that are economically recoverable. We will need to conduct successful
      exploration or development activities or acquire properties containing proved
      reserves, or both. The business of exploring for, developing or acquiring
      reserves is capital intensive. We may not be able to make the necessary capital
      investment to expand our natural gas reserves from cash flows, and external
      sources of capital may be limited or unavailable. Our drilling activities may
      not result in significant reserves, and we may not have continuing success
      drilling productive wells. Exploratory drilling involves more risk than
      development drilling because exploratory drilling is designed to test formations
      in which proved reserves have not been discovered. Additionally, while our
      revenues may increase if prevailing gas prices increase significantly, our
      finding costs for reserves also could increase, and we may not be able to
      finance additional exploration or development activities.





***We
      may have difficulty financing our planned growth.***





We
      have
      incurred and expect to continue to incur substantial capital expenditures and
      working capital needs, particularly as a result of our property acquisition
      and
      development drilling activities. We will require substantial additional
      financing to fund our planned growth. Additional financing may not be available
      to us on acceptable terms or at all. If additional capital resources are
      unavailable, we may be forced to curtail our acquisition, development drilling
      and other activities or to sell some of our assets on an untimely or unfavorable
      basis. We are in the process of evaluating strategic alternatives as of the
      date
      of this report.





***Most
      of our current development activity and producing properties are located
      in***  ***Michigan
      and Indiana, making us vulnerable to risks associated with operating in
      this***  ***region.***





Our
      current development activity is concentrated in Michigan and Indiana, and our
      currently producing properties are located primarily in a six-county area in
      Michigan. As a result, we may be disproportionately exposed to the impact of
      drilling and other delays or disruptions of production from these regions caused
      by weather conditions, governmental regulation, lack of field infrastructure,
      or
      other events which impact these areas. In addition, a majority of our leaseholds
      held for development are located in the more untested New Albany shale
      play/trend.





***Our
      potential drilling locations comprise an estimation of part of our
      future***  ***drilling
      plans over several years, making them susceptible to uncertainties
      that***  ***could
      materially alter the occurrence or timing of their
      drilling.***





As
      of
      December 31, 2007, we had over 3,700 net potential drilling locations to be
      included in our future multi-year drilling activities on our existing acreage.
      These drilling locations represent a significant part of our growth strategy.
      Our ability to drill and develop these locations depends on a number of
      uncertainties, including the availability of capital, construction of
      infrastructure, seasonal conditions, regulatory approvals, natural gas prices,
      costs and drilling results. Because of these uncertainties, we do not know
      if
      our numerous potential drilling locations will ever be drilled or if we will
      be
      able to produce natural gas from these or any other potential drilling
      locations, which could materially affect our business.





***We
      may continue to incur losses.***





We
      reported a net loss for the years ended December 31, 2007, 2006, and 2005.
      There is no assurance that we will be able to achieve and maintain
      profitability.


16


***We
      do not operate a substantial amount of our
      properties.***





We
      conduct much of our oil and natural gas exploration, development and production
      activities in joint ventures with others. In some cases, we act as operator
      and
      retain significant management control. In other cases, we have reserved only
      an
      overriding royalty interest and have surrendered all management rights. In
      still
      other cases, we have reserved the right to participate in management decisions,
      but do not have ultimate decision-making authority. As of December 31, 2007,
      we
      operated 35% of our gross wells and 67% of our net wells. As a result of these
      varying levels of management control, for those properties that we do not
      operate, we have no control over:





●
            the
                number of wells to be drilled;


●
            the
                location of wells to be drilled;


●
            the
                timing of drilling and re-completing of wells;


●
            the
                field company hired to drill and maintain the wells;


●
            the
                timing and amounts of production;


●
            the
                approval of other participants in drilling wells;


●
            development
                and operating costs;


●
            capital
                calls on working interest owners; and


●
            pipeline
                nominations.





These
      and
      other aspects of the operation of our properties and the success of our drilling
      and development activities will in many cases be dependent on the expertise
      and
      financial resources of our joint venture partners and third-party
      operators.





***We
      may be unable to make acquisitions of producing properties or prospects
      or***  ***successfully
      integrate them into our operations.***





Acquisitions
      of producing properties and undeveloped oil and natural gas leases have been
      an
      essential part of our long-term growth strategy. As of December 31, 2007, we
      had
      acquired approximately 1,283,183 (712,215 net) acres with 166,595 mmcfe in
      net
      proved reserves. We may not be able to identify suitable acquisitions in the
      future or to finance these acquisitions on favorable terms or at all. In
      addition, we compete against other companies for acquisitions, many of whom
      have
      substantially greater managerial and financial resources than we have. The
      successful acquisition of producing properties and undeveloped natural gas
      leases requires an assessment of the properties’ potential natural gas reserves,
      future natural gas prices, development costs, operating costs, potential
      environmental and other liabilities and other factors beyond our control. These
      assessments are necessarily inexact and their accuracy inherently uncertain.
      Such a review may not reveal all existing or potential problems, nor will it
      necessarily permit us to become sufficiently familiar with the properties to
      fully assess their merits and deficiencies. Significant acquisitions can change
      the nature of our operations and business depending upon the character of the
      acquired properties, which may be substantially different in operating and
      geological characteristics or geographic location than existing properties.
      Our
      acquisitions may not be integrated successfully into our operations and may
      not
      achieve desired profitability objectives.





***We
      may lose key management personnel.***





Our
      current management team has substantial experience in the oil and natural gas
      business. We do not currently have employment agreements with any members of
      our
      management team. The loss of any of these individuals could adversely affect
      our
      business. If one or more members of our management team dies, becomes disabled
      or voluntarily terminates employment with us, there is no assurance that a
      suitable or comparable replacement will be found.





***Much
      of our proved reserves are not yet generating production
      revenues.***





Of
      our
      proved natural gas reserves as of December 31, 2007, approximately 61% are
      classified as proved developed producing, 9% are classified as proved developed
      non-producing, and 30% are classified as proved undeveloped.





17




You
      should be aware that our ability to convert proved reserves into revenues is
      subject to certain limitations, including the following:





●
            Reserves
                characterized as proved developed producing reserves may be producing
                predominantly water and generate little or no production
                revenue;




●
            Production
                revenues from estimated proved developed non-producing reserves will
                not
                be realized until some time in the future, after we have installed
                supporting infrastructure or taken other necessary steps. It will
                be
                necessary to incur additional capital expenditures to install this
                required infrastructure;




●
            Production
                revenues from estimated proved undeveloped reserves will not be realized
                until after such time, if ever, as we make significant capital
                expenditures with respect to the development of such reserves, including
                expenditures to fund the cost of drilling wells, dewatering the wells,
                and
                building the supporting
                infrastructure; and




●
            The
                reserve data assumes that we will make significant capital expenditures
                to
                develop our reserves. Although we have prepared estimates of the
                costs
                associated with developing these reserves in accordance with industry
                standards, no assurance can be given that our estimates of capital
                expenditures will prove accurate, that our financing sources will
                be
                sufficient to fully fund our planned development activities, or that
                development activities will be either successful or in accordance
                with our
                schedule. We cannot control the performance of our joint venture
                partners
                on whom we depend for development of a substantial number of properties
                in
                which we have an economic interest and which are included in our
                reserves.
                Further, any significant decrease in oil and natural gas prices or
                any
                significant increase in the cost of development could result in a
                significant reduction in the number of wells drilled. No assurance
                can be
                given that any wells will yield commercially viable
                quantities.





***Our
      oil and natural gas reserve data are estimates based
      on***  ***assumptions
      that may be inaccurate and existing economic and operating
      conditions***  ***that
      may differ from future economic and operating
      conditions.***





Reservoir
      engineering is a subjective and inexact process of estimating underground
      accumulations of oil and natural gas that cannot be measured in an exact manner
      and is based upon assumptions that may change from year to year and vary
      considerably from actual results. Accordingly, reserve estimates may be subject
      to downward or upward adjustment. Actual production, revenue and expenditures
      with respect to our reserves will likely vary from estimates, and such variances
      may be material. Information regarding discounted future net cash flows should
      not be considered as the current market value of the estimated oil and natural
      gas reserves that will be attributable to our properties. Examples of items
      that
      may cause our estimates to be inaccurate include, but are not limited to, the
      following:





●
            The
                estimated discounted future net cash flows from proved reserves are
                based
                on prices and costs as of the date of the estimate, while actual
                future
                prices and costs may be materially higher or
                lower;





●
            Because
                we have limited operating cost data to draw upon, the estimated operating
                costs used to calculate our reserve values may be
                inaccurate;





●
            Actual
                future net cash flows also will be affected by factors such as the
                amount
                and timing of actual production, supply and demand for oil and natural
                gas, increases or decreases in consumption, and changes in governmental
                regulations or taxation;




18


●
            The
                reserve report for our Michigan Antrim and New Albany shale properties
                assumes that production will be generated from each well for a period
                of
                50 years. Because production is expected for such an extended period
                of time, the probability is enhanced that conditions at the time
                of
                production will vary materially from the current conditions used
                to
                calculate future net cash
                flows; and





●
            The
                10% discount factor, which is required by the Financial Accounting
                Standards Board in Statement of Financial Accounting Standards No. 69
                to be used in calculating discounted future net cash flows for reporting
                purposes, is not necessarily the most appropriate discount factor
                based on
                interest rates in effect from time to time and risks that will be
                associated with our operations or the oil and natural gas industry
                in
                general.





***Our
      drilling activities may be unsuccessful.***





We
      cannot
      predict prior to drilling and testing a well whether the well will be productive
      or whether we will recover all or any portion of our investment in the well.
      Our
      drilling for natural gas may involve unprofitable efforts, not only from dry
      holes but from wells that are productive but do not produce sufficient
      quantities to cover drilling and completion costs and are not economically
      viable. Our efforts to identify commercially productive reservoirs, such as
      studying seismic data, the geology of the area and production history of
      adjoining fields, do not conclusively establish that natural gas is present
      in
      commercial quantities. If our drilling efforts are unsuccessful, our
      profitability will be adversely affected. For the 36-month period ending
      December 31, 2007, approximately 6% of the gross wells we drilled were
      unsuccessful.





***Production
      levels cannot be predicted with certainty.***





Until
      a
      well is drilled and has been in production for a number of months, we will
      not
      know what volume of production we can expect to achieve from the well. Even
      after a well has achieved its full production capacity, we cannot be certain
      how
      long the well will continue to produce or the production decline that will
      occur
      over the life of the well. Estimates as to production volumes and production
      life are based on studies of similar wells (of which there are relatively few
      in
      the New Albany play) and, therefore, are speculative and not fully reliable.
      As
      a result, our revenue budgets for producing wells may prove to be
      inaccurate.





***Drilling
      and production delays may occur.***





In
      order
      to generate revenues from the sale of oil and natural gas production from new
      wells, we must complete significant development activity. Delay in receiving
      governmental permits, adverse weather, a shortage of labor or parts, and/or
      dewatering time frames may cause delays, as discussed below. These delays will
      result in delays in achieving revenues from these new wells.





Oil
      and
      natural gas producers often compete for experienced and competent drilling,
      completion and facilities installation vendors and production laborers. The
      unavailability of experienced and competent vendors and laborers may cause
      development and production delays.





From
      time
      to time, vendors of equipment needed for oil and natural gas drilling and
      production become backlogged, forcing delays in development until suitable
      equipment can be obtained.





For
      each
      new well, before drilling can commence, we will have to obtain a drilling permit
      from the state in which the well is located. We will also have to obtain a
      permit for each salt water disposal well. It is possible that for reasons
      outside of our control, the issuance of the required permits will be delayed,
      thereby delaying the time at which production is achieved. We have previously
      experienced a delay in receiving permits from the State of Michigan, Department
      of Environmental Quality ("DEQ"), for drilling horizontal wells, while the
      DEQ
      further reviews this drilling methodology. As a result of these delays, we
      have
      had to defer the drilling of certain wells in the Antrim shale until the review
      by the DEQ was completed and permits were issued. The DEQ has also forced
      producers to discontinue operations in certain areas of the Michigan Antrim
      so
      that the DEQ can inspect the salt water disposal wells operated in those areas.
      We have no control over this type of regulatory delay.





19




The
      DEQ
      has also recently instituted a water sampling and monitoring requirement for
      wells north of a line that includes most of our Antrim projects. The drilling
      permits for these wells require produced water monitoring and reporting of
      gas
      and water volume and water quality. If the water produced by a well has levels
      of chloride or total dissolved solids concentration below specified levels,
      we
      may be required to shut-in the well. If such wells cannot be remediated so
      that
      fresh water is no longer produced, we may be required to plug such
      wells.





In
      September 2007, the DEQ collected and analyzed water samples from certain wells
      in the Arrowhead, Blue Chip, and Gaylord Fishing Club projects. On January
      31,
      2008, we met with the DEQ to review the analyses. Since the water composition
      in
      most of the wells fell within the range deemed by the DEQ to be fresh water,
      the
      DEQ requested that we plug six wells, plug or remediate an additional 15 wells,
      and collect water samples from the remaining wells that had not been previously
      sampled. We are currently preparing to collect a new round of water samples
      from
      every producing well, and the potential for remediation is under
      review.





Adverse
      weather may postpone any drilling or development activity, forcing delays until
      more favorable weather conditions develop. This is more likely to occur during
      the winter and spring months, but can occur at other times of the
      year.





Different
      natural gas reservoirs contain different amounts of water. The actual amount
      of
      time required for dewatering with respect to each well cannot be predicted
      with
      accuracy. The period of time when the volume of gas that is produced is limited
      by the dewatering process may be extended, thereby delaying revenue production.
      As noted above, a well producing too much water may have to be
      plugged.





***We
      do not own any drilling equipment.***





Since
      we
      do not own any drilling equipment, we are affected by competition for drilling
      rigs and the availability of related equipment. In the past, the oil and natural
      gas industry has experienced shortages of drilling rigs, equipment, and
      personnel which has delayed development drilling and other exploration
      activities and has caused significant price increases. We are unable to predict
      when or if such shortages may again occur or how they would affect our
      development and exploration program.





***Pipeline
      capacity may be inadequate.***





Because
      of the nature of natural gas development, there may be periods of time when
      pipeline capacity is inadequate to meet our gas transportation needs. It is
      often the case that as new development comes online, pipelines are close to
      or
      at capacity before new pipelines are built. During periods when pipeline
      capacity is inadequate, we may be forced to reduce production or incur
      additional expense as existing production requires additional compression to
      enter existing pipelines.





***Our
      reliance on third parties for gathering and distribution could curtail
      future***  ***exploration
      and production activities.***





The
      marketability of our production will depend on the proximity of our reserves
      to,
      and the capacity of, third party facilities and services, including oil and
      natural gas gathering systems, pipelines, trucking or terminal facilities,
      and
      processing facilities. The unavailability or insufficient capacity of these
      facilities and services could force us to shut-in producing wells, delay the
      commencement of production, or discontinue development plans for some of our
      properties, which would adversely affect our financial condition and
      performance. During 2006, our production was hampered by curtailments in a
      third-party processing facility. We have since completed construction of our
      own
      processing facility and built an alternate pipeline route in response to this
      curtailment.





***There
      is a potential for increased costs.***





The
      oil
      and natural gas industry has historically experienced periods of rapidly
      increasing drilling and production costs, frequently during times of increased
      drilling activities. If significant cost increases occur with respect to our
      development activity, we may have to reduce the number of wells we drill, which
      may adversely affect our financial performance.





20




***We
      may incur compression difficulties and expense.***





As
      production of natural gas increases, more compression is generally required
      to
      compress the production into the pipeline. As more compression is required,
      production costs increase, primarily because more fuel is required in the
      compression process. Furthermore, because compression is a mechanical process,
      a
      breakdown may occur that will cause us to be unable to deliver natural gas
      until
      repairs are made.





***We
      may not have good and marketable title to our
      properties.***





It
      is
      customary in the oil and natural gas industry that upon acquiring an interest
      in
      a non-producing property, only a preliminary title investigation is done at
      that
      time and that a drilling title opinion is done prior to the initiation of
      drilling, neither of which can substitute for a complete title investigation.
      We
      have followed this custom to date and intend to continue to follow this custom
      in the future. Furthermore, title insurance is not available for mineral leases,
      and we will not obtain title insurance or other guaranty or warranty of good
      title. If the title to our prospects should prove to be defective, we could
      lose
      the costs that we have incurred in their acquisition or incur substantial costs
      for curative title work.





***Competition
      in our industry is intense, and we are smaller and have a more
      limited***  ***operating
      history than most of our competitors.***





We
      compete with major and independent oil and natural gas companies for property
      acquisitions and for the equipment and labor required to develop and operate
      these properties. Most of our competitors have substantially greater financial
      and other resources than we do. In addition, larger competitors may be able
      to
      absorb the burden of any changes in federal, state and local laws and
      regulations more easily than we can, which would adversely affect our
      competitive position. These competitors may be able to pay more for exploratory
      prospects and productive oil and natural gas properties and may be able to
      define, evaluate, bid for and purchase a greater number of properties and
      prospects than we can. Our ability to explore for oil and natural gas prospects
      and to acquire additional properties in the future will depend on our ability
      to
      conduct operations, to evaluate and select suitable properties and to complete
      transactions in this highly competitive environment.





***Oil
      and natural gas operations involve various operating
      risks.***





The
      oil
      and natural gas business involves operating hazards such as well blowouts,
      craterings, explosions, uncontrollable flows of crude oil, natural gas or well
      fluids, fires, formations with abnormal pressures, pipeline ruptures or spills,
      pollution, releases of toxic gas and other environmental hazards and risks.
      Personal injuries, damage to property and equipment, reservoir damage, or loss
      of reserves may occur if such a catastrophe occurs, any one of which could
      cause
      us to experience substantial losses. In addition, we may be liable for
      environmental damage caused by previous owners of properties purchased or leased
      by us. To illustrate this risk, in late December 2006, a well in which we had
      a
      13.33% cost interest experienced a blow-out. Our associated liability was
      $762,000, only $266,666 of which was covered by insurance.





Federal
      and state regulation of oil and natural gas production and transportation,
      tax
      and energy policies, changes in supply and demand and general economic
      conditions all could adversely affect our ability to produce and market our
      natural gas and crude oil. Production from natural gas wells in many geographic
      areas of the United States has been curtailed or shut-in for considerable
      periods of time due to a lack of market demand, and such curtailments may
      continue for a considerable period of time in the future. There may be an excess
      supply of natural gas in areas where our operations will be conducted. If so,
      it
      is possible that there will be no market or a very limited market for our
      production.





As
      a
      result of operating hazards, regulatory risks and other uninsured risks, we
      could incur substantial liabilities to third parties or governmental entities,
      the payment of which could reduce or eliminate funds available for exploration,
      development or acquisitions.





21




***We
      may lack insurance that could lower risks to our
      investors.***





We
      have
      procured insurance policies for general liability, property/pollution, well
      control and director and officer liability in amounts considered by management
      to be adequate, as well as a $20 million excess liability umbrella policy.
      Nonetheless, the policy limits may be inadequate in the case of a catastrophic
      loss, and there are some risks that are not insurable. We have limited business
      interruption insurance. An uninsured loss could adversely affect our financial
      performance.





***Our
      credit facilities have operating restrictions and financial covenants that
      limit***  ***our
      flexibility and may limit our borrowing capacity; needed increases in
      borrowing***  ***capacity
      may not be available.***





As
      of
      December 31, 2007, our outstanding debt included a senior credit facility with
      a
      current approved borrowing base of $70 million, $56 million of which was
      drawn, and a five-year second lien term loan facility with a current approved
      borrowing base of $50 million, of which $50 million is currently
      drawn. All of our credit facilities, other than our office mortgage loan, have
      operational restrictions and credit ratio compliance requirements that limit
      our
      flexibility. If the ratio requirements are not satisfied, curative action may
      be
      required, such as repaying a part of the outstanding principal, and we will
      be
      unable to draw more funds to use in development. We may not have sufficient
      funds available to make any required repayment, which could cause us to be
      in
      default of our credit facilities.





The
      value
      of the assets pledged as collateral under our senior credit facility and second
      lien term loan facility will depend on the then current commodity prices for
      natural gas. If prices drop significantly, we may have difficulty satisfying
      the
      ratio covenants of these credit facilities. As noted above, oil and natural
      gas
      prices are volatile.





In
      order
      to execute our current development plan we will need to increase our credit
      availability as we add proved reserves. If we are unable to convert our assets
      to proved reserves at our planned pace, or if the value of our proved reserves
      drops as described above, we may be unable to increase our available credit
      as
      needed. Furthermore, any increases to our available credit will be entirely
      within the discretion of our lenders and may not be available to us even if
      we
      are successful in increasing the value of our proved reserves.





If
      we are
      unable to make use of our credit facilities, it may be difficult to find
      replacement sources of financing to use for working capital, capital
      expenditures, drilling, technology purchases or other purposes. Even if
      replacement financing is available, it may be on less advantageous terms than
      the current credit facilities. If we are unable to obtain increases in our
      borrowing capacity as needed, we may be unable to execute our development
      plans.





***Our
      debt level and the covenants in our credit facility agreements could negatively
      impact our financial condition, results of operations and business
      prospects.***





Our
      level
      of indebtedness, and the covenants contained in our credit facility agreements,
      could have important consequences for our operations, including:




●
            increasing
                our vulnerability to general adverse economic and industry conditions
                and
                detracting from our ability to withstand successfully a downturn
                in our
                business or the economy generally;


●
            requiring
                us to dedicate a substantial portion of our cash flow from operations
                to
                required payments on debt, thereby reducing the availability of cash
                flow
                for working capital, capital expenditures and other general business
                activities;


●
            limiting
                our ability to obtain additional financing in the future for working
                capital, capital expenditures, acquisitions and general corporate
                and
                other activities;


●
            limiting
                our flexibility in planning for, or reacting to, changes in our business
                and the industry in which we operate;


●
            placing
                us at a competitive disadvantage relative to other less leveraged
                competitors; and


●
            making
                us vulnerable to increases in interest rates, because borrowings
                under our
                credit facility may be at rates prevailing at the time of each borrowing.




22




***We
      may incur non-cash charges to our operations as a result of current and future
      financing transactions*** .





Under
      current accounting rules and requirements, we may incur additional non-cash
      charges to future operations beyond the stated contractual interest payments
      required under our current and potential future credit facilities. While such
      charges are generally non-cash, they would impact our results of operations
      and
      earnings per share and could be material.





***We
      may be required under accounting rules to take
      write-downs.***





Under
      full cost accounting rules, capitalized costs of proved oil and gas properties
      may not exceed the present value of estimated future net revenues from proved
      reserves, discounted at 10%. Application of the ceiling test generally requires
      pricing future revenue at the unescalated prices in effect as of the end of
      each
      fiscal quarter and requires a write-down for accounting purposes if the ceiling
      is exceeded. If a write-down is required, it would result in a charge to
      earnings but would not impact cash flow from operating activities. Once
      incurred, a write-down of oil and gas properties is not reversible at a later
      date.





***We
      may incur limitations on the effectiveness of
      controls.***





Our
      management, including our Chief Executive Officer and Chief Financial Officer,
      do not expect that our disclosure controls or our internal controls can prevent
      all possible error or fraud. A control system, no matter how well conceived
      and
      operated, can provide only reasonable, not absolute assurance that the
      objectives of the control system are met. Further, the design of a control
      system must reflect the fact that there are resource constraints, and the
      benefits of controls must be considered relative to their costs. Because of
      the
      inherent limitations on all control systems, no evaluation of controls can
      provide absolute assurance that we have detected all control issues and
      instances of fraud, if any. These inherent limitations include the realities
      that judgments in decision making can be faulty and that breakdowns can occur
      because of error or mistake. Additionally, controls can be circumvented by
      the
      individual acts of some persons, by collusion of two or more people or by
      management override of the control. The design of any system of controls also
      is
      based in part upon certain assumptions about the likelihood of future events,
      and there can be no assurance that any design will succeed in achieving its
      stated goals under all potential future conditions; over time, controls may
      become inadequate because of changes in conditions, or the degree of compliance
      with the policies or procedures may deteriorate. Because of the inherent
      limitations in a cost-effective control system, misstatements due to error
      or
      fraud may occur and not be detected.





***We
      have hedged and may continue to hedge a portion of our production, which
      may***  ***result
      in our making cash payments or prevent us from receiving the full benefit
      of***  ***increases
      in prices for oil and natural gas.***





In
      order
      to reduce our exposure to short-term fluctuations in the price of oil and
      natural gas, and in some cases as required by our lenders, we periodically
      enter
      into hedging arrangements. Our hedging arrangements apply to only a portion
      of
      our production and provide only partial price protection against declines in
      oil
      and natural gas prices. Such hedging arrangements may expose us to risk of
      financial loss in certain circumstances, including instances where production
      is
      less than expected, our customers fail to purchase contracted quantities of
      oil
      or natural gas or a sudden, unexpected event materially impacts oil or natural
      gas prices. In addition, our hedging arrangements may limit the benefit to
      us of
      increases in the price of oil and natural gas.


23


***We
      are subject to complex federal, state and local laws and regulations that
      could***  ***adversely
      affect our business.***





Oil
      and
      natural gas operations are subject to various federal, state and local
      government laws and regulations, which may be changed from time to time in
      response to economic or political conditions. Matters that are typically
      regulated include:





●
            discharge
                permits for drilling operations;


●
            drilling
                bonds;


●
            reports
                concerning operations;


●
            spacing
                of wells;


●
            unitization
                and pooling of properties;


●
            environmental
                protection; and


●
            taxation.





From
      time
      to time, regulatory agencies have imposed price controls and limitations on
      production by restricting the rate of flow of oil and natural gas wells below
      actual production capacity to conserve supplies of natural gas and crude oil.
      We
      also are subject to changing and extensive tax laws, the effects of which we
      cannot predict.





The
      development, production, handling, storage, transportation and disposal of
      natural gas and crude oil, by-products and other substances and materials
      produced or used in connection with oil and natural gas operations are subject
      to laws and regulations primarily relating to protection of human health and
      the
      environment. The discharge of natural gas, crude oil or pollutants into the
      air,
      soil or water may give rise to significant liabilities on our part to the
      government and third parties and may result in the assessment of civil or
      criminal penalties or require us to incur substantial costs of
      remediation.





Legal
      and
      tax requirements frequently are changed and subject to interpretation, and
      we
      are unable to predict the ultimate cost of compliance with these requirements
      or
      their effect on our operations. Existing laws or regulations, as currently
      interpreted or reinterpreted in the future, could harm our business, results
      of
      operations and financial condition.





**RISKS
      RELATED TO THE OWNERSHIP OF OUR STOCK**





***We
      may experience volatility in our stock price.***





For
      the
      36-month period ending December 31, 2007, our stock traded as high as $7.44
      per
      share and as low as $1.09 per share. The market price of our common stock may
      fluctuate significantly in response to a number of factors, some of which are
      beyond our control, including:





●
            changes
                in natural gas prices;


●
            changes
                in the natural gas industry and the overall economic
                environment;


●
            quarterly
                variations in operating results;


●
            changes
                in financial estimates by securities analysts;


●
            changes
                in market valuations of other similar companies;


●
                announcements
                    by us or our competitors of new discoveries or of significant
                    technical
                    innovations, contracts, acquisitions, strategic partnerships
                    or joint
                    ventures;


●
            additions
                or departures of key personnel;


●
            any
                deviations in net sales or losses from levels expected by securities
                analysts; and


●
            future
                sales of our common stock.





In
      addition, the stock market from time to time experiences extreme volatility
      that
      has often been unrelated to the performance of particular companies. These
      market fluctuations may cause our stock price to fall regardless of our
      performance.





24




***A
      voting block is created by certain voting agreements and irrevocable proxies,
      and we do not have cumulative***  ***voting.***





In
      connection with the closing of the merger of Cadence Resources Corporation
      and
      Aurora Energy, Ltd. certain of our shareholders, including certain former Aurora
      shareholders who became shareholders of us in connection with the merger,
      executed and delivered voting agreements pursuant to which they agreed, until
      October 31, 2008, to vote their shares of our common stock in favor of
      (i) five directors designated by William W. Deneau, who were initially
      William W. Deneau, Earl V. Young, Gary J. Myles, Richard Deneau, and Ronald
      E.
      Huff; and (ii) two directors designated by William W. Deneau from among our
      board of directors immediately before the closing of the merger, who were
      initially Howard Crosby and Kevin Stulp. Howard Crosby and Ronald E. Huff have
      since resigned from our board of directors. In addition, these shareholders
      agreed to vote all of their shares of common stock to ensure that the size
      of
      our board of directors will be set and remain at seven directors. After recent
      amendments to the voting agreements, an aggregate of 11,702,580 shares,
      approximately 11.5% of our outstanding shares, are subject to these voting
      agreements.





Also
      in
      connection with the closing of the merger, certain of our shareholders executed
      and delivered irrevocable proxies that currently name William W. Deneau and
      John
      E. McDevitt as proxies to vote their shares through October 31, 2008, in
      the manner determined by such proxies. An aggregate of approximately
      10.7 million shares of our common stock held by such shareholders was
      subject to these proxies at December 31, 2007. These provisions will reduce
      our
      other shareholders’ ability to influence the outcome of shareholder votes
      through October 31, 2008, including votes concerning the election of
      directors, the adoption or amendment of provisions in our articles of
      incorporation or bylaws and the approval of mergers and other significant
      corporate transactions.





Our
      shareholders do not have the right to cumulative voting in the election of
      our
      directors. Cumulative voting, in some cases, could allow a minority group to
      elect at least one director to our board. Because there is no provision for
      cumulative voting, a minority group will not be able to elect any directors.
      Accordingly, the holders of a majority of the shares of common stock, present
      in
      person or by proxy, will be able to elect all of the members of our board of
      directors.





***Our
      articles of incorporation contain provisions that discourage a change of
      control.***





Our
      articles of incorporation contain provisions that could discourage an
      acquisition or change of control without our board of directors’ approval. Our
      articles of incorporation authorize our board of directors to issue preferred
      stock without shareholder approval. If our board of directors elects to issue
      preferred stock, it could be more difficult for a third party to acquire control
      of us, even if that change of control might be beneficial to our
      shareholders.





***You
      may experience dilution of your ownership interests due to the future issuance
      of***  ***shares
      of our common stock, which could have an adverse effect on our stock
      price.***





We
      may,
      in the future, issue our previously authorized and unissued securities,
      resulting in the dilution of the ownership interests of our present
      shareholders. Our authorized capital stock consists of 250,000,000 shares
      of common stock and 20,000,000 shares of preferred stock with such
      designations, preferences and rights as may be determined by our board of
      directors. On December 31, 2007, we had 101,769,456 shares of common stock
      outstanding and no shares of preferred stock outstanding.





At
      December 31, 2007, we had warrants and options outstanding that were exercisable
      for 4,892,609 shares of our common stock. We have an additional 5,257,500 shares
      available for award as either option or stock grants under our existing
      incentive plans. The potential issuance of such additional shares of common
      stock may create downward pressure on the trading price of our common stock.
      We
      may also issue additional shares of our common stock, preferred stock, or other
      securities that are convertible into or exercisable for common stock in
      connection with the hiring of personnel, future acquisitions, private placements
      of our securities for capital raising purposes, debt refinancing, or for other
      business purposes. In the future, we may engage in public offerings of our
      stock. Future sales of substantial amounts of our common stock, or the
      perception that sales could occur, could have a material adverse effect on
      the
      price of our common stock.





