**UNITED
      STATES**


**SECURITIES
      AND EXCHANGE COMMISSION**


**WASHINGTON,
      D.C. 20549**




**FORM
      10-KSB**




x
            ANNUAL
                REPORT UNDER SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
                1934




For
      the
      fiscal year ended December 31, 2006.




o
            TRANSITION
                REPORT UNDER SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
                1934.




For
      the
      transition period from ___________ to _____________.




Commission
      file number: 000-25170




**AURORA
      OIL & GAS CORPORATION**


(Name
      of
      Small Business Issuer in Its Charter)




Utah
            87-0306609(State
                or Other Jurisdiction of Incorporation 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 under Section 12(b) of the Exchange Act:




Title
                of each class
            
            Name
                of each exchange on which registeredCommon
                stock, par value $0.01
            
            American
                Stock ExchangeSecurities
                registered under Section 12(g) of the Exchange Act:(Title
                of class)





Check
      whether the issuer is not required to file reports pursuant to Section 13 or
      15(d) of the Exchange Act. o




Check
      whether the issuer (1) filed all reports required to be filed by Section 13
      or
      15(d) of the Securities Exchange Act of 1934 during the past 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




Check
      if
      there is no disclosure of delinquent filers in response to Item 405 of
      Regulation S-B contained in this form, and no disclosure will 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-KSB or any
      amendment to this Form 10-KSB. o





Indicate
      by check mark whether the registrant is a shell company (as defined in Rule
      12b-2 of the Exchange Act).


Yes
o No x




State
      issuer’s revenues for its most recent fiscal year: $23,117,445.




The
      aggregate market value of the voting and non-voting common equity held by
      non-affiliates of the issuer as of March 2, 2007, was approximately
      $141,529,689. For purposes of this computation, all executive officers,
      directors and 10% stockholders were deemed affiliates. Such a determination
      should not be construed as an admission that such 10% stockholders are
      affiliates.




As
      of
      March 2, 2007, there were 101,577,790 shares of the common stock, par value
      $0.01 per share, of the issuer issued and outstanding.




Documents
      Incorporated by Reference: Pursuant to instruction E.3 to Form 10-KSB, Items
      9,
      10, 11, 12, and 14 are omitted because we will file a definitive proxy statement
      (the “Proxy Statement”) pursuant to Regulation 14A of the Securities Exchange
      Act of 1934 not later than 120 days after the close of the fiscal year. The
      information required by these items will be included in the Proxy Statement
      to
      be filed for our annual meeting of the shareholders to be held on or about
      May
      18, 2007, and is hereby incorporated by reference.




Transitional
      Small Business Disclosure Format: Yes o No x










**TABLE
      OF CONTENTS**


PART
                  I
              
              
              
              2ITEMS
                  1 AND 2.
              
              DESCRIPTION
                  OF BUSINESS AND PROPERTIES
              
              2ITEM
                  3.
              
              LEGAL
                  PROCEEDINGS
              
              25ITEM
                  4.
              
              SUBMISSION
                  OF MATTERS TO A VOTE OF SECURITY HOLDERS
              
              24PART
                  II
              
              
              
              25ITEM
                  5.
              
              MARKET
                  FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND SMALL BUSINESS
                  ISSUER
                  PURCHASES OF EQUITY SECURITIES
              
              25ITEM
                  6.
              
              MANAGEMENT’S
                  DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
                  OPERATIONS
              
              30ITEM
                  7.
              
              FINANCIAL
                  STATEMENTS
              
              40ITEM
                  8.
              
              CHANGES
                  IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
                  DISCLOSURE
              
              73ITEM
                  8A.
              
              CONTROLS
                  AND PROCEDURES
              
              73ITEM
                  8B.
              
              OTHER
                  INFORMATION
              
              73PART
                  III
              
              
              
              72ITEM
                  9.
              
              DIRECTORS,
                  EXECUTIVE OFFICERS, PROMOTERS, AND CONTROL PERSONS; COMPLIANCE
                  WITH
                  SECTION 16(a) OF THE EXCHANGE ACT
              
              74ITEM
                  10.
              
              EXECUTIVE
                  COMPENSATION
              
              74ITEM
                  11.
              
              SECURITY
                  OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
                  STOCKHOLDER MATTERS
              
              74ITEM
                  12.
              
              CERTAIN
                  RELATIONSHIPS AND RELATED TRANSACTIONS
              
              74ITEM
                  13.
              
              EXHIBITS
              
              74ITEM
                  14.
              
              PRINCIPAL
                  ACCOUNTANT FEES AND SERVICES
              
              75




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 below under 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.




1


**CERTAIN
      DEFINITIONS**





As
      used
      in this Annual 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 Annual
      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 Annual Report, unless
      otherwise noted, are reported on a “net” basis.





**PART
      I**




**ITEMS
      1 AND 2.**  **DESCRIPTION
      OF BUSINESS** **AND PROPERTIES**




**GENERAL**





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.





We
      commenced operations in 1969 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.





Our
      strategy is to maximize shareholder value by leveraging our significant acreage
      position and the experience of our management and technical teams in finding
      and
      developing natural gas reserves to profitably grow our reserves and production.
      Over the last several years we have focused primarily on the acquisition of
      properties in the Antrim and New Albany shale. As an early stage developer
      of
      properties, 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 and net potential drilling
      locations as of December 31, 2006:




**Play/Trend**
            
            **Location**
            
            **Gross
                Acres**
            
            **Net
                Acres**
            
            **Net
                Potential****Drilling
                Locations(a)**Antrim
            
            
            Michigan
            
            
            290,730
            
            
            154,643
            
            
            1,546New
                Albany
            
            
            Southern
                Indiana and Western Kentucky
            
            
            811,628
            
            
            441,351
            
            
            1,379Other
            
            
            Various
            
            
            114,422
            
            
            93,897
            
            
            587Total
            
            
            
            
            
            1,216,780
            
            
            689,891
            
            
            3,512




(a)  Net
      potential drilling locations are locations quantified by management based on
      well spacing criteria for a particular play/trend. For example, Antrim drilling
      locations are based upon 100-acre spacing per well, New Albany drilling
      locations are based upon 320-acre spacing per well, and Other drilling locations
      are based upon 160-acre spacing per well.




As
      of
      December 31, 2005, our net proved reserves were approximately 64 bcfe, of
      which 99% were natural gas reserves. As of December 31, 2006, our estimated
      net proved reserves had grown to 153 bcfe representing a 139% increase over
      our
      December 31, 2005 net proved reserves. The primary increase was
      attributable to our increased drilling activity of 66 bcfe and an acquisition
      of
      oil and natural gas properties with proven reserves of 23 bcfe completed in
      January 2006.




2


Unconventional
        shale plays tend to be characterized by high drilling success rates. For
        the
        12-month period ending December 31, 2006, we incurred $53.2 million to
        drill and complete 209 (112 net) wells, with a 94% drilling success rate.
        In addition, we incurred $51.3 million on property and leasehold
        acquisitions. Average net daily production increased from 609 mcfe/d in January
        2005 to 8,150 mcfe/d in December 2006. The table below highlights our portfolio
        of wells as of December 31, 2006.


**Play
                /Trend**
            
            **Gross
                Wells**
              **Producing**
            
            **Net
                Wells**
              **Producing**
            
            **Gross
                Wells Waiting**
              **Hook-Up**
            
            **Net
                Wells Waiting**
              **Hook-Up**Antrim
            
            
            413.00
            
            
            198.86
            
            
            82.00
            
            
            51.17New
                Albany
            
            
            14.00
            
            
            0.70
            
            
            20.00
            
            
            6.87Other
            
            
            28.00
            
            
            13.70
            
            
            3.00
            
            
            1.34Total
            
            
            455.00
            
            
            213.26
            
            
            105.00
            
            
            59.38





**Our
      Strategy**




The
      principal elements of our strategy to maximize shareholder value
      are:





***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 substantial majority of our future capital
      expenditures will be directed toward the drilling of wells, although we expect
      to continue to acquire additional leasehold interests. Initially, we anticipate
      reserve growth will be our primary focus with a more balanced reserve and
      production growth profile as we continue to execute our growth strategy.





***Focus
      on lower risk shale development projects, with selective expenditures outside
      our focus areas.*** Most
      of
      our acreage in the Antrim and New Albany shale contains lower risk
      unconventional natural gas development plays, including 595,994 net leasehold
      acres on which we have identified approximately 2,925 net potential drilling
      locations. In the Antrim shale play there have been over 8,000 successful gas
      wells drilled since the inception of the play. The New Albany shale play is
      an
      emerging play without the history of the Antrim shale play, but we believe
      it
      will have similar success characteristics to the Antrim shale play. We believe
      that by focusing our drilling budget on development oriented activities in
      our
      shale areas in the short run, we can maintain high drilling success rates
      yielding attractive rates of return. We anticipate committing a small portion
      of
      our drilling budget to locations outside of our shale project areas to
      continually evaluate and test new areas for exploration and development
      potential.





***Employ
      leading edge technologies to grow reserves and production and enhance returns.*** We
      employ
      several leading edge technologies in the drilling, completion and development
      of
      our natural gas reserves. For example, our employees have developed and
      implemented a low pressure natural gas production system to increase the
      estimated recoverable reserves and improve production rates of shale-oriented
      natural gas. We have installed several low pressure, small modular style
      compression facilities in our Antrim shale play. We believe this system has
      reduced development costs, increased production rates, extended the commercial
      life of existing wells and increased the total amount of reserves ultimately
      recoverable from each well bore when compared to the high pressure, large
      compression facilities that are typically used in the Antrim shale play. We
      believe this innovative system gives us a competitive advantage compared to
      other operators in the area.





***Manage
      costs by maximizing operational control.*** We
      seek
      to exert control over our exploration, exploitation and development activities.
      As the operator of our projects, we have greater control over the amount and
      timing of the expenditures associated with those activities. As we manage our
      growth, we are focused on reducing lease operating expenses, general and
      administrative costs and finding and development costs on a per mcfe basis.
      As
      of December 31, 2006, we operated 39% of our completed wells. We believe this
      percentage will continue to increase as we plan to operate approximately 44%
      of
      our wells drilled in 2007.





***Pursue
      complementary leasehold interest and property acquisitions.*** We
      intend
      to use our experience and regional expertise to supplement our drilling strategy
      with complementary leasehold interest and property acquisitions.




**Our
      Strengths**




We
      believe that our strengths will help us successfully execute our strategy.
      These
      strengths include:




***Inventory
      of growth opportunities.*** We
      have
      established an asset base of approximately 595,994 net leasehold acres in our
      shale areas, of which approximately 92% were undeveloped as of December 31,
      2006. As of that date, we had approximately 2,925 net potential drilling
      locations on this acreage. At our current planned drilling rate, this would
      accommodate approximately nine years of drilling activity.