25




***The
      market price of our common stock could be adversely affected by sales
      of***  ***substantial
      amounts of our common stock in the public markets.***





We
      have
      filed two shelf registration statements that together would register almost
      20.6 million shares of common stock for resale. These registration
      statements are not currently effective. The sale of a large number of shares
      of
      our common stock pursuant to the resale registration statements, the perception
      that any such sale might occur, or the issuance of a large number of shares
      of
      our common stock in connection with future acquisitions, equity financings
      or
      otherwise, could cause the market price of our common stock to decline
      significantly. As of December 31, 2007, we had approximately 101.8 million
      shares of common stock issued and outstanding, including approximately
      10.5 million shares of our common stock held or controlled by our executive
      officers and directors. Of those 10.5 million shares, 8.6 million are
      subject to lock-up agreements through October 31, 2008, 0.5 million are eligible
      for resale on two S-8 registration statements, and the balance are eligible
      for
      sale under Rule 144 ("Rule 144") under the Securities Act of 1933, as amended
      (the "Securities Act"). We have two currently effective S-8 registration
      statements that, combined, include 469,996 shares owned or controlled by our
      executive officers and directors that are registered for resale.





**ITEM
      1B.**  **UNRESOLVED
      STAFF COMMENTS**




On
      December 18, 2007, we received an SEC comment letter pertaining to our Form
      10-KSB for the year ended December 31, 2006, and our Form 10-Q for the period
      ended September 30, 2007. The SEC comments addressed: (i) a presentation
      issue in the statement of operations; (ii) disclosures relating to asset
      retirement obligations, income (loss) per share, shareholders’ equity,
      methodologies for capitalizing interest, changes in standardized measure of
      discounted future cash flow, and SFAS 69; (iii) clarification on fourth
      quarter adjustments; and (iv) engineering comments with respect to our oil
      and gas reserves. On January 17, 2008, we filed our response. On February 13,
      2008, we received a letter from the SEC with follow-up engineering comments
      and,
      on February 28, 2008, we filed our response. We have not yet received a reply
      from the SEC addressing our responses. We have incorporated into this Form
      10-K
      several of the changes we suggested in our response to the SEC. We do not
      currently have reason to believe that there are any material open items but,
      since the SEC has not yet replied to our accounting response, we cannot be
      sure
      if there are any material open items.





**ITEM
      2.**  **PROPERTIES**




Information
      regarding our properties is included in Item 1 of this report.





**ITEM
      3.**  **LEGAL
      PROCEEDINGS**




Our
      management is unaware of any threatened or pending material legal claims or
      proceedings against us or our properties of a non-routine nature.





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




There
      were no matters submitted to a vote of our security holders for the quarter
      ended December 31, 2007.


26


**PART
      II**





**ITEM
      5.**  **MARKET
      FOR COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY
      SECURITIES**




**PRICE
      RANGE OF COMMON STOCK**





Our
      common stock trades under the symbol AOG on the American Stock Exchange
      ("AMEX"). Prior to May 2006, our common stock traded under the symbol CDNR.BB
      on
      the Over-the-Counter Bulletin Board Electronic Quotation System maintained
      by the National Association of Securities Dealers. The following chart shows
      the
      range of high and low bid prices/sales prices for our common stock for each
      fiscal quarter in the two most recent fiscal years. The prices during the time
      in which our stock traded over-the-counter are bid prices, without retail
      mark-up, mark-down or commission, and may not necessarily represent actual
      transactions. The prices during the time in which our stock traded on AMEX
      are
      actual sales prices.





Quarter
                Ended
            
            High Bid/
              Sales Price
            
            Low Bid/
              Sales PriceMarch 31,
                2006
            
            $
            7.44
            
            $
            4.45June 30,
                2006
            
            $
            6.10
            
            $
            3.76September 30,
                2006
            
            $
            4.74
            
            $
            2.94December
                31, 2006
            
            $
            3.22
            
            $
            3.08March
                31, 2007
            
            $
            3.30
            
            $
            2.06June
                30, 2007
            
            $
            2.77
            
            $
            1.30September
                30, 2007
            
            $
            2.35
            
            $
            1.37December
                31, 2007
            
            $
            1.75
            
            $
            1.16





On
      February 26, 2008, the last reported sale price of our common stock on AMEX
      was
      $0.70 and there were 102,299,456 shares of our common stock outstanding and
      approximately 517 holders of record.





**DIVIDEND
      POLICY**





There
      have been no cash dividends declared on our common stock since we were formed.
      We do not intend to pay cash dividends on our common stock for the foreseeable
      future. Our current credit facilities prohibit us from declaring
      dividends.


27


**STOCK
      PERFORMANCE GRAPH**





The
      graph
      below compares the monthly performance of our common stock to the Russell 2000
      Index and the AMEX Natural Gas Index for the period beginning on the close
      of
      our first day of trading on the AMEX on May 24, 2006, and ending on the close
      of
      trading on the AMEX on December 31, 2007. The graph assumes a $100 investment
      in
      our common stock and each of the indices and reinvestment of
      dividends.










**SECURITIES
      AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS**





In
      October 1997, Aurora adopted a 1997 Stock Option Plan pursuant to which it
      was
      authorized to issue compensatory options to purchase up to 1,000,000 shares
      of
      common stock. Aurora issued options to purchase a total of 580,000 shares of
      Aurora's common stock under this plan, which upon closing the merger, converted
      into the right to acquire up to 1,160,000 shares of our common stock. Because
      of
      the merger, no further awards will be made under this plan.





In
      2001,
      Aurora's board of directors and shareholders approved the adoption of an Equity
      Compensation Plan for Non-Employee Directors. This plan provided that each
      non-employee director is entitled to receive options to purchase 100,000 shares
      of Aurora's common stock, issuable in increments of options to purchase 33,333
      shares each year over a period of three years, so long as the director continues
      in office. Prior to the merger closing, Aurora had issued options to purchase
      a
      total of 309,997 shares of Aurora common stock under this plan, which upon
      closing the merger converted to the right to acquire 619,994 shares of our
      common stock. Because of the merger, no further awards will be made under this
      plan.





In
      2004,
      our board of directors adopted a 2004 Equity Incentive Plan. Our shareholders
      approved this plan, also in 2004. This plan provides for the grant of options
      or
      restricted shares for compensatory purposes for up to 1,000,000 shares of common
      stock. The number of shares issued or subject to options issued under this
      plan
      total 910,500. Although we do not intend to make any further awards under this
      plan, the plan currently continues to exist.





28





In
      March
      2006, our board of directors adopted, and in May 2006 our shareholders approved,
      the 2006 Stock Incentive Plan. This Plan provides for the award of options
      or
      restricted shares for compensatory purposes for up to 8,000,000 shares. As
      of
      December 31, 2007, we had awarded restricted stock and options to purchase
      restricted stock in a total amount of 2,742,500 shares, leaving
      5,257,500 shares available for future awards.





We
      have
      awarded compensatory options and warrants to individuals that are considered
      outside the awards issued under our 2004 Equity Incentive Plan. Aurora has
      also
      issued compensatory options and warrants to individuals that are considered
      outside the awards issued under its 1997 Stock Option Plan and Equity
      Compensation Plan for Non-Employee Directors.





The
      following chart sets forth certain information as of December 31, 2007 regarding
      the shares of our common stock (i) issuable upon exercise of options or warrants
      granted as compensation for services; and (ii) available for grant under
      existing plans.





Plan
                Category
            
            No. of Securities to
              be Issued Upon
              Exercise of
              Outstanding
              Options, Warrants
              and Rights
            
            Weighted Average
              Exercise Price of
              Outstanding
              Options, Warrants
              and Rights
            
            No. of Securities
              Remaining Available for
              Future Issuance Under
              Equity Compensation
              Plans (Excluding
              Securities in the First
              Column of this TableEquity
                compensation plansapproved by security holders
            
            
            2,873,664
            
            $
            3.04
            
            
            5,257,500Equity
                compensation plansand awards not approved by security
                holders
            
            
            86,280(a
            )
            $
            1.69
            
            
            -0-Total/combined
            
            
            2,959,944
            
            $
            3.00
            
            
            5,257,500





(a)
            These
                options and warrants to purchase shares were issued as follows:




Warrants
                to purchase 56,000 shares (these are Aurora conversion shares originally
                issued to purchase 28,000 shares of Aurora common stock) were issued
                to
                Nathan A. Low's designees in compensation for investment banking
                services
                rendered.




Options
                to purchase 30,280 shares were issued in two separate individualized
                compensation arrangements with executive officers and/or directors
                not
                pursuant to a formal plan.





**UNREGISTERED
      EQUITY SALES/PURCHASES**





None.




29


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




The
      following table sets forth our December 31, 2007, 2006, and 2005, year end
      selected financial data as of and for each of the periods indicated. The data
      as
      of and for the years ended December 31, 2007, 2006, and 2005, is derived
      from our audited consolidated financial statements for the periods indicated.
      You should review this information together with “Management’s Discussion and
      Analysis of Financial Condition and Results of Operations” and audited
      consolidated financial statements and related notes included elsewhere in this
      report. The following information is not necessarily indicative of our future
      financial results.





2007
            
            2006
            
            2005**Statement
                of Operations Data**Revenues:Oil
                and natural gas sales
            
            $
            26,723,818
            
            $
            21,591,811
            
            $
            6,743,444Pipeline
                transportation and marketing
            
            
            792,587
            
            
            489,473
            
            
            -Field
                service and sales
            
            
            390,401
            
            
            125,611
            
            
            -Interest
                and other
            
            
            549,149
            
            
            220,592
            
            
            666,850Total
                revenues
            
            
            28,455,955
            
            
            22,427,487
            
            
            7,410,294Expenses:Production
                taxes
            
            
            1,123,070
            
            
            877,319
            
            
            506,635Production
                and lease operating expense
            
            
            8,761,445
            
            
            5,966,341
            
            
            1,587,205Pipeline
                operating expense
            
            
            359,865
            
            
            265,795
            
            
            -Field
                services expense
            
            
            321,753
            
            
            90,913
            
            
            -General
                and administrative expense
            
            
            8,029,122
            
            
            7,531,718
            
            
            3,435,507Oil
                and natural gas depletion and amortization
            
            
            3,769,104
            
            
            2,681,290
            
            
            767,511Other
                assets depreciation and amortization
            
            
            2,396,026
            
            
            2,083,191
            
            
            308,647Interest
                expense
            
            
            4,582,021
            
            
            4,573,785
            
            
            1,307,370Loss
                on debt extinguishment
            
            
            3,448,520
            
            
            -
            
            
            -Taxes,
                other
            
            
            19,021
            
            
            250,884
            
            
            29,651Total
                expenses
            
            
            32,809,947
            
            
            24,321,236
            
            
            7,942,526Loss
                before minority interest
            
            
            (4,353,992
            )
            
            (1,893,749
            )
            
            (532,232
            )Minority
                interest in (income) loss of subsidiaries
            
            
            (67,841
            )
            
            (50,898
            )
            
            15,960Net
                loss
            
            $
            (4,421,833
            )
            $
            (1,944,647
            )
            $
            (516,272
            )Net
                loss per common share-basic and diluted
            
            $
            (0.04
            )
            $
            (0.02
            )
            $
            (0.01
            )Weighted
                average common shares outstanding - basic and diluted
            
            
            101,633,162
            
            
            82,288,243
            
            
            40,622,000**Cash
                Flow Data**Cash
                provided by (used in) operating activities
            
            $
            10,079,049
            
            $
            5,467,910
            
            $
            (2,404,739
            )Cash
                used by investing activities
            
            
            (61,100,489
            )
            
            (89,606,098
            )
            
            (39,869,326
            )Cash
                provided by financing activities
            
            
            51,711,722
            
            
            73,892,946
            
            
            49,075,121




30




As
                of December 31,2007
            
            2006**Balance
                Sheet Data**Cash
                and cash equivalents
            
            $
            2,425,678
            
            $
            1,735,396Other
                current assets
            
            
            8,901,774
            
            
            11,306,797Oil
                and natural gas properties, net (using full cost
                accounting)
            
            
            209,818,344
            
            
            161,471,277Other
                property and equipment, net
            
            
            10,365,599
            
            
            10,465,897Other
                assets
            
            
            23,160,273
            
            
            27,407,825Total
                assets
            
            $
            254,671,668
            
            $
            212,387,192Current
                liabilities
            
            $
            8,580,990
            
            $
            18,040,082Long-term
                debt, net of current maturities
            
            
            113,835,028
            
            
            54,538,138Minority
                interest in nets assets of subsidiaries
            
            
            112,661
            
            
            77,873Shareholders’
                equity
            
            
            132,142,989
            
            
            139,731,099Total
                liabilities and shareholders’ equity
            
            $
            254,671,668
            
            $
            212,387,192




31


**ITEM
      7.**  **MANAGEMENT’S
      DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
      OPERATIONS**




*The
      following discussion and analysis should be read in conjunction with the
“Selected Historical Financial Data” and the consolidated financial statements
      and related notes included elsewhere in this report. This discussion contains
      forward-looking statements reflecting our current expectations and estimates
      and
      assumptions concerning events and financial trends that may affect our future
      operating results or financial position. Actual results and the timing of events
      may differ materially from those contained in these forward-looking statements
      due to a number of factors, including those discussed in the sections entitled
      “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements”
appearing elsewhere in this report.*




**Executive
      Summary**





We
      are a
      growing independent energy company focused on the exploration, exploitation,
      and
      development of unconventional natural gas reserves. Our unconventional natural
      gas projects target shale plays where large acreage blocks can be easily
      evaluated with a series of low cost test wells. Shale plays tend to be
      characterized by high drilling success and relatively low drilling costs when
      compared to conventional exploration and development plays. Our project areas
      are focused in the Antrim shale of Michigan and New Albany shale of Southern
      Indiana and Western Kentucky.





In
      1969,
      we commenced operations to explore and mine natural resources under the name
      Royal Resources, Inc. In July 2001, we reorganized our business to pursue oil
      and gas exploration and development opportunities and changed our name to
      Cadence Resources Corporation. We acquired Aurora Energy, Ltd. ("Aurora") on
      October 31, 2005 through the merger of our wholly-owned subsidiary with and
      into
      Aurora. The acquisition of Aurora was accounted for as a reverse merger, with
      Aurora being the acquiring party for accounting purposes. The Aurora executive
      management team also assumed management control at the time the merger closed,
      and we moved our corporate offices to Traverse City, Michigan.





As
      a
      result of the reverse merger, the historical financial statements presented
      for
      periods prior to the acquisition date are the financial statements of Aurora.
      The operations of the former Cadence Resources Corporation businesses have
      been
      included in the consolidated financial statements from the date of
      acquisition. Effective May 11, 2006, Cadence Resources Corporation amended its articles
      of incorporation to change the parent company name to Aurora Oil & Gas
      Corporation.




**Operational
      Highlights**





For
      the
      year ended December 31, 2007, we continued to shift our focus from acquisition
      of properties to an early stage developer of unconventional shale development
      projects. As of December 31, 2007, our leasehold acres were 1,283,183 (712,215
      net) which represent a 5% increase over our December 31, 2006 net acres. These
      leasehold acres are included in the following plays: 310,141 (156,481 net)
      leasehold acres in the Michigan Antrim shale play, 15,683 (15,683 net) leasehold
      acres in the Indiana Antrim shale play, 833,365 (443,457 net) acres in the
      New
      Albany shale play, 37,325 (33,219 net) acres in the Woodford shale play, and
      86,669 (64,175 net) acres in the Other play areas.




With
      regard to our strategy to generate growth through drilling, we drilled or
      participated in 101 (59 net) wells for the year ended December 31, 2007, with
      a
      92% success rate. As of December 31, 2007, we had 649 (305 net) producing wells,
      31 (15 net) wells awaiting hook-up, 54 (37 net) wells undergoing resource
      assessment and 9 (2 net) wells temporarily abandoned. We also continued our
      strategy to have greater control over our projects by operating 258 (240 net)
      wells, thus, operating 35% of our gross wells and 67% of our net
      wells.


32


We
      began
      2007 with estimated proved reserves of 153 bcfe and at December 31, 2007 had
      167
      bcfe, an increase of 14 bcfe, or 9%. The New Albany shale provided the largest
      increase in proved reserves during the year, adding a net 27 bcfe, which is
      a
      900% increase over the 3.0 bcfe reported on December 31, 2006. The growth in
      the
      New Albany shale proved reserves was largely the result of 6 net wells drilled
      in 2007, which were 100% owned by Aurora. The Antrim shale proved reserves
      were
      reduced by a net 10.1 bcfe due to a 24.5 bcfe increase from positive drilling
      results in the Antrim shale and offset by a 34.6 bcfe reduction in certain
      properties. This reduction reflected a lower production projection to be
      consistent with actual operating experience.




Oil
      and
      natural gas production for 2007 was 3,207,155 mcfe, or a 21% increase over
      the
      2,653,427 mcfe produced in 2006. During 2007, production continued to be
      hampered by delays in bringing wells into production, weather, dewatering,
      and
      certain properties not meeting expected production targets. Our average daily
      production for 2007 was 8,787 mcfe per day compared to 7,270 mcfe per day in
      2006.





On
      September 10, 2007, we announced that we have established an acreage position
      of
      over 30,000 net acres in the Woodford shale natural gas play of Oklahoma. The
      identified target area is focused in central Oklahoma, which is experiencing
      a
      significant increase in leasing and drilling activity. It is positioned among
      geological provinces with active Woodford shale development, with average depths
      over 5,000 feet and organic shale thickness up to 300 feet. We currently have
      expended approximately $8.0 million for an 89% working interest in over 37,000
      gross acres in the play. The early leasing activities have allowed us to
      establish this competitive position in the targeted play area. Leasing
      activities are continuing. We have targeted 2008 for a pilot program of 5 test
      wells in the project area. Since our current capital expenditure budget has
      been
      dedicated to further development of the Antrim and New Albany shales, we have
      been in discussions with potential financing sources and joint venture partners
      to facilitate testing and development of this acreage. No financing for this
      development has been procured as of the date of this filing.




In
      the
      third quarter of 2007, we drilled six wells in the South Knox project area
      of
      the New Albany shale and began construction of our first operated sales outlet
      in the New Albany Shale. Our wholly-owned subsidiary, Bach Services and
      Manufacturing Company (“Bach”) was responsible for building the sales outlet.
      Bach completed a pipeline which included trenching 10.6 miles with installation
      of 20 miles of poly piping and 10 miles of steel piping as well as building
      a
      processing and compression facility. The facility is tapped into the Ohio Valley
      Hub, LLC pipeline system, a wholly-owned subsidiary of ProLiance Energy, LLC.
      We
      began test flowing gas from these wells on December 31, 2007.




**Other
      Developments**





On
      August
      20, 2007, we entered into a second lien term loan agreement with BNP, as the
      arranger and administrative agent, and several other lenders forming a
      syndication. The initial term loan is $50 million for a 5-year term which may
      increase up to $70 million under certain conditions over the life of the loan
      facility. The proceeds of the loan were used to pay off our existing mezzanine
      financing with TCW and for general corporate purposes. In connection with the
      loan, we also agreed to the amendment and restatement of our senior secured
      credit facility with BNP and other lenders, pursuant to which the borrowing
      base
      under the senior secured credit facility was increased from the current
      authorized borrowing base of $50 million to $70 million.





In
      September 2007, we retained Johnson Rice & Company, L.L.C. (“JRCO”) to
      investigate our strategic alternatives. The alternatives, among other things,
      were to include revisions to our strategic plan, asset divestitures, operating
      partnerships, identifying additional capital sources, or a sale, merger, or
      other business combination. During this investigative period, we reduced our
      drilling activities, postponed significant asset divestitures, and focused
      on
      maintaining our current operations pending the outcome of the evaluation
      process.





With
      the
      assistance of JRCO, our Board of Directors determined that the best way to
      create value was to strengthen our management team, increase our capital
      availability, focus on drilling our undeveloped properties, and optimize our
      asset portfolio through the sale, joint venture, farm-out, or development of
      our
      non-core leasehold.


33


On
      January 25, 2008, we announced the signing of a non-binding Letter of Intent
      to
      acquire Acadian Energy, LLC, a private company focused on development of the
      unconventional resources found in the New Albany shale. The proposed acquisition
      is valued at approximately $12.5 million and will include over 10,000 acres
      of
      New Albany shale properties, four development wells, and approximately 7 bcf
      in
      proved reserves. The company is jointly owned and operated by John E. McDevitt
      and Gilbert A. Smith (60% and 40% beneficial ownership,
      respectively).





As
      part
      of that announcement, we also noted that, effective January 22, 2008, the Board
      of Directors named Mr. McDevitt President, Chief Operating Officer, and
      Director. Mr. Smith was named Vice President of Business Development, effective
      as of February 1, 2008. Each of these gentlemen offers approximately 40 years
      of
      experience, which includes executive-level experience, some of it at large
      exploration and production companies. In addition, Mr. McDevitt has spent the
      bulk of his career specializing in structured finance for emerging
      enterprises.





With
      Mr.
      McDevitt’s assistance, we have determined that our existing capital structure is
      not adequate to continue our planned growth. In fact, we believe that the best
      way to pursue the development of our acreage base is to install project
      financing directed toward each play or subset of each play. At this time, we
      are
      negotiating several term sheets with certain recognized energy lenders offering
      credit facilities for a minimum of at least $50 million per project for at
      least
      two of our development projects—one for the New Albany shale and one for the
      Woodford shale. Upon closing, we expect to have to establish separate financing
      for these projects which will be non-recourse to our other businesses. Our
      goal is to have these term sheets signed within approximately 30 days and
      closed, subject to BNP consent, within 90 days. We anticipate announcing the
      terms of the respective credit facilities upon the closing of such
      agreements. There can be no assurance that we will be able to successfully
      procure the project financings that we are seeking.





Also,
      our
      Board of Directors is in the process of completing its work with JRCO. This
      evaluation process did not lead to an asset divestiture, operating partnership,
      or identification of additional capital sources. It did, however, lead to a
      revision in our strategic plan, the related non-binding Letter of Intent to
      acquire Acadian Energy, LLC, and the change in our management team. We believe
      that, despite the operational slowdown we experienced over the past 6 months,
      this process has enabled the Board of Directors to retain a more experienced
      management team, has led to the receipt of term sheets from new financial
      institutions which are expected to increase our capital availability, and has
      established a more disciplined focus on optimizing our entire asset
      base.


34


**RESULTS
      OF OPERATIONS**


**Operating
      Statistics**




The
      following table sets forth certain key operating statistics for the years ended
      December 31, 2007, 2006, and 2005:




Year
                Ended December 31,2007
            
            2006
            
            2005Net
                wells drilledAntrim
            
            
            33
            
            
            93
            
            
            105New
                Albany
            
            
            11
            
            
            7
            
            
            -Other
            
            
            8
            
            
            5
            
            
            1Dry
            
            
            7
            
            
            7
            
            
            7Total
            
            
            59
            
            
            112
            
            
            113Total
                producing net wellsAntrim
                – producing
            
            
            287
            
            
            199
            
            
            110Antrim
                – awaiting hookup
            
            
            7
            
            
            51
            
            
            52NAS
                – producing
            
            
            3
            
            
            1
            
            
            -NAS
                – awaiting hookup
            
            
            5
            
            
            7
            
            
            2Other
                – producing
            
            
            15
            
            
            14
            
            
            13Other
                – awaiting hookup
            
            
            3
            
            
            1
            
            
            6Total
            
            
            320
            
            
            273
            
            
            183ProductionNatural
                gas (mcf)
            
            
            3,039,714
            
            
            2,517,897
            
            
            687,271Crude
                oil (bbls)
            
            
            27,907
            
            
            22,588
            
            
            10,628Natural
                gas equivalent (mcfe)
            
            
            3,207,155
            
            
            2,653,427
            
            
            751,039Average
                daily productionNatural
                gas (mcf)
            
            
            8,328
            
            
            6,898
            
            
            1,883Crude
                oil (bbls)
            
            
            76
            
            
            62
            
            
            29Natural
                gas equivalent (mcfe)
            
            
            8,787
            
            
            7,270
            
            
            2,057Average
                sales prices (including realized gains or losses from
                hedging)Natural
                gas ($ per mcf)
            
            $
            8.15
            
            $
            8.02
            
            $
            9.00Crude
                oil ($ per bbl)
            
            $
            69.49
            
            $
            61.96
            
            $
            52.55Natural
                gas equivalent ($ per mcfe)
            
            $
            8.33
            
            $
            8.14
            
            $
            8.98Production
                revenueNatural
                gas
            
            $
            24,784,658
            
            $
            20,192,366
            
            $
            6,184,989Crude
                oil
            
            
            1,939,160
            
            
            1,399,445
            
            
            558,455Total
            
            $
            26,723,818
            
            $
            21,591,811
            
            $
            6,743,444Average
                expenses ($ per mcfe)Production
                taxes
            
            $
            0.35
            
            $
            0.33
            
            $
            0.67Post-production
                expenses
            
            
            0.59
            
            
            0.46
            
            
            0.50Leasing
                operating expenses
            
            
            2.14
            
            
            1.78
            
            
            1.61General
                and administrative expense
            
            
            2.50
            
            
            2.84
            
            
            4.57General
                and administrative expense excluding stock-based compensation
            
            
            1.81
            
            
            2.00
            
            
            4.57Oil
                and natural gas depreciation, depletion and amortization expense
            
            
            1.18
            
            
            1.01
            
            
            1.02Other
                assets depreciation and amortization
            
            
            0.75
            
            
            0.79
            
            
            0.41Interest
                expense
            
            
            1.43
            
            
            1.72
            
            
            1.74Taxes
            
            
            0.01
            
            
            0.09
            
            
            0.04Number
                of employees including Bach employees
            
            
            68
            
            
            90
            
            
            36


35




**Year
      Ended December 31, 2007, compared with Year Ended December 31,
      2006**





**General** .
      For the
      year ended December 31, 2007, we had a net loss of $4.4 million, or $(0.04)
      per
      diluted common share, on total revenues of $28.5 million. This compares to
      a net
      loss of $1.9 million, or $(0.02) per diluted common share, on total revenue
      of
      $22.4 million during the year ended December 31, 2006. The $6.1 million increase
      in revenue represents increased production and improved price realization as
      a
      result of higher market prices and financial hedging. In addition, the net
      loss
      of $4.4 million in 2007 included a $3.4 million in a one time charge on debt
      extinguishment and $2.2 million in stock-based compensation
      expense.





**Oil
      and Natural Gas Sales** .
      During
      2007, oil and natural gas sales were $26.7 million compared to $21.6 million
      in
      2006. We produced 3,207,155 mcfe at a weighted average price of $8.33 compared
      to 2,653,427 mcfe at a weighted average price of $8.14. This increase in
      production was due to new wells placed on-line and production growth of existing
      wells. We had 305 net wells producing as of December 31, 2007 as compared to
      214
      net wells producing as of December 31, 2006. The 2007 weighted average price
      included $3.9 million of realized gains from the gas derivative contracts.
      Production from the Antrim shale play represented approximately 91% of our
      oil
      and natural gas revenue for 2007.





The
      following table summarizes our oil and natural gas revenue by play/trend in
      the
      periods set forth below:


Year Ended
                December 31, 2007
              
              Year Ended
                December 31, 2006Play/Trend
              
              (mcfe)
              
              Amount
              
              (mcfe)
              
              AmountAntrim
              
              
              2,975,715
              
              $
              24,346,250
              
              
              2,353,691
              
              $
              18,948,300New
                  Albany
              
              
              57,186
              
              
              404,967
              
              
              28,517
              
              
              190,079Other
              
              
              174,254
              
              
              1,972,601
              
              
              271,219
              
              
              2,453,432Total
              
              
              3,207,155
              
              $
              26,723,818
              
              
              2,653,427
              
              $
              21,591,811





**Other
      Revenues** .
      Other
      revenues increased by $0.9 million, or 107% to $1.7 million in 2007 from $0.8
      million in 2006. This increase is attributed to two acquisitions completed
      in
      2006 and the sale of mining claims in 2007. The first acquisition is the Hudson
      gas properties with pipeline business component and the second acquisition
      is
      Bach which provides oil and natural gas field services.





**Production
      Taxes.** Production
      taxes were $1.1 million in 2007 compared to $0.9 million in 2006. This increase
      is attributed to production growth and the state mix of production. On a unit
      of
      production basis, production taxes were $0.35 per mcfe in 2007 compared to
      $0.33
      per mcfe in 2006.


****


**Production
      and Lease Operating Expenses** .
      Our
      production and lease operating expenses include services related to producing
      oil and natural gas, such as post production costs, including marketing and
      transportation, and expenses to operate the wells and equipment on producing
      leases.





Production
      and lease operating expenses were $8.8 million in 2007 compared to $6.0 million
      in 2006. On a unit of production basis, production and lease operating expenses
      were $2.73 per mcfe in 2007 compared to $2.24 per mcfe in 2006. The increase
      in
      2007 was primarily attributable to our expanding operations which increased
      energy costs, property taxes, pumping costs, repair, and maintenance associated
      with meters, compressors and pumps, and outside labor. On a component basis,
      post-production expenses were $1.9 million, or $0.59 per mcfe in 2007 compared
      to $1.2 million or $0.46 per mcfe in 2006 and lease operating expenses were
      $6.9
      million, or $2.14 per mcfe in 2007 compared to $4.7 million, or $1.78 per mcfe
      in 2006.





Production
      and lease operating expenses for operated properties were $2.64 per mcfe in
      2007
      compared to $2.23 per mcfe in 2006. Non-operated production and lease operating
      expenses were $2.91 per mcfe in 2007 compared to $2.74 in 2006. Our operated
      Arrowhead and Chandler North projects negatively impacted our operating cost
      controls and efficiency due to extensive dewatering needs. Production and lease
      operating expenses for operated properties excluding Arrowhead and Chandler
      North were $2.51 per mcfe in 2007.





36




**Pipeline
      Operating Expense and Field Services Expenses** .
      Pipeline operating expenses were $0.4 million in 2007 compared to $0.3 million
      in 2006. Field services expenses were $0.3 million in 2007 compared to $0.1
      million in 2006, which was attributable to the Bach acquisition in October
      2006.





**General
      and Administrative Expenses** .
      Our
      general and administrative expenses include officer and employee compensation,
      travel, audit, tax and legal fees, office supplies, utilities, insurance,
      consulting fees and office related expense. General and administrative expenses
      in 2007 increased by $0.5 million, or 6%, from 2006. This increase is the result
      of increases in our employee and related costs.





Payroll
      and related costs increased by $1.5 million to $6.3 million in 2007. This
      included staffing additions and merit increases ($0.8 million), stock-based
      compensation ($0.3 million), 2007 retention bonuses ($0.2 million) and health
      care ($0.2 million). Legal, accounting, and other consulting services were
      reduced by $0.4 million to $1.4 million in 2007 compared to $1.8 million in
      2006, even though Section 404 of the Sarbanes-Oxley Act of 2002 was
      implemented for $0.2 million. Insurance had a slight increase of $65,000 due
      to
      coverage associated with Bach, while there were offsets of $0.4 million from
      the
      disposal of legacy Cadence stock investments and a correction of the stock
      ledger associated with a prior Cadence transaction.





We
      follow
      the full cost method of accounting under which all costs associated with
      property acquisition, exploration and development activities are capitalized.
      We
      capitalized certain internal costs that can be directly identified with our
      acquisition, exploration and development activities and did not include any
      costs related to production, general corporate overhead or similar activities.
      During the year ended December 31, 2007, we capitalized $1.3 million of payroll
      and benefit costs to oil and natural gas properties.





**Oil
      and Natural Gas Depletion, Depreciation and Amortization
      (“DD&A”)** .
      DD&A of oil and natural gas properties was $3.8 million and $2.7 million
      during 2007 and 2006, respectively. DD&A is a function of capitalized costs
      in the full cost pool and related underlying reserves in the periods presented.
      This increase is the result of $46.1 million being added to proved properties
      in
      the full cost pool, production growth, and the underlying reserves increasing
      by
      13.1 bcfe. The average DD&A cost per mcfe was $1.18 and $1.01 in 2007
      and 2006, respectively





**Other
      Assets Depreciation and Amortization (“D&A”)** .
      D&A
      of other assets was $2.4 million in 2007, compared to $2.1 million in 2006.
      This
      increase was primarily the result of additions in other assets.





**Interest
      Expense** .
      Interest expense was $4.6 million in 2007 and $4.6 million in 2006 which remain
      relatively stable given higher utilization of debt to continue our growth
      strategy of acquiring and developing operating interests in the Antrim shale
      and
      the New Albany shale.





**Loss
      on Debt Extinguishment.** We
      recorded $3.4 million as a loss on debt extinguishment due to the termination
      of
      the mezzanine debt held by TCW. Under the termination provisions, we were
      required to pay certain fees and prepayment charges associated with early
      termination. The following represents the expenses incurred: (i) $0.35 million
      payment of interest make-whole provision from August 21, 2007, through September
      27, 2007; (ii) $1.25 million payment of prepayment premium; (iii) $0.2 million
      payment for a make-whole provision on principal greater than $30 million; and
      (iv) $1.6 million write-off of unamortized debt issuance cost





**Taxes,
      Other.** Tax
      expense was $19,021 in 2007, compared to $0.3 million in 2006. This decrease
      represents a 2005 Indiana tax refund of approximately $46,000 and a $45,000
      reduction in estimated Louisiana state taxes. We have significant net operating
      loss carry forwards, thus no federal income tax expense has been recognized.


37




**Year
      Ended December 31, 2006, compared with Year Ended December 31,
      2005**





**General** .
      For the
      year ended December 31, 2006, we had a net loss of $1.9 million, or $(0.02)
      per
      diluted common share, on total revenues of $22.4 million. This compares to
      a net
      loss of $0.5 million, or $(0.01) per diluted common share, on total revenue
      of
      $7.4 million during the year ended December 31, 2005. The $15.0 million increase
      in revenue represents our initial steps as an early stage developer of oil
      and
      natural gas properties.





**Oil
      and Natural Gas Sales** .
      During
      2006, oil and natural gas sales were $21.6 million compared to $6.7 million
      in
      the 2005. We produced 2,653,427 mcfe at a weighted average price of $8.14
      compared to 751,039 mcfe at a weighted average price of $8.98. This increase
      in
      production was due to new wells placed on-line, acquisition of additional
      working interest in the Hudson properties and the producing assets from the
      Cadence reverse merger. We had 214 net wells producing as of December 31, 2006
      as compared to 123 net wells producing as of December 31, 2005. The weighted
      average price included $2.7 million of realized gains from the gas derivative
      contract entered into 2006. Production from the Antrim shale play represented
      approximately 88% of our oil and natural gas revenue for the 2006.





The
      following table summarizes our oil and natural gas revenue by play/trend in
      the
      periods set forth below:


Year Ended
                December 31, 2006
              
              Year Ended
                December 31, 2005Play/Trend
              
              (mcfe)
              
              Amount
              
              (mcfe)
              
              AmountAntrim
              
              
              2,353,691
              
              $
              18,948,300
              
              
              649,660
              
              $
              6,139,670New
                  Albany
              
              
              28,517
              
              
              190,079
              
              
              11,079
              
              
              94,620Other
              
              
              271,219
              
              
              2,453,432
              
              
              90,300
              
              
              509,154Total
              
              
              2,653,427
              
              $
              21,591,811
              
              
              751,039
              
              $
              6,743,444





**Other
      Revenues** .
      Other
      revenues increased by $0.2 million, or 25% to $0.8 million in 2006 from $0.7
      million in 2005. This increase is attributed to two acquisitions completed
      in
      2006. The first acquisition is the Hudson gas properties with pipeline business
      component and the second acquisition is Bach which provides oil and natural
      gas
      field services.





**Production
      Taxes.** Production
      taxes were $0.9 million in 2006 compared to $0.5 million in 2005. This increase
      is attributed to new wells being added and production growth of existing wells.
      On a unit of production basis, production taxes were $0.33 per mcfe in 2006
      compared to $0.67 per mcfe in 2005.


****


**Production
      and Lease Operating Expenses** .
      Our
      production and lease operating expenses include services related to producing
      oil and natural gas, such as post production costs, including marketing and
      transportation, and expenses to operate the wells and equipment on producing
      leases.





Production
      and lease operating expenses were $6.0 million in 2006 compared to $1.6 million
      in 2005. On a unit of production basis, production and lease operating expenses
      were $2.24 per mcfe in 2006 compared to $2.11 per mcfe in 2005. The increase
      in
      2006 was primarily attributable to increased energy costs, pumping costs,
      repair, and maintenance associated with compressors and pumps and road and
      location maintenance. On a component basis, post-production expenses were $1.2
      million, or $0.46 per mcfe in 2006 compared to $0.4 million or $0.50 per mcfe
      in
      2005 and lease operating expenses were $4.8 million, or $1.78 per mcfe in 2006
      compared to $1.2 million, or $1.61 per mcfe in 2005.





Production
      and lease operating expenses for operated properties were $2.22 per mcfe in
      2006
      compared to $1.53 per mcfe in 2005. Non-operated production and lease operating
      expenses were $2.77 per mcfe in 2006 compared to $2.36 in 2005.





38




**Pipeline
      Operating Expense and Field Services Expenses** .
      Pipeline operating expenses were $0.3 million in 2006 compared to no expense
      in
      2005 which are attributable to the Hudson acquisition. Field services expenses
      were $0.1 million in 2006 compared to no expense in 2005 which are attributable
      to the Bach acquisition.





**General
      and Administrative Expenses** .
      Our
      general and administrative expenses include officer and employee compensation,
      travel, audit, tax and legal fees, office supplies, utilities, insurance,
      consulting fees and office related expense. General and administrative expenses
      in 2006 increased by $4.1 million, or 119%, from 2005. This increase is the
      result of executing our growth strategy as well as costs of becoming and
      maintaining a public entity. This has resulted in substantial increases in
      employees and related costs, legal and accounting services related to SEC
      filings as well as increased consulting services. General and administrative
      expenses in 2005 primarily reflected Aurora as a private entity.





Payroll
      and related costs increased by $2.1 million to $4.6 million in 2006. This
      included stock-based compensation of $2.2 million in 2006 which consists of
      $0.8
      million for directors, $0.8 for senior management and $0.6 for employees. Fiscal
      year 2005 did not have any stock-based compensation. We incurred $1.8 million
      in
      legal, accounting and other consulting services as a result of our growth
      strategy including development costs associated with becoming a public entity
      and on-going public costs.





We
      follow
      the full cost method of accounting under which all costs associated with
      property acquisition, exploration and development activities are capitalized.
      We
      capitalized certain internal costs that can be directly identified with our
      acquisition, exploration and development activities and do not include any
      costs
      related to production, general corporate overhead or similar activities. During
      the year ended December 31, 2006, we capitalized $1.4 million of payroll and
      benefit costs to oil and natural gas properties.





**Oil
      and Natural Gas Depletion, Depreciation and Amortization
      (“DD&A”)** .
      DD&A of oil and natural gas properties was $2.7 million and $0.8 million
      during 2006 and 2005, respectively. DD&A is a function of capitalized costs
      in the full cost pool and related underlying reserves in the periods presented.
      This increase is the result of $81.5 million being added to proved properties
      in
      the full cost pool, production growth, and the underlying reserves increasing
      by
      89 bcfe. The average DD&A cost per mcfe was $1.01 and $1.02 in 2006 and
      2005, respectively





**Other
      Assets Depreciation and Amortization (“D&A”)** .
      D&A
      of other assets was $2.1 million in 2006, compared to $0.3 million in 2005.
      This
      increase was primarily the result of intangible assets amortization of $1.5
      million connected with the Cadence merger, pipeline depreciation of $0.3 million
      related to the 2006 Hudson pipeline acquisition and $0.3 million depreciation
      related to other property and equipment.





**Interest
      Expense** .
      Interest expense was $4.6 million in 2006, compared to $1.3 million in 2005.
      This increase is due to higher utilization of debt to continue our growth
      strategy of acquiring and developing operating interests in the Antrim shale
      and
      the New Albany shale.





**Taxes,
      Other.** Tax
      expense was $0.3 million in 2006, compared to $29,651 in 2005. This increase
      represents state taxes on Texas and Louisiana properties, as well as real and
      personal property taxes in Michigan.


39


**LIQUIDITY
      AND CAPITAL RESOURCES**





In
      September 2007, we retained Johnson Rice & Company, L.L.C. (“JRCO”) to
      assist the Board of Directors with investigating our strategic alternatives.
      These alternatives, among other things, were to include revisions to our
      strategic plan, asset divestitures, operating partnerships, identifying
      additional capital sources, or a sale, merger, or other business combination.
      During this investigative period, we reduced our drilling activities, postponed
      asset divestitures, and focused on maintaining current operations pending the
      outcome of the evaluation process. Based upon the alternatives presented by
      JRCO, our Board of Directors have determined the best way to create value is
      as
      follows: (i) to strengthen our management team; (ii) adjust our capital
      structure to improve capital availability; (iii) focus on drilling our
      undeveloped properties; and (iv) optimize our asset portfolio through a
      combination of asset divestitures, joint venture, or farm-out of our non-core
      assets.




Currently,
      we are able to maintain our existing operations through the existing cash
      balances and internally generated cash flows from sales of oil and natural
      gas
      production. However, we have determined that our existing capital structure
      is
      not adequate to fund our planned growth. We believe the best way to pursue
      our
      growth strategy is with project financing for our emerging plays in the New
      Albany shale and the Woodford shale. At this time, we are in the process of
      negotiating several term sheets with certain recognized energy lenders offering
      mezzanine/project equity financing for at least two areas in our emerging plays.
      Our goal is to establish separate financing entities for each emerging play
      while ensuring the financing structure is non-recourse to our parent entity.
      Our
      current credit facilities are reserve-based lending which is appropriate for
      a
      mature development play like our Antrim shale. We are currently in discussion
      to
      improve our existing credit facilities. As of the date of this filing, no
      project financing or amendments to our existing credit facilities have been
      procured. There can be no assurance that we will be successful in procuring
      the
      financing and amendments we are seeking. Future cash flows are subject to a
      number of variables, including the level of production, natural gas prices
      and
      successful drilling efforts. There can be no assurance that operations and
      other
      capital resources will provide cash in sufficient amounts to maintain planned
      or
      future levels of capital expenditures.




On
      August
      20, 2007, we entered into a second lien term loan agreement with BNP, as the
      arranger and administrative agent, and several other lenders forming a
      syndicate. The initial term loan is $50 million for a 5-year term which may
      increase up to $70 million under certain conditions over the life of the loan
      facility. The proceeds of the loan were used to retire the Company’s existing
      mezzanine financing with TCW and for general corporate purposes.




Interest
      under the second lien term loan is payable at rates based on the London
      Interbank Offered Rate plus 700 basis points with a step-down of 25 basis points
      once our ratio of total indebtedness to earnings before interest, taxes,
      depreciation, depletion, amortization, and other noncash charges is lower than
      or equal to a ratio of 4.0 to 1.0 on a trailing four quarters basis. We have
      the
      ability to prepay the loan during the first year at a price equal to 103% of
      par, during the second year at a price equal to 102% of par, and thereafter
      at a
      price equal to 100% of par.




The
      loan
      contains, among other things, a number of financial and non-financial covenants
      relating to restricted payments (as defined), loans or advances to others,
      additional indebtedness, incurrence of liens, geographic limitations on
      operations to the United States, and maintenance of certain financial and
      operating ratios, including (i) maintenance of a maximum of indebtedness to
      earnings before interest, income taxes, depreciation, depletion and amortization
      and non-cash expenses, and (ii) maintenance of minimum reserve value to
      indebtedness. Any event of default under the senior secured credit facility
      that
      accelerates the maturity of any indebtedness thereunder is also an event of
      default under the second lien term loan. As of December 31, 2007, we were in
      compliance with all of the applicable covenants.




In
      both
      the loan and senior secured credit facility, we agreed to an affirmative
      covenant regarding production exit rates. The production exit target is 12.0
      MMcfe per day as December 31, 2007 (which has been achieved), and as of the
      last
      day of each quarter thereafter. In addition, we were required to purchase
      financial hedges at prices and aggregate notional volumes satisfactory to BNP,
      as administrative agent which requirement has been satisfied.


40


Our
      senior secured credit facility is a $100 million senior secured credit facility
      with BNP. In connection with the second lien term loan, we also agreed to the
      amendment and restatement of our senior secured credit facility with BNP and
      other lenders, pursuant to which the borrowing base under the senior secured
      credit facility was increased from the previous authorized borrowing base of
      $50
      million to $70 million. The amount of the borrowing base is based primarily
      upon
      the estimated value of our oil and natural gas reserves. The borrowing base
      amount is redetermined by the lenders semi-annually on or about April 1 and
      October 1 of each year or at other times required by the lenders or at our
      request. The required semiannual reserve report may result in an increase or
      decrease in credit availability. The security for this facility is substantially
      all of our oil and natural gas properties, guarantees from all material
      subsidiaries, and a pledge of 100% of the stock or member interest of all
      material subsidiaries.




The
      senior secured credit facility provides for borrowings tied to BNP’s prime rate
      (or, if higher, the federal funds effective rate plus 0.5%) or LIBOR-based
      rate
      plus 1.25% to 2.0% depending on the borrowing base utilization, as selected
      by
      us. The borrowing base utilization is the percentage of the borrowing base
      that
      is drawn under the senior secured credit facility from time to time. As the
      borrowing base utilization increases, the LIBOR-based interest rates increase
      under this facility. As of December 31, 2007, interest on the borrowings had
      a
      weighted average interest rate of 6.93%. The maturity date of the outstanding
      loan may be accelerated by the lenders upon occurrence of an event of default
      under the senior secured credit facility.




The
      senior secured credit facility contains, among other things, a number of
      financial and non-financial covenants relating to restricted payments (as
      defined), loans or advances to others, additional indebtedness, incurrence
      of
      liens, geographic limitations on operations to the United States, and
      maintenance of certain financial and operating ratios, including (i) maintenance
      of a minimum current ratio, and (ii) maintenance of a minimum interest coverage
      ratio. Any event of default under the second lien term loan that accelerates
      the
      maturity of any indebtedness thereunder is also an event of default under the
      senior secured credit facility. As of December 31, 2007, we were in compliance
      with all of the applicable covenants.




In
      both
      the loan and senior secured credit facility, the Company agreed to an
      affirmative covenant regarding production exit rates. The production exit target
      is 12.0 MMcfe per day as of December 31, 2007 (which was achieved), and as
      of
      the last day of each quarter thereafter. In addition, the Company was required
      to purchase financial hedges at prices and aggregate notional volumes
      satisfactory to BNP, as administrative agent.





Our
      total
      capitalization was as follows for the periods set forth:


As
                  of December 312007
              
              2006Short-term
                  bank borrowings
              
              $
              -
              
              $
              542,788Obligations
                  under capital lease
              
              
              7,784
              
              
              17,096Notes
                  payable
              
              
              219,478
              
              
              280,321Mortgage
                  payable
              
              
              3,082,196
              
              
              3,175,298Mezzanine
                  financing
              
              
              -
              
              
              40,000,000Senior
                  secured credit facility
              
              
              56,000,000
              
              
              10,000,000Second
                  lien term loan
              
              
              50,000,000
              
              
              -Total
                  debt
              
              
              109,309,458
              
              
              54,015,503Minority
                  interest in net assets of subsidiaries
              
              
              112,661
              
              
              77,873Shareholders’
                  equity
              
              
              132,142,989
              
              
              139,731,099Total
                  capitalization
              
              $
              241,565,108
              
              $
              193,824,475




41


**Cash
      Flows from Operating Activities**





Cash
      provided by operating activities increased 84% to $10.1 million in 2007,
      compared to $5.5 million in 2006. This $4.6 million increase in net cash
      provided by operating activities was due to an increase in production revenues
      as well as increases in other service income. See “Results of Operations” for
      discussion of changes in revenues and expenses. Non-cash charges increased
      due
      to higher depreciation, depletion and amortization and a one-time charge on
      debt
      extinguishment. Changes in current operating assets and liabilities decreased
      cash flow from operations by $2.5 million.





Cash
      provided by operating activities was $5.5 million in 2006, compared to cash
      used
      of $2.4 million in 2005. This $7.9 million increase in net cash provided by
      operating activities was substantially due to a 220% increase in production
      revenues. See “Results of Operations” for discussion of changes in revenues and
      expenses. Non-cash charges increased due to higher depreciation, depletion
      and
      amortization as well as recognition of stock-based compensation in 2006. Changes
      in current operating assets and liabilities decreased cash flow from operations
      by $0.8 million.





**Cash
      Flows used in Investing Activities**





Cash
      flows used in investing activities was $61.1 million in 2007, $89.6 million
      in
      2006, and $39.9 million in 2005. The following table describes our significant
      investing transactions that we completed in the periods set forth
      below:




42




Year
                Ended December 312007
            
            2006
            
            2005Acquisitions
                of leaseholdMichigan
                Antrim shale
            
            $
            1,443,243
            
            $
            5,325,872
            
            $
            5,747,079Indiana
                Antrim shale
            
            
            491,127
            
            
            4,631
            
            
            -New
                Albany shale(a)
            
            
            3,476,568
            
            
            15,567,504
            
            
            8,488,834Woodford
                shale
            
            
            5,413,132
            
            
            2,063,181
            
            
            -Other
            
            
            172,459
            
            
            1,233,485
            
            
            4,047,089Drilling
                and development of oil and natural gas propertiesMichigan
                Antrim shale
            
            
            22,123,120
            
            
            20,449,950
            
            
            20,981,270Indiana
                Antrim shale
            
            
            1,398,811
            
            
            500
            
            
            -New
                Albany shale
            
            
            10,318,178
            
            
            2,808,030
            
            
            9,422Other
            
            
            1,502,129
            
            
            5,918,128
            
            
            321,416Infrastructure
                propertiesMichigan
                Antrim shale
            
            
            10,128,646
            
            
            10,988,527
            
            
            6,523,298New
                Albany shale
            
            
            1,791,091
            
            
            1,789,816
            
            
            105,770Other
            
            
            10,438
            
            
            350,268
            
            
            -Capitalized
                interest and general and administrative cost on exploration, development
                and leasehold
            
            
            5,646,672
            
            
            5,252,900
            
            
            1,146,084Acquisitions
                of oil and natural gas properties
            
            
            2,405,609
            
            
            24,011,335
            
            
            -Acquisitions/additions
                for pipeline, property and equipment
            
            
            1,586,328
            
            
            4,647,497
            
            
            4,523,706Other,
                net
            
            
            186,334
            
            
            855,070
            
            
            485,741Subtotal
                of capital expenditures
            
            $
            68,093,885
            
            $
            101,266,694
            
            $
            52,379,709Sale
                of oil and natural gas properties(a)
            
            
            (2,079,518
            )
            
            (11,489,456
            )
            
            (11,504,428
            )Sale
                and leaseback of gas compression equipment
            
            
            (3,844,500
            )
            
            -
            
            
            -Sale
                of other investments
            
            
            (1,069,378
            )
            
            (171,140
            )
            
            (48,935
            )Net
                cash acquired in merger
            
            
            -
            
            
            -
            
            
            (957,020
            )Subtotal
                of capital divestitures
            
            
            (6,993,396
            )
            
            (11,660,596
            )
            
            (12,510,383
            )Total
            
            $
            61,100,489
            
            $
            89,606,098
            
            $
            39,869,326




(a)
      On
      February 2, 2006, Aurora closed an acquisition of certain New Albany shale
      acreage located in Indiana, commonly called the Wabash project. Aurora acquired
      64,000 acres of oil and natural gas leases from Wabash Energy Partners, L.P.
      for
      a purchase price of $11,840,000. We were required to deposit into escrow for
      the
      sellers $3.2 million in 2005. Aurora then sold half its interest in a combined
      95,000 acre lease position in the Wabash project to New Albany-Indiana, L.L.C.,
      an affiliate of Rex Energy Operating Corporation (“Rex”) for a sale price of
      $10,500,000. Rex placed $3.5 million in an escrow account in 2005 as a deposit
      until the closing in February 2006. Internal funds of Aurora were used to pay
      the net transaction cost of these transactions.





**Cash
      Flows Provided by Financing Activities**





Cash
      flows provided by financing activities were $51.7 million in 2007 compared
      to
      $73.9 million in 2006. Cash flows provided in 2007 included: 1) $55.0 million
      of
      senior secured credit borrowing; 2) $50.0 million of second lien term loan;
      and
      3) $0.2 million of net proceeds received from exercise of common stock options
      and warrants. Cash flows used in 2007 included: 1) $40.0 million pay-down of
      the
      mezzanine financing; 2) net pay-down of $0.5 million in short-term bank
      borrowings; 3) $9.0 million pay-down of the senior secured credit facility;
      4)
      pay-down of $0.3 million in mortgage obligations; 5) payment of $1.9 million
      of
      prepayment penalties associated with debt extinguishment; and 6) payment of
      $1.75 million in financing fees.





43




Cash
      flows provided by financing activities were $73.9 million in 2006 compared
      to
      $49.1 million in 2005. Cash flows provided in 2006 included: 1) $60.0 million
      of
      senior secured credit borrowing, of which, $27.6 million was paid directly
      for
      the Hudson acquisition; 2) $54.5 million of proceeds from public equity
      offering; and 3) $17.6 million of net proceeds received from exercise of common
      stock options and warrants and rescission of certain officer exercised stock
      options. Cash flows used in 2006 included: 1) net pay-down of $5.8 in short-term
      bank borrowings; 2) $50.0 million pay-down of the senior secured credit
      facility; 3) pay-down of $0.1 million in mortgage obligations; and 4) payment
      of
      $2.5 million in financing fees.





Cash
      flows provided by financing activities in 2005 included: 1) $14.7 million of
      proceeds received from sales of common stock; 2) $30.0 million of mezzanine
      borrowing; 3) $2.9 million of mortgage obligation to purchase office space;
      and
      4) $5.9 million of net short-term bank borrowings. Cash flows used by financing
      in 2005 included: 1) pay-off of $3.0 million of certain related-party notes;
      2)
      distributions of $0.8 million to minority interest members for their
      proportionate share of the El Paso sale proceeds; and 3) pay-down of $0.5
      million in financing fees.




**CRITICAL
      ACCOUNTING POLICIES**




Our
      consolidated financial statements are prepared in accordance with accounting
      principles generally accepted in the United States of America. The reported
      financial results and disclosures were determined using the significant
      accounting policies, practices and estimates described in the notes to the
      consolidated financial statements. We believe that the reported financial
      results are reliable and the ultimate actual results will not differ materially
      from those reported. Uncertainties associated with the methods, assumptions
      and
      estimates underlying our critical accounting measurements are discussed
      below.





**Use
      of Estimates**




The
      preparation of consolidated financial statements in conformity with generally
      accepted accounting principles requires management to make estimates and
      assumptions that affect the reported amounts of assets and liabilities and
      disclosure of contingent assets and liabilities at the date of the consolidated
      financial statements and the reported amounts of revenues and expenses during
      the reporting period. Actual results could differ from those estimates.
      Significant estimates underlying these consolidated financial statements include
      the estimated quantities of proved oil and natural gas reserves used to compute
      depletion of oil and natural gas properties and to evaluate the full cost pool
      in the ceiling test analysis, the estimated fair value of financial derivatives
      instruments, and the estimated fair value of asset retirement
      obligations.





**Oil
      and Gas Properties**




We
      utilize the full cost method of accounting for oil and natural gas properties.
      Under this method, subject to a limitation based on estimated value, all costs
      associated with property acquisition, exploration, and development activities
      of
      oil and natural gas, including costs of unsuccessful exploration and overhead
      charges directly related to acquisition, exploration, and development
      activities, are capitalized. We are currently participating in oil and natural
      gas exploration and development projects in the Antrim shale of Michigan and
      the
      New Albany shale of southern Indiana and western Kentucky. Thus, all capitalized
      costs of oil and natural gas properties considered proven, are amortized on
      the
      unit-of-production method using estimates of proven reserves. No gain or loss
      is
      recognized upon the sale or abandonment of undeveloped or producing oil and
      natural gas properties unless the sale represents a significant portion of
      oil
      and natural gas properties and the gain or loss significantly alters the
      relationship between capitalized costs and proven reserves.





Capitalized
      costs of oil and natural gas properties may not exceed an amount equal to the
      present value, discounted at 10%, of estimated future net revenues from proven
      reserves plus the lower of cost or fair value of unproven properties. Should
      capitalized costs exceed this ceiling, an impairment is recognized. The present
      value of estimated future net cash flows is computed by applying year-end prices
      of oil and natural gas to estimated future production of proved oil and natural
      gas reserves as of year end less estimated future expenditures to be incurred
      in
      developing and producing the proved reserves and assuming continuation of
      existing economic conditions.





44




**Oil
      and Gas Reserves**




Our
      estimates of oil and natural gas reserves, by necessity, are projections based
      on geological and engineering data, and there are uncertainties inherent in
      the
      interpretation of such data, as well as the projection of future rates of
      production and the timing of development expenditures. Reserve engineering
      is a
      subjective process of estimating underground accumulations of oil and natural
      gas that are difficult to measure. The accuracy of any reserve estimate is
      a
      function of the quality of available data, engineering and geological
      interpretation and judgment. Estimates of economically recoverable oil and
      natural gas reserves and future net cash flows necessarily depend upon a number
      of variable factors and assumptions, such as historical production from the
      area
      compared with production from other producing areas, the assumed effects of
      regulations by governmental agencies and assumptions governing future oil and
      natural gas prices, future operating costs, severance and excise taxes,
      development costs, and workover and remedial costs, all of which may, in fact,
      vary considerably from actual results. For these reasons, estimates of the
      economically recoverable quantities of oil and natural gas attributable to
      any
      particular group of properties, classifications of such reserves based on risk
      of recovery, and estimates of the future net cash flows expected from there
      may
      vary substantially. Any significant variance in the assumptions could materially
      affect the estimated quantity and value of the reserves, which could affect
      the
      carrying value of our oil and natural gas properties and/or the rate of
      depletion of the oil and natural gas properties. Actual production, revenues,
      and expenditures with respect to our reserves will likely vary from estimates,
      and such variances may be material.





Many
      factors will affect actual net cash flows, including the following: the amount
      and timing of actual production; supply and demand for natural gas; curtailments
      or increases in consumption by natural gas purchasers; and changes in
      governmental regulations or taxation.





**Stock-Based
      Compensation**




On
      January 1, 2006, we adopted SFAS No. 123 (revised 2004), “Share-Based Payment”
(SFAS No. 123R), to account for stock-based employee compensation. Among other
      items, SFAS No. 123R eliminates the use of Accounting Principles Board Opinion
      (“APB”) No. 25, “Accounting for Stock Issued to Employees,” and the intrinsic
      value method of accounting and requires companies to recognize the cost of
      employee services received in exchange for stock-based awards based on the
      grant
      date fair value of those awards in their financial statements. We elected to
      use
      the modified prospective method for adoption, which requires compensation
      expense to be recorded for all unvested stock options beginning in the first
      quarter of adoption. For stock-based awards granted or modified subsequent
      to
      January 1, 2006, compensation expense, based on the fair value on the date
      of
      grant, will be recognized in the financial statements over the vesting
      period.





For
      the
      years ended December 31, 2007 and 2006, we recorded the following stock-based
      compensation:







For
                the Years Ended December 31,
            
            2007
            
            2006General
                and administrative expenses
            
            $
            2,222,200
            
            $
            2,206,801Oil
                and natural gas properties
            
            
            175,795
            
            
            457,013Total
            
            $
            2,397,995
            
            $
            2,663,814





The
      impact on future net income is estimated to be $1,105,949 recognized over the
      applicable requisite service period of approximately 3
      years.


45


**Income
      Taxes**




We
      have
      adopted the provisions of Statement of Financial Accounting Standards No. 109,
      “Accounting for Income Taxes” (“SFAS No. 109”). Under the asset and liability
      method of SFAS No. 109, deferred tax assets and liabilities are recognized
      for
      future tax consequences attributable to the differences between the consolidated
      financial statement carrying amounts of existing assets and liabilities and
      their respective tax bases and operating loss and tax credit carryforwards.
      Deferred tax assets and liabilities are measured using enacted income tax rates
      to apply to taxable income in the years in which those differences are expected
      to be recovered or settled. Under SFAS No. 109, the effect on deferred tax
      assets and liabilities of a change in income tax rates is recognized in the
      results of operations in the period that includes the enactment date. At
      December 31, 2007, we had approximately $85.1 million of net operating loss
      carryforwards which expire between 2010 and 2027.





**SIGNIFICANT
      ACCOUNTING PRINCIPLES RELATING TO THE MERGER**




As
      a
      result of the reverse merger, we were required to conform certain of Cadence’s
      accounting principles to the accounting principles used by Aurora prior to
      the
      merger. This was required because Aurora was considered to be the accounting
      acquirer. Our financial statements for the year ended December 31, 2005 were
      prepared using these accounting principles. A summary of these accounting
      principles is as follows:





●
            Aurora
                is treated as the acquirer in the merger for accounting purposes,
                and
                accordingly, reverse acquisition accounting is applied to the business
                combination.





●
            We
                measured the cost of the business acquired in the merger by reference
                to
                the fair value of the target's securities (i.e., shares of Cadence
                common
                stock, including outstanding options and warrants to purchase such
                shares)
                at the date of the merger agreement, January 31, 2005. The fair value
                was
                determined to be approximately $41,500,000.





●
            We
                uniformly apply the full cost method to all of our oil and natural
                gas
                operations. Accordingly, the financial statements include a net upward
                adjustment to the Cadence assets in the amount of $774,912 to capitalized
                costs previously expensed by Cadence under the successful efforts
                method.
                This increased capitalized costs was used to recalculate depreciation
                on
                the new asset base.





●
            In
                accounting for stock-based compensation for the year ended December
                31,
                2005, we continued to use the intrinsic value method under APB Opinion
                25.
                For the year ending December 31, 2006, we will use FAS No. 123(R).
                Aurora
                stock options outstanding as of the date of the merger are not accounted
                for under APB Opinion 25 or FAS 123 because these options were fully
                vested at the time of the merger. Their fair value was included in
                the
                cost of the business acquired, as discussed
                above.