3





***Experienced
      management and technical teams.*** Our
      four
      senior executive officers average 24 years of experience in the natural gas
      industry. In addition, we employ two senior geologists, one staff geologist,
      two
      senior oil and gas petroleum engineer, one drilling superintendent, one
      production supervisor and three senior land professionals with an average over
      25 years of oil and gas experience.





***Operational
      control*** **.** As
      of
      December 31, 2006, we operated approximately 39% of the wells in which we have
      an interest, and we expect our 56% average working interest in leases to allow
      us to increase the number of wells we will operate in the future. This will
      afford us a significant degree of control over costs and other operational
      matters.





***Financial
      flexibility.*** We
      seek
      to maintain a conservative financial position and believe that our operating
      cash flow and proceeds from our November 2006 equity offering combined with
      additional debt financing will provide us with the financial flexibility to
      pursue our planned exploration and development activities through
      2007.





**OPERATING
      AREAS**





***Antrim
      Shale***





Our
      Antrim shale properties are located in Michigan and represent our primary area
      of development over the next 12 months. Nearly all of our development operations
      in this play/trend are focused on unconventional shale plays. Shale development
      typically results in higher drilling success and lower drilling costs when
      compared to conventional exploration and development activity.





Antrim
      shale underlies the entire Michigan basin. The shale is very thick (140 to
      over
      200 feet) and has a high percentage of organic content (up to 20%). Due to
      the
      makeup of the natural fractures in the Antrim shale, production will vary from
      well to well.





The
      productive, fractured trend for the Antrim shale runs across the northern
      portion of the Michigan basin from Lake Huron to Lake Michigan (160 miles).
      Gas
      wells have been drilled and produced in the Antrim shale from depths of 250
      feet
      down to 1,500 feet below the surface. A high percentage of the wells drilled
      in
      the Antrim shale have been put into production and levels of production vary
      from well to well. Over 8,000 wells are currently producing in the Antrim shale.
      In recent years, 200 to 400 wells have been drilled annually by all operators
      in
      the Antrim shale.





The
      gas
      produced from the Antrim shale is primarily a biogenic gas due to the presence
      of microbes in the low to medium saline waters. The low-density pay zones in
      the
      Antrim shale are over 100 feet thick. Methane gas is continuously being
      generated by anaerobic bacteria that feed on C0 2 organic
      material, and the heavier oil and gases stored in the shale.





The
      Antrim shale gas adsorbs to organic material in a manner similar to gas in
      coal
      seams. Water in the natural fractures of the shale provides a trapping mechanism
      to hold the gas in place. As the water is produced, lowering the fluid and
      pressure in the reservoir, gases are released from the organic material and
      are
      produced to the surface. At depths of less than 1,500 feet, the gas-in-place
      is
      typically 90% methane or greater, with the balance being C0 2 and some
      heavier gases.





The
      oldest Antrim shale gas field was drilled in the 1940s, and it is still in
      production today. The production curve for the shale typically contains a peak
      rate of gas occurring after the first two years of production when the shale
      reservoir has been thoroughly dewatered. Peak rate production usually continues
      for some time. After the water is taken from the formation and the gas is able
      to fully release from the shale into the well bore, the rate of production
      will
      typically begin to decline 2% to 7% per year.





We
      have
      identified the Michigan Antrim shale as an area with natural fractures using
      a
      variety of diagnostic tests, including a review of production trends, fracture
      imaging logs and geological mapping. In management's opinion, based upon
      performance information from over 8,000 wells with comparable geologic
      characteristics, areas with natural fractures in shale have compelling
      production potential.




4





At
      December 31, 2006, we owned working interests in 495 Antrim wells. In 2006,
      we
      drilled 173 (98 net) Antrim wells and successfully completed 164 gross wells
      for
      a success rate of 95%. In 2005, we drilled and successfully completed or
      participated in a total of 143 (105 net) Antrim wells, including some horizontal
      wells. On average, our Antrim wells are drilled to depths ranging from 250
      to
      1,500 feet targeting reserves of 0.513 bcfe per well from our December 31,
      2006,
      Schlumberger reserve report.





***New
      Albany shale***





Our
      New
      Albany shale properties are located in Southern Indiana and Western Kentucky
      and
      represent a relatively new area of activity for us. Most of our exploratory
      and
      developmental operations in the Illinois geological basin are focused on
      unconventional shale plays. The New Albany shale play, much of which is located
      in Indiana, is an emerging play with similar characteristics to the Antrim
      shale
      play. It is also very thick (100 to over 200 feet) and covers approximately
      6,000,000 gross acres, with proven producing pay zones throughout. The shale
      is
      capped by the Borden shale, a very thick, dense, gray-green shale.





In
      the
      New Albany shale, a well commonly produces water along with the gas. In the
      early 1900's, it was learned that a simple open-hole completion in the very
      top
      of the shale would yield commercial gas wells that would last for many years,
      even while producing some water. Vertical fractures in the shale feed the gas
      flow at the top of the shale. The potential of these wells was seldom realized
      in the early to mid-twentieth century, as the production systems for handling
      the associated water were limited. However, with current technology, the water
      can be dealt with cost effectively and allow for better rates of gas
      production.





Significant
      research and study has been conducted to evaluate the producibility of the
      New
      Albany shale. In cooperation with the Gas Research Institute, we combined
      resources and data with 11 other industry partners in a shale gas producibility
      consortium lasting almost two years (concluded in 1999). The consortium
      identified critical differences and similarities of the New Albany shale play
      to
      other shale plays. The consortium study observed that the New Albany shale
      reservoir contained high-angled (vertical or nearly so) natural fractures that
      are open to unimpeded flow. The predominant fracture system is oriented
      east-west with spacing between joints estimated to average five feet based
      on
      outcrop studies and production simulations. Based on this information, it was
      concluded that increases in performance could be achieved with a horizontally
      drilled well compared to a vertically drilled well in the same reservoir.





Reserve
      studies were conducted on behalf of the consortium by Schlumberger Holditch
      & Associates for both vertical producing wells and horizontal wells. Since
      then, we have participated in approximately 30 pilot horizontal well drilling
      projects across multiple counties which support the conclusions of the
      consortium. With the data from these pilot wells, we have established a
      development concept for the New Albany shale, which we began to implement in
      2006.





Our
      New
      Albany shale projects are characterized by declining natural gas and water
      production with peak natural gas and water flow rates occurring in the first
      60
      days. Our New Albany shale wells are drilled to depths ranging from 500 to
      3,000
      feet and based on our December 31, 2006, Schlumberger reserve report could
      yield
      an average reserve of 1.2 bcfe per well. At December 31, 2006, we owned working
      interests in 34 (7.57 net) New Albany shale wells. In 2006, we drilled 26 (7.49
      net) New Albany shale wells and successfully completed 25 of these wells for
      a
      success rate of 96%. In 2005, we drilled and successfully completed or
      participated in a total of 3 (0.15 net) New Albany shale wells.





***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. Directional drilling with enhanced shale technology
      fracturing helps test New Albany exploration areas for development
      potential.





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 lower down-hole
      reservoir pressure enhancing dewatering and gas recovery.




5





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 extended rat-hole,
      which is used for gas-water separation. The wells are then hydraulically
      fractured with a specifically designed fracture procedures 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,
      no
      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.





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 dewatering process could be
      as
      much as two years, thereby delaying peak revenue production.





We
      use
      skid mounted compressors in a series 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 12-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, and by
      not
      building central processing facilities, but instead 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, 2006 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 46% of our proved reserves are
      classified as either proved developed non-producing or proved
      undeveloped.




6





**As
                of December 31, 2006****Oil
                and Natural Gas Reserves(a)**
            
            **Oil**
            
            **Gas**
            
            **Total**
            
            **PV-10(d)**
            
            **Standardized
                Measure(e)****(mbbls)**
            
            **(mmcf)**
            
            **(mmcfe)**
            
            **(In
                thousands)**
            
            **(In
                thousands)**Proved
                developed producing
            
            
            54
            
            
            82,580
            
            
            82,904
            
            $
            97,553
            
            $
            76,952Proved
                developed non-producing
            
            
            -
            
            
            22,693
            
            
            22,693
            
            
            28,428
            
            
            19,238Proved
                undeveloped
            
            
            27
            
            
            47,691
            
            
            47,853
            
            
            32,802
            
            
            34,272Total
                proved (b) (c)
            
            
            81
            
            
            152,964
            
            
            153,450
            
            $
            158,783
            
            $
            130,462




**Oil
                and Natural Gas Reserves by Play/Trend(a)**
            
            
            
            
            
            
            
            
            **Total**
            
            
            **Percent
                of Proved Reserves**
            
            
            **PV-10****(mmcfe)**
            
            
            
            
            
            **(In
                thousands**)****Antrim
            
            
            
            
            
            
            
            
            150,107
            
            
            98
            %
            $
            152,427New
                Albany
            
            
            
            
            
            
            
            
            2,298
            
            
            1
            %
            
            2,977Other
            
            
            
            
            
            
            
            
            1,045
            
            
            1
            %
            
            3,379Total
            
            
            
            
            
            
            
            
            153,450
            
            
            100
            %
            $
            158,783




**Change
                in reserve quantity information for the year ended December 31,
                2006(a)**
            
            
            
            
            
            
            
            
            **Oil**
            
            
            **Gas**
            
            
            **Total****(mbbls)**
            
            
            **(mmcf**)****
            
            
            **(mmcfe**)****Proved
                reserves as of December 31, 2005
            
            
            
            
            
            
            
            
            99
            
            
            63,322
            
            
            63,916Revisions
                of previous estimates
            
            
            
            
            
            
            
            
            (40
            )
            
            4,880
            
            
            4,640Purchases
                of minerals in place
            
            
            
            
            
            
            
            
            -
            
            
            22,843
            
            
            22,843Extensions
                and discoveries
            
            
            
            
            
            
            
            
            45
            
            
            65,095
            
            
            65,365Production
            
            
            
            
            
            
            
            
            (23
            )
            
            (2,511
            )
            
            (2,649
            )Sales
                of minerals in place
            
            
            
            
            
            
            
            
            -
            
            
            (665
            )
            
            (665
            )Proved
                reserves as of December 31, 2006
            
            
            
            
            
            
            
            
            81
            
            
            152,964
            
            
            153,450





(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
                following financial hedges: (i) 5,000 mmbtu/day at a price of $8.59/mmbtu
                through March 2007 and (ii) 5,000 mmbtu/day at a price of $9.00/mmbtu
                from
                April 2007 through December 2008.





(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 proven 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, 2006. The estimated future production is priced at December 31,
                2006,
                without escalation, using $57.81 per bbl and $5.84 per mmbtu, in
                each case
                adjusted by lease 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:





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




7




(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 $7,766,102 to
                $138,227,923.