**RECENTLY
      ISSUED ACCOUNTING STANDARDS**





In
      September 2006, the FASB issued SFAS 157, “Fair Value Measurements,” (“SFAS
      157”) which provides guidance for using fair value to measure assets and
      liabilities. The standard applies whenever other standards require (or permit)
      assets or liabilities to be measured at fair value but does not expand the
      use
      of fair value in any new circumstances. The standard clarifies that, for items
      that are not actively traded, such as certain kinds of derivatives, fair value
      should reflect the price in a transaction with a market participant, including
      an adjustment for risk, not just our mark-to-model value. SFAS 157 also requires
      expanded disclosure of the effect on earnings for items measured using
      unobservable data. The provisions of SFAS 157 are effective for financial
      statements issued for fiscal years beginning after November 15, 2007, and
      interim periods within those fiscal years. Management does not anticipate the
      adoption of this standard to have a material impact on our consolidated
      financial statements.


46


On
      February 15, 2007, the FASB issued SFAS 159, “Fair Value Option for Financial
      Assets and Financial Liabilities”—including an amendment of SFAS Statement No.
      115 (“SFAS 115”). SFAS 159 permits entities to choose to measure many financial
      instruments and certain other items at fair value. The FASB believes the
      statement will improve financial reporting by providing companies the
      opportunity to mitigate volatility in reported earnings by measuring related
      assets and liabilities differently without having to apply complex hedge
      accounting provisions. Use of the statement will expand the use of fair value
      measurements for accounting for financial instruments. The provisions of SFAS
      159 are effective for financial statements issued for fiscal years beginning
      after November 15, 2007, and interim periods within those fiscal years.
      Management does not anticipate the adoption of this standard to have a material
      impact on our consolidated financial statements.





In
      November 2007, the FASB issued SFAS 141 (revised 2007), “Business Combination”
(“SFAS 141R”) and SFAS 160, “Noncontrolling Interests in Consolidated Financial
      Statements, an amendment of ARB No. 51” (“SFAS 160”). SFAS 141R will change how
      business acquisitions are accounted for and will impact financial statements
      both on the acquisition date and in subsequent periods. SFAS 160 will change
      the
      accounting and reporting for minority interests, which will be recharacterized
      as noncontrolling interests and classified as a component of equity. SFAS 141R
      and SFAS 160 are effective for fiscal years beginning on or after December
      15,
      2008. SFAS 141R will be applied prospectively. SFAS 160 requires retroactive
      adoption of the presentation and disclosure requirements for existing minority
      interests. All other requirements of SFAS 160 will be applied prospectively.
      Early adoption is prohibited for both standards. Management is currently
      evaluating the requirements of SFAS 141R and SFAS 160 and has not yet determined
      the impact on its consolidated financial statements.





**OFF
      BALANCE SHEET ARRANGEMENTS**




We
      have
      no special purpose entities, financing partnerships, guarantees, or off-balance
      sheet arrangements other than the $1.2 million of outstanding letters of credit
      discussed in Note 11 “Commitments and Contingencies” to our consolidated
      financial statements.





**CONTRACTUAL
      OBLIGATIONS**




The
      following summarizes our contractual obligations as of December 31, 2007, and
      the effect such obligations are expected to have on our liquidity and cash
      flow
      in future periods (in thousands):


Total
              
              2008
              
              2009
              
              2010
              
              2011
              
              2012
              
              2013
                  and thereafterLong-term
                  debt
              
              $
              106,000
              
              
              -
              
              
              -
              
              $
              56,000
              
              
              -
              
              $
              50,000
              
              
              -Interest
                  on long-term debt (a)
              
              
              34,493
              
              
              9,206
              
              
              9,223
              
              
              6,342
              
              
              5,953
              
              
              3,769
              
              
              -Notes
                  and mortgage payable
              
              
              3,302
              
              
              189
              
              
              550
              
              
              171
              
              
              2,392
              
              
              -
              
              
              -Capital
                  leases
              
              
              7
              
              
              6
              
              
              1
              
              
              -
              
              
              -
              
              
              -
              
              
              -Land
                  and mineral leases (b)
              
              
              6,626
              
              
              476
              
              
              1,364
              
              
              2,553
              
              
              1,693
              
              
              540
              
              
              -Operating
                  leases
              
              
              3,784
              
              
              649
              
              
              612
              
              
              611
              
              
              611
              
              
              611
              
              
              690Total
                  contractual cash obligations
              
              $
              154,212
              
              $
              10,526
              
              $
              11,750
              
              $
              65,677
              
              $
              10,649
              
              $
              54,920
              
              $
              690





(a)
      Amounts estimated based on current interest rates.





(b)
      Amount represents lease renewal options available to the Company. Renewal
      options are evaluated on a periodic basis and, based on those evaluations,
      the
      amount stated above may be lower.


47


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




**Commodity
      Price Risk**




Our
      results of operations and operating cash flows are impacted by the fluctuations
      in the market prices of natural gas. To mitigate a portion of the exposure
      to
      adverse market changes, we will periodically enter into various derivative
      instruments with a major financial institution. The purpose of the derivative
      instrument is to provide a measure of stability to our cash flow in meeting
      financial obligations while operating in a volatile natural gas market
      environment. The derivative instrument reduces our exposure on the hedged
      production volumes to decreases in commodity prices and limits the benefit
      we
      might otherwise receive from any increases in commodity prices on the hedged
      production volumes. The following natural gas contracts were in place as of
      December 31, 2007:


Period
              
              Type of
                Contract
              
              Natural Gas
                Volume per Day
              
              Price per
                mmbtu
              
              Fair Value Asset
                  (Liability)April
                  2007—December 2008
              
              
              Swap
              
              
              5,000
                  mmbtu
              
              $
              9.00
              
              $
              1,881,500April
                  2007—December 2008
              
              
              Collar
              
              
              2,000
                  mmbtu
              
              $
              7.55/$
                  9.00
              
              
              45,770January
                  2008—December 2008
              
              
              Swap
              
              
              2,000
                  mmbtu
              
              $
              8.41
              
              
              320,720January
                  2009—December 2009
              
              
              Swap
              
              
              7,000
                  mmbtu
              
              $
              8.72
              
              
              104,899January
                  2010—March 2011
              
              
              Swap
              
              
              7,000
                  mmbtu
              
              $
              8.68
              
              
              (534,402
              )April
                  2011—September 2011
              
              
              Swap
              
              
              7,000
                  mmbtu
              
              $
              7.62
              
              
              (944,668
              )Total
                  estimated fair value
              
              
              
              
              
              
              
              
              
              
              $
              873,819




**Interest
      Rate Risk**




Our
      use
      of debt directly exposes us to interest rate risk. Our policy is to manage
      interest rate risk through the use of a combination of fixed and floating rate
      debt. Interest rate swaps may be used to adjust interest rate exposure when
      appropriate. In August 2007, we entered into a 3-year interest rate swap
      agreement in the notional amount of $50 million with BNP to hedge our exposure
      to the floating interest rate on the $50 million second lien term loan. The
      swap
      converted the debt’s floating 3-month LIBOR base to 4.86% fixed base. This swap
      on $50 million will yield an effective interest rate of 11.86% for the period
      from August 23, 2007 through August 23, 2010, on the second lien term loan.
      Fair
      value liability of the interest rate swap agreement at December 31, 2007,
      amounted to $1,258,861.




The
      following table sets forth our principal financing obligation and the related
      interest rates as of December 31, 2007:


Expected Maturity
              
              Average Interest Rate as of
                  December 31, 2007
              
              Principal
                OutstandingObligations
                  under capital lease
              
              
              01/10/09
              
              
              8.25%
              
              $
              7,784Notes
                  payable
              
              
              08/01/07-04/25/11
              
              
              5.50%
                  - 7.50%
              
              
              219,478Mortgage
                  payable
              
              
              10/15/09
              
              
              Fixed
                  at 6.00%
              
              
              369,408Mortgage
                  payable
              
              
              2/08/11
              
              
              Fixed
                  at 6.50%
              
              
              2,712,788Second
                  lien term loan
              
              
              08/20/12
              
              
              Hedged
                  at 11.86%
              
              
              50,000,000Senior
                  secured credit facility
              
              
              01/31/10
              
              
              Variable
                  - 6.93%
              
              
              56,000,000Total
                  debt
              
              
              
              
              
              
              
              $
              109,309,458




While
      our
      senior secured facility exposes us to the risk of rising interest rates,
      management does not believe that the potential exposure is material to our
      overall financial position or results of operations. Based on current borrowing
      levels, a 1.0% increase or decrease in current market interest rates would
      have
      the effect of causing $0.6 million additional charge or reduction to our
      statement of operations.


48


**ITEM
      8.**  **FINANCIAL
      STATEMENTS**




**AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES**





**INDEX
      TO CONSOLIDATED FINANCIAL STATEMENTS**


PageManagement’s
                    Report on Internal Control Over Financial Reporting
                50Reports
                    of Independent Registered Public Accounting Firms
                51-52Consolidated
                    Financial StatementsConsolidated
                    Balance Sheets as of December 31, 2007 and 2006
                53-54Consolidated
                    Statements of Operations for the Years Ended December 31, 2007,
                    2006 and
                    2005
                55Consolidated
                      Statements of Shareholders’ Equity for the Years Ended December 31, 2007,
                      2006 and 2005
                56Consolidated
                    Statements of Cash Flows for the Years Ended December 31, 2007,
                    2006 and
                    2005
                57-58Notes
                    to Consolidated Financial Statements
                59Supplemental
                    Oil and Natural Gas Information (Unaudited)
                85


49


MANAGEMENT’S
      REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING




It
      is the
      responsibility of management of Aurora Oil & Gas Corporation to establish
      and maintain adequate internal control over the financial reporting (as defined
      in Rule 13a-15(f) under the Securities Exchange Act of 1934). Management
      utilized the Committee of Sponsoring Organizations of the Treadway Commission’s *Internal
      Control—Integrated Framework* (COSO
      framework) in conducting the required assessment of effectiveness of the
      Company’s internal control over financial reporting.





Management
      has performed an assessment of the effectiveness of the Company’s internal
      control over financial reporting and has determined the Company’s internal
      control over financial reporting was effective as of December 31,
      2007.





Our
      management’s assessment of the effectiveness of the Company’s internal control
      over financial reporting as of December 31, 2007, has been attested by Weaver
      and Tidwell, L.L.P., an independent registered public accounting firm, as stated
      in its report which appears herein.


William
                  W. DeneauChairman,
                  Director, and Chief Executive OfficerBarbara
                  E. LawsonChief
                  Financial Officer


50


REPORT
      OF
      INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM




Board
      of
      Directors and Shareholders


Aurora
      Oil & Gas Corporation


Traverse
      City, Michigan





We
      have
      audited the accompanying consolidated balance sheet of Aurora Oil & Gas
      Corporation (the Company) as of December 31, 2007, and the related consolidated
      statements of operations, shareholders’ equity and cash flows for the year then
      ended. We
      have
      also audited Aurora
      Oil & Gas Corporation’s internal
      control over financial reporting as of December 31, 2007, based on criteria
      established in *Internal
      Control—Integrated Framework issued by the Committee of Sponsoring Organizations
      of the Treadway Commission (the COSO criteria).*  Aurora
      Oil & Gas Corporation’s management is responsible for these financial
      statements, for maintaining effective internal control over financial reporting,
      and for its assessment of the effectiveness of internal control over financial
      reporting, included in the accompanying Management’s
      Report on Internal Control Over Financial Reporting .
      Our
      responsibility is to express an opinion on these consolidated financial
      statements and an opinion on the company’s internal control over financial
      reporting 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 audits to obtain reasonable assurance about whether the
      financial statements are free of material misstatement and whether effective
      internal control over financial reporting was maintained in all material
      respects. Our audit of the financial statements included 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, and evaluating the overall financial statement presentation.
      Our audit of internal control over financial reporting included obtaining an
      understanding of internal control over financial reporting, assessing the risk
      that a material weakness exists, and testing and evaluating the design and
      operating effectiveness of internal control based on the assessed risk. Our
      audits also included performing such other procedures as we considered necessary
      in the circumstances. We believe that our audits provide a reasonable basis
      for
      our opinions.





A
      company’s internal control over financial reporting is a process designed to
      provide reasonable assurance regarding the reliability of financial reporting
      and the preparation of financial statements for external purposes in accordance
      with generally accepted accounting principles. A company’s internal control over
      financial reporting includes those policies and procedures that (1) pertain
      to
      the maintenance of records that, in reasonable detail, accurately and fairly
      reflect the transactions and dispositions of the assets of the company;
      (2) provide reasonable assurance that transactions are recorded as
      necessary to permit preparation of financial statements in accordance with
      generally accepted accounting principles, and that receipts and expenditures
      of
      the company are being made only in accordance with authorizations of management
      and directors of the company; and (3) provide reasonable assurance
      regarding prevention or timely detection of unauthorized acquisition, use,
      or
      disposition of the company’s assets that could have a material effect on the
      financial statements.





Because
      of its inherent limitations, internal control over financial reporting may
      not
      prevent or detect misstatements. Also, projections of any evaluation of
      effectiveness to future periods are subject to the risk that controls may become
      inadequate because of changes in conditions, or that the degree of compliance
      with the policies or procedures may deteriorate.





In
      our
      opinion, the consolidated financial statements referred to above present fairly,
      in all material respects, the consolidated financial position of Aurora Oil
      & Gas Corporation at December 31, 2007, and the consolidated results of
      their operations and their cash flows for the year then ended, in conformity
      with accounting principles generally accepted in the United States of America.
      Also i n
      our
      opinion, Aurora
      Oil & Gas Corporation maintained, in all material respects, effective internal control over financial
      reporting as of December 31, 2007, based on the COSO criteria.





**WEAVER AND
      TIDWELL, L.L.P.**


Fort
      Worth, Texas


March
      7,
      2008


51


REPORT
      OF
      INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM





Board
      of
      Directors and Shareholders


Aurora
      Oil & Gas Corporation and Subsidiaries


Traverse
      City, Michigan








We
      have
      audited the accompanying consolidated balance sheet of Aurora Oil & Gas
      Corporation and Subsidiaries as of December 31, 2006, and the related
      consolidated statements of operations, shareholders’ equity, and cash flows for
      each of the two years in the period then ended. These consolidated financial
      statements are the responsibility of the Company’s management. Our
      responsibility is to express an opinion on these consolidated 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 consolidated financial statements referred to above present fairly,
      in all material respects, the financial position of Aurora Oil & Gas
      Corporation and Subsidiaries as of December 31, 2006, and the results of
      their operations and their cash flows for each of the two years in the period
      then ended in conformity with accounting principles generally accepted in the
      United States.





As
      discussed in Note 3 to the consolidated financial statements, the Company
      changed the manner in which it accounts for share-based payments in
      2006.





**RACHLIN
      LLP**


**(formerly
      known as Rachlin Cohen & Holtz LLP)**





Miami,
      Florida


March
      13,
      2007


52





AURORA
                OIL & GAS CORPORATION AND SUBSIDIARIESCONSOLIDATED
                BALANCE SHEETS




December 31,
            
            December 31,2007
            
            2006**ASSETS****CURRENT
                ASSETS:**Cash
                and cash equivalents
            
            $
            2,425,678
            
            $
            1,735,396Accounts
                receivable:Oil
                and natural gas sales
            
            
            5,036,416
            
            
            4,082,231Joint
                interest owners
            
            
            851,638
            
            
            3,079,715Notes
                receivable
            
            
            -
            
            
            341,698Prepaid
                expenses and other current assets
            
            
            765,730
            
            
            251,093Short-term
                derivative instruments
            
            
            2,247,990
            
            
            3,552,060Total
                current assets
            
            
            11,327,452
            
            
            13,042,193**PROPERTY
                AND EQUIPMENT:**Oil
                and natural gas properties, using full cost accounting:Proved
                properties
            
            
            167,282,245
            
            
            121,178,499Unproved
                properties
            
            
            56,937,683
            
            
            42,024,648Properties
                held for sale
            
            
            -
            
            
            8,896,568Less:
                accumulated depletion and amortization
            
            
            (14,401,584
            )
            
            (10,628,438
            )Total
                oil and natural gas properties, net
            
            
            209,818,344
            
            
            161,471,277Other
                property and equipment:Pipelines,
                processing facilities, and compression
            
            
            6,469,336
            
            
            6,125,909Other
                property and equipment
            
            
            5,450,452
            
            
            5,093,777Less:
                accumulated depreciation
            
            
            (1,554,189
            )
            
            (753,789
            )Total
                other property and equipment, net
            
            
            10,365,599
            
            
            10,465,897Total
                property and equipment, net
            
            
            220,183,943
            
            
            171,937,174**OTHER
                ASSETS:**Long-term
                derivative instruments
            
            
            -
            
            
            1,668,573Goodwill
            
            
            19,373,264
            
            
            19,373,264Intangibles
                  (net of accumulated amortization of$4,497,920 and $2,946,250,
                  respectively)
            
            
            457,080
            
            
            2,008,750Other
                investments
            
            
            733,836
            
            
            985,706Debt
                  issuance costs (net of accumulated amortization of$360,972 and
                  $892,535, respectively)
            
            
            1,661,603
            
            
            2,363,898Other
            
            
            934,490
            
            
            1,007,634Total
                other assets
            
            
            23,160,273
            
            
            27,407,825**TOTAL
                ASSETS**
            
            $
            254,671,668
            
            $
            212,387,192




The
      accompanying notes are an integral part of these consolidated financial
      statements.


53





AURORA
                OIL & GAS CORPORATION AND SUBSIDIARIESCONSOLIDATED
                BALANCE SHEETS




December
                31,
            
            December
                31,2007
            
            2006**LIABILITIES
                AND SHAREHOLDERS' EQUITY****CURRENT
                LIABILITIES:**Accounts
                payable and accrued liabilities
            
            $
            6,490,981
            
            $
            5,623,591Accrued
                exploration, development, and leasehold costs
            
            
            1,341,917
            
            
            11,587,850Short-term
                bank borrowings
            
            
            -
            
            
            542,788Current
                portion of obligations under capital leases
            
            
            6,288
            
            
            8,868Current
                portion of note payable
            
            
            76,416
            
            
            161,774Current
                portion of mortgage payable
            
            
            112,326
            
            
            95,828Drilling
                advances
            
            
            168,356
            
            
            19,383Short-term
                derivative instruments
            
            
            384,706
            
            
            -Total
                current liabilities
            
            
            8,580,990
            
            
            18,040,082**LONG-TERM
                LIABILITIES:**Obligations
                under capital leases, net of current portion
            
            
            1,496
            
            
            8,228Asset
                retirement obligation
            
            
            1,494,745
            
            
            1,331,893Notes
                payable
            
            
            143,062
            
            
            118,547Mortgage
                payable
            
            
            2,969,870
            
            
            3,079,470Senior
                secured credit facility
            
            
            56,000,000
            
            
            10,000,000Second
                lien term loan
            
            
            50,000,000
            
            
            -Mezzanine
                financing
            
            
            -
            
            
            40,000,000Long-term
                derivative instruments
            
            
            2,248,326
            
            
            -Other
                long-term liabilities
            
            
            977,529
            
            
            -Total
                long-term liabilities
            
            
            113,835,028
            
            
            54,538,138Total
                liabilities
            
            
            122,416,018
            
            
            72,578,220Minority
                interest in net assets of subsidiaries
            
            
            112,661
            
            
            77,873**COMMITMENTS,
                CONTINGENCIES, AND SUBSEQUENT EVENTS (Note 11 and Note
                16)****SHAREHOLDERS'
                EQUITY:**Common
                  stock, $0.01 par value; authorized 250,000,000shares; issued and
                  outstanding 101,769,456 and101,412,966 shares,
                  respectively
            
            
            1,017,695
            
            
            1,014,130Additional
                paid-in capital
            
            
            140,541,460
            
            
            138,105,626Accumulated
                other comprehensive income (loss)
            
            
            (385,043
            )
            
            5,220,633Accumulated
                deficit
            
            
            (9,031,123
            )
            
            (4,609,290
            )Total
                shareholders' equity
            
            
            132,142,989
            
            
            139,731,099**TOTAL
                LIABILITIES AND SHAREHOLDERS' EQUITY**
            
            $
            254,671,668
            
            $
            212,387,192








The
      accompanying notes are an integral part of these consolidated financial
      statements.


54





AURORA
                OIL & GAS CORPORATION AND SUBSIDIARIES
              CONSOLIDATED
                STATEMENTS OF OPERATIONS




Year
                Ended December 31,2007
            
            2006
            
            2005**REVENUES:**Oil
                and natural gas sales
            
            $
            26,723,818
            
            $
            21,591,811
            
            $
            6,743,444Pipeline
                transportation and processing
            
            
            792,587
            
            
            489,473
            
            
            -Field
                service and sales
            
            
            390,401
            
            
            125,611
            
            
            -Interest
                and other
            
            
            549,149
            
            
            220,592
            
            
            666,850Total
                revenues
            
            
            28,455,955
            
            
            22,427,487
            
            
            7,410,294**EXPENSES:**Production
                taxes
            
            
            1,123,070
            
            
            877,319
            
            
            506,635Production
                and lease operating expenses
            
            
            8,761,445
            
            
            5,966,341
            
            
            1,587,205Pipeline
                and processing operating expenses
            
            
            359,865
            
            
            265,795
            
            
            -Field
                services expenses
            
            
            321,753
            
            
            90,913
            
            
            -General
                and administrative expenses
            
            
            8,029,122
            
            
            7,531,718
            
            
            3,435,507Oil
                and natural gas depletion and amortization
            
            
            3,769,104
            
            
            2,681,290
            
            
            767,511Other
                assets depreciation and amortization
            
            
            2,396,026
            
            
            2,083,191
            
            
            308,647Interest
                expense
            
            
            4,582,021
            
            
            4,573,785
            
            
            1,307,370Loss
                on debt extinguishment
            
            
            3,448,520
            
            
            -
            
            
            -Taxes,
                other
            
            
            19,021
            
            
            250,884
            
            
            29,651Total
                expenses
            
            
            32,809,947
            
            
            24,321,236
            
            
            7,942,526**LOSS
                BEFORE MINORITY INTEREST**
            
            
            (4,353,992
            )
            
            (1,893,749
            )
            
            (532,232
            )**MINORITY
                INTEREST IN (INCOME) LOSS OF SUBSIDIARIES**
            
            
            (67,841
            )
            
            (50,898
            )
            
            15,960**NET
                LOSS**
            
            $
            (4,421,833
            )
            $
            (1,944,647
            )
            $
            (516,272
            )**NET
                LOSS PER COMMON SHARE—BASIC and DILUTED**
            
            $
            (0.04
            )
            $
            (0.02
            )
            $
            (0.01
            )**WEIGHTED
                AVERAGE COMMONSHARES OUTSTANDING—BASIC and
                DILUTED**
            
            
            101,633,162
            
            
            82,288,243
            
            
            40,622,000




**Supplemental
      Information**




Net
      loss
      for the years ended December 31, 2007, 2006, and 2005, included stock-based
      compensation expense of $2,222,200, $2,206,801, and none, respectively, under
      Statement of Financial Accounting Standards No. 123 (revised 2004). See Note
      10
“Common Stock Options” for additional information.





The
      accompanying notes are an integral part of these consolidated financial
      statements.





55


AURORA
                OIL & GAS CORPORATION AND SUBSIDIARIES
              CONSOLIDATED
                STATEMENTS OF SHAREHOLDERS’ EQUITY




Year
                  Ended December 31,2007
              
              2006
              
              2005Shares
              
              Amount
              
              Shares
              
              Amount
              
              Shares
              
              Amount**COMMON
                  STOCK:**Balance,
                  beginning
              
              
              101,412,966
              
              $
              1,014,130
              
              
              61,536,261
              
              $
              615,363
              
              
              13,775,933
              
              $
              13,776Cashless
                  exercise of stock options and warrants
              
              
              78,158
              
              
              782
              
              
              3,280,105
              
              
              32,801
              
              
              245,068
              
              
              2,451Conversion
                  of redeemable convertible preferred stock to common stock
              
              
              -
              
              
              -
              
              
              34,984
              
              
              349
              
              
              298,050
              
              
              298Issuance
                  of stock in private placement, net of commissions and fees
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              4,972,200
              
              
              4,972Exercise
                  of stock options prior to merger
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              10,000
              
              
              10Issuance
                  of stock in connection with the merger between Cadence and
                  Aurora
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              39,592,510
              
              
              567,431Exercise
                  of stock options and warrants
              
              
              353,332
              
              
              3,533
              
              
              15,823,457
              
              
              158,235
              
              
              2,642,500
              
              
              26,425Issuance
                  of stock in connection with public equity offering
              
              
              -
              
              
              -
              
              
              19,600,000
              
              
              196,000
              
              
              -
              
              
              -Issuance
                  of stock in connection with an acquisition
              
              
              -
              
              
              -
              
              
              1,378,299
              
              
              13,783
              
              
              -
              
              
              -Issuance
                  of stock to officers and directors in lieu of compensation
              
              
              -
              
              
              -
              
              
              90,000
              
              
              900
              
              
              -
              
              
              -Issuance
                  of stock to related parties in lieu of commission relating to exercise
                  of
                  warrants
              
              
              -
              
              
              -
              
              
              1,469,860
              
              
              14,699
              
              
              -
              
              
              -Rescission
                  of stock option exercises by certain officers
              
              
              -
              
              
              -
              
              
              (1,800,000
              )
              
              (18,000
              )
              
              -
              
              
              -Adjustment
                  to stock ledger
              
              
              (75,000
              )
              
              (750
              )
              
              -
              
              
              -
              
              
              -
              
              
              -Balance,
                  ending
              
              
              101,769,456
              
              
              1,017,695
              
              
              101,412,966
              
              
              1,014,130
              
              
              61,536,261
              
              
              615,363**ADDITIONAL
                  PAID-IN CAPITAL:**Balance,
                  beginning
              
              
              
              
              
              138,105,626
              
              
              
              
              
              58,670,698
              
              
              
              
              
              8,183,025Cashless
                  exercise of stock options and warrants
              
              
              
              
              
              (782
              )
              
              
              
              
              (32,801
              )
              
              
              
              
              (2,451
              )Conversion
                  of redeemable convertible preferred stock to common stock
              
              
              
              
              
              -
              
              
              
              
              
              59,576
              
              
              
              
              
              148,727Issuance
                  of stock in private placement, net of commissions and fees
              
              
              
              
              
              -
              
              
              
              
              
              -
              
              
              
              
              
              11,020,028Exercise
                  of stock options prior to merger
              
              
              
              
              
              -
              
              
              
              
              
              -
              
              
              
              
              
              7,490Issuance
                  of stock in connection with the merger between Cadence and
                  Aurora
              
              
              
              
              
              -
              
              
              
              
              
              -
              
              
              
              
              
              35,706,179Stock-based
                  compensation
              
              
              
              
              
              2,397,995
              
              
              
              
              
              2,663,814
              
              
              
              
              
              -Exercise
                  of stock options and warrants
              
              
              
              
              
              194,967
              
              
              
              
              
              18,143,714
              
              
              
              
              
              3,607,700Issuance
                  of stock in connection with public equity offering
              
              
              
              
              
              (10,096
              )
              
              
              
              
              54,309,807
              
              
              
              
              
              -Issuance
                  of stock in connection with an acquisition
              
              
              
              
              
              -
              
              
              
              
              
              4,686,217
              
              
              
              
              
              -Issuance
                  of stock to officers and directors in lieu of compensation
              
              
              
              
              
              -
              
              
              
              
              
              348,300Issuance
                  of stock to related parties in lieu of commission relating to exercise
                  of
                  warrants
              
              
              
              
              
              -
              
              
              
              
              
              (14,699
              )
              
              
              
              
              -Rescission
                  of stock option exercises by certain officers
              
              
              
              
              
              -
              
              
              
              
              
              (729,000
              )
              
              
              
              
              -Adjustment
                  to stock ledger
              
              
              
              
              
              (146,250
              )
              
              
              
              
              -
              
              
              
              
              
              -Balance,
                  ending
              
              
              
              
              
              140,541,460
              
              
              
              
              
              138,105,626
              
              
              
              
              
              58,670,698**ACCUMULATED
                  OTHER COMPREHENSIVE INCOME (LOSS):**Balance,
                  beginning
              
              
              
              
              
              5,220,633
              
              
              
              
              
              -
              
              
              
              
              
              -Changes
                  in fair value of derivative instruments
              
              
              
              
              
              (1,679,507
              )
              
              
              
              
              7,903,933
              
              
              
              
              
              -Recognition
                  of gain on derivative instruments
              
              
              
              
              
              (3,926,169
              )
              
              
              
              
              (2,683,300
              )
              
              
              
              
              -Balance,
                  ending
              
              
              
              
              
              (385,043
              )
              
              
              
              
              5,220,633
              
              
              
              
              
              -**ACCUMULATED
                  DEFICIT:**Balance,
                  beginning
              
              
              
              
              
              (4,609,290
              )
              
              
              
              
              (2,660,134
              )
              
              
              
              
              (2,099,522
              )Dividends
                  accrued on redeemable convertible preferred stock
              
              
              
              
              
              -
              
              
              
              
              
              (4,509
              )
              
              
              
              
              (44,340
              )Net
                  loss
              
              
              
              
              
              (4,421,833
              )
              
              
              
              
              (1,944,647
              )
              
              
              
              
              (516,272
              )Balance,
                  ending
              
              
              
              
              
              (9,031,123
              )
              
              
              
              
              (4,609,290
              )
              
              
              
              
              (2,660,134
              )**TOTAL
                  SHAREHOLDERS’ EQUITY**
              
              
              
              
              $
              132,142,989
              
              
              
              
              $
              139,731,099
              
              
              
              
              $
              56,625,927


The
      accompanying notes are an integral part of these consolidated financial
      statements.