Management
      uses 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, 2006, 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)**
            
            **Total****Play/Trend**
            
            **Gross**
            
            **Net**
            
            **Gross**
            
            **Net**
            
            **Gross**
            
            **Net**Antrim
            
            
            112,835
            
            
            42,970
            
            
            177,895
            
            
            111,673
            
            
            290,730
            
            
            154,643New
                Albany
            
            
            103,632
            
            
            5,181
            
            
            707,996
            
            
            436,170
            
            
            811,628
            
            
            441,351Other
            
            
            841
            
            
            842
            
            
            113,581
            
            
            93,055
            
            
            114,422
            
            
            93,897Total
            
            
            217,308
            
            
            48,993
            
            
            999,472
            
            
            640,898
            
            
            1,216,780
            
            
            689,891





(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 summarize sales volumes, sales prices, and production cost
      information for the periods indicated:





**Year
                Ended December 31****Production**
            
            **2006**
            
            **2005**Oil
                (bbls)
            
            
            22,588
            
            
            10,628Natural
                gas (mcf)
            
            
            2,517,897
            
            
            687,271Natural
                gas equivalent (mcfe)
            
            
            2,653,427
            
            
            751,039**Oil
                and natural gas sales**Oil
                sales
            
            $
            1,399,445
            
            $
            558,455Natural
                gas sales
            
            
            20,192,366
            
            
            6,184,989Total
            
            $
            21,591,811
            
            $
            6,743,444**Average
                sales price (including realized gains or losses from
                hedging)**Oil
                ($ per bbl)
            
            $
            61.95
            
            $
            52.54Natural
                gas ($ per mcf)
            
            
            8.02
            
            
            9.00Natural
                gas equivalent ($ per mcfe)
            
            
            8.14
            
            
            8.98**Average
                production expenses ($ per mcfe)**Production
                taxes
            
            $
            0.33
            
            $
            0.67Post-production
                expenses
            
            
            0.55
            
            
            0.50Leasing
                operating expenses
            
            
            1.82
            
            
            1.62Total
            
            $
            2.70
            
            $
            2.79





***Productive
      wells***





The
      following table sets forth as of December 31, 2006, 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**
            
            **Oil****Play/Trend**
            
            **Gross
                Wells**
            
            **Net
                Wells**
            
            **Gross
                Wells**
            
            **Net
                Wells**Antrim
            
            
            495
            
            
            250.03
            
            
            -
            
            
            -New
                Albany
            
            
            34
            
            
            7.57
            
            
            -
            
            
            -Other
            
            
            3
            
            
            1.24
            
            
            28
            
            
            13.80Total
            
            
            532
            
            
            258.84
            
            
            28
            
            
            13.80





***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
                Wells****Type
                of Well**
            
            **Productive****(b)**
            
            **Dry****(c)**
            
            **Total**
            
            **Productive****(b)**
            
            **Dry****(c)**
            
            **Total**Year
                Ended 12/31/06Exploratory(a)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)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)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)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.





***Sale
      of production***





We
      use
      different strategies for gas sales depending on the location of the field and
      the local markets. In some locations, we may use proprietary C0 2 reduction units to process our own gas and sell it to nearby local markets.
      In
      other cases, we connect to nearby high pressure transmission pipelines. We
      are
      not currently aware of any restraints with respect to pipeline availability
      other than curtailments in existing pipelines that may occur from time to time
      due to technical difficulties. However, because of the nature of natural gas
      development, there may be periods of time when pipeline capacity is inadequate
      to meet our transportation needs. It is often the case that as new development
      comes on-line, pipelines are near or at capacity before new pipelines are built.





We
      entered into a firm delivery gas contract to be effective for the period April
      1, 2006 through March 31, 2007 for the delivery of 5,000 mmbtu per day. Under
      this contract, we are paid $0.01 per mmbtu less than the published index for
      this gas. The contract covers much of our existing production operated by us.





We
      also
      have five other base contracts for the sale of natural gas. We set our firm
      delivery volume obligation under these contracts on a monthly basis, with the
      amount of our obligation varying from month to month. As we bring new wells
      on-line and our production volume increases, we will sell the new production
      in
      the spot markets or under the monthly base contracts. We expect that we will
      usually sell in this fashion, partly through firm gas delivery contracts and
      partly in the spot markets.




10





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***




In
      order
      to reduce exposure to fluctuations in the price of natural gas, we will
      periodically enter into financial arrangements with a major financial
      institution. We have entered into a swap transaction in order to hedge a portion
      of our production. The purpose of the swap is to provide a measure of stability
      to our cash flow in meeting financial obligations while operating in a volatile
      gas market environment. The swap reduces our exposure on the hedged volumes
      to
      decreases in commodity prices and limits the benefit we might otherwise receive
      from any increases in commodity prices on the hedged volumes.




Effective
      April 1, 2006, we entered into a financial swap contract for 5,000 mmbtu per
      day
      at a fixed price of $8.59 per mmbtu covering a 12-month period. On July 14,
      2006, we entered into another financial swap contract for 5,000 mmbtu per day
      at
      a fixed price of $9.00 per mmbtu for the period from April 1, 2007 through
      December 31, 2008. On January 29, 2007, we entered into a costless collar
      contract for 2,000 mmbtu per day with a ceiling price of $9.00 per mmbtu and
      a
      floor price of $7.55 per mmbtu for the period from April 1, 2007 through
      December 31, 2008.




***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 a number of properties, although
      we do not presently consider them to be material to our business.




***Employees***




As
      of
      December 31, 2006, we had 88 full-time employees and 2 part-time employees.
      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
            
            62
            
            Director,
                Chairman and PresidentRonald
                E. Huff
            
            51
            
            Director
                and Chief Financial OfficerJohn
                V. Miller, Jr.
            
            48
            
            Vice
                President, Business and Corporate DevelopmentThomas
                W. Tucker
            
            64
            
            Vice
                President, Exploration





***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 continues to hold. William W. Deneau is the brother of Richard
      M.
      Deneau, another one of our Directors.





***Ronald
      E. Huff*** has
      served as our Chief Financial Officer since June 19, 2006 and as a Director
      since November 21, 2005. From December 5, 2005 through June 18, 2006, Mr. Huff
      served as Chairperson of our Audit Committee. He resigned from the Audit
      Committee on June 18, 2006. From 2004 until he became our Chief Financial
      Officer, Mr. Huff served as the Chief Financial Officer and Vice President
      of
      Finance for Visual Edge Technology, Inc., a California holding company engaged
      in acquiring imaging companies. From 1999 to 2004, Mr. Huff was a Principal
      and
      Founder of TriMillennium Ventures, LLC, a private equity investment company.
      From 1986 to 1999, Mr. Huff was an executive at Belden & Blake Corporation
      serving as Chief Financial Officer and President of this large Appalachian
      and
      Michigan Basin exploration and production company.




11





***John
      V. Miller*** has
      served as a Vice President since November 1, 2005, holding positions variously
      titled as Vice President of Exploration and Production, Vice President of
      Science and Strategic Planning, and Vice President of Business and Corporate
      Development. Mr. Miller 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. From April 1997 to the present, he has been the
      Vice President responsible for overseeing exploration and development activities
      for Aurora. From June 1997 through October 2005 he served as a Director of
      Aurora.





***Thomas
      W. Tucker*** ** has
      served as a Vice President since November 1, 2005, holding positions variously
      titled as Vice President of Land Development, Vice President of Operations,
      and
      Vice President of Exploration. Mr. Tucker 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. From April 1997 to the present,
      he has been the Vice President responsible for overseeing land development
      activities for Aurora. From June 1997 to October 2005 he served as a Director
      of
      Aurora.




***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.




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 may
      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.




12




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.




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.




13




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 is
      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.




***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 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 Annual 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. Information contained on our website does
      not constitute a part of this Annual Report.




14


**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, during 2006, 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.




***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, in addition to the proceeds from this offering and the cash generated
      from our operations, 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.





***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 is located in the more untested New Albany shale
      play/trend.





15




***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, 2006, we had approximately 3,512 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, 2006, and 2005. There
      is no assurance that we will be able to achieve and maintain
      profitability.





***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, 2006,
      we
      operated 39% of our 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, 2006, we
      had
      acquired approximately 1,216,780 (689,891 net) acres with 153,450 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. For example, in 2006 we closed on
      the
      acquisition of all of the assets of Bach Enterprises, Inc. (or "Bach") and
      certain of its affiliates. Bach is an oil and natural gas services company
      whose
      services include building compressors, CO 2 removal,
      pipelining and facility construction. Although the Bach acquisition will be
      operated separately from our current production operations, we have no prior
      experience in the management of such a service company, and may encounter issues
      that prevent us from successfully integrating it as part of our
      business.


16





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





Our
      current management team has substantial experience in the oil and natural gas
      business. We only have an employment agreement with one member 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, 2006, approximately 54% are
      classified as proved developed producing, 15% are classified as proved developed
      non-producing, and 31% are classified as proved undeveloped.





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.





***The
      oil and natural gas reserve data included in this document 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;




17




·
            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;





·
            The
                reserve report for our Michigan Antrim 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 two year period ending
      December 31, 2006, 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
      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 is completed and permits are issued. The DEQ has also recently 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. Recently, our Chandler
      project was released from this DEQ salt water disposal well study. Our Chandler
      project represents approximately 5,900 net acres and 20 potential drilling
      locations.




18





Adverse
      weather may foreclose 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.





***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, production was hampered by curtailments in a
      third-party processing facility; we recently completed construction of our
      own
      processing facility and built an alternative 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.





***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.




19





***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.





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.





***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, 2006, our outstanding debt includes a senior credit facility with
      a
      current approved borrowing base of $50 million, $10 million of which is
      currently drawn, a mezzanine financing facility with a current approved
      borrowing base of $50 million, of which $40 million is currently
      drawn, and a $5 million revolving line of credit, of which $0.4 million is
      currently drawn. Our mezzanine credit facility limits the amount of earnings
      from production that are available to us with regard to the properties pledged
      as collateral on the loan. 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 or pledging more assets as collateral, and we will be
      unable to draw more funds to use in development.





The
      value
      of the assets pledged as collateral under our senior credit facility and
      mezzanine financing facility will depend on the then current commodity prices
      for natural gas. If prices drop significantly, we may have trouble satisfying
      the ratio covenants of these credit facilities. As noted above, oil and natural
      gas prices are volatile. The value of the stock pledged to support the guaranty
      of our revolving line of credit is tied to the price at which our stock is
      trading. We will be unable to control this variable.




20





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 plan
      as described in this Prospectus.




***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.





***We
      will be subject to the requirements of Section 404 of the Sarbanes-Oxley
      Act.***  ***If
      we are unable to timely comply with Section 404 or if the costs related
      to***  ***compliance
      are significant, our profitability, stock price and results of
      operations***  ***and
      financial condition could be materially adversely
      affected.***





We
      will
      be required to comply with the provisions of Section 404 of the
      Sarbanes-Oxley Act of 2002 as of December 31, 2007. Section 404
      requires that we document and test our internal controls over financial
      reporting and issue management’s assessment of our internal controls over
      financial reporting. This section also requires that our independent registered
      public accounting firm opine on those internal controls and management’s
      assessment of those controls. We will be required to evaluate our existing
      controls against the criteria established in "Internal Control — Integrated
      Framework" issued by the Committee of Sponsoring Organizations of the Treadway
      Commission, or COSO. During the course of our ongoing evaluation and integration
      of the internal control over financial reporting, we may identify areas
      requiring improvement, and we may have to design enhanced processes and controls
      to address issues identified through this review.