56




AURORA
                OIL & GAS CORPORATION AND SUBSIDIARIES
              CONSOLIDATED
                STATEMENTS OF CASH FLOWS




Year Ended December 31,2007
            
            2006
            
            2005**CASH
                FLOWS FROM OPERATING ACTIVITIES:**Net
                loss
            
            $
            (4,421,833
            )
            $
            (1,944,647
            )
            $
            (516,272
            )Adjustments
                to reconcile net loss to net cash provided by (used in) operating
                activities:Depreciation,
                depletion, and amortization
            
            
            6,165,130
            
            
            4,764,481
            
            
            1,076,158Amortization
                of debt issuance costs
            
            
            779,943
            
            
            813,715
            
            
            79,096Accretion
                of asset retirement obligation
            
            
            76,768
            
            
            74,097
            
            
            -Loss
                on debt extinguishment
            
            
            3,448,520
            
            
            -
            
            
            -Stock-based
                compensation
            
            
            2,222,200
            
            
            2,206,801
            
            
            -Equity
                loss of other investments and other
            
            
            (317,367
            )
            
            291,890
            
            
            116,372Realized
                gain on sale of other investments
            
            
            (434,849
            )
            
            -
            
            
            -Minority
                interest income (loss) of subsidiaries
            
            
            67,841
            
            
            50,899
            
            
            (15,960
            )Changes
                in operating assets and liabilities:Accounts
                receivable—oil and natural gas sales
            
            
            (954,185
            )
            
            (785,126
            )
            
            (516,624
            )Accounts
                receivable—joint interest owners
            
            
            2,562,020
            
            
            1,182,819
            
            
            (3,294,953
            )Drilling
                advance—liabilities
            
            
            148,973
            
            
            19,383
            
            
            (387,175
            )Notes
                receivable
            
            
            221,788
            
            
            20,720
            
            
            (12,621
            )Prepaid
                expenses and other assets
            
            
            (1,838
            )
            
            (1,105,539
            )
            
            41,634Accounts
                payable and accrued liabilities
            
            
            515,938
            
            
            (121,583
            )
            
            1,025,606Net
                cash provided by (used in) operating activities
            
            
            10,079,049
            
            
            5,467,910
            
            
            (2,404,739
            )**CASH
                FLOWS FROM INVESTING ACTIVITIES:**Exploration
                and development of oil and natural gas properties
            
            
            (51,955,565
            )
            
            (42,776,914
            )
            
            (29,087,260
            )Leasehold
                expenditures, net
            
            
            (11,960,049
            )
            
            (28,975,878
            )
            
            (18,283,002
            )Acquisition
                of oil and natural gas properties
            
            
            (2,405,609
            )
            
            (24,011,335
            )
            
            -Sale
                of oil and natural gas properties
            
            
            2,079,518
            
            
            11,489,456
            
            
            11,504,428Sale
                and leaseback of gas compression equipment
            
            
            3,844,500
            
            
            -
            
            
            -Acquisitions/additions
                for pipeline, property, and equipment
            
            
            (1,586,328
            )
            
            (4,647,497
            )
            
            (4,523,706
            )Additions
                in other investments
            
            
            (186,334
            )
            
            (855,070
            )
            
            (485,741
            )Sales
                of other investments
            
            
            1,069,378
            
            
            171,140Other
            
            
            -
            
            
            -
            
            
            48,935Net
                cash acquired in merger
            
            
            -
            
            
            -
            
            
            957,020Net
                cash used in investing activities
            
            
            (61,100,489
            )
            
            (89,606,098
            )
            
            (39,869,326
            )**CASH
                FLOWS FROM FINANCING ACTIVITIES:**Short-term
                bank borrowings
            
            
            16,412,822
            
            
            5,580,199
            
            
            6,210,000Short-term
                bank payments
            
            
            (16,955,610
            )
            
            (11,355,827
            )
            
            (350,000
            )Advances
                on senior secured credit facility
            
            
            55,000,000
            
            
            60,000,000
            
            
            -Payments
                on senior secured credit facility
            
            
            (9,000,000
            )
            
            (50,000,000
            )
            
            -Advances
                on mezzanine financing
            
            
            -
            
            
            -
            
            
            30,000,000Payments
                on mezzanine financing
            
            
            (40,000,000
            )
            
            -
            
            
            -Advances
                on second lien term loan
            
            
            50,000,000
            
            
            -
            
            
            -Payments
                on mortgage obligations and notes payable
            
            
            (272,471
            )
            
            (73,205
            )
            
            2,865,477Payments
                of financing fees on credit facilities
            
            
            (1,691,371
            )
            
            (2,452,786
            )
            
            (508,542
            )Prepayment
                penalties on debt extinguishment
            
            
            (1,866,580
            )
            
            -
            
            
            -Capital
                contributions from minority interest members
            
            
            16,786
            
            
            -
            
            
            -Distributions
                to minority interest members
            
            
            (49,839
            )
            
            -
            
            
            (805,000
            )Proceeds
                from sales of common stock
            
            
            -
            
            
            54,505,807
            
            
            14,666,625Proceeds
                from exercise of options and warrants
            
            
            198,500
            
            
            17,554,949
            
            
            -Dividends
                paid on preferred stock
            
            
            -
            
            
            (20,250
            )
            
            (44,340
            )Other
            
            
            (80,515
            )
            
            154,059
            
            
            (2,959,099
            )Net
                cash provided by financing activities
            
            
            51,711,722
            
            
            73,892,946
            
            
            49,075,121Net
                increase (decrease) in cash and cash equivalents
            
            
            690,282
            
            
            (10,245,242
            )
            
            6,801,056Cash
                and Cash equivalents, beginning of the period
            
            
            1,735,396
            
            
            11,980,638
            
            
            5,179,582Cash
                and cash equivalents, end of the period
            
            $
            2,425,678
            
            $
            1,735,396
            
            $
            11,980,638




57





AURORA
                OIL & GAS CORPORATION AND SUBSIDIARIES
              CONSOLIDATED
                STATEMENTS OF CASH FLOWS




Year Ended December 31,2007
            
            2006
            
            2005**NONCASH
                FINANCING AND INVESTING ACTIVITIES:**Oil
                and natural gas properties asset retirement obligation
            
            $
            116,324
            
            $
            1,257,796
            
            $
            -Accrued
                exploration and development costs on oil and natural gas
                properties
            
            
            947,109
            
            
            11,161,730
            
            
            1,464,032Accrued
                leasehold costs
            
            
            394,808
            
            
            426,120
            
            
            516,890Properties
                acquired in connection with Cadence merger in exchange for
                equity—Oil
                and natural gas properties
            
            
            -
            
            
            -
            
            
            14,647,614—Intangibles
                and goodwill
            
            
            -
            
            
            -
            
            
            20,578,346—Other
                investments
            
            
            -
            
            
            -
            
            
            1,701,238Field
                service acquisition through common stock issuance, including $600,000
                of
                unproven leasehold
            
            
            -
            
            
            4,686,217
            
            
            -Pipeline
                acquisition, transfer of investment to pipeline costs
            
            
            -
            
            
            1,100,973
            
            
            -Processing
                facilities and compression, transfer from unproven
                properties
            
            
            1,244,669
            
            
            -
            
            
            -Oil
                and natural gas properties capitalized stock-based
                compensation
            
            
            175,795
            
            
            457,013
            
            
            -Oil
                and natural gas properties acquisition through other long-term
                liability
            
            
            600,000
            
            
            -
            
            
            -Conversion
                of redeemable convertible preferred stock to common stock
            
            
            -
            
            
            59,925
            
            
            -Conversion
                of accounts receivable to notes receivable
            
            
            35,469
            
            
            118,072
            
            
            -Vehicle
                purchase through financing
            
            
            118,526
            
            
            -
            
            
            -**SUPPLEMENTAL
                INFORMATION OF INTEREST ANDINCOME TAXES PAID:**Interest,
                net of amount capitalized of $4,508,767, $3,896,645, and $1,146,084,
                respectively
            
            $
            2,811,714
            
            $
            3,389,966
            
            $
            1,069,661Income
                taxes
            
            
            107,700
            
            
            6,629
            
            
            40,994




The
      accompanying notes are an integral part of these consolidated financial
      statements.




58


AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES
      TO
      CONSOLIDATED FINANCIAL STATEMENTS





**NOTE
      1. ORGANIZATION AND NATURE OF BUSINESS**





Aurora
      Oil & Gas Corporation (“AOG”) and its wholly owned subsidiaries
      (collectively, the “Company”) is a growing independent energy company focused on
      the exploration, development, and production of unconventional natural gas
      reserves. The Company generates most of its revenue from the production and
      sale
      of natural gas. The Company is currently focused on acquiring and developing
      operating interests in unconventional drilling programs in the Michigan Antrim
      shale, the New Albany shale of Indiana and Kentucky and the Woodford shale
      in
      Oklahoma. The Company is a Utah corporation whose common stock is listed and
      traded on the American Stock Exchange.




The
      Company’s revenue, profitability, and future rate of growth are substantially
      dependent on prevailing prices of natural gas and oil. Historically, the energy
      markets have been very volatile, and it is likely that oil and natural gas
      prices will continue to be subject to wide fluctuations in the future. A
      substantial or extended decline in natural gas and oil prices could have a
      material adverse effect on the Company’s financial position, results of
      operations, cash flows, access to capital, and the quantities of natural gas
      and
      oil reserves that can be economically produced.




**NOTE
      2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING
      POLICIES**





***Principles
      of Consolidation***





The
      accompanying consolidated financial statements of the Company include the
      accounts of the wholly-owned subsidiaries and other subsidiaries in which the
      Company holds a controlling financial or management interest of which the
      Company determined that it is primary beneficiary. The Company uses the equity
      method of accounting for investments in entities in which the Company has an
      ownership interest between 20% and 50% and exercises significant influence.
      The
      Company also consolidates its pro rata share of oil and natural gas joint
      ventures. All significant intercompany accounts and transactions have been
      eliminated in consolidation.




As
      a
      result of the reverse acquisition discussed in Note 6 “Merger with Aurora
      Energy, Ltd.,” the historical financial statements presented for the period
      prior to the acquisition date of October 31, 2005 are the financial statements
      of Aurora. The operations of the former Cadence Resources Corporation
      (“Cadence”) businesses have been included in the financial statements from the
      date of acquisition. The common stock per share information in the consolidated
      financial statements for the year ended December 31, 2005, and related notes
      have been retroactively adjusted to give effect to the reverse merger on October
      31, 2005.




***Use
      of Estimates***





The
      preparation of consolidated financial statements in conformity with generally
      accepted accounting principles requires management to make estimates and
      assumptions that affect the reported amounts of assets and liabilities and
      disclosure of contingent assets and liabilities at the date of the consolidated
      financial statements and the reported amounts of revenues and expenses during
      the reporting period. Actual results could differ from those estimates.
      Significant estimates underlying these consolidated financial statements include
      the estimated quantities of proved oil and natural gas reserves used to compute
      depletion of oil and natural gas properties and to evaluate the full cost pool
      in the ceiling test analysis, the estimated fair value of financial derivatives
      instruments, and the estimated fair value of asset retirement
      obligations.




***Reclassifications***





Certain
      reclassifications have been made to consolidated financial statements for 2006
      and 2005 in order to conform to the presentation used for the 2007 consolidated
      financial statements. These reclassifications had no effect on net loss or
      net
      cash flows as previously reported.




59


AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES
      TO
      CONSOLIDATED FINANCIAL STATEMENTS


(Continued)


***Cash
      and Cash Equivalents***





The
      Company considers all highly liquid investments with an initial maturity of
      3
      months or less to be cash equivalents. The Company’s bank accounts periodically
      exceed federally insured limits. As of December 31, 2007, cash in excess of
      FDIC
      limits amounted to approximately $1.7 million. The Company maintains its
      deposits with high quality financial institutions and, accordingly, believes
      its
      credit risk exposure associated with cash is remote.





***Accounts
      Receivable and Credit Policy***





Accounts
      receivable generally consist of amounts due from the sale of oil and natural
      gas
      and from working interest partners for their proportionate share of expenses
      related to certain oil and natural gas projects. Each customer and/or partner
      is
      reviewed as to credit worthiness prior to the extension of credit and on a
      regular basis thereafter. When collections of specific amounts due are no longer
      reasonably assured, an allowance for doubtful accounts is
      established.





The
      Company extends credit, primarily in the form of uncollateralized oil and
      natural gas sales and joint interest owner's receivables, to various companies
      in the oil and natural gas industry which results in a concentration of credit
      risk. The concentration of credit risk may be affected by changes in economic
      or
      other conditions within the industry and may accordingly impact the Company’s
      overall credit risk. However, the risk of these unsecured receivables is
      mitigated by the size, reputation, and nature of the companies to which the
      Company extends credit.





***Capitalized
      Interest***





The
      Company capitalizes interest on debt related to expenditures made in connection
      with exploration and development projects that are not subject to the full
      cost
      amortization pool. Interest is capitalized only for the period that exploration
      and development activities are in progress. Interest is capitalized using a
      weighted average interest rate based on the outstanding borrowing and cost
      of
      equity of the Company. Capitalized interest was $4,508,767, $3,896,645, and
      $1,146,084 for the years ended December 31, 2007, 2006, and 2005,
      respectively.





***Oil
      and Natural Gas Properties***





The
      Company utilizes the full cost method of accounting for oil and natural gas
      properties. Under this method, subject to a limitation based on estimated value,
      all costs associated with property acquisition, exploration, and development
      activities of oil and natural gas, including costs of unsuccessful exploration
      and overhead charges directly related to acquisition, exploration, and
      development activities, are capitalized. The Company is currently participating
      in oil and natural gas exploration and development projects in the Antrim shale
      of Michigan, the New Albany shale of southern Indiana and western Kentucky
      and
      the Woodford shale in Oklahoma. Thus, all capitalized costs of oil and natural
      gas properties considered proven, are amortized on the unit-of-production method
      using estimates of proven reserves. No gain or loss is recognized upon the
      sale
      or abandonment of undeveloped or producing oil and natural gas properties unless
      the sale represents a significant portion of oil and natural gas properties
      and
      the gain or loss significantly alters the relationship between capitalized
      costs
      and proven reserves.





Capitalized
      costs of oil and natural gas properties may not exceed an amount equal to the
      present value, discounted at 10%, of estimated future net revenues from proven
      reserves plus the lower of cost or fair value of unproven properties. Should
      capitalized costs exceed this ceiling, an impairment is recognized. The present
      value of estimated future net cash flows is computed by applying year-end prices
      of oil and natural gas to estimated future production of proved oil and natural
      gas reserves as of year end less estimated future expenditures to be incurred
      in
      developing and producing the proved reserves and assuming continuation of
      existing economic conditions.




60


AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


The
      following table sets forth financial data associated with unproved oil and
      natural gas properties costs at December 31, 2007:





Balance as of
            
            Net Costs Incurred During the Year Ended December 31,December 31, 2007
            
            2007
            
            2006
            
            2005
            
            2004 and priorAcquisition
                costs
            
            $
            37,004,553
            
            $
            6,516,149
            
            $
            8,695,056
            
            $
            13,811,621
            
            $
            7,981,727Development
                costs
            
            
            19,933,130
            
            
            5,458,271
            
            
            (1,011,683
            )
            
            15,486,542
            
            
            -Total
                unproved properties
            
            $
            56,937,683
            
            $
            11,974,420
            
            $
            7,683,373
            
            $
            29,298,163
            
            $
            7,981,727





Interest
      costs capitalized on unproved properties during the years ended December 31,
      2007, and 2006, totaled $5,596,880 and $3,805,503, respectively. No interest
      was
      capitalized during the year ended December 31, 2005.





***Asset
      Retirement Obligation***





On
      January 1, 2006, the Company adopted Financial Accounting Standards Board
      (“FASB”) Interpretation No. 47, “Accounting for Conditional Asset Retirement
      Obligations,” which is an interpretation of FASB Statement No. 143 “Accounting
      for Asset Retirement Obligations.” Accordingly, an entity is required to
      recognize a liability for the fair value of a conditional asset retirement
      obligation if the fair value can be reasonably estimated. The Company estimates
      a fair value of the obligation on each well in which it owns an interest by
      identifying costs associated with the future dismantlement and removal of
      production equipment and facilities and the restoration and reclamation of
      a
      field’s surface to a condition similar to that existing before oil and natural
      gas extraction began.




In
      general, the amount of an Asset Retirement Obligation (“ARO”) and the costs
      capitalized will be equal to the estimated future cost to satisfy the
      abandonment obligation using current prices that are escalated by an assumed
      inflation factor up to the estimated settlement date which is then discounted
      back to the date that the abandonment obligation was incurred using an assumed
      cost of funds for the Company. After recording these amounts, the ARO is
      accreted to its future estimated value using the same assumed cost of funds
      and
      the additional capitalized costs are depreciated on a unit-of-production basis
      within the related full cost pool. The accretion expense is included in interest
      expense and the depreciation expense is included in depreciation, depletion,
      and
      amortization in the consolidated statements of operations.




Effective
      January 1, 2007, the accretion of the ARO on producing wells was adjusted
      for a change in the estimated life of the wells based on a reserve study
      prepared by Data & Consulting Services, Division of Schlumberger Technology
      Corporation, an independent reserve engineering firm. The estimated life of
      the
      wells was increased by 10 years to an estimated life of 50 years per well
      resulting in a reduction of $625,241 to estimated liabilities. In addition,
      revisions of estimated liabilities included increases due to removal of
      equipment salvage value totaling $97,062 and a decrease in the estimated well
      plugging costs for certain non-Antrim wells totaling $32,409. Revisions of
      estimated liabilities for 2006 included reductions in well working interest
      totaling $55,358 and increases in the salvage value of equipment totaling
      $94,900.




The
      change in the ARO for the year ended December 31, 2007 and 2006 is as
      follows:





2007
            
            2006Beginning
                balance
            
            $
            1,331,893
            
            $
            812,634Liabilities
                incurred
            
            
            707,926
            
            
            719,229Liabilities
                settled
            
            
            (62,254
            )
            
            (123,809
            )Accretion
                expense
            
            
            76,768
            
            
            74,097Revisions
                of estimated liabilities
            
            
            (559,588
            )
            
            (150,258
            )Ending
                balance
            
            $
            1,494,745
            
            $
            1,331,893




61


AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)




***Other
      Property and Equipment***





Other
      property and equipment are recorded at original cost and depreciated using
      the
      straight-line method over the estimated useful lives. Major improvements,
      replacements, and renewals are capitalized while ordinary maintenance and
      repairs are expensed as incurred. Long-lived assets, other than oil and natural
      gas properties, are evaluated annually for impairment to determine if current
      circumstances and market conditions indicate the carrying amount may not be
      recoverable. The Company has not recognized any impairment losses for the years
      ended December 31, 2007, 2006 and 2005. A summary of the other property and
      equipment for the year ended December 31, 2007 and 2006 and the useful lives
      are
      as follows:





2007
            
            2006
            
            Useful
              Life in
              YearsPipelines
            
            $
            5,071,144
            
            $
            4,881,240
            
            
            15Processing
                facilities and compression
            
            
            1,389,121
            
            
            1,241,162
            
            
            10Building
            
            
            9,071
            
            
            3,507
            
            
            30Total
                pipelines, processing facilities and compression
            
            
            6,469,336
            
            
            6,125,909Less:
                accumulated depreciation
            
            
            (818,138
            )
            
            (412,591
            )Pipelines,
                processing facilities, and compression, net
            
            $
            5,651,198
            
            $
            5,713,318Land
            
            $
            78,000
            
            $
            78,000
            
            
            N/ABuildings
            
            
            3,552,392
            
            
            3,552,392
            
            
            40Furniture
                and fixtures
            
            
            328,841
            
            
            328,173
            
            
            5-10Office
                equipment
            
            
            68,321
            
            
            65,781
            
            
            5Computer
                equipment
            
            
            251,894
            
            
            234,782
            
            
            5Software
            
            
            256,578
            
            
            188,434
            
            
            3-5Vehicles
                and other equipment
            
            
            914,427
            
            
            646,215
            
            
            5Total
                other property and equipment
            
            
            5,450,452
            
            
            5,093,777Less:
                accumulated depreciation
            
            
            (736,051
            )
            
            (341,198
            )Other
                property and equipment, net
            
            $
            4,714,401
            
            $
            4,752,579





***Other
      Investments***





The
      Company uses the equity method of accounting for investments in entities in
      which the Company has an ownership interest between 20% and 50% and exercises
      significant influence. Under the equity method of accounting, the Company’s
      proportionate share of the investees’ net income or loss is included in the
      results of operations as other income. A summary of the other investments for
      the years ended December 31, 2007 and 2006, are as follows:





2007
            
            2006Investments
                in equity method investees:GeoPetra
                Partners, LLC
            
            $
            528,136
            
            $
            721,596Mineral
                properties
            
            
            204,628
            
            
            197,406Other
            
            
            1,072
            
            
            66,704Total
                other investments
            
            $
            733,836
            
            $
            985,706





62


AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


Equity
      investments are deemed immaterial. Therefore, financial information is not
      presented.





***Goodwill***





Goodwill
      represents the excess of the purchase price over the fair value of net assets
      acquired. The Company follows SFAS No. 142, “Goodwill and Other Intangible
      Assets,” which requires that goodwill and intangible assets with indefinite
      useful lives not to be amortized but written down, as needed, based on an
      impairment test that must occur at least annually or sooner if an event occurs
      or circumstances change that would more likely than not result in an impairment
      loss. The amount of goodwill impairment, if any, is measured on projected
      discounted future operating cash flows using a 10% discount rate. Future
      impairment of goodwill could result if the Company’s estimated future operating
      cash flows are not achieved. No impairment loss was recorded for the years
      ended
      December 31, 2007, 2006 and 2005, respectively.





***Intangible
      Assets***





Acquired
      intangible assets consist of noncompete agreements, pending patents, and
      proprietary business relationships. These assets are recorded at fair value
      or
      cost and amortized on a straight-line basis using estimated useful lives of
      3 to
      6 years. A summary of amortization expense over the next 5 years is as
      follows:





2008
            
            $
            194,5812009
            
            
            66,6662010
            
            
            66,6662011
            
            
            66,6672012
            
            
            62,500$
            457,080





***Revenue
      Recognition***





Oil
      and
      natural gas revenue is recognized as income as production is extracted and
      sold.
      Revenues from service contracts are recognized ratably over the term of the
      contract.





***Sales
      and Major Customers***





The
      Company markets natural gas and oil production on a competitive basis for its
      operated properties. In most cases, the Company connects to nearby high pressure
      transmission pipelines and utilizes a gas marketing firm for the sale of
      production. Effective June 1, 2007, the Company entered into a firm sales
      contract with Integrys Energy Services, Inc. (formerly WPS) for 5,000 mmbtu
      per
      day at MichCon city-gate for the period June 1, 2007, through December 31,
      2008.
      Integrys Energy Services, Inc. is the Company’s primary marketing partner for
      the majority of Michigan operated properties. In addition, the Company has
      established other base contracts primarily for future natural gas sales in
      Indiana and Michigan. The Company sets the firm delivery volume obligation
      under
      these contracts on either a monthly or a daily basis with the amount of the
      obligation varying from month to month or day to day. As new wells come online
      and production volume increases, new production will be sold under the base
      contracts on a spot market pricing structure.




For
      the
      year ended December 31, 2007, two gas marketing firms accounted for 56% of
      total
      oil and natural gas revenues. For the year ended December 31, 2006, one gas
      marketing firm accounted for 62% of total oil and natural gas revenues. For
      the
      year ended December 31, 2005, one gas marketing firm accounted for 56% of total
      oil and natural gas revenues.




63




AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES
      TO
      CONSOLIDATED FINANCIAL STATEMENTS


(Continued)


***Stock-Based
      Compensation***





On
      January 1, 2006, the Company adopted SFAS No. 123 (revised 2004), “Share-Based
      Payment” (SFAS No. 123R), to account for stock-based employee compensation.
      Among other items, SFAS No. 123R eliminates the use of Accounting Principles
      Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees,” and
      the intrinsic value method of accounting and requires companies to recognize
      the
      cost of employee services received in exchange for stock-based awards based
      on
      the grant date fair value of those awards in their financial statements. The
      Company elected to use the modified prospective method for adoption, which
      requires compensation expense to be recorded for all unvested stock options
      beginning in the first quarter of adoption. For stock-based awards granted
      or
      modified subsequent to January 1, 2006, compensation expense, based on the
      fair
      value on the date of grant, is recognized in the financial statements over
      the
      vesting period. The Company utilizes the Black-Scholes option pricing model
      to
      measure the fair value of stock options. To the extent compensation cost relates
      to employees directly involved in oil and natural gas exploration and
      development activities, such amounts are capitalized to oil and natural gas
      properties. Amounts not capitalized to oil and natural gas properties are
      recognized as general and administrative expense.





Prior
      to
      2006, the Company applied APB No. 25 and related interpretations in accounting
      for its plans. Under APB 25, if the exercise price of the stock options was
      greater than the market value of the shares at the date of grant, no
      compensation cost was recognized in the consolidated financial statements.
      If
      the Company had applied the fair value recognition provisions of SFAS 123R
      during the year ended December 31, 2005, there would have been additional
      stock-based compensation expense of $298,745 with a pro forma net loss of
      $815,017 or $(0.02) per share based on basic and diluted.





For
      the
      years ended December 31, 2007 and 2006, the Company recorded the following
      stock-based compensation:




For
                the Years Ended December 31,
            
            2007
            
            2006General
                and administrative expenses
            
            $
            2,222,200
            
            $
            2,206,801Oil
                and natural gas properties
            
            
            175,795
            
            
            457,013Total
            
            $
            2,397,995
            
            $
            2,663,814




The
      following table provides the unrecognized compensation expense related to
      unvested stock options as of December 31, 2007. The expense is expected to
      be
      recognized over the following remaining periods indicated:




Period
                to be
              Recognized
            
            2008
            
            2009
            
            20101stQuarter
            
            $
            441,781
            
            $
            37,255
            
            $
            1,1462ndQuarter
            
            
            371,364
            
            
            16,532
            
            
            -3rdQuarter
            
            
            125,070
            
            
            6,284
            
            
            -4thQuarter
            
            
            103,561
            
            
            2,956
            
            
            -Total
            
            $
            1,041,776
            
            $
            63,027
            
            $
            1,146





***Income
      Taxes***





The
      Company and its subsidiaries file income tax returns in the U.S. federal
      jurisdiction and various states. With few exceptions, the Company is no longer
      subject to U.S. federal, state, and local examinations by tax authorities for
      years before 2003. The Company is currently not under an examination by any
      U.S.
      federal, state, or local tax authorities.





64




AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES
      TO
      CONSOLIDATED FINANCIAL STATEMENTS


(Continued)


The
      Company has adopted the provisions of Statement of Financial Accounting
      Standards No. 109, “Accounting for Income Taxes” (“SFAS 109”). Under the asset
      and liability method of SFAS 109, deferred tax assets and liabilities are
      recognized for the estimated future tax consequences attributable to the
      differences between the consolidated financial statement carrying amounts of
      existing assets and liabilities and their respective tax bases and operating
      loss and tax credit carryforwards. Deferred tax assets and liabilities are
      measured using enacted income tax rates to apply to taxable income in the years
      in which those temporary differences are expected to be recovered or settled.
      Under SFAS 109, the effect on deferred tax assets and liabilities of a change
      in
      income tax rates is recognized in the results of operations in the period that
      includes the enactment date. A valuation allowance is provided when it is more
      likely than not that some portion or all of the deferred tax assets will not
      be
      realized.





In
      July
      2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in
      Income Taxes—an interpretation of SFAS 109” (“FIN 48”). This interpretation
      clarifies the application of SFAS 109 by defining the criterion that an
      individual tax position must meet for any part of the benefit of that position
      to be recognized in an entity’s financial statements and also provides guidance
      on measurement, derecognition, classification, interest and penalties,
      accounting in interim periods, and disclosure. The provisions of FIN 48 are
      effective for fiscal years beginning after December 15, 2006. The
      Company adopted the provisions of FIN 48 on January 1, 2007. The
      adoption of this standard did not have a material impact on the Company’s
      consolidated financial statements. No
      liabilities or assets have been recognized as a result of the implementation
      of
      Interpretation 48.





As
      of
      December 31, 2007, the Company had approximately $10 million of tax positions
      for which the ultimate deductibility is highly certain but for which there
      is
      uncertainty about the timing of such deductibility. Because of the Company’s
      significant unutilized tax net operating loss carry-forwards, the disallowance
      of the shorter deductibility period would not accelerate the payment of cash
      to
      the taxing authorities to an earlier period or result in any interest of penalty
      for tax underpayment. In addition, because of the impact of deferred tax
      accounting, the disallowance of the shorter deductibility period would not
      affect the annual effective tax rate of the Company. Accordingly, the Company
      has not recognized any penalty, interest or tax impact from this uncertain
      tax
      position.





***Comprehensive
      Income (Loss)***





Comprehensive
      income (loss) is comprised of net income and other comprehensive income. Other
      comprehensive income includes income resulting from derivative instruments
      designated as hedging transactions. The details of comprehensive income (loss)
      are as follows:





Years
                Ended December 31,2007
            
            2006
            
            2005Net
                Loss
            
            $
            (4,421,833
            )
            $
            (1,944,647
            )
            $
            (516,272
            )Other
                comprehensive income:Changes
                in fair value of natural gas derivative instruments
            
            
            (472,335
            )
            
            7,903,933
            
            
            -Changes
                in fair value of interest rate derivative instruments
            
            
            (1,207,172
            )
            
            -
            
            
            -Recognition
                of gains on derivative instruments
            
            
            (3,926,169
            )
            
            (2,683,300
            )
            
            -(5,605,676
            )
            
            5,220,633
            
            
            -Comprehensive
                Income (Loss)
            
            $
            (10,027,509
            )
            $
            3,275,986
            
            $
            (516,272
            )





65




AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


***Income
      (Loss) Per Share***





Basic
      net
      income (loss) per common share is computed based on the weighted average number
      of common shares outstanding during each period. Diluted net income (loss)
      per
      common share is computed based on the weighted average number of common shares
      outstanding plus other dilutive securities, such as stock options, warrants,
      and
      redeemable convertible preferred stock. The following securities were not
      included in the computation of diluted net income (loss) per share as their
      effect would have been anti-dilutive:





2007
            
            2006
            
            2005Options
                to purchase common stock
            
            
            2,175,280
            
            
            766,500
            
            
            1,120,640Warrants
                to purchase common stock
            
            
            -
            
            
            -
            
            
            15,560,000Convertible
                preferred stock
            
            
            -
            
            
            -
            
            
            34,9502,175,280
            
            
            766,500
            
            
            16,715,590





**NOTE
      3. RECENT ACCOUNTING PRONOUNCEMENTS**





In
      September 2006, the FASB issued SFAS 157, “Fair Value Measurements,” (“SFAS
      157”) which provides guidance for using fair value to measure assets and
      liabilities. The standard applies whenever other standards require (or permit)
      assets or liabilities to be measured at fair value but does not expand the
      use
      of fair value in any new circumstances. The standard clarifies that, for items
      that are not actively traded, such as certain kinds of derivatives, fair value
      should reflect the price in a transaction with a market participant, including
      an adjustment for risk, not just the Company’s mark-to-model value. SFAS 157
      also requires expanded disclosure of the effect on earnings for items measured
      using unobservable data. The provisions of SFAS 157 are effective for financial
      statements issued for fiscal years beginning after November 15, 2007, and
      interim periods within those fiscal years. Management does not anticipate the
      adoption of this standard to have a material impact on the Company’s
      consolidated financial statements.





On
      February 15, 2007, the FASB issued SFAS 159, “Fair Value Option for Financial
      Assets and Financial Liabilities”—including an amendment of SFAS Statement No.
      115 (“SFAS 115”). SFAS 159 permits entities to choose to measure many financial
      instruments and certain other items at fair value. The FASB believes the
      statement will improve financial reporting by providing companies the
      opportunity to mitigate volatility in reported earnings by measuring related
      assets and liabilities differently without having to apply complex hedge
      accounting provisions. Use of the statement will expand the use of fair value
      measurements for accounting for financial instruments. The provisions of SFAS
      159 are effective for financial statements issued for fiscal years beginning
      after November 15, 2007, and interim periods within those fiscal years.
      Management does not anticipate the adoption of this standard to have a material
      impact on the Company’s consolidated financial statements.