We
      believe that the out-of-pocket costs, the diversion of management’s attention
      from running the day-to-day operations and operational changes caused by the
      need to comply with the requirements of Section 404 of the Sarbanes-Oxley
      Act could be significant. If the time and costs associated with such compliance
      significantly exceed our current expectations, our results of operations could
      be materially affected.





We
      cannot
      be certain at this time that we will be able to successfully complete the
      procedures, certification and attestation requirements of Section 404 or
      that we or our auditors will not identify material weaknesses in internal
      control over financial reporting. If we fail to comply with the requirements
      of
      Section 404 or if we or our auditors identify and report such material
      weakness, the accuracy and timeliness of the filing of our annual and quarterly
      reports may be materially adversely affected and could cause investors to lose
      confidence in our reported financial information, which could have a negative
      effect on the trading price of our common stock. In addition, a material
      weakness in the effectiveness of our internal controls over financial reporting
      could result in an increased chance of fraud and the loss of customers, reduce
      our ability to obtain financing and require additional expenditures to comply
      with these requirements, each of which could have a material adverse effect
      on
      our business, results of operations and financial condition.




21





***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.***





During
      2006, our stock traded as high as $7.44 per share and as low as $2.60 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 in 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.





***A
      small number of existing shareholders control us 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. 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% of our outstanding shares, are subject to these voting
      agreements.




22





Also
      in
      connection with the closing of the merger, certain of our shareholders executed
      and delivered irrevocable proxies naming William W. Deneau and Lorraine King
      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, 2006. These provisions will limit 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, 2006, we had 101,412,966 shares of common stock
      outstanding.





At
      December 31, 2006, we had warrants and options outstanding that were exercisable
      for 6,942,276 shares of our common stock. We have an additional 5,532,000 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 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, 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.





***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
      three shelf registration statements that are currently effective, which together
      have registered almost 40 million shares of common stock for resale. 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, 2006,
      we
      had approximately 101.4 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,
      0.7 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"). On May 15, 2006, we filed an
      S-8
      registration statement with the Commission providing for the registration of
      9,589,496  shares of our common stock issued or reserved for issuance under
      our employee plans. Within that filing, we registered 659,996 shares owned
      or
      controlled by our executive officers and directors for resale. On December
      22,
      2006, we filed another S-8 registration statement with the Commission providing
      for the registration of an additional 420,000 shares of our common stock issued
      or reserved for issuance under our employee plans, including the registration
      for resale of 20,000 shares owned by one of our directors.




23





**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, 2006.




24


**PART
      II**




**ITEM
      5.**  **MARKET
      FOR COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND SMALL BUSINESS 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 last two calendar 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, 2005
            
            $
            2.95
            
            $
            1.05June
                30, 2005
            
            $
            2.67
            
            $
            2.00September
                30, 2005
            
            $
            3.47
            
            $
            1.86December
                31, 2005
            
            $
            4.85
            
            $
            3.15March
                31, 2006
            
            $
            7.44
            
            $
            4.45June
                30, 2006
            
            $
            6.10
            
            $
            3.76September
                30, 2006
            
            $
            4.74
            
            $
            2.94December
                31, 2006
            
            $
            3.22
            
            $
            3.08





On
      December 29, 2006, the last trading day of the year, the last reported per
      share
      sale price of our common stock on AMEX was $3.21, there were 101,412,966 shares
      of our common stock outstanding, and we had 578 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 our borrowing subsidiaries from
      declaring dividends, which means that we will generally not have cash flow
      available from which to pay cash 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 currently intend to make any further awards
      under this plan, the plan continues to exist and we may decide to use it in
      the
      future.




25





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.





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, 2006 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 plans approved by security holders
            
            
            3,432,496
            
            $
            2.89
            
            
            5,532,000Equity
                compensation plans and awards not approved by security
                holders
            
            
            86,280
            (a)
            $
            1.69
            
            
            -0-Total/combined
            
            
            3,518,776
            
            $
            2.86
            
            
            5,532,000





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




Warrants
                and options 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**





During
      the period from October 1, 2006 through December 31, 2006, we sold securities
      that were not registered under the Securities Act in two separate transactions
      as follows:





On
      October 6, 2006, we issued 1,378,299 shares of unregistered common stock to
      Richard Bach and Robin Bach as partial consideration for our purchase of all
      of
      the assets of Bach Enterprises, Inc. and certain assets of Bach Energy, LLC.
      The
      number of shares issued were based on a purchase value of $4,700,000 divided
      by
      $3.41 per share, which was the average of the closing price for the Company’s
      common stock for the 30-day calendar period immediately preceding October 6,
      2006, the closing date for the acquisitions of assets. We paid an additional
      $200,000 in cash for these assets.





On
      December 29, 2006, one of our directors, Kevin D. Stulp exercised a warrant
      that
      was issued to him on March 1, 2002, to purchase 100,000 shares of our common
      stock at an exercise price of $0.75 per share for a total exercise price of
      $75,000.




26





The
      shares issued in both of the foregoing transactions were issued in reliance
      on
      the exemption from registration provided by Section 4(2) of the Securities
      Act
      of 1933, as amended. All of the investors are accredited investors as that
      term
      is defined in Section 501 of Regulation D. There were no commissions paid
      on these transactions.





We
      did
      not repurchase any of our outstanding equity securities during the quarter
      ended
      December 31, 2006. We did, however, agree to the rescission of three
      previously exercised options, and return the exercise price. In January 2006,
      three of our executive officers, William W. Deneau, John V. Miller, Jr., and
      Thomas W. Tucker, each exercised an option to purchase 600,000 shares of our
      common stock at an exercise price of $0.415 per share for a total exercise
      price
      of $249,000. In December 2006, these option exercises were rescinded, and we
      returned the $249,000 exercise price to each of Mr. Deneau, Mr. Miller and
      Mr.
      Tucker.




27


**SELECTED
      HISTORICAL FINANCIAL DATA**




The
      following table sets forth our December 31, 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, 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 document.
      The
      following information is not necessarily indicative of our future
      results.





**2006**
            
            **2005**(a)**Statement
                of Operating Data**Revenues:Oil
                and natural gas sales
            
            $
            21,591,811
            
            $
            6,743,444Pipeline
                transportation and marketing
            
            
            1,179,431
            
            
            -Field
                service and sales
            
            
            125,611
            
            
            -Interest
                and other
            
            
            220,592
            
            
            666,850Total
                revenues
            
            
            23,117,445
            
            
            7,410,294Expenses:Production
                taxes
            
            
            877,319
            
            
            506,635Production
                and lease operating expense
            
            
            6,278,131
            
            
            1,587,205Pipeline
                operating expense
            
            
            643,963
            
            
            -Field
                services expense
            
            
            90,913
            
            
            -General
                and administrative expense
            
            
            7,531,718
            
            
            3,435,507Oil
                and natural gas depletion and amortization
            
            
            2,681,290
            
            
            767,511Other
                assets depreciation and amortization
            
            
            2,083,191
            
            
            308,647Interest
                expense
            
            
            4,573,785
            
            
            1,307,370Taxes,
                other
            
            
            250,884
            
            
            29,651Total
                expenses
            
            
            25,011,194
            
            
            7,942,526Loss
                before minority interest
            
            
            (1,893,749
            )
            
            (532,232
            )Minority
                interest in (income) loss of subsidiaries
            
            
            (50,898
            )
            
            15,960Net
                loss
            
            $
            (1,944,647
            )
            $
            (516,272
            )Net
                loss per common share-basic and diluted
            
            $
            (0.02
            )
            $
            (0.01
            )Weighted
                average common shares outstanding - basic and diluted
            
            
            82,288,243
            
            
            40,622,000**Cash
                Flow Data**Cash
                provided by (used in) operating activities
            
            $
            2,244,535
            
            $
            (2,392,118
            )Cash
                used by investing activities
            
            
            (86,317,737
            )
            
            (39,881,947
            )Cash
                provided by financing activities
            
            
            73,827,960
            
            
            49,075,121




28


**As
                  of December 31,****2006**
              
              **2005(a)****Balance
                  Sheet Data**Cash
                  and cash equivalents
              
              $
              1,735,396
              
              $
              11,980,638Other
                  current assets
              
              
              12,728,588
              
              
              7,274,869Oil
                  and natural gas properties, net (using full cost
                  accounting)
              
              
              161,294,155
              
              
              68,960,754Other
                  property and equipment, net
              
              
              9,221,228
              
              
              3,610,138Other
                  assets
              
              
              27,407,825
              
              
              24,995,746Total
                  assets
              
              $
              212,387,192
              
              $
              116,822,145Current
                  liabilities
              
              $
              18,117,955
              
              $
              17,341,431Long-term
                  debt, net of current maturities
              
              
              54,538,138
              
              
              42,794,862Redeemable
                  convertible preferred stock
              
              
              -
              
              
              59,925Shareholders’
                  equity
              
              
              139,731,099
              
              
              56,625,927Total
                  liabilities and shareholders’ equity
              
              $
              212,387,192
              
              $
              116,822,145




(a) 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. 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
      (now known as Aurora Oil & Gas Corporation) 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 years ended
      December 31, 2006, and 2005, and related notes have been retroactively adjusted
      to give effect to the reverse merger on October 31, 2005.




29


**ITEM
      6.**  **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 document. 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 document.*




**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.





We
      commenced operations in 1969 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.





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.




**Highlights**





For
      the
      year ended December 31, 2006, we continued to execute our strategy of focusing
      on lower risk shale development projects. As of December 31, 2006, our leasehold
      acres (both developed and undeveloped) were 1,216,780 (689,891 net) which
      represent a 89% increase over our December 31, 2005 net acres. Of the 401,316
      (325,801 net) leasehold acres acquired in 2006, 78,480 net acres were in the
      Antrim shale play and 169,460 net acres were in the New Albany shale play with
      the balance in Other areas.




With
      regard to our strategy to generate growth through drilling, we drilled or
      participated in 209 (112 net) wells for the year ended December 31, 2006. As
      of
      December 31, 2006, we had 455 (213 net) producing wells and 105 (59 net) wells
      awaiting hook-up. We also continued our strategy to have greater control over
      our projects by operating 220 (204 net) wells, thus, operating 39% of our gross
      wells. We also supplemented our drilling strategy with the Hudson properties
      acquisition. This acquisition increased our proved reserves by approximately
      23
      bcfe in the Antrim shale play.





We
      began
      2006 with estimated proved reserves of 64 bcfe and at December 31, 2006 had
      153
      bcfe, an increase of 89 bcfe, or 139%. Of the 153 bcfe in estimated proved
      reserves, 150 bcfe was from the Antrim shale play, and two bcfe was from the
      New
      Albany shale play with the balance in Other areas.


30





Oil
      and
      natural gas production for 2006 was 2,653,427 mcfe, or 253% over the 751,039
      mcfe produced in 2005. During 2006, production was hampered by curtailments
      on a
      third-party processing facility and delays bringing wells into production.
      The
      Company recently completed construction of our own processing facility and
      built
      an alternative pipeline route in response to the curtailment. Our average daily
      production for December 2006 was 8,150 mcfe per day.





In
      order
      to reduce exposure to fluctuations in the price of natural gas, we will
      periodically enter into financial arrangements with a major financial
      institution. We have entered into a financial swap contract for 5,000 mmbtu
      per
      day at a fixed price of $8.59 per mmbtu covering the period of April 2006
      through March 2007 and another financial swap contract on July 14, 2006 for
      5,000 mmbtu per day at a fixed price of $9.00 per mmbtu for the period from
      April 2007 through December 2008. On January 29, 2007, we entered into a
      costless collar contract for 2,000 mmbtu per day with a ceiling price of $9.00
      per mmbtu and a floor price of $7.55 per mmbtu for the period from April 1,
      2007, through December 31, 2008.





To
      further our growth, we entered into a senior secured credit facility on January
      31, 2006 with an initial borrowing base of $40 million. As proved reserves
      are
      added, the borrowing base may increase to $50 million without consent under
      our
      mezzanine financing arrangement and $100 million with consent under the
      mezzanine financing arrangement. Effective July 14, 2006, the borrowing
      base was increased to $50 million.





From
      late
      December 2005 through early February 2006, we reduced the exercise price of
      certain outstanding options and warrants in order to encourage the early
      exercise of these securities. 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 warrants or options. 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.





We
      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 we received net
      proceeds of approximately $10.2 million.





31


**RESULTS
      OF OPERATIONS**


**Operating
      Statistics**




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




**Increase
                (Decrease)****2006**
            
            **2005**
            
            **Amount**
            
            **Percent**Total
                net acreage heldAntrim
                shale
            
            
            154,643
            
            
            78,163
            
            
            76,480
            
            
            98
            %New
                Albany shale
            
            
            441,351
            
            
            271,891
            
            
            169,460
            
            
            62
            %Other
            
            
            93,897
            
            
            14,036
            
            
            79,861
            
            
            569
            %Total
            
            
            689,891
            
            
            364,090
            
            
            325,801
            
            
            90
            %Net
                wells drilledAntrim
                shale
            
            
            93
            
            
            105
            
            
            (12
            )
            
            (11
            %)New
                Albany shale (“NAS”)
            
            
            7
            
            
            -
            
            
            7
            
            
            100
            %Other
            
            
            5
            
            
            1
            
            
            4
            
            
            400
            %Dry
            
            
            7
            
            
            7
            
            
            -
            
            
            -Total
            
            
            112
            
            
            113
            
            
            (1
            )
            
            (1
            %)Total
                net wellsAntrim
                - producing
            
            
            199
            
            
            110
            
            
            89
            
            
            81
            %Antrim
                - awaiting hookup
            
            
            51
            
            
            52
            
            
            (1
            )
            
            (2
            %)NAS
                - producing
            
            
            1
            
            
            -
            
            
            1
            
            
            100
            %NAS
                - awaiting hookup
            
            
            7
            
            
            2
            
            
            5
            
            
            250
            %Other
                - producing
            
            
            14
            
            
            13
            
            
            1
            
            
            8
            %Other
                -awaiting hookup
            
            
            1
            
            
            6
            
            
            (5
            )
            
            (83
            %)Total
            
            
            273
            
            
            183
            
            
            90
            
            
            49
            %ProductionNatural
                gas (mcf)
            
            
            2,517,897
            
            
            687,271
            
            
            1,830,626
            
            
            266
            %Crude
                oil (bbls)
            
            
            22,588
            
            
            10,628
            
            
            11,960
            
            
            113
            %Natural
                gas equivalent
            
            
            2,653,427
            
            
            751,039
            
            
            1,902,388
            
            
            253
            %Average
                daily productionNatural
                gas (mcf)
            
            
            6,898
            
            
            1,883
            
            
            5,015
            
            
            266
            %Crude
                oil (bbls)
            
            
            62
            
            
            29
            
            
            33
            
            
            113
            %Natural
                gas equivalent
            
            
            7,270
            
            
            2,057
            
            
            5,213
            
            
            253
            %Average
                sales pricesNatural
                gas (mcf)
            
            $
            8.02
            
            $
            9.00
            
            $
            (0.98
            )
            
            (11
            %)Crude
                oil (bbl)
            
            $
            61.95
            
            $
            52.54
            
            $
            9.41
            
            
            18
            %Natural
                gas equivalent
            
            $
            8.14
            
            $
            8.98
            
            $
            (0.84
            )
            
            (9
            %)Production
                revenueNatural
                gas
            
            $
            20,192,366
            
            $
            6,184,989
            
            $
            14,007,377
            
            
            226
            %Crude
                oil
            
            
            1,399,445
            
            
            558,455
            
            
            840,990
            
            
            151
            %Total
            
            $
            21,591,811
            
            $
            6,743,444
            
            $
            14,848,367
            
            
            220
            %Production
                expense
            
            $
            7,155,450
            
            $
            2,093,840
            
            $
            5,061,610
            
            
            242
            %Average
                production expenses ($ per mcfe)Production
                taxes
            
            $
            0.33
            
            $
            0.67
            
            $
            (0.34
            )
            
            (51
            %)Post-production
                expenses
            
            
            0.55
            
            
            0.50
            
            
            0.05
            
            
            10
            %Leasing
                operating expenses
            
            
            1.82
            
            
            1.62
            
            
            0.20
            
            
            12
            %$
            2.70
            
            $
            2.79
            
            $
            0.09
            
            
            (3
            %)Number
                of employees
            
            
            90
            
            
            36
            
            
            54
            
            
            150
            %




32




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





**General** .
      For the
      year ended December 31, 2006, the Company had a net loss of $1.9 million, or
      $(0.02) per diluted common share, on total revenues of $23.1 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
      $15.7
      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. The Company 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 213 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, 2005****Play/Trend**
              
              **(mcfe)**
              
              **Amount**
              
              **(mcfe)**
              
              **Amount**Antrim
              
              
              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 $0.9 million, or 129% to $1.5 million in 2006 from $0.7
      million in 2005. This increase is attributed to two acquisitions 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 $6.3 million in 2006 compared to $1.6 million
      in 2005. On a unit of production basis, production and lease operating expenses
      were $2.37 per mcfe in 2006 compared to $2.11 per mcfe in 2005. The increase
      in
      2006 was primarily attributable to higher energy costs, higher pumping costs,
      repair and maintenance associated with compressors and pumps, and road and
      location maintenance. On a component basis, post-production expenses were $1.5
      million, or $0.55 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 $1.82 per mcfe in 2006
      compared to $1.2 million, or $1.62 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.





**Pipeline
      Operating Expense and Field Services Expenses** .
      Pipeline operating expenses were $0.6 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.


33





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.





The
      Company follows 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.





**LIQUIDITY
      AND CAPITAL RESOURCES**





We
      expect
      to fund our growth strategy using a combination of debt, existing cash balances,
      internally generated cash flows from natural gas production, and the proceeds
      from the 2006 equity offering. Our 2007 capital budget for drilling and related
      well work and infrastructure is estimated to be approximately $105.6 million
      with an anticipated participation in 410 (228 net) wells. Our 2007 capital
      budget for leasehold interest and property acquisitions is estimated to be
      approximately $9 million and $1.0 million, respectively. We believe that the
      proceeds of the 2006 equity offering, our available credit facilities and our
      operating cash flow will be sufficient to fund our operations and capital
      expenditures for the next 12 months. However, future cash flows are subject
      to a
      number of variables, including the level of production and prices. 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.





Our
      mezzanine financing is a $50 million credit facility with Trust Company of
      the
      West (“TCW”) for the Michigan Antrim shale drilling program. It has a maturity
      date of September 30, 2009. Borrowings under the TCW credit facility as of
      December 31, 2006 were $40 million with available borrowing capacity of $10
      million. The interest rate is fixed at 11.5% per year, calculated and payable
      in
      arrears. Beginning September 28, 2006 and quarterly thereafter, the required
      principal payment is 75% (100% if coverage deficiency or default occurs) of
      Adjusted Net Cash Flow determined by deducting applicable operating expenses
      and
      capital expenditures from gross revenue. The TCW borrowing base is subject
      to
      semi-annual re-determination and certain other re-determinations based upon
      several factors. The borrowing base is impacted by, among other factors, the
      fair value of our natural gas reserves that are pledged to TCW. Changes in
      the
      fair value of our oil and natural gas reserves are caused by changes in prices
      for natural gas and crude oil, operating expenses and the results of drilling
      activity. A significant decline in the fair value of these reserves could cause
      us to be unable to meet certain facility covenants, which could result in a
      reduction in our borrowing base. The TCW loan agreement prohibits the
      declaration or payment of dividends and contains certain covenants. As of
      December 31, 2006, we were in compliance with all of the applicable
      covenants.


34





Our
      senior secured credit facility is a $100 million senior secured credit facility
      with BNP Paribas (“BNP”). The initial borrowing base under this facility was $40
      million. As proved reserves are added, this borrowing base may increase to
      $50
      million without TCW consent, and $100 million with TCW consent. This facility
      matures the earlier of January 31, 2010 or 91 days prior to the maturity of
      the
      mezzanine credit facility. This facility provides for borrowings tied to prime
      rate or LIBOR plus 1.25 to 2.0% depending on the borrowing base utilization
      that
      we select. As of December 31, 2006, interest on borrowings under our senior
      credit facility had a weighted average interest rate of 6.625%. A required
      semi-annual reserve report may result in an increase or decrease in credit
      availability.





On
      July
      14, 2006, the senior secured credit facility was amended in the following
      manner: 1) the credit availability was increased to $50 million, and 2) the
      trailing 12-month interest coverage ratio covenant was amended to defer this
      requirement until the fourth quarter of 2006, and to provide for a reduced
      ratio
      for that quarter. On September 22, 2006, the Company agreed that BNP could
      establish a syndication thereby allowing various financial institutions to
      participate under the senior secured credit facility. In addition, effective
      December 21, 2006, the senior secured credit facility was amended to eliminate
      the interest coverage ratio covenant for the fiscal quarter ending December
      31,
      2006, and to modify the 2007 fiscal quarters’ interest coverage ratio covenants.
      At December 31, 2006, our total borrowings under this facility were $10
      million.





The
      senior secured credit facility contains, among other things, certain covenants
      relating to restricted payments, loans or advances to others, additional
      indebtedness, and incurrence of liens. It also provides for the maintenance
      of
      certain financial and operating ratios, including current ratio and specified
      coverage ratios (collateral coverage and proved developed producing reserves
      coverage ratios). As of December 31, 2006, we were in compliance with all of
      the
      applicable covenants.