In
      November 2007, the FASB issued SFAS 141 (revised 2007), “Business Combination”
(“SFAS 141R”) and SFAS 160, “Noncontrolling Interests in Consolidated Financial
      Statements, an amendment of ARB No. 51” (“SFAS 160”). SFAS 141R will change how
      business acquisitions are accounted for and will impact financial statements
      both on the acquisition date and in subsequent periods. SFAS 160 will change
      the
      accounting and reporting for minority interests, which will be recharacterized
      as noncontrolling interests and classified as a component of equity. SFAS 141R
      and SFAS 160 are effective for fiscal years beginning on or after December
      15,
      2008. SFAS 141R will be applied prospectively. SFAS 160 requires retroactive
      adoption of the presentation and disclosure requirements for existing minority
      interests. All other requirements of SFAS 160 will be applied prospectively.
      Early adoption is prohibited for both standards. Management is currently
      evaluating the requirements of SFAS 141R and SFAS 160 and has not yet determined
      the impact on its consolidated financial statements.





66




AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES
      TO
      CONSOLIDATED FINANCIAL STATEMENTS


(Continued)


**NOTE
      4. RISK MANAGEMENT ACTIVITIES**





***Natural
      Gas Derivative Instruments***




The
      Company’s results of operations and operating cash flows are impacted by the
      fluctuations in the market prices of natural gas. To mitigate a portion of
      the
      exposure to adverse market changes, the Company will periodically enter into
      various derivative instruments with a major financial institution. The purpose
      of the derivative instrument is to provide a measure of stability to the
      Company’s cash flow in meeting financial obligations while operating in a
      volatile natural gas market environment. The derivative instrument reduces
      the
      Company’s exposure on the hedged production volumes to decreases in commodity
      prices and limits the benefit the Company might otherwise receive from any
      increases in commodity prices on the hedged production volumes.




The
      Company recognizes all derivative instruments as assets or liabilities in the
      balance sheet at fair value. The accounting treatment for changes in fair value,
      as specified in SFAS No. 133 “Accounting for Derivative Investments and Hedging
      Activities,” is dependent upon whether or not a derivative instrument is
      designated as a hedge. For derivatives designated as cash flow hedges, changes
      in fair value, to the extent the hedge is effective, are recognized in
      Accumulated Other Comprehensive Income on the accompanying balance sheet until
      the hedged item is recognized in earnings as natural gas revenue. If the hedge
      has an ineffective portion, that particular portion of the gain or loss would
      be
      immediately reported in earnings. The following natural gas contracts were
      in
      place as of December 31, 2007, and qualified as cash flow hedges:




Period
            
            Type of
              Contract
            
            Natural Gas
                Volume per Day
            
            Price
                per mmbtu
            
            Fair
                Value Asset (Liability)April
                2007—December 2008
            
            
            Swap
            
            
            5,000 mmbtu
            
            $
            9.00
            
            $
            1,881,500April
                2007—December 2008
            
            
            Collar
            
            
            2,000 mmbtu
            
            $
            7.55/$
                9.00
            
            
            45,770January
                2008 - December 2008
            
            
            Swap
            
            
            2,000 mmbtu
            
            $
            8.41
            
            
            320,720January
                2009—December 2009
            
            
            Swap
            
            
            7,000 mmbtu
            
            $
            8.72
            
            
            104,899January
                2010—March 2011
            
            
            Swap
            
            
            7,000 mmbtu
            
            $
            8.68
            
            
            (534,402
            )April
                2011 – September 2011
            
            
            Swap
            
            
            7,000 mmbtu
            
            $
            7.62
            
            
            (944,668
            )Total
                Estimated Fair Value
            
            
            
            
            
            
            
            
            
            
            $
            873,819





For
      the
      year ended December 31, 2007, the Company has recognized in Comprehensive Income
      (Loss) changes in fair value of $(472,335) on the contracts that have been
      designated as cash flow hedges on forecasted sales of natural gas. See
“Comprehensive Income (Loss)” found in this note section. For the year ended
      December 31, 2007, and 2006, the Company recognized $3,874,480 and $2,683,300,
      respectively, in net gains from hedging activities included in oil and natural
      gas revenues.




***Interest
      Rate Derivative Instruments***




The
      Company’s use of debt directly exposes it to interest rate risk. The Company’s
      policy is to manage interest rate risk through the use of a combination of
      fixed
      and floating rate debt. Interest rate swaps may be used to adjust interest
      rate
      exposure when appropriate. These derivatives are used as hedges and are not
      for
      speculative purposes. These derivatives involve the exchange of amounts based
      on
      variable interest rates and amounts based on a fixed interest rate over the
      life
      of the agreement without an exchange of the notional amount upon which payments
      are based. The interest rate differential to be received or paid on the swaps
      is
      recognized over the lives of the swaps as an adjustment to interest
      expense.




In
      August
      2007, the Company entered into a 3-year interest rate swap agreement in the
      notional amount of $50 million with BNP to hedge its exposure to the floating
      interest rate on the $50 million second lien term loan. The swap converted
      the
      debt’s floating three month LIBOR base to 4.86% fixed base. This swap on $50
      million will yield an effective interest rate of 11.86% for the period from
      August 23, 2007 through August 23, 2010 on the second lien term
      loan.




67




AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


For
      the
      year ended December 31, 2007, the Company has recognized in Comprehensive Income
      (Loss) changes in fair value of $(1,207,172) on the interest rate swap. See
      “Comprehensive Income (Loss)” found in this note section. For the year ended
      December 31, 2007, the Company recognized $51,689 in interest savings related
      to
      the hedge activity which is recorded as an adjustment to interest expense.
      Fair
      value liability of the interest rate swap agreement at December 31, 2007,
      amounted to $1,258,861.




***Financial
      Instruments***





The
      Company’s financial instruments consist primarily of cash, accounts receivable,
      loans receivable, accounts payable, accrued expenses, and debt. The carrying
      amounts of such financial instruments approximate their respective estimated
      fair value due to the short-term maturities and approximate market interest
      rates of these instruments.





**NOTE
      5. ACQUISITIONS AND DISPOSITIONS**





**2007 –
      Rex Energy Exercised Option to Acquire Interest in Oil and Natural Gas
      Leases**




On
      September 7, 2007, Rex Energy Corporation exercised an option to acquire a
      30%
      working interest in various undeveloped oil and natural gas leases located
      in
      the New Albany shale for approximately $1.1 million. The interest in oil and
      gas
      leases covers approximately 70,324 (21,097 net) acres in Lawrence, Jackson,
      Washington and Orange Counties, Indiana.




**2007 –
      GFS and Federated Oil and Gas Properties**




On
      August
      31, 2007, the Company entered into two Purchase Letter Agreements to buy GFS
      Energy, Inc. and Federated Oil & Gas Properties, Inc. non-operated working
      interests and overriding royalty interests in various developed oil and natural
      gas properties located in the Antrim shale for approximately $3.0 million.
      The
      properties included 93 (33 net) wells, producing approximately 500 mcfe per
      day,
      and approximately 4,700 (1,706 net) acres. This transaction had an effective
      date of September 1, 2007.




**2007 –
      Knox County, Indiana**




On
      July
      30, 2007, the Company purchased from Horizontal Systems, Inc. its working
      interest in various undeveloped oil and natural gas leases located in Knox
      County, Indiana for approximately $1.2 million pursuant to a Sale and Assignment
      of Oil and Gas Interests Agreement. The properties included 25% working interest
      in one well and approximately 9,642 net acres.




**2007 –
      Mining Claims**




On
      May
      15, 2007, the Company sold certain mining claims and mineral leases to U.S.
      Silver-Idaho, Inc. for $400,000 in cash and 50,000 shares of common stock in
      U.S. Silver Corporation. This non-core property sale consisted of 14 unpatented
      and 27 patented mining claims as well as 5 mineral leases located in Idaho.
      A
      $418,000 gain was recognized in other income since these non-core properties
      were being recognized as an investment.




**2007 –
      Kansas Project**




On
      February 7, 2007, the Company entered into a Purchase and Sale Letter Agreement
      to sell to Harvest Energy, LLC all of the Company’s interest in various
      developed and undeveloped oil and natural gas properties located in Lane and
      Ness Counties in the State of Kansas for approximately $1.0 million. The
      properties included two net wells, 98 mmcfe in proven reserves, and
      approximately 23,110 net acres. This transaction closed on March 9,
      2007.




**2007 –
      Other Investments**




From
      time
      to time, the Company has acquired and disposed of legacy Cadence stock
      investments and non-core working interests. For the year ended December 31,
      2007, the Company recognized minor stock investments valued at approximately
      $290,000 and disposed of non-core working interests and stock investments of
      approximately $490,000.




68


AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)




**2006 –
      Hudson Pipeline and Processing Co., L.L.C.**





On
      January 31, 2006, Aurora Antrim North, L.L.C. (“North”), a wholly-owned
      subsidiary of Aurora, completed the acquisition of oil and natural gas leases,
      working interests, and interests in related pipelines and production facilities
      that are located in the Hudson Township area of the Michigan Antrim shale play.
      The interests acquired are collectively referred to as the Hudson Properties.
      In
      addition, interests in the related pipelines and production facilities were
      acquired by purchasing additional membership interests in Hudson Pipeline and
      Processing Co., L.L.C. (“HPPC”). North previously owned a working interest in
      the properties and a membership interest in HPPC. This acquisition increased
      North’s working interest in the Hudson Properties from an average of 49% to 96%
      and increased the membership interest in HPPC from 48.75% to 90.94%.





The
      total
      purchase price for the Hudson Properties and HPPC was approximately $27.6
      million. North also acquired an additional 2.5% membership interest in HPPC,
      effective January 1, 2006, which increased the membership interest to 93.60%.





With
      these increases in membership interest in HPPC, effective January 1, 2006,
      HPPC
      was converted from the equity method to being consolidated as a subsidiary
      in
      the Company’s accompanying consolidated financial statements.





**2006 –
      Wabash Project**





On
      February 2, 2006, Aurora closed on two Purchase and Sale Agreements with respect
      to certain New Albany Shale acreage located in Indiana, commonly called the
      Wabash project. Aurora acquired 64,000 acres of oil and natural gas leases
      from
      Wabash Energy Partners, L.P. for a purchase price of $11.84 million. The Company
      was required to deposit into escrow for the seller $3.2 million





Aurora
      then sold half its interest in a combined 95,000-acre lease position in the
      Wabash project to New Albany-Indiana, L.L.C. (“New Albany”), an affiliate of Rex
      Energy Operating Corporation, for a sale price of $10.5 million. Pursuant to
      the
      terms of this sales agreement, $3.5 million was placed in escrow by New Albany
      on behalf of the Company as a deposit until the closing in February 2006.





**2006 –
      DeSoto Parish, Louisiana**





On
      July
      20, 2006, the Company entered into a Purchase and Sale Agreement with respect
      to
      the DeSoto Parish, Louisiana, properties to sell certain assets to BEUSA Energy,
      Inc. for a purchase price of $4.75 million. BEUSA Energy, Inc. is the current
      operator and joint interest owner in these properties. The properties included:
      (1) fourteen gross wells with working interest ranging from 22.5% to 45%; (2)
      4,480 (1,657 net) acres; and (3) various pipelines and facilities. The effective
      date of the sale was July 1, 2006.





**2006 –
      Crossroads Project, Henry, Ohio**





Effective
      August 15, 2006, the Company agreed to assign all of its working interests
      in
      the Crossroads Project located in Henry County, Ohio, to an unrelated party.
      The
      7.06% working interest included 15,519 (1,096 net) leasehold acres, 13 (0.92
      net) wells, and pipeline assets. Aurora agreed to pay $251,225 for disposition
      costs but will receive future pipeline revenue over the life of the project.




69




AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)




**2006 –
      Bach**





On
      October 6, 2006, the Company closed on the purchase of all assets of Bach
      Enterprises, Inc., certain assets owned by Bach Energy, LLC, and a limited
      liability company known as Kingsley Development LLC (together “Bach”). Bach is
      primarily an oil and natural gas service company. The Company has been working
      exclusively with Bach as a service business in Michigan for several years.
      Services they have provided include building compressors, CO2 removal,
      pipelining, and facility construction. The purchase price included common stock
      and cash. The common stock issued was subject to a 1-year lock-up period. In
      addition, the Company entered into 5-year employment agreements with two
      principals of Bach who agreed not to compete during their employment and for
      a
      period of 1 year following termination of their employment.





**NOTE
      6. MERGER WITH AURORA ENERGY, LTD.**





On
      October 31, 2005, the Company (formerly Cadence) acquired Aurora Energy, Ltd.
      (“Aurora”) through the merger of a wholly-owned subsidiary with and into Aurora.
      As a result of the merger, Aurora became a wholly-owned subsidiary. The merger
      has been accounted for as a reverse acquisition using the purchase method of
      accounting. Although the merger was structured such that Aurora became a
      wholly-owned subsidiary of the Company, Aurora has been treated as the acquiring
      company for accounting purposes under Statement of Financial Accounting
      Standards (“SFAS”) No. 141, “Business Combinations,” due to the following
      factors: (1) Aurora’s stockholders received the larger share of the voting
      rights in the merger; (2) Aurora received the majority of the members of
      the board of directors; and (3) Aurora’s senior management, prior to the
      merger, dominated the senior management of the combined company.




The
      definitive merger agreement was executed on January 31, 2005, whereby Cadence
      agreed to acquire 100% of the outstanding stock and options of Aurora.
      Consideration in this transaction consisted of the issuance of two shares of
      common stock of Cadence for every one share of outstanding stock of Aurora
      and
      the issuance of two options for the purchase of stock in Cadence for each option
      outstanding of Aurora. The purchase price was $41,546,351 determined as
      follows:





Fair
                value of Cadence’s common stock outstanding at January 31,
                2005(a)
            
            $
            33,951,817Fair
                value of Cadence’s stock options outstanding at January 31,
                2005
            
            
            536,210Fair
                value of Cadence’s warrants outstanding at January 31,
                2005
            
            
            7,058,324Total
                purchase price
            
            $
            41,546,351





(a)
      The
      $33,951,817 was computed as 20,702,327 shares of Cadence common stock multiplied
      by $1.64, the market price of Cadence common stock as of January 31, 2005,
      the
      date of the definitive merger agreement.





In
      recording the acquisition of Cadence, the following table summarizes the
      estimated fair value of the assets acquired and the liabilities assumed at
      the
      date of acquisition. The Company obtained third-party valuations of certain
      tangible and intangible assets acquired from Cadence.





Net
                working capital, adjusted for Cadence operating activity from date
                of
                definitive merger agreement to October 31, 2005
            
            $
            4,679,078Oil
                and natural gas properties and property and equipment, net
            
            
            14,647,614Investments
            
            
            1,503,832Other
                mineral properties
            
            
            197,406Noncompete
                agreements
            
            
            3,265,000Proprietary
                business relationships
            
            
            1,340,000Goodwill
            
            
            15,973,346Redeemable
                convertible preferred stock
            
            
            (59,925
            )$
            41,546,351





70




AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)




The
      following unaudited condensed pro forma results of operations reflect the pro
      forma combination of Aurora and Cadence as if the combination had occurred
      at
      the beginning of fiscal year 2005 compared with the historical results of
      operations of Aurora for the same period.





2005Historical
            
            Pro
                FormaOil
                and natural gas revenues
            
            $
            6,743,444
            
            $
            8,821,869Production
                expenses
            
            
            (2,093,840
            )
            
            (2,846,316
            )Net
                operating revenues
            
            
            4,649,604
            
            
            5,975,553Net
                loss
            
            $
            (516,272
            )
            $
            (4,293,053
            )Net
                loss per common share - basic and diluted
            
            $
            (0.01
            )
            $
            (0.07
            )Weighted
                average number of common shares outstanding – basic and
                diluted
            
            
            40,622,000
            
            
            58,108,000





**NOTE
      7. DEBT**





**Short-Term
      Bank Borrowings**




The
      Company had a $5.0 million revolving line of credit agreement with Northwestern
      Bank for general corporate purposes through October 15, 2007. The Company
      elected not to request an extension of this revolving line of credit beyond
      the
      expiration date of October 15, 2007. The interest rate under the revolving
      line
      of credit was Wall Street prime (7.50% at October 31, 2007, and 8.25% at
      December 31, 2006) with interest payable monthly in arrears. Principal was
      payable at the expiration of the revolving line of credit agreement. Interest
      expense on the revolving line of credit for the years ended December 31, 2007,
      2006, and 2005, was $32,873, $283,163, and $37,326, respectively.




Northwestern
      Bank continues to provide letters of credit for the Company’s drilling program
      (as described in Note 11 “Commitments and Contingencies”). These letters of
      credit may be extended or may be replaced upon their expiration dates by letters
      of credit under the Company’s senior secured credit facility.




**Short-Term
      Bank Borrowings – Bach Services & Manufacturing Co., L.L.C. (“Bach”), a
      wholly-owned subsidiary**




Effective
      December 12, 2007, Bach obtained an increase in its borrowing capacity under
      the
      revolving line of credit from $0.5 million to $1.0 million with Northwestern
      Bank. This revolving line of credit agreement is for general company purposes
      and is secured by all of Bach’s personal property owned or hereafter acquired
      and is non-recourse to the Company. The interest rate under the revolving line
      of credit is Wall Street prime (7.25% at December 31, 2007, and 8.25% at
      December 31, 2006) with interest payable monthly in arrears. Principal is
      payable at the expiration of the revolving line of credit agreement. The
      expiration date is October 1, 2008. Interest expense for the years ended
      December 31, 2007, and 2006, was $3,082 and $2,166, respectively.




71




AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


**Mortgage
      and Notes Payable - Bach**




Bach’s
      outstanding debt was as follows with interest expense for the periods
      indicated:




Principal
              Amount
            
            Interest
                ExpenseDescription
                of Loan
            
            Date
                of Loan
            
            Maturity
                Date
            
            Interest
                Rate
            
            Outstanding
            
            2007
            
            2006Mortgage
                payable on building
            
            
            10/06/06
            
            
            10/15/09
            
            
            6.00
            %
            $
            369,408
            
            $
            20,657
            
            $
            5,352Notes
                payable:Vehicles
            
            
            10/06/06
            
            
            10/01/10
            
            
            7.50
            %
            
            68,231
            
            
            6,006
            
            
            1,618Equipment
            
            
            10/06/06
            
            
            09/01/07
            
            
            5.50
            %
            
            -
            
            
            253
            
            
            198Vehicles
            
            
            12/18/06
            
            
            12/20/09
            
            
            7.25
            %
            
            48,452
            
            
            4,158
            
            
            -Vehicles
            
            
            04/23/07
            
            
            04/25/11
            
            
            7.00
            %
            
            80,490
            
            
            4,213
            
            
            -Vehicles
            
            
            09/13/07
            
            
            09/15/10
            
            
            6.95
            %
            
            22,305
            
            
            424
            
            
            -Total
                notes payable
            
            
            
            
            
            
            
            
            
            
            $
            219,478
            
            $
            15,054
            
            $
            1,816




**Mortgage
      Payable**




On
      October 4, 2005, the Company entered into a mortgage loan from Northwestern
      Bank
      in the amount of $2,925,000 for the purchase of an office condominium and
      associated interior improvements. The security for this mortgage is the office
      condominium real estate. Effective February 14, 2008, the Company refinanced
      the
      existing loan by extending its maturity date through February 1, 2011. The
      payment schedule is principal and interest in 36 monthly payments of $21,969
      with one principal and interest payment of $2,692,849 on February 1, 2011.
      The
      interest rate is 5.95% per year. As of December 31, 2007, the principal amount
      outstanding was $2,712,788. Interest expense for the years ended December 31,
      2007, 2006, and 2005, was $174,972, $192,814, and $15,732,
      respectively.




**Note
      Payable – Directors and Officers Insurance**




On
      November 13, 2006, the Company entered into a financing agreement with AICCO,
      Inc. to finance the insurance premium related to director and officer liability
      insurance coverage in the amount of $184,230. A monthly payment of $15,807
      was
      required beginning November 30, 2006, through August 1, 2007. The interest
      rate
      was 7.01% per year. Interest expense for the year ended December 31, 2007,
      was
      $2,546.




**Second
      Lien Term Loan**




On
      August
      20, 2007, the Company entered into a second lien term loan agreement with BNP
      Paribas (“BNP”), as the arranger and administrative agent, and several other
      lenders forming a syndicate. The initial term loan is $50 million for a 5-year
      term (expires 8/20/12) which may increase up to $70 million under certain
      conditions over the life of the loan facility. The proceeds of the loan were
      used to repay the outstanding balance under the Company’s mezzanine financing
      with Trust Company of the West (“TCW”) and for general corporate purposes.
      Interest under the loan is payable at rates based on the London Interbank
      Offered Rate (“LIBOR”) plus 700 basis points with a step-down of 25 basis points
      once the Company’s ratio of total indebtedness to earnings before interest,
      taxes, depreciation, depletion, amortization, and other non-cash charges is
      lower than or equal to a ratio of 4.0 to 1.0 on a trailing four quarters basis.
      The Company has the ability to prepay the loan during the first year at a price
      equal to 103% of par, during the second year at a price equal to 102% of par,
      and thereafter at a price equal to 100% of par.




72




AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)




The
      loan
      contains, among other things, a number of financial and non-financial covenants
      relating to restricted payments (as defined), loans or advances to others,
      additional indebtedness, incurrence of liens, geographic limitations on
      operations to the United States, and maintenance of certain financial and
      operating ratios, including (i) maintenance of a maximum of indebtedness to
      earnings before interest, income taxes, depreciation, depletion and amortization
      and non-cash expenses, and (ii) maintenance of minimum reserve value to
      indebtedness. Any event of default under the senior secured credit facility
      that
      accelerates the maturity of any indebtedness thereunder is also an event of
      default under the second lien term loan.




In
      both
      the loan and senior secured credit facility, the Company agreed to an
      affirmative covenant regarding production exit rates. The production exit target
      is 12.0 MMcfe per day as of December 31, 2007 (which was achieved), and as
      of
      the last day of each quarter thereafter. In addition, the Company was required
      to purchase financial hedges at prices and aggregate notional volumes
      satisfactory to BNP, as administrative agent.




For
      the
      year ended December 31, 2007, interest and fees incurred for the loan was
      $2,244,539. The Company has also incurred deferred financing fees of
      approximately $1.3 million with regard to the loan. The deferred financing
      fees
      are being amortized on a straight-line basis over the remaining terms of the
      loan obligation. Amortization expense for the loan is estimated to be $264,000
      per year through 2011. Amortization expense was $96,724 for the year ended
      December 31, 2007. In addition, the Company incurs annual agency fees which
      are
      recorded to interest expense.




**Mezzanine
      Financing**




Effective
      August 20, 2007, the Company’s subsidiary Aurora Antrim North, L.L.C. (“North”)
      terminated its Amended Note Purchase Agreement with TCW which provided $50
      million in mezzanine financing. As of the effective date, North had outstanding
      borrowing of $40 million. The interest rate was fixed at 11.5% per year,
      compounded quarterly, and payable in arrears. TCW had limited the borrowing
      base
      and the agreement contained a commitment expiration date of August 12, 2007.
      Under the termination provisions, the Company was required to pay certain fees
      and prepayment charges associated with early termination. The following
      represents the expenditures paid to TCW: (i) $40 million payment of principal;
      (ii) $0.7 million payment of interest expense from June 27, 2007, through August
      20, 2007; (iii) $0.36 million payment of interest make-whole provision from
      August 21, 2007, through September 27, 2007; (iv) $1.25 million payment of
      prepayment premium; and (v) $0.2 million payment for a make-whole provision
      on
      principal greater than $30 million.




As
      part
      of the mezzanine financing with TCW, North provided an affiliate of TCW an
      overriding royalty interest of 4% in certain leases to be drilled or developed
      in the Counties of Alcona, Alpena, Charlevoix, Cheboygan, Montmorency, and
      Otsego in the State of Michigan. The overriding royalty interest will also
      continue on leases, including extensions or renewals, held by the Company and
      its affiliates at August 20, 2007, that may be developed through September
      29,
      2009.




For
      the
      years ended December 31, 2007, 2006, and 2005, interest and fees incurred for
      the mezzanine credit facility was $2,989,305, $4,714,861, and $2,171,389,
      respectively. In addition, the Company completed a write-off $1.6 million of
      unamortized debt issuance cost associated with the early extinguishment of
      the
      mezzanine financing.




73




AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


**Senior
      Secured Credit Facility**




On
      January 31, 2006, the Company entered into a $100 million senior secured credit
      facility with BNP and other lenders for drilling, development, and acquisitions,
      as well as other general corporate purposes. In connection with the second
      lien
      term loan discussed above, the Company also agreed to the amendment and
      restatement of the senior secured credit facility, pursuant to which the
      borrowing base under the senior secured credit facility was increased from
      the
      current authorized borrowing base of $50 million to $70 million effective August
      20, 2007. The amount of the borrowing base is based primarily upon the estimated
      value of the Company’s oil and natural gas reserves. The borrowing base amount
      is redetermined by the lenders semi-annually on or about April 1 and October
      1
      of each year or at other times required by the lenders or at the Company’s
      request. The required semi-annual reserve report may result in an increase
      or
      decrease in credit availability. The security for this facility is substantially
      all of the Company’s oil and natural gas properties; guarantees from all
      material subsidiaries; and a pledge of 100% of the stock or member interest
      of
      all material subsidiaries.




This
      facility provides for borrowings tied to BNP’s prime rate (or, if higher, the
      federal funds effective rate plus 0.5%) or LIBOR-based rate plus 1.25% to 2.0%
      depending on the borrowing base utilization, as selected by the Company. The
      borrowing base utilization is the percentage of the borrowing base that is
      drawn
      under the senior secured credit facility from time to time. As the borrowing
      base utilization increases, the LIBOR-based interest rates increase under this
      facility. As of December 31, 2007, interest on the borrowings had a weighted
      average interest rate of 6.93%. For the years ended December 31, 2007, and
      2006,
      interest and fees incurred for the senior secured credit facility were
      $2,723,170 and $2,323,732, respectively. All outstanding principal and accrued
      and unpaid interest under the senior secured facility is due and payable on
      January 31, 2010. The maturity date of the outstanding loan may be accelerated
      by the lenders upon occurrence of an event of default under the senior secured
      credit facility.




The
      senior secured credit facility contains, among other things, a number of
      financial and non-financial covenants relating to restricted payments (as
      defined), loans or advances to others, additional indebtedness, incurrence
      of
      liens, geographic limitations on operations to the United States, and
      maintenance of certain financial and operating ratios, including (i) maintenance
      of a minimum current ratio, and (ii) maintenance of a minimum interest coverage
      ratio. Any event of default under the second lien term loan that accelerates
      the
      maturity of any indebtedness thereunder is also an event of default under the
      senior secured credit facility.




The
      Company has incurred deferred financing fees of $703,811 with regard to the
      senior secured credit facility. The deferred financing fees are being amortized
      on a straight-line basis over the remaining terms of the debt obligation.
      Amortization expense for the senior secured credit facility is estimated to
      be
      $202,000 per year through 2009. Amortization expense was $163,526 and $100,722
      for the years ended December 31, 2007, and 2006, respectively. In addition,
      the
      Company incurs various annual fees associated with unused commitment and agency
      fees which are recorded to interest expense.




Scheduled
      principal maturities of long-term debt for each of the years succeeding December
      31, 2007, are summarized as follows (in thousands):




Year
            
            Amount2008
            
            $
            1892009
            
            
            5502010
            
            
            56,1712011
            
            
            2,3922012
            
            
            50,000Total
            
            $
            109,302




74




AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)




**NOTE
      8. SHAREHOLDERS’ EQUITY**





**Redeemable
      Convertible Preferred Stock**





On
      April 23, 2001, the Company’s board of directors authorized
      20,000,000 shares of preferred stock with a par value of $0.01 per
      share and rights and preferences to be determined. During 2003, the Company
      issued 34,984 shares of its Class A preferred stock to investors at
      prices ranging from $1.50 to $2.00 per share for aggregate proceeds of
      $59,925. The shares were convertible to common stock at a price of $1.50 to
      $2.00 per share under certain terms and conditions. The shares carried a
      preferred dividend of 15% per annum. In 2006, the shareholders converted
      all of the 34,984 shares of redeemable convertible preferred stock into
      common stock.





**Common
      Stock**





**2007**




From
      February 2007 through December 2007, 210,000 common stock options were exercised
      by various Company employees under the existing stock option plans at exercise
      prices ranging from $0.375 to $1.25 per share. The Company received $92,500
      in
      conjunction with these exercises.




In
      June
      2007, 75,000 shares of the Company’s common stock valued at $147,000 were
      cancelled in order to reconcile with the Company’s transfer agent.




From
      February through December 2007, 143,332 common stock options were exercised
      by
      various Company directors under the existing stock option plans at exercise
      prices ranging from $0.375 to $1.42 per share. The Company received $106,000
      in
      conjunction with these exercises.




In
      January 2007, 78,158 shares of the Company’s common stock were issued in
      connection with the exercise of outstanding warrants by a non-affiliated party
      in a net issue (cashless) exercise transaction.




**2006**





From
      late
      December 2005 through early February 2006, the Company reduced the exercise
      price of certain outstanding options and warrants in order to encourage the
      early exercise of these securities. Each holder who took advantage of the
      reduced exercise price was required to execute a 6-month lock-up agreement
      with
      respect to the shares issued in the exercise. As a result of the options and
      warrants exercised pursuant to this reduced exercise price arrangement and
      pursuant to other exercises of outstanding options, an additional 20,573,422
      shares were issued during the year ended December 31, 2006, representing
      15,823,457 shares issued for cash proceeds of $18,301,949, and 4,749,965 shares
      issued pursuant to cashless exercises of the applicable and other warrants
      or
      options. Substantially, all of the options and warrants exercised under the
      reduced exercise price option were noncompensatory in nature and were accounted
      for as equity transaction.





In
      December 2006, three officers of the Company rescinded option exercises for
      600,000 shares each. The option exercise price of $249,000 was returned to
      each
      of these officers and in exchange each officer surrendered 600,000 shares of
      common stock.





In
      February 2006, a special meeting of the shareholders was held where they voted
      to increase the number of authorized shares of common stock from 100,000,000
      to
      250,000,000.





In
      June
      2006, an officer of the Company was issued 30,000 shares for services provided
      in 2005. Compensation expense related to this activity was recorded in 2005.
      Additionally, two directors of the Company were issued 30,000 shares each for
      their services provided to Aurora as Board members prior to the merger with
      Cadence. Compensation expense related to this activity was recorded in
      2005.




75


AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)




In
      October 2006, upon the acquisition of the assets of Bach Enterprises, Inc.
      and
      its affiliates, 1,378,299 of unregistered common shares were issued. Of the
      shares issued, 500,000 shares have been placed in an escrow for one year as
      security for any indemnity obligation resulting from a breach of any
      representation or warranty in the purchase agreement.





The
      Company closed on the public offering of 16 million shares on November 7, 2006,
      and received net proceeds of approximately $44.4 million, which were utilized
      to
      repay amounts outstanding under the senior secured credit facility. The 30-day
      over-allotment option granted to the underwriters for the purchase of 3.6
      million additional shares was exercised and closed on November 13, 2006, and
      the
      Company received net proceeds of approximately $10.2 million.