Our
      short-term line of credit is a $5 million revolving line of credit with
      Northwestern Bank for general corporate purposes. At December 31, 2006, our
      total borrowings under this facility were $0.4 million with available borrowing
      capacity of $4.6 million. The interest rate is the prime rate with interest
      payable monthly in arrears. Principal is payable at the expiration of the line
      of credit, October 15, 2007.





From
      late
      December 2005 through early February 2006, we 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. 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.





We
      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
      we
      received net proceeds of approximately $10.2 million. We expect to use the
      net
      proceeds primarily to fund exploration and development activities.




35





Our
      total
      capitalization was as follows:





**As
                of December 31****2006**
            
            **2005**Short-term
                bank borrowings
            
            $
            542,788
            
            $
            6,210,000Obligations
                under capital lease
            
            
            17,096
            
            
            11,085Notes
                payable
            
            
            280,321
            
            
            69,833Mortgage
                payable
            
            
            3,175,298
            
            
            2,865,477Mezzanine
                financing
            
            
            40,000,000
            
            
            40,000,000Senior
                secured credit facility
            
            
            10,000,000
            
            
            -Total
                debt
            
            
            54,015,503
            
            
            49,156,395Redeemable
                convertible preferred stock
            
            
            -
            
            
            59,925Shareholders’
                equity
            
            
            139,731,099
            
            
            56,625,927Total
                capitalization
            
            $
            193,746,602
            
            $
            105,842,247





**Cash
      Flows from Operating Activities**





Cash
      provided by operating activities was $2.2 million in 2006, compared to cash
      used
      of $2.4 million in 2005. This $4.6 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 $4.0 million.





Operating
      cash flows are impacted by many variables, the most significant of which is
      the
      volatility of prices for natural gas and oil produced. Prices for these
      commodities are determined primarily by prevailing market conditions. As of
      December 31, 2006, we have entered into the following financial hedges: (i)
      5,000 mmbtu/day at a price of $8.59 per mmbtu through March 2007 and (ii) 5,000
      mmbtu per day at a price of $9.00 per mmbtu from April 2007 through December
      2008. On January 29, 2007, we entered into a zero cost collar contract for
      2,000
      mmbtu per day with a cap price of $9.00 per mmbtu and a floor price of $7.55
      per
      mmbtu for the period from April 1, 2007, through December 31, 2008. Based on
      our
      December 31, 2006 production exit rate of 8,600 mcfe per day, we have 58% of
      our
      existing production hedged through March, 2007 and beginning April 2007, we
      will
      have 81% of our existing production hedged with a floor price of $8.59 per
      mmbtu.





**Cash
      Flows used in Investing Activities**





Cash
      flows used in investing activities was $86.3 million in 2006, compared to $39.9
      million in 2005. The following table describes our significant investing
      transactions that we completed in the periods set forth below:


36


**Year
                  Ended December 31****2006**
              
              **2005**Acquisitions
                  of leaseholdAntrim
                  shale
              
              $
              7,138,014
              
              
              5,747,079New
                  Albany shale(a)
              
              
              16,143,356
              
              
              8,488,834Other
              
              
              3,556,327
              
              
              4,047,089Drilling
                  and development of oil and natural gas propertiesAntrim
                  shale
              
              
              22,088,181
              
              
              22,127,354New
                  Albany shale
              
              
              3,050,097
              
              
              9,422Other
              
              
              2,561,400
              
              
              321,416Infrastructure
                  propertiesAntrim
                  shale
              
              
              12,035,440
              
              
              6,523,298New
                  Albany shale
              
              
              1,934,415
              
              
              105,770Other
              
              
              378,566
              
              
              -Acquisitions
                  of oil and natural gas properties
              
              
              24,011,335
              
              
              -Acquisitions/additions
                  for pipeline, property and equipment
              
              
              4,111,780
              
              
              4,523,706Other,
                  net
              
              
              855,070
              
              
              485,741Subtotal
                  of capital expenditures
              
              $
              97,863,981
              
              $
              52,379,709Sale
                  of oil and natural gas properties(a)
              
              
              (11,489,456
              )
              
              (11,504,428
              )Other,
                  net
              
              
              (56,788
              )
              
              (36,314
              )Net
                  cash acquired in merger
              
              
              -
              
              
              (957,020
              )Subtotal
                  of capital divestitures
              
              $
              (11,546,244
              )
              $
              (12,497,762
              )Total
              
              $
              86,317,737
              
              $
              39,881,947
  (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. The Company
                  was
                  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 $73.8 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) $5.8 million of net short-term bank borrowings. Cash flows used by financing
      in 2005 included: 1) pay-off of $2.9 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.




37


**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.





**Oil
      and 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 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.





**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.


38





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, 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, will be recognized in the financial statements
      over
      the vesting period.





For
      the
      year ended December 31, 2006, the Company recorded stock-based compensation
      of
      $2,663,814 under the 2006 Stock Incentive Plan and 1997 Stock Option Plan,
      as
      well as a certain employment agreement. Of that amount, $2,206,801 has been
      included in general and administrative expense on the consolidated statement
      of
      operations and $457,013 has been capitalized in oil and natural gas properties.
      The impact on future net income is estimated to be $3,411,000 recognized over
      the applicable requisite service period of approximately 3 years.





***Income
      Taxes***





The
      Company has 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, 2006, the Company had approximately $34.3
      million of net operating loss carryforwards which expire between 2010 and
      2026.





**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.





**OFF
      BALANCE SHEET ARRANGEMENTS**




We
      have
      no off-balance sheet arrangements, special purpose entities, financing
      partnerships or guarantees.


39


**ITEM
      7.**  **FINANCIAL
      STATEMENTS**




**AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES**





**INDEX
      TO CONSOLIDATED FINANCIAL STATEMENTS**





PageReport
                of Independent Registered Public Accounting Firm
            
            
            41Consolidated
                Balance Sheets as of December 31, 2006 and 2005
            
            
            42-43Consolidated
                Statements of Operations for the Years Ended December 31, 2006 and
                2005
            
            
            44Consolidated
                Statements of Shareholders’ Equity for the Years Ended December 31, 2006
                and 2005
            
            
            45Consolidated
                Statements of Cash Flows for the Years Ended December 31, 2006 and
                2005
            
            
            46Notes
                to Consolidated Financial Statements
            
            
            47Supplemental
                Oil and Natural Gas Information (Unaudited)
            
            
            69




40




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 sheets of Aurora Oil & Gas
      Corporation and Subsidiaries as of December 31, 2006 and 2005, and the related
      consolidated statements of operations, shareholders’ equity, and cash flows for
      each of the years 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 2005, and the
      results of their operations and their cash flows for each of the years 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
      COHEN & HOLTZ LLP**





Miami,
      Florida


March
      13,
      2007




41





AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


CONSOLIDATED
      BALANCE SHEETS





December
                31,
            
            December
                31,2006
            
            2005**ASSETS****CURRENT
                ASSETS:**Cash
                and cash equivalents
            
            $
            1,735,396
            
            $
            11,980,638Accounts
                receivableOil
                and natural gas sales
            
            
            4,082,231
            
            
            2,409,675Joint
                interest owners
            
            
            3,079,715
            
            
            4,380,606Notes
                receivableRelated
                party
            
            
            -
            
            
            35,720Other
            
            
            341,698
            
            
            208,626Drilling
                advances
            
            
            1,408,860
            
            
            -Prepaid
                expenses and other current assets
            
            
            264,024
            
            
            240,242Short-term
                derivative instruments
            
            
            3,552,060
            
            
            -Total
                current assets
            
            
            14,463,984
            
            
            19,255,507**PROPERTY
                AND EQUIPMENT:**Oil
                and natural gas properties, using full cost accounting:Proved
                properties
            
            
            121,178,499
            
            
            39,643,003Unproved
                properties
            
            
            41,847,526
            
            
            37,279,889Properties
                held for sale
            
            
            8,896,568
            
            
            -Less:
                accumulated depletion and amortization
            
            
            (10,628,438
            )
            
            (7,962,138
            )Total
                oil and natural gas properties, net
            
            
            161,294,155
            
            
            68,960,754Pipelines
            
            
            4,881,240
            
            
            -Other
                property and equipment
            
            
            5,093,777
            
            
            3,723,918Less:
                accumulated depreciation
            
            
            (753,789
            )
            
            (113,780
            )Total
                property and equipment, net
            
            
            170,515,383
            
            
            72,570,892**OTHER
                ASSETS:**Long-term
                derivative instruments
            
            
            1,668,573
            
            
            -Deposits
                on purchase of oil and natural gas properties
            
            
            -
            
            
            3,206,102Goodwill
            
            
            19,373,264
            
            
            15,973,346Intangibles
                (net of accumulated amortization of$2,946,250
                and $1,407,083, respectively)
            
            
            2,008,750
            
            
            3,197,917Other
                investments
            
            
            985,706
            
            
            1,855,977Debt
                issuance costs (net of accumulated amortizationof
                $892,535 and $79,096, respectively)
            
            
            2,363,898
            
            
            723,993Other
            
            
            1,007,634
            
            
            38,411Total
                other assets
            
            
            27,407,825
            
            
            24,995,746**TOTAL
                ASSETS**
            
            $
            212,387,192
            
            $
            116,822,145




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


42





AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


CONSOLIDATED
      BALANCE SHEETS





December
                31,
            
            December
                31,2006
            
            2005**LIABILITIES
                AND SHAREHOLDERS' EQUITY****CURRENT
                LIABILITIES:**Accounts
                payable and accrued liabilities
            
            $
            5,701,464
            
            $
            5,489,657Accrued
                exploration, development, and leasehold costs
            
            
            11,587,850
            
            
            1,980,922Short-term
                bank borrowings
            
            
            542,788
            
            
            6,210,000Current
                portion of obligations under capital leases
            
            
            8,868
            
            
            8,823Current
                portion of note payable - related party
            
            
            -
            
            
            69,833Current
                portion of note payable - other
            
            
            161,774
            
            
            -Current
                portion of mortgage payable
            
            
            95,828
            
            
            72,877Drilling
                advances
            
            
            19,383
            
            
            -Deposit
                on sale of oil and natural gas properties
            
            
            -
            
            
            3,509,319Total
                current liabilities
            
            
            18,117,955
            
            
            17,341,431**LONG-TERM
                LIABILITIES:**Obligations
                under capital leases, net of current portion
            
            
            8,228
            
            
            2,262Asset
                retirement obligation
            
            
            1,331,893
            
            
            -Notes
                payable
            
            
            118,547
            
            
            -Mortgage
                payable
            
            
            3,079,470
            
            
            2,792,600Senior
                secured credit facility
            
            
            10,000,000
            
            
            -Mezzanine
                financing
            
            
            40,000,000
            
            
            40,000,000Total
                long-term liabilities
            
            
            54,538,138
            
            
            42,794,862Total
                liabilities
            
            
            72,656,093
            
            
            60,136,293**COMMITMENTS,
                CONTINGENCIES and SUBSEQUENT EVENT (Notes 11 and
                16)****REDEEMABLE
                CONVERTIBLE PREFERRED STOCK:**Authorized
                20,000,000 shares; outstanding noneand
                34,984 shares, respectively
            
            
            -
            
            
            59,925**SHAREHOLDERS'
                EQUITY:**Common
                stock, $.01 par value; authorized 250,000,000shares;
                issued and outstanding 101,412,966 sharesand
                61,536,261, respectively
            
            
            1,014,130
            
            
            615,363Additional
                paid-in capital
            
            
            138,105,626
            
            
            58,670,698Accumulated
                other comprehensive income
            
            
            5,220,633
            
            
            -Accumulated
                deficit
            
            
            (4,609,290
            )
            
            (2,660,134
            )Total
                shareholders' equity
            
            
            139,731,099
            
            
            56,625,927**TOTAL
                LIABILITIES AND SHAREHOLDERS' EQUITY**
            
            $
            212,387,192
            
            $
            116,822,145




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


43





AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


CONSOLIDATED
      STATEMENTS OF OPERATIONS


Year
                  Ended December 31,2006
              
              2005**REVENUES:**Oil
                  and natural gas sales
              
              $
              21,591,811
              
              $
              6,743,444Pipeline
                  transportation and marketing
              
              
              1,179,431
              
              
              -Field
                  service and sales
              
              
              125,611
              
              
              -Interest
                  and other
              
              
              220,592
              
              
              666,850Total
                  revenues
              
              
              23,117,445
              
              
              7,410,294**EXPENSES:**Production
                  taxes
              
              
              877,319
              
              
              506,635Production
                  and lease operating expense
              
              
              6,278,131
              
              
              1,587,205Pipeline
                  operating expense
              
              
              643,963
              
              
              -Field
                  services expense
              
              
              90,913
              
              
              -General
                  and administrative expense
              
              
              7,531,718
              
              
              3,435,507Oil
                  and natural gas depletion and amortization
              
              
              2,681,290
              
              
              767,511Other
                  assets depreciation and amortization
              
              
              2,083,191
              
              
              308,647Interest
                  expense
              
              
              4,573,785
              
              
              1,307,370Taxes,
                  other
              
              
              250,884
              
              
              29,651Total
                  expenses
              
              
              25,011,194
              
              
              7,942,526**LOSS
                  BEFORE MINORITY INTEREST**
              
              
              (1,893,749
              )
              
              (532,232
              )**MINORITY
                  INTEREST IN (INCOME)****LOSS
                  OF SUBSIDIARIES**
              
              
              (50,898
              )
              
              15,960**NET
                  LOSS**
              
              $
              (1,944,647
              )
              $
              (516,272
              )**NET
                  LOSS PER COMMON SHARE-BASIC AND DILUTED**
              
              $
              (0.02
              )
              $
              (0.01
              )**WEIGHTED
                  AVERAGE COMMON SHARES****OUTSTANDING
                  - BASIC AND DILUTED**
              
              
              82,288,243
              
              
              40,622,000





**Supplemental
      Information**




Net
      loss
      for the years ended December 31, 2006, and 2005, included stock-based
      compensation expense of $2,206,801 and none, respectively, under Statement
      of
      Financial Accounting Standards No. 123 (revised 2004). See Note 3 “Common Stock
      Options” for additional information.





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


44




AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


CONSOLIDATED
      STATEMENTS OF SHAREHOLDERS' EQUITY


Year
                  Ended December 31,2006
              
              2005Shares
              
              Amount
              
              Shares
              
              Amount**COMMON
                  STOCK:**Balance,
                  beginning
              
              
              61,536,261
              
              $
              615,363
              
              
              13,775,933
              
              $
              13,776Cashless
                  exercise of stock options and warrants
              
              
              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
              
              
              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
              
              
              900Issuance
                  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
              )
              
              -
              
              
              -Balance,
                  end
              
              
              101,412,966
              
              $
              1,014,130
              
              
              61,536,261
              
              $
              615,363**ADDITIONAL
                  PAID-IN CAPITAL:**Balance,
                  beginning
              
              
              
              
              
              58,670,698
              
              
              
              
              
              8,183,025Cashless
                  exercise of stock options and warrants
              
              
              
              
              
              (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 merger between Cadence and
                  Aurora
              
              
              
              
              
              
              
              
              
              
              
              35,706,179Stock-based
                  compensation
              
              
              
              
              
              2,663,814
              
              
              
              
              
              -Exercise
                  of stock options and warrants
              
              
              
              
              
              18,143,714
              
              
              
              
              
              3,607,700Issuance
                  of stock in connection with public equity offering
              
              
              
              
              
              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 party in lieu of commission relating to exercise
                  of
                  warrants
              
              
              
              
              
              (14,699
              )
              
              
              
              
              -Rescission
                  of stock option exercises by certain officers
              
              
              
              
              
              (729,000
              )
              
              
              
              
              -Balance,
                  end
              
              
              
              
              $
              138,105,626
              
              
              
              
              $
              58,670,698**ACCUMULATED
                  OTHER COMPREHENSIVE INCOME:**Balance,
                  beginning
              
              
              
              
              
              -
              
              
              
              
              
              -Unrealized
                  gains on derivative instruments
              
              
              
              
              
              7,903,933
              
              
              
              
              
              -Recognition
                  of gain on derivative instruments
              
              
              
              
              
              (2,683,300
              )
              
              
              
              
              -Balance,
                  end
              
              
              
              
              $
              5,220,633
              
              
              
              
              
              -**ACCUMULATED
                  DEFICIT:**Balance,
                  beginning
              
              
              
              
              
              (2,660,134
              )
              
              
              
              
              (2,099,522
              )Dividends
                  accrued on redeemable convertible preferred stock
              
              
              
              
              
              (4,509
              )
              
              
              
              
              (44,340
              )Net
                  loss
              
              
              
              
              
              (1,944,647
              )
              
              
              
              
              (516,272
              )Balance,
                  end
              
              
              
              
              
              (4,609,290
              )
              
              
              
              
              (2,660,134
              )**TOTAL
                  SHAREHOLDERS' EQUITY**
              
              
              
              
              $
              139,731,099
              
              
              
              
              $
              56,625,927




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


45


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


Year
                  Ended December 31,**CASH
                  FLOWS FROM OPERATING ACTIVITIES:**
              
              2006
              
              2005Net
                  loss
              
              $
              (1,944,647
              )
              $
              (516,272
              )Adjustments
                  to reconcile net loss to net cash provided by (used in) operating
                  activities:Depreciation,
                  depletion and amortization
              
              
              4,764,481
              
              
              1,076,158Amortization
                  of debt issuance costs
              
              
              813,715
              
              
              79,096Accretion
                  of asset retirement obligation
              
              
              74,097
              
              
              -Stock-based
                  compensation
              
              
              2,206,801
              
              
              -Equity
                  loss of other investments and other
              
              
              329,902
              
              
              116,372Changes
                  in operating assets and liabilities, net of effects of merger and
                  acquisitions:Accounts
                  receivable
              
              
              532,765
              
              
              (3,827,537
              )Drilling
                  advance, net
              
              
              (1,389,477
              )
              
              (387,175
              )Prepaid
                  expenses
              
              
              (66,173
              )
              
              41,634Other
                  assets
              
              
              (1,052,297
              )
              
              -Accounts
                  payable and accrued liabilities
              
              
              (2,024,632
              )
              
              1,025,606Net
                  cash provided by (used in) operating activities
              
              
              2,244,535
              
              
              (2,392,118
              )**CASH
                  FLOWS FROM INVESTING ACTIVITIES:**Exploration
                  and development of oil and natural gas properties
              
              
              (42,048,099
              )
              
              (29,087,260
              )Leasehold
                  expenditures, net
              
              
              (26,837,697
              )
              
              (18,283,002
              )Acquisition
                  of oil and natural gas properties
              
              
              (24,011,335
              )
              
              -Sale
                  of oil and natural gas properties
              
              
              11,489,456
              
              
              11,504,428Acquisitions/additions
                  for pipeline, property and equipment
              
              
              (4,111,780
              )
              
              (4,523,706
              )Additions
                  in other investments
              
              
              (855,070
              )
              
              (485,741
              )Other,
                  net
              
              
              56,788
              
              
              36,314Net
                  cash acquired in merger
              
              
              -
              
              
              957,020Net
                  cash used in investing activities
              
              
              (86,317,737
              )
              
              (39,881,947
              )**CASH
                  FLOWS FROM FINANCING ACTIVITIES:**Net
                  short-term bank borrowings (payments)
              
              
              (5,775,628
              )
              
              5,860,000Advances
                  on senior secured credit facility
              
              
              60,000,000
              
              
              -Payments
                  on senior secured credit facility
              
              
              (50,000,000
              )
              
              -Advances
                  on mezzanine financing
              
              
              -
              
              
              30,000,000Advances
                  (payments) on mortgage obligations
              
              
              (73,205
              )
              
              2,865,477Payments
                  of financing fees on credit facilities
              
              
              (2,452,786
              )
              
              (508,542
              )Distributions
                  to minority interest members
              
              
              -
              
              
              (805,000
              )Net
                  proceeds from sales of common stock
              
              
              54,505,807
              
              
              14,666,625Net
                  proceeds from exercise of options and warrants
              
              
              17,554,949
              
              
              -Dividends
                  paid on preferred stock
              
              
              (20,250
              )
              
              (44,340
              )Other,
                  net
              
              
              89,073
              
              
              (2,959,099
              )Net
                  cash provided by financing activities
              
              
              73,827,960
              
              
              49,075,121Net
                  (decrease) increase in cash and cash equivalents
              
              
              (10,245,242
              )
              
              6,801,056Cash
                  and cash equivalents, beginning of the period
              
              
              11,980,638
              
              
              5,179,582Cash
                  and cash equivalents, end of the period
              
              $
              1,735,396
              
              $
              11,980,638**NONCASH
                  FINANCING AND INVESTING ACTIVITIES:**Oil
                  and natural gas properties asset retirement obligation
              
              $
              1,257,796
              
              $
              -Accrued
                  exploration and development costs on oil and natural gas
                  properties
              
              
              11,161,730
              
              
              1,464,032Accrued
                  leasehold costs
              
              
              426,120
              
              
              516,890Properties
                  acquired in connection with Cadence merger in exchange for
                  equity—Oil
                  and natural gas properties, net
              
              
              
              
              
              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 assets
              
              
              1,100,973
              
              
              -Oil
                  and natural gas properties capitalized stock-based
                  compensation
              
              
              457,013
              
              
              -**CASH
                  PAID FOR INTEREST**
              
              $
              7,286,611
              
              $
              2,215,745


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


46


AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES
      TO
      CONSOLIDATED FINANCIAL STATEMENTS





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





Effective
      May 11, 2006, Cadence Resources Corporation (“Cadence”) and its wholly owned
      subsidiaries (collectively, the “Company”) amended its articles of incorporation
      to change its name to Aurora Oil & Gas Corporation (“AOG”). The Company is
      an oil and natural gas corporation engaged in the exploration, acquisition,
      development, production, and sale of natural gas and crude oil. 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 and the New Albany
      shale of Indiana and Kentucky.