**2005**





The
      Company sold 4,972,200 shares of common stock to unrelated third parties at
      $2.50 per share in the first quarter of 2005. Total net proceeds from the
      sale of these shares, after commissions and fees, amounted to $11,025,000.
      In
      connection with the sale of these shares, together with the sale of certain
      common stock by Cadence at that same time, an affiliate of one of the Company’s
      major shareholders was paid a commission of approximately $976,000 and was
      issued a warrant to purchase 1,821,000 shares of common stock for services
      rendered as the placement agent in the transaction. Included in accounts payable
      at December 31, 2005, is a balance of $50,000 due to this affiliate.





The
      Company issued 10,000 shares of common stock to a director upon the
      exercise of options at a price of $0.75 per share.





As
      a
      result of the reverse merger, Aurora’s shareholders’ equity reflects the
      following transactions:





The
      total
      outstanding Aurora shares, at the effective date of the merger, of 19,056,183
      were in the 2 for 1 exchange.





Cadence
      returned 600,000 shares to treasury stock for 300,000 shares it held
      in Aurora at the time of merger which became 600,000 shares in the 2 for 1
      exchange. This is reflected as a reduction to Aurora’s equity.





The
      total
      outstanding Cadence shares, at the effective date of the merger, of 21,136,327
      were added to Aurora’s equity.





The
      Company issued 2,642,500 shares of common stock upon the exercise of
      certain options and warrants at prices ranging from $1.25 to $1.75 per
      share.





During
      the last quarter of 2005, certain option and warrant holders exercised their
      options and warrants under the cashless exercise provision within their options
      and warrants. This resulted in the issuance of 245,068 shares of the
      Company’s stock. In December 2005, an additional 2,160,000 shares were issued
      for cash proceeds of $2,916,000.




76




AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


**Common
      Stock Warrants**





The
      following table provides information related to stock warrant activity for
      the
      years ended December 31:





2007
            
            2006
            
            2005Number of Shares
                UnderlyingWarrants
            
            Number of Shares
                UnderlyingWarrants
            
            Number of Shares
                UnderlyingWarrantsOutstanding
                at the beginning of the period
            
            
            2,079,500
            
            
            19,697,500
            
            
            -Granted
            
            
            -
            
            
            -
            
            
            2,402,000Assumed
                upon merger:2
                for 1 exchange of Aurora warrants
            
            
            -
            
            
            -
            
            
            2,402,000Cadence
                warrants
            
            
            -
            
            
            -
            
            
            17,498,500Exercised
                under early exercise program
            
            
            -
            
            
            (13,182,625
            )
            
            -Exercised
            
            
            (78,158
            )
            
            (3,589,871
            )
            
            (2,596,677
            )Forfeitures
                and other adjustments
            
            
            (49,342
            )
            
            (845,504
            )
            
            (8,323
            )Outstanding
                at the end of the period
            
            
            1,952,000
            
            
            2,079,500
            
            
            19,697,500





As
      of
      December 31, 2007, these common stock warrants had an average remaining
      contractual life of 1.09 years and weighted average exercise price per share
      of
      $1.74.





**NOTE
      9. INCOME TAXES**





Income
      tax expense (benefit) for the years ended December 31 consists of the following
      (in thousands):





For
                the Years Ended December 31,
            
            2007
            
            2006
            
            2005Current
                taxes
            
            $
            -
            
            $
            -
            
            $
            -Deferred
                taxes
            
            
            (7,875
            )
            
            1,862
            
            
            175Less:
                change in valuation allowance
            
            
            7,875
            
            
            (1,862
            )
            
            (175
            )Net
                income tax expense (benefit)
            
            $
            -
            
            $
            -
            
            $
            -





The
      effective income tax rate for the years ended December 31 differs from the
      U.S.
      federal statutory income tax rate due to the following (in
      thousands):





For
                the Years Ended December 31,
            
            2007
            
            2006
            
            2005Tax
                at federal statutory income tax rate
            
            $
            (1,504
            )
            $
            (661
            )
            $
            (176
            )Adjustment
                of estimated income tax provision of prior years(a)
            
            
            (6,371
            )
            
            2,523
            
            
            -Change
                in valuation allowance
            
            
            7,875
            
            
            (1,862
            )
            
            176Net
                income tax expense (benefit)
            
            $
            -
            
            $
            -
            
            $
            -





(a)  2006
      adjustment of estimated income tax provision of prior year is due primarily
      to
      intangible costs that were expensed in 2005 calculation but capitalized and
      amortized in actual 2005 tax return. 2007 adjustment of estimated income tax
      provision of prior year is due primarily to a 2006 revision to the method of
      tax
      accounting treatment for stock options which lead to a significant change in
      the
      net operating loss carryover.




77




AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


The
      components of the deferred tax assets and liabilities as of December 31 are
      as
      follows (in thousands):





2007
            
            2006
            
            2005Deferred
                tax assets:Net
                operating loss carryover
            
            $
            28,926
            
            $
            11,661
            
            $
            12,324Stock
                options
            
            
            1,612
            
            
            928
            
            
            -Section
                1231 carryover
            
            
            109
            
            
            -
            
            
            147Capital
                loss carryover
            
            
            -
            
            
            33
            
            
            66,000Less
                valuation allowance
            
            
            (8,405
            )
            
            (530
            )
            
            (2,392
            )Deferred
                tax assets, net
            
            
            22,242
            
            
            12,092
            
            
            10,146Deferred
                tax liabilities:Excess
                assigned acquisition value
            
            
            (4,165
            )
            
            (4,339
            )
            
            (4,339
            )Intangible
                drilling costs and other
            
            
            (18,077
            )
            
            (7,753
            )
            
            (5,807
            )Deferred
                tax liabilities, net
            
            
            (22,242
            )
            
            (12,092
            )
            
            (10,146
            )Net
                deferred tax assets (liabilities)
            
            $
            -
            
            $
            -
            
            $
            -





The
      Company has net operating loss carryforwards available to offset future federal
      taxable income of approximately $85.1 million, which expire from 2010 through
      2027. Included in this amount is a pre-merger net operating loss carryforward
      incurred by Cadence of approximately $16.9 million. The valuation allowance
      increased (decreased) by approximately $7.9 million, ($1.9 million), and ($0.2
      million) as of December 31, 2007, 2006, and 2005, respectively. Due to the
      net
      operating loss carryforwards, no income tax expense was recorded in 2007, 2006,
      and 2005.





**NOTE
      10. COMMON STOCK OPTIONS**





**Stock
      Option Plans**





In
      October 1997, Aurora adopted a 1997 Stock Option Plan pursuant to which it
      was
      authorized to issue compensatory options to purchase up to 1,000,000 shares
      of
      common stock. The 1997 Stock Option Plan provides that the total number of
      shares of common stock of Aurora which may be granted as options shall not
      exceed 10% of the outstanding shares of the Company as of December 31 of each
      year for the following year. Aurora issued options to purchase a total of
      580,000 shares of Aurora's common stock under this plan which, upon closing
      the
      merger, converted into the right to acquire up to 1,160,000 shares of common
      stock. The maximum term of options granted is 10 years. Because of the merger,
      no further awards will be made under this plan.





In
      2001,
      Aurora's board of directors and shareholders approved the adoption of an Equity
      Compensation Plan for Non-Employee Directors. This plan provided that each
      nonemployee director is entitled to receive options to purchase 100,000 shares
      of Aurora's common stock, issuable in increments of options to purchase 33,333
      shares each year over a period of 3 years, so long as the director continues
      in
      office. Prior to the merger closing, Aurora had issued options to purchase
      a
      total of 309,997 shares of Aurora common stock under this plan which, upon
      closing the merger, converted to the right to acquire 619,994 shares of our
      common stock. Because of the merger, no further awards will be made under this
      plan.





In
      2004,
      Cadence’s board of directors adopted, and the shareholders approved, a 2004
      Equity Incentive Plan. This plan provides for the grant of options or restricted
      shares for compensatory purposes for up to 1,000,000 shares of common stock.
      The
      number of shares issued or subject to options issued under this plan total
      910,500. The maximum term of options granted is 10 years. The Company does
      not
      currently intend to make any further awards under this plan, the plan continues
      to exist, and the Company may decide to use it in the future.




78


AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES
      TO
      CONSOLIDATED FINANCIAL STATEMENTS


(Continued)





In
      March
      2006, the Company’s board of directors adopted, and, in May 2006, shareholders
      approved, the 2006 Stock Incentive Plan. This Plan provides for the award of
      options or restricted shares for compensatory purposes for up to 8,000,000
      shares. The purpose of the Plan is to promote the interests of the Company
      by
      aligning the interests of employees (including directors and officers who are
      employees) of the Company, consultants, and nonemployee directors of the Company
      and to provide incentives for such persons to exert maximum efforts for the
      success of the Company and its affiliates. The maximum term for options granted
      is 10 years.





Activity
      related to the stock option plans referenced above was as follows for the years
      ended December 31, 2007, 2006 and 2005:





For
                the Years Ended December 31,
            
            2007
            
            2006
            
            2005Options
                outstanding at beginning of period
            
            
            3,432,496
            
            
            1,804,994
            
            
            943,994Options
                granted
            
            
            185,000
            
            
            2,727,500
            
            
            146,000Assumed
                upon merger:2
                for 1 exchange of Aurora options
            
            
            -
            
            
            -
            
            
            490,000Cadence
                options
            
            
            -
            
            
            -
            
            
            400,000Options
                exercised
            
            
            (353,332
            )
            
            (592,732
            )
            
            (195,000
            )Options
                forfeited and other adjustments
            
            
            (390,500
            )
            
            (507,266
            )
            
            20,000Options
                outstanding at end of period
            
            
            2,873,664
            
            
            3,432,496
            
            
            1,804,994





The
      weighted average assumptions used in the Black-Scholes option-pricing model
      used
      to determine fair value were as follows:





2007
            
            2006
            
            2005Risk-free
                interest rate
            
            
            4.67
            %
            
            4.1
            %
            
            4
            %Expected
                years until exercise
            
            
            3.25-6.0
            
            
            2.5-6.0
            
            
            10Expected
                stock volatility
            
            
            71.41
            %
            
            41
            %
            
            41
            %Dividend
                yield
            
            
            0
            %
            
            0
            %
            
            0
            %





**All
      Stock Options**





In
      addition, Cadence awarded compensatory options and warrants totaling 30,280
      on
      an individualized basis that was considered outside the awards issued under
      its
      2004 Equity Incentive Plan. Aurora also issued options and warrants totaling
      1,400,000 on an individualized basis that was considered outside the awards
      issued under its 1997 Stock Option Plan and Equity Compensation Plan for
      Non-Employee Directors.




79




AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)




Activity
      with respect to all stock options is presented below for the years ended
      December 31, 2007, 2006 and 2005:





2007
            
            2006
            
            2005Shares
            
            Weighted
              Average
              Exercise
              Price
            
            Shares
            
            Weighted
              Average
              Exercise
              Price
            
            Shares
            
            Weighted
              Average
              Exercise
              PriceOptions
                outstanding at the beginning of period
            
            
            4,862,776
            
            $
            2.23
            
            
            6,448,468
            
            $
            0.72
            
            
            2,700,664
            
            $
            0.99Options
                granted
            
            
            185,000
            
            
            3.35
            
            
            2,727,500
            
            
            3.89
            
            
            156,000
            
            
            3.32Assumed
                upon merger:2
                for 1 exchange of Aurora options
            
            
            -
            
            
            
            
            
            -
            
            
            -
            
            
            2,856,664
            
            
            -Cadence
                options
            
            
            -
            
            
            
            
            
            -
            
            
            -
            
            
            1,124,349
            
            
            1.79Options
                exercised
            
            
            (353,332
            )
            
            0.56
            
            
            (3,800,926
            )
            
            0.67
            
            
            (357,500
            )
            
            1.20Forfeitures
                and other adjustments
            
            
            (390,500
            )
            
            4.10
            
            
            (512,266
            )
            
            3.65
            
            
            (31,709
            )
            
            0.43Options
                outstanding at end of period
            
            
            4,303,944
            
            $
            2.25
            
            
            4,862,776
            
            $
            2.23
            
            
            6,448,468
            
            $
            0.72Exercisable
                at end of period
            
            
            2,940,609
            
            $
            1.56
            
            
            2,775,609
            
            $
            1.01Weighted
                average fair value of options granted during the period
            
            $
            1.20
            
            
            
            
            $
            3.85





The
      intrinsic value of a stock option is the amount by which the current market
      value of the underlying stock exceeds the exercise price of the option. The
      intrinsic value of the options outstanding at December 31, 2007, was
      approximately $1.9 million and the intrinsic value of the options exercisable
      at
      December 31, 2007, was approximately $1.9 million. The intrinsic value of the
      options exercised during the year ended December 31, 2007, was
      approximately $350,000.





The
      weighted average remaining life by exercise price as of December 31, 2007,
      is
      summarized below:





Range of
              Exercise Prices
            
            Outstanding
              Shares
            
            Weighted Average
              Life
            
            Exercisable
              Shares
            
            Weighted Average
              Life$0.38
                - $0.63
            
            
            1,896,664
            
            
            1.5
            
            
            1,896,664
            
            
            1.5$1.75
                - $2.55
            
            
            405,280
            
            
            5.9
            
            
            332,280
            
            
            6.0$2.90
                - $3.55
            
            
            268,000
            
            
            8.3
            
            
            135,000
            
            
            7.8$3.62
            
            
            1,140,000
            
            
            3.0
            
            
            300,000
            
            
            2.9$4.45
                - $4.70
            
            
            494,000
            
            
            7.7
            
            
            176,665
            
            
            7.3$5.50
            
            
            100,000
            
            
            3.2
            
            
            100,000
            
            
            3.2$0.38
                - $5.50
            
            
            4,303,944
            
            
            3.5
            
            
            2,940,609
            
            
            2.5





**NOTE
      11. COMMITMENTS AND CONTINGENCIES**





**Environmental
      Risk**




Due
      to
      the nature of the oil and natural gas business, the Company is exposed to
      possible environmental risks. The Company manages its exposure to environmental
      liabilities for both properties it owns as well as properties to be acquired.
      The Company has historically not experienced any significant environmental
      liability and is not aware of any potential material environmental issues or
      claims at December 31, 2007.




80




AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)




**Letters
      of Credit**




For
      each
      salt water disposal well drilled in the State of Michigan, the Company is
      required to issue a letter of credit to the Michigan Supervisor of Wells. The
      Supervisor of Wells may draw on the letter of credit if the Company fails to
      comply with the regulatory requirements relating to the locating, drilling,
      completing, producing, reworking, plugging, filling of pits, and clean up of
      the
      well site. The letter of credit or a substitute financial instrument is required
      to be in place until the salt water disposal well is plugged and abandoned.
      For
      drilling natural gas wells, the Company is required to issue a blanket letter
      of
      credit to the Michigan Supervisor of Wells. This blanket letter of credit allows
      the Company to drill an unlimited number of natural gas wells. The majority
      of
      existing letters of credit have been issued by Northwestern Bank of Traverse
      City, Michigan, and are secured only by a Reimbursement and Indemnification
      Commitment issued by the Company, together with a right of setoff against all
      of
      the Company’s deposit accounts with Northwestern Bank. At December 31, 2007,
      letters of credit in the amount of $1.2 million were outstanding with the
      majority issued to the Michigan Supervisor of Wells.




***Employment
      Agreement***




Ronald
      E.
      Huff resigned as President, Chief Financial Officer and Director of AOG
      effective January 21, 2008. The Company had a 2-year Employment Agreement with
      Mr. Huff, providing for an annual salary of $200,000 per year and an award
      of a
      stock bonus in the amount of 500,000 shares of the Company’s common stock on
      January 1, 2009, so long as he remained employed by the Company through June
      18,
      2008, which requires the Company to record approximately $2.1 million in
      stock-based compensation expense over the contract period. Mr. Huff’s employment
      agreement will be honored by the Company through its June 18, 2008 termination
      date. At December 31, 2007, the stock bonus amount of 500,000 shares was
      unvested. However, this agreement has been modified to accelerate the award
      of
      Mr. Huff’s stock bonus in the amount of 500,000 shares of common stock from
      January 1, 2009, to June 18, 2008.





**Equipment
      Sale - Leaseback Agreement**




Effective
      June 21, 2007, the Company entered into an agreement with Fifth Third Bank
      to
      sell and leaseback three natural gas compressors, which were accounted for
      as an
      operating lease. The net carrying value of the natural gas compressors sold
      was
      $1.2 million. Because the net carrying value of the natural gas compressors
      was
      equal to the sales price, there was no gain or loss recognized on the sale.
      The
      lease agreement has a base lease term of 84 months with a monthly rental fee
      of
      $13,610 beginning July 1, 2007. For the year ended December 31, 2007, total
      rental expense incurred by the Company under this lease was $83,475, of which
      $8,713 was capitalized in oil and natural gas properties.




Effective
      December 19, 2007, the Company entered into an agreement with Fifth Third Bank
      to sell and leaseback eleven natural gas compressors for $2.7 million. Under
      the
      agreement, the Company is leasing back the property over a base lease term
      of 60
      months with a monthly rental fee of $37,110 beginning January 1, 2008. The
      Company is accounting for the leaseback as an operating lease. The gain of
      $0.7
      million realized in this transaction has been deferred and will be amortized
      to
      income in proportion to rent charged over the term of the lease. At December
      31,
      2007, the deferred gain of $0.7 million is shown on the Company’s Balance Sheet
      as “Other long-term liabilities” for the long-term portion of $0.6 million and
      as “Accounts payable and accrued liabilities” for the short-term portion of $0.1
      million. For the year ended December 31, 2007, no rental expense was incurred
      by
      the Company under this lease.




The
      minimum lease payments required by both leases are as follows:




2008
            
            $
            608,6382009
            
            
            608,6392010
            
            
            608,6382011
            
            
            608,6392012
            
            
            608,638Thereafter
            
            
            244,982$
            3,288,174




81




AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)




**Fry
      Well Loss**




The
      Company participated with Savoy Energy, L.P. (“Savoy”) in an exploratory well
      known as the Fry 1-13 located in Mecosta County, Michigan. In late December
      2006, the well experienced a blow-out event which incurred approximately $5.6
      million associated with controlling the well and other related costs. The
      Company had a 13.33% cost interest (10% working interest) in this well to casing
      point and paid approximately $762,000 to cover its portion of the loss to Savoy.
      The Company’s insurance covered approximately 34% or $266,666 of the well
      control costs.




**NOTE
      12. RELATED PARTY TRANSACTIONS**





William Deneau
      and John Miller, who were officers during the reporting period, are involved
      as
      equity owners in numerous corporations and limited liability companies that
      are
      active in the oil and natural gas business. They also own miscellaneous
      overriding royalty interests in wells in which the Company has an interest
      but
      are operated by unrelated third parties. During 2006, these officers divested
      themselves of all interests for which the Company served as
      operator.





At
      the
      time of the merger, Aurora had a lease for office and storage space from
      South 31, L.L.C. William W. Deneau owned one-third of South 31, L.L.C.
      Rent was paid through December 31, 2005, on a lease extending through
      March 31, 2007. After the Company moved the corporate offices in early
      December 2005, the Company no longer had a need for the space in the
      South 31, L.L.C. property. The Company entered into a Settlement Agreement
      and Mutual Release with South 31, L.L.C. pursuant to which a payment was
      made to South 31, L.L.C. in the amount of $65,250 on January 27, 2006,
      and South 31, L.L.C. released the Company from any further obligation on
      the lease. The Company currently maintains a month-to-month storage lease with
      South 31, L.L.C. for $600 per quarter.





Effective
      May 30, 2007, the board of directors named John C. Hunter as Vice President
      of
      Exploration and Production. He has worked for AOG since 2005 as Senior Petroleum
      Engineer. Prior to that, Mr. Hunter was instrumental in certain projects
      associated with the Company’s New Albany shale play. Over a series of agreements
      with the Company, Mr. Hunter (controlling member of Venator Energy, LLC) has
      acquired 1.25% working interest in certain leases. The leases cover
      approximately 132,600 acres (1,658 net) in certain counties located in Indiana.
      The 1.25% carried working interest shall be effective until development costs
      exceed $30 million. Thereafter, participation may continue as a standard 1.25%
      working interest owner. The Company is entitled to recovery of 100% of
      development costs (plus interest at a rate of 6.75% per annum compounded
      annually) from 85% of the net operating revenue generated from oil and gas
      production developed directly or indirectly in the area of mutual interest
      covered by the agreement. As of December 31, 2007, there is no production
      associated with this working interest and development costs were approximately
      $12.4 million.




Effective
      July 1, 2004, Aurora Energy, Ltd., (“AEL”), entered into a Fee Sharing Agreement
      with Mr. Hunter as compensation for bringing Bluegrass Energy Enhancement Fund,
      LLC (“Bluegrass”) and AEL together for the development of the 1500 Antrim and
      Red Run Projects in Michigan. At this time, AEL and Bluegrass have discontinued
      leasing activities in both projects. In the 1500 Antrim project, there are
      23,989.41 acres. Mr. Hunter's carried working interest share of 0.8333% is
      approximately 199.95 net acres. The carried working interest relates to the
      first 55 wells that are drilled in the area of mutual interest. Thereafter,
      Mr.
      Hunter would pay his proportionate share of working interest expenses.
      Currently, there are no producing wells. The Red Run project contains 12,893.64
      acres. Mr. Hunter's carried working interest share of 0.8333% is approximately
      107.44 net acres. The carried working interest relates to the first 55 wells
      that are drilled in the area of mutual interest. Thereafter, Mr. Hunter would
      pay his proportionate share of working interest expenses. Currently, there
      are 3
      wells permitted for the Red Run project and one well was temporarily
      abandoned.




82




AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)




**NOTE
      13. RETIREMENT BENEFITS**





***401(k)
      Plan***





Effective
      May 1, 2006, the Company established a qualified retirement plan referred to
      as
      the Aurora 401(k) Plan (the “Plan”). The Plan is available to all employees who
      have completed at least 1,000 hours of service over their first 12 consecutive
      months of employment and are at least 21 years of age. Effective July 1, 2006,
      the Company waived the age and service requirements for any employee employed
      by
      the Company on or before July 1, 2006. The Company may provide: (1)
      discretionary matching of employee contributions; (2) discretionary
      profit-sharing contributions; and (3) qualified nonelective contributions to
      the
      Plan. Company-provided contributions are subject to certain vesting schedules.
      For the years ended December 31, 2007, and 2006, the Company contributed $66,211
      and $42,350, respectively, as a discretionary matching
      contribution.





**Retention
      Bonus**




On
      September 19, 2007, the Company announced that it had retained Johnson Rice
      & Company, L.L.C. to assist the Board of Directors with investigating
      strategic alternatives for the Company. These alternatives, among other things,
      may include revisions to the Company’s strategic plan, asset divestitures,
      operating partnerships, identifying additional capital sources, or a sale,
      merger, or other business combination of the Company. The Board of Directors
      of
      the Company has approved a retention bonus arrangement to encourage certain
      key
      officers and employees to remain with the Company through the completion of
      the
      Company’s review of potential strategic alternatives. The Board of Directors
      recognizes that certain key officers and employees will have increased
      responsibilities and duties during the evaluation of strategic alternatives
      and
      will contribute significantly to the process. The aggregate retention bonus
      consists of four payments over an 8-month period beginning in late October
      2007
      through late April 2008. The key officers and employees must remain continuously
      employed with the Company as well as remain in good standing on the scheduled
      payment dates. As of December 31, 2007, the Company had recorded $237,500 for
      estimated retention bonuses in 2007.




***2007
      Incentive Bonus Plan***





The
      Company had adopted an incentive bonus plan for the year 2007. The incentive
      bonus plan was available to all full-time employees, excluding officers and
      employees of subsidiaries. The bonus would be up to 10% of eligible employees’
compensation during the year 2007 if certain objectives are met. Those
      objectives were not met and no bonus expense was incurred.





**NOTE
      14. FOURTH QUARTER ADJUSTMENTS—2006**





During
      the fourth quarter of 2006, the Company modified its approach to estimating
      capitalized interest. The Company’s original approach to capitalization of
      interest cost was to relate the specific exploration and development activities
      in progress that were allowed under the mezzanine credit facility to specific
      mezzanine credit facility borrowings. If there were no such borrowings in a
      month that matched the drilling activities, then no interest was capitalized.
      On
      January 31, 2006, the Company entered into a new senior secured revolving credit
      facility for drilling, development, and acquisitions, which was not limited
      to
      certain exploration and development activities. In this connection, the
      mezzanine credit facility was subordinated to the new senior credit facility,
      and no further borrowings occurred under the mezzanine facility. The Company
      reviewed its approach to capitalized interest and began treating all oil and
      gas
      properties that were not being depreciated, depleted, or amortized, as well
      as
      any exploration and development activities that were in progress of being
      developed as qualifying assets under SFAS No. 34. The Company identified all
      its
      long-term debt borrowings to be included in the weighted average rate
      calculation for capitalized interest. This change resulted in additional $3.2
      million of capitalized interest for the entire fiscal year of 2006 which was
      recorded in the fourth quarter; of this amount, $1.9 million related to prior
      quarters.




83




AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)




During
      the fourth quarter of 2006, the Company modified its approach to estimating
      oil
      and natural gas depreciation, depletion and amortization (“DD&A”). The
      Company’s original accounting approach was to amortize all capitalized costs of
      oil and natural gas properties considered proven developed, on the
      unit-of-production method using estimates of proven developed reserves. However,
      applicable accounting principles and related guidance provides that capitalized
      costs of oil and natural gas properties can be amortized on a unit-of-production
      method based on all proved oil and natural gas reserves. As of December 31,
      2006, all of the Company’s proven reserves were evaluated by an independent
      petroleum engineering group which resulted in a 89 bcfe increase in proved
      reserves associated with the full cost pool. This change in estimate from proven
      developed reserves to proven reserves as well as an updated reserve report
      resulted in a reduction of $ 2.7 million in oil and natural gas depreciation,
      depletion and amortization.





**NOTE
      15. SELECTED QUARTERLY DATA (Unaudited)**




Quarter EndedMarch 31
            
            June 30
            
            September 30
            
            December 312007Operating
                revenues (a)
            
            $
            6,248,362
            
            $
            6,820,177
            
            $
            7,205,388
            
            $
            7,632,879Operating
                income (b)
            
            
            1,531,336
            
            
            2,231,935
            
            
            2,876,491
            
            
            2,671,790Net
                (loss) income
            
            
            (740,319
            )
            
            229,477
            
            
            (3,254,294
            )
            
            (656,697
            )Basic
                net earnings per share
            
            
            (0.01
            )
            
            0.00
            
            
            (0.03
            )
            
            (0.01
            )Diluted
                net earnings per share
            
            
            (0.01
            )
            
            0.00
            
            
            (0.03
            )
            
            (0.01
            )2006Operating
                revenues (a)
            
            
            5,528,632
            
            
            5,654,887
            
            
            5,313,261
            
            
            5,710,115Operating
                income (b)
            
            
            2,023,772
            
            
            2,361,513
            
            
            1,613,107
            
            
            1,476,417Net
                (loss) income
            
            
            (939,183
            )
            
            (1,185,188
            )
            
            (2,086,234
            )
            
            2,091,433Basic
                net earnings per share
            
            
            (0.01
            )
            
            (0.01
            )
            
            (0.03
            )
            
            0.02Diluted
                net earnings per share
            
            
            (0.01
            )
            
            (0.01
            )
            
            (0.03
            )
            
            0.02





(a)
            Includes
                (1) oil and natural gas sales, (2) pipeline transportation and
                processing, and (3) field services and
                sales.





(b)
            Includes
                (1) production taxes, (2) production and processing operating
                expenses, (3) field services expenses, and (4) general and
                administrative expenses.





**NOTE
      16. SUBSEQUENT EVENTS**





**Letter
      of Intent**




Effective
      January 22, 2008, the Board of Directors named John E. McDevitt as President,
      Chief Operating Officer and Director. The Board of Directors also named Gilbert
      A. Smith as Vice President of Business Development effective as of February
      1,
      2008. The Company has signed a non-binding Letter of Intent to acquire Acadian
      Energy, LLC. Mr. McDevitt (through a controlled entity) and Mr. Smith are the
      sole members of Acadian Energy, LLC (60% and 40% respectively). The proposed
      acquisition is valued at approximately $12.5 million and will include over
      10,000 acres of New Albany Shale properties, 4 development wells, and
      approximately 7 bcf in proved reserves .





**Other
      Investment Transfer**




Effective
      March 31, 2007, the Company withdrew from active participation in the GeoPetra
      Partners, LLC investment.  The Company has a full ownership interest in all
      projects in which it elected to participate and in properties and interest
      acquired in the investment prior to the effective date of the withdrawal. 
The carrying value of $528,136 is expected to be converted from "Other
      Investments" on the Balance Sheet to working interests in oil and natural gas
      properties for applicable projects in the first quarter of 2008.




84




AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


SUPPLEMENTAL
      INFORMATION ON OIL AND NATURAL


GAS
      EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES


(Unaudited)








***Supplemental
      Reserve Information*** .
      The
      information set forth below on our proved oil and natural gas reserves is
      presented in accordance with regulations prescribed by the Securities and
      Exchange Commission. The Company emphasizes that reserve estimates are
      inherently imprecise. Our reserve estimates were generally based upon
      extrapolation of historical production trends, analogy to similar properties
      and
      volumetric calculations. Accordingly, these estimates are expected to change
      and
      such changes could be material and occur in the near term as future information
      becomes available.





The
      Company retained the service of an independent petroleum consultant (Data &
Consulting Services, Division of Schlumberger Technology Corporation) to
      estimate its proved natural gas reserves at December 31, 2007, 2006, and 2005.
      Included in the tables set forth below are proved oil and natural gas reserves
      located in Michigan that were acquired as a separate property acquisition early
      in 2006 and proved oil and natural gas reserves acquired in conjunction with
      the
      reverse merger with Cadence Resources Corporation effective October 31, 2005.
      These proved reserves acquired in the reverse merger were estimated by
      Netherland, Sewell & Associates, Inc. and Ralph E. Davis Associates,
      Inc.





The
      following table sets forth a summary of changes in estimated reserves for 2007,
      2006 and 2005:





Estimates of Proved Reserves
            
            Oil
              (mbbl)
            
            Natural Gas
              (mmcf)
            
            Total
              (mmcfe)Proved
                reserves as of December 31, 2004
            
            
            -
            
            
            34,949
            
            
            34,949Revisions
                of previous estimates
            
            
            6
            
            
            5,382
            
            
            5,394Purchases
                of minerals in place
            
            
            103
            
            
            1,572
            
            
            2,190Extensions
                and discoveries
            
            
            -
            
            
            22,107
            
            
            22,107Production
            
            
            (10
            )
            
            (688
            )
            
            (748
            )Proved
                reserves as of December 31, 2005
            
            
            99
            
            
            63,322
            
            
            63,916Revisions
                of previous estimates
            
            
            (40
            )
            
            4,880
            
            
            5,120Purchases
                of minerals in place
            
            
            -
            
            
            22,843
            
            
            22,843Extensions
                and discoveries
            
            
            45
            
            
            65,095
            
            
            65,365Production(1)
            
            
            (23
            )
            
            (2,511
            )
            
            2,649Sales
                of minerals in place
            
            
            -
            
            
            (665
            )
            
            (665
            )Proved
                reserves as of December 31, 2006
            
            
            81
            
            
            152,964
            
            
            153,450Revisions
                of previous estimates
            
            
            20
            
            
            (34,651
            )
            
            (34,531
            )Purchases
                of minerals in place
            
            
            -
            
            
            2,943
            
            
            2,943Extensions
                and discoveries
            
            
            131
            
            
            47,256
            
            
            48,042Production(1)
            
            
            (28
            )
            
            (3,034
            )
            
            (3,202
            )Sales
                of minerals in place
            
            
            (16
            )
            
            (11
            )
            
            (107
            )Proved
                reserves as of December 31, 2007
            
            
            188
            
            
            165,467
            
            
            166,595Proved
                developed reserves:December
                31, 2005
            
            
            70
            
            
            45,205
            
            
            45,625December
                31, 2006
            
            
            54
            
            
            82,580
            
            
            82,904December
                31, 2007
            
            
            74
            
            
            100,887
            
            
            101,331





(1)  Production
      for both 2007 and 2006 does not reflect 5 mcfe and 142 mcfe, respectively,
      of
      production the Company received in association with certain non-operated wells
      excluded in the year end reserve report.




85




AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 SUPPLEMENTAL
        INFORMATION ON OIL AND NATURAL
 GAS
        EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
 (Unaudited—continued)




During
      2007, the Company recorded downward revisions to certain Antrim properties
      of
      34.5 bcfe to the December 31, 2006, estimates of our reserves. This was due
      primarily to the 2007 lower realized production levels from certain project
      areas. The production curves used in the reserve report were adjusted to reflect
      lower future production to be consistent with the 2007 actual experience. This
      decrease was net of the upward adjustments caused by higher natural gas prices
      at December 31, 2007. Increase in pricing extends the economic lives of the
      properties which subsequently increases the reserves.





The
      Company recorded an increase in extensions and discoveries of 48 bcfe which
      was
      due to positive results from our 2007 drilling activity. Positive drilling
      results in the New Albany Shale added nearly 24 bcfe, while positive drilling
      results in the Antrim added 24 bcfe. Increases in the number of identifiable
      offsets also moved certain probable reserves to proved reserves. The Company
      also acquired 2.9 bcfe of proved reserves through the purchase of certain Antrim
      working interests for $3 million and sold 0.11 bcfe of proved reserves for
      approximately $1 million.





During
      2006, the Company experienced significant changes in reserves due to extensions
      and discoveries associated with drilling activities conducted by both the
      Company and by third parties. Approximately 99.6% of the 65.4 bcfe of reserves
      attributable to extensions and discoveries are associated with the
      following:





The
      drilling of 16 gross (0.9 net) New Albany shale wells in Daviess and Greene
      Counties, Indiana, resulted in two field discoveries and reserves of 2.3 bcfe
      associated with 40 gross (2.4 net) wells. Approximately 67% of the reserves
      are
      undeveloped and are expected to be developed in 2007 and 2008.





The
      drilling of 196 gross (90.1 net) Antrim shale wells in Alcona, Alpena, Antrim,
      Charlevoix, Cheboygan, Montmorency, and Otsego Counties, Michigan, resulted
      in
      reserve extensions of 62.8 bcfe associated with 257 gross (138.1 net) wells.
      Approximately 59% of the reserve extensions are undeveloped and are expected
      to
      be developed in 2007 and 2008. The Company also acquired approximately 23 bcfe
      of proved reserves through purchases of natural gas properties for approximately
      $24.0 million and sold 0.7 bcfe of proved reserves for approximately $4.75
      million.





During
      2006, the Company recorded upward revisions of 5.1 bcfe to the December 31,
      2005, estimates of our reserves. This was due primarily to the increase in
      the
      lives of the wells from 40 years to 50 years. Our reserve report for 2005
      recognized a maximum well life of 40 years for Antrim shale wells. Schlumberger
      Data & Consulting Services, the preparer of the Company’s reserve reports,
      extended the maximum well life for the Antrim shale by an additional 10 years
      in
      the 2006 reserve report, and they also recognized a 50-year maximum life for
      the
      New Albany shale for several reasons. First, a number of Antrim shale properties
      operated by third parties have exhibited extended lives that suggest that a
      50-year life is a reasonable expectation. Second, in most cases, our properties
      are projected to still be economic to produce after 50 years of production.
      Third, the casing in our wells is expected to maintain its integrity for 50+
      years. Finally, we noted that at least one of the leading Antrim shale and
      New
      Albany shale producing companies projects their Antrim shale reserves and New
      Albany shale reserves using a 50-year maximum well life. The New Albany shale
      properties were included for the first time in our 2006 reserve report. The
      New
      Albany shale reservoir is comparable to the Antrim shale in its age, depth,
      pay
      thickness, gas content, gas origin, and production characteristics, so it is
      our
      belief that the maximum well life will be comparable. This increase was net
      of
      the downward adjustments caused by lower natural gas prices at December 31,
      2006. A decrease in pricing reduces the economic lives of the properties which
      subsequently reduces the reserves.





During
      2005, the Company recorded upward revisions of 5.4 bcfe to the December 31,
      2004, estimates of our reserves. This upward revision was primarily due to
      positive initial production rates from one particular project area which
      outperformed prior year expectations which resulted in an upward adjustment
      to
      the projected production profile. This new profile became the analog for the
      entire project area increasing the reserves accordingly.




86




AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 SUPPLEMENTAL
        INFORMATION ON OIL AND NATURAL
 GAS
        EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
 (Unaudited—continued)




Also
      in
      2005, the Company recorded an increase in extensions and discoveries of 22
      bcfe
      which was due to positive results from our 2005 drilling and leasing activity.
      Certain positive drilling results coupled with increased drilling opportunities
      from leasing activity resulted in an increase in the number of identifiable
      offsets which moved certain probable reserves to proved reserves. The Company
      also acquired approximately 1.7 bcfe of proved reserves of oil and natural
      gas
      properties through our reverse merger.





**Standardized
      Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Natural
      Gas Reserves**





The
      following information has been developed utilizing procedures prescribed by
      SFAS
      No. 69 and based on oil and natural gas reserve and production volumes estimated
      by the Company’s independent reserve engineers. It may be useful for certain
      comparison purposes but should not be solely relied upon in evaluating the
      Company or its performance. Further, information contained in the following
      table should not be considered as representative of realistic assessments of
      future cash flows nor should the Standardized Measure of Discounted Future
      Net
      Cash Flows be viewed as representative of the current value of the
      Company.





The
      future cash flows presented below are computed by applying year-end prices
      to
      year-end quantities of proved oil and natural gas reserves. Future production
      and development costs are computed by estimating the expenditures to be incurred
      in developing and producing the Company’s proved reserves based on year-end
      costs and assuming continuation of existing economic conditions. It is expected
      that material revisions to some estimates of oil and natural gas reserves may
      occur in the future, development and production of the reserves may occur in
      periods other than those assumed, and actual prices realized and costs incurred
      may vary significantly from those used. Additionally, certain capital funding
      constraints may impact the Company’s ability to develop the
      properties.





Management
      does not rely upon the following information in making investment and operating
      decisions. Such decision are based upon a wide range of factors, including
      estimates of probable as well as proved reserves, and varying price and cost
      assumptions are considered more representative of a range of possible economic
      conditions that may be anticipated.





The
      following table sets forth the our future net cash flows relating to proved
      oil
      and natural gas reserves based on the standardize measure prescribed in SFAS
      69:





Year
                Ended December 31,
            
            2007
            
            2006
            
            2005Future
                gross revenues (1)
            
            $
            1,204,891,690
            
            $
            884,186,810
            
            $
            632,058,720Future
                production costs (2)
            
            
            (556,123,590
            )
            
            (378,345,360
            )
            
            (182,710,406
            )Future
                development costs (2)
            
            
            (42,298,790
            )
            
            (37,324,420
            )
            
            (15,073,590
            )Future
                income tax expense (3)
            
            
            (102,354,760
            )
            
            (83,566,133
            )
            
            (101,521,160
            )Future
                net cash flows after income taxes
            
            
            504,114,550
            
            $
            384,950,897
            
            $
            332,753,564Discount
                at 10% per annum
            
            
            (328,571,410
            )
            
            (254,489,076
            )
            
            (179,885,324
            )Standardized
                measure of discounted future net cash flows relating to proved oil
                and
                natural gas reserves
            
            $
            175,543,140
            
            $
            130,461,821
            
            $
            152,868,240





(1)
            Oil
                and natural gas revenues are based on year-end prices (see table
                below)
                with adjustments for changes reflected in existing contracts. There
                is no
                consideration for future discoveries or risks associated with future
                production of proved reserves.


(2)
            Based
                on economic conditions at year-end and does not include administrative,
                general, or financing costs.


(3)
            Future
                income taxes are computed by applying the statutory tax rate to future
                net
                cash flows reduced by the tax basis of the properties, the estimated
                permanent differences applicable to future oil and natural gas producing
                activities, and net operating loss carryforwards.




87




AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


SUPPLEMENTAL
      INFORMATION ON OIL AND NATURAL


GAS
      EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES


(Unaudited—continued)




The
      following table summarizes the year-end prices (net of basis adjustments) used
      to estimate reserves and future net cash flows in accordance with SEC
      guidelines.





As
                of December 31,
            
            2007
            
            2006
            
            2005Natural
                gas (per mmbtu)
            
            $
            7.18
            
            $
            5.84
            
            $
            9.89Oil
                (per barrel)
            
            $
            90.18
            
            $
            57.81
            
            $
            56.41





**Changes
      in Standardized Measure of Discounted Future Cash Flows**





The
      following table sets forth the principal sources of change in the standardized
      measure of discounted future net cash flows:





Year
                Ended December 31,
            
            2007
            
            2006
            
            2005Beginning
                balance
            
            $
            130,461,821
            
            $
            152,868,240
            
            $
            32,159,710Revisions
                to reserves proved in prior years:Net
                change in prices and production costs(1)
            
            
            28,130,498
            
            
            (113,774,170
            )
            
            85,425,515Net
                changes in future development costs
            
            
            (5,261,045
            )
            
            (802,360
            )
            
            6,299,524Net
                changes due to revisions in quantity estimates(2)
            
            
            (42,260,444
            )
            
            3,484,229
            
            
            33,335,739Net
                change in accretion of discount(3)
            
            
            15,878,281
            
            
            19,950,751
            
            
            (66,761,600
            )Other(4)
            
            
            4,469,458
            
            
            (15,976,529
            )
            
            38,137,602Total
                revisions to reserves provided in prior years
            
            
            956,747
            
            
            (107,118,080
            )
            
            96,436,780New
                discoveries and extensions, net of future development and production
                costs
            
            
            65,772,000
            
            
            62,343,872
            
            
            76,487,826Purchases
                of minerals in place
            
            
            4,371,832
            
            
            23,605,950
            
            
            11,834,500Sales
                of oil and gas properties
            
            
            (1,023,701
            )
            
            (4,756,826
            )
            
            -Sales
                of oil and natural gas produced, net of production costs
            
            
            (16,839,303
            )
            
            (14,436,361
            )
            
            (4,696,416
            )Previously
                estimated development costs incurred
            
            
            5,772,092
            
            
            -
            
            
            -Net
                change in income taxes
            
            
            (13,928,348
            )
            
            17,955,026
            
            
            (59,354,160
            )Net
                change in standardized measure of discounted cash flows
            
            
            45,081,319
            
            
            (22,406,419
            )
            
            120,708,530Ending
                balance
            
            $
            175,543,140
            
            $
            130,461,821
            
            $
            152,868,240





(1) “Net
      changes in prices and production costs” – Our reserves consist primarily of
      natural gas. A significant change in natural gas price between reporting periods
      resulted in differences between 2005, 2006 and 2007. These price fluctuations
      were offset by changes in production costs. A summary of the changes is as
      follows:





Price
            
            Change
                in
              Price
            
            Production
              Cost
            
            Change
                in
              Production
              Cost2007
            
            $
            7.18
            
            $
            1.34
            
            $
            3.34
            
            $
            0.872006
            
            $
            5.84
            
            $
            (4.05
            )
            $
            2.47
            
            $
            (0.39
            )2005
            
            $
            9.89
            
            $
            3.69
            
            $
            2.86
            
            $
            (0.74
            )2004
            
            $
            6.20
            
            
            
            
            $
            2.12





88


AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 SUPPLEMENTAL
        INFORMATION ON OIL AND NATURAL
 GAS
        EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
 (Unaudited—continued)


(2) “Revisions
      in quantity estimates” – The quantity estimates varied significantly
      between 2005, 2006 and 2007. The large reduction reflected in 2007 resulted
      when
      year end prices were applied to the downward adjustments of 34 bcfe to the
      12/31/06 reserves for certain Antrim properties, then discounted back to present
      value. Certain fluctuations occurred in 2006 versus 2005 due to the
      classification of additional wells being added to the proved undeveloped
      category from the 12/31/05 report versus the 12/31/06 report. The additional
      wells were treated as “revisions” in the 2005 report but as new discoveries or
      extensions in the 2006 report which impacts the comparability between the 2
      years. In addition, an upward revision was made in 2005. This was due to
      positive initial production rates from one particular project area which
      outperformed prior year expectations resulting in an upward adjustment to the
      projected production profile.





(3) “Accretion
      to the discount” – In 2005, this line item was computed as the change in
      the overall discount between the 2004 report and the 2005 report. In 2006 and
      2007, it was computed using the more simplified and industry-recognized method
      as a computation of the 10% of the pre-tax present value of the prior year
      reserve report.





(4) “Other” –
      This line item reflects reconciling amounts which is made available to capture
      those timing and other differences, including modifications to the methodology
      applied from 2005, 2006, and 2007.





**Capitalized
      Costs Related to Oil and Natural Gas Producing Activities**





The
      following table sets forth the capitalized costs relating to the Company’s oil
      and natural gas producing activities:





As
                of December 31,
            
            2007
            
            2006
            
            2005Proved
                properties
            
            $
            167,282,245
            
            $
            128,381,121
            
            $
            39,643,003Unproved
                properties
            
            
            56,937,683
            
            
            43,718,594
            
            
            37,279,889Total
                oil and natural gas properties
            
            
            224,219,928
            
            
            172,099,715
            
            
            76,922,892Less
                accumulated depreciation, depletion, and amortization
            
            
            (14,401,584
            )
            
            (10,628,438
            )
            
            (7,962,138
            )Oil
                and natural gas properties—net
            
            $
            209,818,344
            
            $
            161,471,277
            
            $
            68,960,754




**Costs
      Incurred in Oil and Natural Gas Producing Activities**





The
      acquisition, exploration, and development costs disclosed in the following
      table
      are in accordance with definitions in SFAS No. 19, “Financial Accounting and
      Reporting by Oil and Gas Producing Companies.” Acquisition costs include costs
      incurred to purchase, lease, or otherwise acquire property. Exploration costs
      include exploration expenses, additions to exploration wells in progress, and
      depreciation of support equipment used in exploration activities. Development
      costs include additions to production facilities and equipment, additions to
      development wells in progress and related facilities, and depreciation of
      support equipment and related facilities used in development
      activities.




89


AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 SUPPLEMENTAL
        INFORMATION ON OIL AND NATURAL
 GAS
        EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
 (Unaudited—continued)


The
      following table sets forth capitalized costs incurred related to the Company’s
      oil and natural gas activities:





Years
                Ended December 31,
            
            2007
            
            2006
            
            2005Property
                acquisition costsProved
            
            $
            3,005,609
            
            $
            24,011,335
            
            $
            22,763,734Unproved
            
            
            16,012,328
            
            
            27,718,336
            
            
            19,607,099Exploration
            
            
            11,687,015
            
            
            8,360,779
            
            
            781,586Development
            
            
            24,504,278
            
            
            46,575,829
            
            
            29,707,367Total
                costs incurred(1)
            
            
            55,209,230
            
            
            106,666,279
            
            
            72,859,786Sales
                of oil and natural gas properties
            
            
            (3,089,017
            )
            
            (11,489,456
            )
            
            (11,504,428
            )Total
            
            $
            52,120,213
            
            $
            95,176,823
            
            $
            61,355,358





(1)  Total
      costs incurred includes (a) capitalized general and administrative costs
      directly associated with the acquisition, exploration, and development efforts
      of approximately $1.3 million, $1.3 million, and $0 million for years ended
      December 31, 2007, 2006, and 2005, respectively, and (b) capitalized
      interest on unproven properties of $4.5 million, $3.9 million, and $1.1 million
      for years ended December 31, 2007, 2006, and 2005, respectively. Certain
      non-cash transactions are included as follows: (a) 2007 and 2006 asset
      retirement obligation and capitalized stock compensation of $0.12 million and
      $1.3 million and $0.17 million and $0.45 million, respectively, (b) net transfer
      of $0.31 million from 2005 deposits to 2006 oil and natural gas properties,
      and
      (c) the 2005 fair market value of properties received from Cadence in the
      merger valued at $22.4 million.





**Results
      of Operations**





The
      Company’s results of operations related to oil and natural gas activities are
      set forth below. The following table includes revenues and expenses associated
      directly with our oil and natural gas producing activities. It does not include
      any interest costs, general and administrative costs or provision for income
      taxes due to the net operating loss carryforward, and therefore, is not
      necessarily indicative of the contribution to consolidated net operating results
      of our oil and natural gas operations.





For
                Year Ended December 31,
            
            2007
            
            2006
            
            2005Oil
                and natural gas sales
            
            $
            26,723,818
            
            $
            21,591,811
            
            $
            6,743,444Production
                taxes
            
            
            (1,123,070
            )
            
            (877,319
            )
            
            (506,635
            )Production
                and lease operating costs
            
            
            (8,761,445
            )
            
            (5,966,341
            )
            
            (1,587,205
            )Depletion
                and amortization
            
            
            (3,769,104
            )
            
            (2,681,290
            )
            
            (767,511
            )Results
                of producing activities
            
            $
            13,070,199
            
            $
            12,066,861
            
            $
            3,882,093  90


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




On
      March
      23, 2007, after the completion of the audit of our financial statements for
      the
      years ended December 31, 2006 and 2005, we dismissed Rachlin Cohen &
Holtz LLP (now known as Rachlin LLP) (“Rachlin”) as our independent auditors.
      The report of Rachlin on our financial statements for the years ended December
      31, 2006 and 2005, contained no adverse opinion or disclaimer of opinion and
      was
      not qualified or modified as to uncertainty, audit scope, or accounting
      principles. In connection with its audit for the years ended December 31, 2006
      and 2005, there have been no disagreements with Rachlin on any matter of
      accounting principles or practices, financial statement disclosure, or auditing
      scope or procedure, which disagreements, if not resolved to the satisfaction
      of
      Rachlin , would have caused them to make reference thereto in their report
      on
      the financial statements for such years except as described in the following
      paragraph:





As
      described under Item 3 of our Form 10-QSB/A for the quarter ended March 31,
      2006
      (as filed on October 31, 2006), Rachlin advised us and we disclosed that we
      had
      a material weakness resulting from a deficiency in internal controls relating
      to
      the lack of accounting recognition given to the stock option grants authorized
      and approved by the Board of Directors in March 2006, which resulted in
      (a) the financial statements being modified to account for all of the stock
      option grants in accordance with the applicable provisions of Statement of
      Financial Accounting Standards No. 123(R) and (b) remedial actions
      being taken by us. In addition, as described under Item 3 of our Form 10-QSB/A
      for the quarter ended June 30, 2006 (as filed on October 31, 2006), we validated
      the remedial actions taken to correct the material weakness in connection with
      the reporting of stock option compensation.





The
      decision to change firms was approved by our Audit Committee of the Board of
      Directors.





We
      engaged Weaver and Tidwell, L.L.P. as our new independent auditors effective
      March 23, 2007, and we have relied upon Weaver and Tidwell, L.L.P. as an expert
      in auditing and accounting from that date.





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




***Evaluation
      of Disclosure Controls and Procedures***




Our
      management has responsibility for establishing and maintaining adequate internal
      control over our financial reporting. Management utilized the Committee of
      Sponsoring Organizations of the Treadway Commissions *Internal
      Control-Integrated Framework* (“COSO
      framework”) in conducting the required assessment of effectiveness of our
      internal control over financial reporting.





Our
      disclosure controls and procedures are designed to provide reasonable assurance
      that information required to be disclosed in our periodic filings under the
      Securities Exchange Act of 1934, as amended, is recorded, processed, summarized,
      and reported within the time periods specified in the Securities and Exchange
      Commission's rules and forms, and that such information is accumulated and
      communicated to our management to allow timely decisions regarding required
      disclosure.





Our
      Chief
      Executive Officer ("CEO") and Chief Financial Officer ("CFO") have evaluated
      the
      effectiveness of our disclosure controls and procedures (as defined in Rule
      13a-15(e) and Rule 15d-15(e) of the Securities Exchange Act of 1934, as amended)
      as of December 31, 2007, and have concluded that these disclosure controls
      and
      procedures are effective at the reasonable assurance level. Our CEO and CFO
      believe that the consolidated financial statements included in this report
      on
      Form 10-K fairly present in all material respects our financial condition,
      results of operations and cash flows for the periods presented in conformity
      with generally accepted accounting principles.





Our
      management, including our  CEO
      and
      CFO, do not expect that our internal controls will prevent or detect all errors
      and all fraud. A control system, no matter how well designed and operated,
      can
      provide only reasonable, not absolute, assurance that the objectives of the
      control system are met with respect to financial statement preparation and
      presentation. In addition, any evaluation of the effectiveness of controls
      is
      subject to risks that those internal controls may become inadequate in future
      periods because of changes in business conditions, or because the degree of
      compliance with the policies or procedures deteriorates.





91




***Changes
      in Internal Controls over Financial Reporting***





There
      have been no changes in our internal controls over financial reporting during
      the most recently completed fiscal quarter that have materially affected, or
      are
      reasonably likely to materially affect, our internal control over financial
      reporting.





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





Management’s
      report on internal control over financial reporting and the attestation report
      of our independent registered public accounting firm are included in Item 8
      of
      this report.





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




Not
      applicable.





**PART
      III**





**ITEM
      10.**  **DIRECTORS,
      EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE**




Pursuant
      to instruction G(3) of Form 10-K, the information required by this Item will
      be
      set forth in our definitive proxy statement which will be filed not later than
      120 days after the end of our fiscal year.





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




Pursuant
      to instruction G(3) of Form 10-K, the information required by this Item will
      be
      set forth in our definitive proxy statement which will be filed not later than
      120 days after the end of our fiscal year.





**ITEM
      12.**  **SECURITY
      OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
      MATTERS**




Pursuant
      to instruction G(3) of Form 10-K, the information required by this Item will
      be
      set forth in our definitive proxy statement which will be filed not later than
      120 days after the end of our fiscal year.





**ITEM
      13.**  **CERTAIN
      RELATIONSHIPS, RELATED TRANSACTIONS, AND DIRECTOR
      INDEPENDENCE**




Pursuant
      to instruction G(3) of Form 10-K, the information required by this Item will
      be
      set forth in our definitive proxy statement which will be filed not later than
      120 days after the end of our fiscal year.





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




Pursuant
      to instruction G(3) of Form 10-K, the information required by this Item will
      be
      set forth in our definitive proxy statement which will be filed not later than
      120 days after the end of our fiscal year.





**PART
      IV**





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




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


The
                  following financial statements are filed as a part of this
                  report:Management’s
                  Report on Internal Control Over Financial ReportingReports
                  of Independent Registered Public Accounting FirmsConsolidated
                  Financial StatementsConsolidated
                  Balance Sheets as of December 31, 2007, and 2006Consolidated
                  Statements of Operations for the Years Ended December 31, 2007,
                  2006, and
                  2005Consolidated
                  Statements of Shareholders’ Equity for the Years Ended December 31,
                  2007




92




**(a)(2)
      Exhibit Index:**





3.1(1)
            Restated
                Articles of Incorporation of Aurora Oil & Gas
                Corporation.3.2
            By-Laws
                of Aurora Oil & Gas Corporation. (filed as an Exhibit 3.2 to our Form
                8-K dated August 16, 2007, filed with the SEC on August 22, 2007
                and incorporated herein by reference.)10.1
            Securities
                Purchase Agreement between Cadence Resources Corporation and the
                investors
                signatory thereto, dated January 31, 2005 (filed as Exhibit 10.2
                to our
                Current Report on Form 8-K filed with the SEC on February 2, 2005,
                and
                incorporated herein by reference.)10.2(2)
            Asset
                Purchase Agreement with Nor Am Energy, L.L.C., Provins Family, L.L.C.
                and
                O.I.L. Energy Corp. dated January 10, 2006.10.3
            First
                Amended and Restated Note Purchase Agreement between Aurora Antrim
                North,
                L.L.C. et al. and TCW Asset Management Company, dated December 8,
                2005 (filed as an Exhibit to our report on Form 10-KSB for the fiscal
                year
                ended September 30, 2005 filed with the SEC on December 29, 2005
                and incorporated herein by reference.)10.4(2)
            First
                Amendment to First Amended and Restated Note Purchase Agreement
                between Aurora Antrim North, L.L.C., et al., and TCW Asset Management
                Company, dated January 31, 2006.10.5
            Amended
                and Restated Credit Agreement dated August 20, 2007, among Aurora
                Oil
                & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent
                and the Lenders Party hereto. (filed as an Exhibit 10.7 to our Form
                8-K
                dated August 16, 2007, filed with the SEC on August 22, 2007 and
                incorporated herein by reference.)10.6(2)
            Confirmation
                from BNP Paribas to Aurora Antrim North, L.L.C., dated February 22,
                2006 relating to gas sale commitment.10.7
            2006
                Stock Incentive Plan. (filed as Exhibit 99.1 to our Form S-8
                Registration Statement filed with the SEC on May 15, 2006 and
                incorporated herein by reference.)10.8(1)
            Employment
                Agreement with Ronald E. Huff dated June 19, 2006.10.9(1)
            Letter
                Agreement with Bach Enterprises dated July 10, 2006. (A redacted
                copy is
                filed as an exhibit to Amendment No. 4 to our Form 10`-QSB/A filed
                on
                January 30, 2008.)10.10(1)
            First
                Amendment to Credit Agreement between Aurora Antrim North, L.L.C.,
                et al. and BNP Paribas dated July 14, 2006.10.11(3)
            LLC
                Membership Interest Purchase Agreement dated October 6, 2006 relating
                to
                Kingsley Development Company, L.L.C.10.12(3)
            Asset
                Purchase Agreement with Bach Enterprises, Inc., et al., dated October
                6,
                2006.10.13(3)
            Form
                of indemnification letter agreement between Aurora Oil & Gas
                Corporation and Rubicon Master Fund.10.14
            Second
                Amendment to Credit Agreement between Aurora Antrim North, L.L.C.,
                et al.
                and BNP Paribas dated December 21, 2006. (filed as an Exhibit 10.24
                to our
                report on Form 10-KSB for the fiscal year ended December 31, 2006,
                filed with the SEC on March 15, 2007 and incorporated herein by
                reference.)10.15
            Third
                Amendment to Credit Agreement between Aurora Antrim North, L.L.C.,
                et al.
                and BNP Paribas dated June 20, 2007. (filed as an Exhibit 10.25 to
                our
                Form 10-Q for the period ended June 30, 2007, filed with the SEC on
                August 9, 2007 and incorporated herein by
                reference.)10.16
            Intercreditor
                Agreement dated August 20, 2007, among Aurora Oil & Gas Corporation,
                the Borrower, BNP Paribas, as Administrative Agent and the Lenders
                Party
                hereto. (Replaced Exhibit 10.8 Intercreditor and Subordination Agreement
                among, BNP Paribas, et al., TCW Asset Management Company, and Aurora
                Antrim North, L.L.C., dated January 31, 2006.) (filed as an Exhibit
                10.26
                to our Form 8-K dated August 16, 2007, filed with the SEC on
                August 22, 2007 and incorporated herein by
                reference.)10.17
            Second
                Lien Term Loan Agreement dated August 20, 2007, among Aurora Oil
& Gas
                Corporation, the Borrower, BNP Paribas, as Administrative Agent and
                the
                Lenders Party hereto. (filed as an Exhibit 10.27 to our Form 8-K
                dated
                August 16, 2007, filed with the SEC on August 22, 2007 and
                incorporated herein by reference.)*
            10.18
            Promissory
                Note from Aurora Oil & Gas Corporation to Northwestern Bank dated
                February 14, 2008.*
            14.1
            Code
                of Conduct and Ethics (updated 2/1/08)16.1
            Letter
                concerning change of certifying accountant from Rachlin Cohen & Holtz,
                LLP (included in Exhibit 23.1)*
            21.1
            List
                of Subsidiaries.




93




*
            23.1
            Consent
                of Rachlin Cohen & Holtz LLP.*
            23.2
            Consent
                of Weaver & Tidwell LLP.*
            23.3
            Consent
                of Ralph E. Davis Associates, Inc.*
            23.4
            Consent
                of Schlumberger Technology Corporation.*
            23.5
            Consent
                of Netherland, Sewell & Associates, Inc.*
            31.1
            Rule
                13a-14(a) Certification of Principal Executive Officer.*
            31.2
            Rule
                13a-14(a) Certification of Principal Financial and Accounting
                Officer.*
            32.1
            Section
                1350 Certification of Principal Executive Officer.*
            32.2
            Section
                1350 Certification of Principal Financial and Accounting
                Officer.




(1)
            Filed
                as an exhibit to our Form 10-QSB for the period ended June 30,
                2006, filed with the SEC on August 7, 2006, and incorporated herein
                by reference.


(2)
            Filed
                as an exhibit to our Form 10-KSB for the fiscal year ended
                December 31, 2005, filed with the SEC on March 31, 2006, and
                incorporated herein by reference.


(3)
            Filed
                on October 27, 2006, with our Amendment No. 3 to Form SB-2 registration
                statement filing, registration no. 333-137176, and incorporated herein
                by
                reference.





*
      Filed
      with this report.




94


**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.


**AURORA
                  OIL & GAS CORPORATION**Date:
                  March 7, 2008
              By:
              /s/ William W. DeneauName:
              William
                  W. DeneauTitle:
              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 and in the
      capacities and on the dates indicated.


SIGNATURE
              
              OFFICE
              
              DATE/s/ William W. Deneau
              
              Chairman,
                  Chief Executive Officer, and
              
              March
                  7, 2008William W. Deneau
              
              Director
                  (Principal Executive Officer)/s/ Barbara E. Lawson
              
              Chief
                  Financial Officer
              
              March
                    7, 2008Barbara E. Lawson
              
              (Principal
                  Financial Officer andPrincipal
                  Accounting Officer)/s/ John E. McDevitt
              
              President,
                  Chief Operating Officer, and
              
              March
                    7, 2008John E. McDevitt
              
              Director/s/ Richard M. Deneau
              
              Director
              
              March
                    7, 2008Richard M. Deneau/s/ Gary J. Myles
              
              Director
              
              March
                    7, 2008Gary J. Myles/s/ Wayne G. Schaeffer
              
              Director
              
              March
                    7, 2008Wayne G. Schaeffer/s/ Kevin D. Stulp
              
              Director
              
              March
                    7, 2008Kevin D. Stulp/s/ Earl V. Young
              
              Director
              
              March
                    7, 2008Earl V. Young
  95