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. See Note 2 “Merger with Aurora Energy, Ltd.” for complete discussion
      of the merger.





The
      Company uses different strategies for natural gas sales depending on the
      location of the field and the local markets. In most cases, the Company connects
      to nearby high pressure transmission pipelines. To cover a portion of the
      existing production, the Company entered into a firm delivery gas contract
      to be
      effective for the period April 1, 2006, through March 31, 2007, for the
      delivery of 5,000 mmbtu per day. The Company will be paid $0.01 per mmbtu less
      than the published index for this gas. The Company also has five other base
      contracts for the sale of natural gas. 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 in
      the
      spot markets or under the base contracts.





As
      an
      independent oil and natural gas producer, 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, and access to capital
      and
      on the quantities of natural gas and oil reserves that can be economically
      produced.





**NOTE
              2.**
            **MERGER
                WITH AURORA ENERGY, LTD.**





On
      October 31, 2005, the Company (formerly Cadence) acquired 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:


47


AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES
      TO
      CONSOLIDATED FINANCIAL STATEMENTS


(Continued)





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





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
              3.**
            **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. 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.


48




AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES
      TO
      CONSOLIDATED FINANCIAL STATEMENTS


(Continued)





As
      a
      result of the reverse acquisition discussed in Note 2 “Merger with Aurora
      Energy, Ltd.,” the historical financial statements presented for periods prior
      to the acquisition date are the financial statements of Aurora. The operations
      of the former 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 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.





***Reclassifications***





Certain
      amounts in the prior year financial statements have been reclassified to conform
      to current year presentations.





***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, 2006, cash in excess of
      FDIC
      limits amounted to approximately $3,123,000. 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
      products and from working interest partners for their proportionate share of
      expenses related to certain oil and natural gas projects. The Company regularly
      assesses the collectibility of accounts receivable and accrues an allowance
      when
      it is believed that a receivable may not be collected. The allowance for
      doubtful accounts was $79,030 and $0 at December 31, 2006, and 2005,
      respectively.





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. Oil and natural gas sales to the primary customer were
      approximately 62% and 56% of total oil and natural gas sales for the years
      ended
      December 31, 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 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.


49


AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES
      TO
      CONSOLIDATED FINANCIAL STATEMENTS


(Continued)





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.





***Asset
      Retirement Obligation***





On
      January 1, 2006, the Company adopted Financial Accounting Standards Board
      (“FASB”) Interpretation No. 47, “Accounting for Conditional Asset Retirement
      Obligations,” and 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 estimated the fair value of the
      obligation 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. Prior to January 1, 2006, such amount
      was
      not considered material.





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 statement of operations.





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





2006Beginning
                balance
            
            $
            812,634Liabilities
                incurred
            
            
            719,229Liabilities
                settled
            
            
            (123,809
            )Accretion
                expense
            
            
            74,097Revisions
                of estimated liabilities
            
            
            (150,258
            )Ending
                balance
            
            $
            1,331,893





***Pipeline,
      Other Property and Equipment***





Pipeline,
      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, 2006, and 2005.




50





AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES
      TO
      CONSOLIDATED FINANCIAL STATEMENTS


(Continued)




A
      summary of the pipeline, other property, and
      equipment for years ended December 31, 2006, and 2005, are as
      follows:


2006
            
            2005
            
            Useful
                Life in YearsLand
            
            $
            78,000
            
            $
            -
            
            
            N/ABuildings
            
            
            3,552,392
            
            
            3,165,382
            
            
            40Furniture
                and fixtures
            
            
            328,173
            
            
            265,115
            
            
            5-10Office
                equipment
            
            
            65,781
            
            
            39,579
            
            
            5Computer
                equipment
            
            
            234,782
            
            
            148,601
            
            
            5Software
            
            
            188,434
            
            
            85,070
            
            
            3-5Vehicles
                and other equipment
            
            
            646,215
            
            
            20,171
            
            
            5Total
                other property and equipment
            
            
            5,093,777
            
            
            3,723,918Less
                accumulated depreciation
            
            
            (341,198
            )
            
            (113,780
            )Other
                property and equipment, net
            
            $
            4,752,579
            
            $
            3,610,138Pipelines
            
            $
            4,881,240
            
            $
            -
            
            
            15Less
                accumulated depreciation
            
            
            (412,591
            )
            
            -Pipelines,
                net
            
            $
            4,468,649
            
            $
            -





***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, 2006, and 2005, are as follows:





2006
            
            2005Investments
                in unconsolidated subsidiaries:Hudson
                Pipeline & Processing Co., LLC
            
            $
            -
            
            $
            1,224,995GeoPetra
                Partners, LLC
            
            
            721,596
            
            
            344,502Mineral
                properties
            
            
            197,406
            
            
            197,406Other
            
            
            66,704
            
            
            89,074$
            985,706
            
            $
            1,855,977





***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, 2006, and 2005, respectively.


51




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




***Intangible
      Assets***





Acquired
      intangible assets, which consist of noncompete agreements, pending patents,
      and
      proprietary business relationships, 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:





2007
            
            $
            1,551,6672008
            
            
            194,5842009
            
            
            66,6662010
            
            
            66,6662011
            
            
            66,667Thereafter
            
            
            62,500$
            2,008,750





***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.





***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, will be recognized in the financial statements
      over
      the vesting period.





For
      the
      year ended December 31, 2006, the Company recorded stock-based compensation
      of
      $2,663,814 under the 2006 Stock Incentive Plan, 2004 Equity Incentive Plan,
      and
      1997 Stock Option Plan (as described in Note 10 “Common Stock Options”), as well
      as a certain employment agreement (as described in Note 11 “Contingencies and
      Commitments”). Of that amount, $2,206,801 has been included in general and
      administrative expense on the consolidated statement of operations and $457,013
      has been capitalized in oil and natural gas properties. The impact on future
      net
      income is estimated to be approximately $3,411,000 recognized over the
      applicable requisite service period of approximately 3 years.





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.
      The
      following table illustrates the effect on net loss and loss per share as if
      the
      Company had applied the fair value recognition provisions of SFAS 123 during
      the
      year ended December 31, 2005:




52


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


2005Net
                loss
            
            $
            (516,272
            )Deduct
                total stock-based compensation expense determined under fair value
                based
                method for all awards, net of related tax effects
            
            
            (298,745
            )Pro
                forma net loss
            
            $
            (815,017
            )Loss
                per share—basic and dilutedAs
                reported
            
            $
            (0.01
            )Pro
                forma
            
            $
            (0.02
            )





***Income
      Taxes***





The
      Company has 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 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 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. 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.





***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,****2006**
            
            **2005**Net
                Loss
            
            $
            (1,944,647
            )
            $
            (516,272
            )Other
                comprehensive income:Unrealized
                gains on derivative instruments
            
            
            7,903,933
            
            
            -Recognition
                of gains on derivative instruments
            
            
            (2,683,300
            )
            
            -5,220,633
            
            
            -Comprehensive
                Income (Loss)
            
            $
            3,275,986
            
            $
            (516,272
            )





***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. During the years ended December 31,
      2006, and 2005, stock options, warrants, and redeemable convertible preferred
      stock were excluded in the computation of diluted loss per share because their
      effect of assumed exercises or conversions was anti-dilutive.




53
 
 AURORA
            OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
            TO
            CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


**NOTE****4.**
            **RECENT
                ACCOUNTING PRONOUNCEMENTS**





In
      February 2006, the FASB issued SFAS 155, “Accounting for Certain Hybrid
      Financial Instruments,” which eliminates the exemption from applying SFAS 133,
“Accounting for Derivative Instruments and Hedging Activities,” to interests in
      securitized financial assets so that similar instruments are accounted for
      similarly, regardless of the form of the instruments. SFAS 155 also allows
      the
      election of fair value measurement at acquisition, at issuance, or when a
      previously-recognized financial instrument is subject to a remeasurement event.
      Adoption is effective for all financial instruments acquired or issued after
      the
      beginning of the first fiscal year that begins after September 15, 2006. The
      adoption did not have an impact on the Company’s consolidated financial
      statements.





In
      February 2006, the FASB issued Financial Staff Position (“FSP”) FAS 123(R)-4
      "Classification of Options and Similar Instruments Issued as Employee
      Compensation that Allow for Cash Settlement upon the Occurrence of a Contingent
      Event." This FSP amends SFAS No. 123(R) addressing cash settlement features
      that
      can be exercised only upon the occurrence of a contingent event that is outside
      the employee's control. These instruments are not required to be classified
      as a
      liability until it becomes probable that the event will occur. The adoption
      did
      not have an impact on the Company’s consolidated financial
      statements.




In
      July
      2006, the FASB issued Interpretation No. 48. This Interpretation clarifies
      the
      accounting for uncertainty in income taxes recognized in an enterprise's
      financial statements in accordance with SFAS Statement No. 109, “Accounting for
      Income Taxes.” This Interpretation prescribes a recognition threshold and
      measurement attribute for the financial statement recognition and measurement
      of
      a tax position taken or expected to be taken in a tax return. This
      Interpretation also provides guidance on derecognition, classification, interest
      and penalties, accounting in interim periods, disclosure, and transition. This
      Interpretation is effective for fiscal years beginning after December 15, 2006.
      Management believes the adoption of this standard will not have a material
      impact on the Company’s consolidated financial statements.




In
      September 2006, the FASB issued SFAS 157, “Fair Value Measurements,” 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. FASB 157 also
      requires expanded disclosure of the effect on earnings for items measured using
      unobservable data. The provisions of FASB 157 are effective for financial
      statements issued for fiscal years beginning after November 15, 2007, and
      interim periods within those fiscal years. Management believes the adoption
      of
      this standard will not have a material impact on the Company’s consolidated
      financial statements.





On
      February 15, 2007, the FASB issued SFAS No. 159, “Fair Value Option for
      Financial Assets and Financial Liabilities”—including an amendment of FASB
      Statement No. 115. SFAS No. 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 Company does not
      believe SFAS No. 159 will have a material impact on its consolidated financial
      statements.





In
      September 2006, the SEC issued Staff Accounting Bulletin No. 108 (“SAB 108”).
      Due to diversity in practice among registrants, SAB 108 expresses the SEC
      staff’s views regarding the process by which misstatements in financial
      statements are evaluated to determine whether financial statement restatement
      is
      necessary. SAB 108 is effective for fiscal years ending after November 15,
      2006.
      SAB 108 did not have a material impact on the Company’s consolidated financial
      statements.




54


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




**NOTE
              5.**
            **RISK
                MANAGEMENT ACTIVITIES**





***Derivative
      Instruments***





In
      order
      to reduce exposure to fluctuations in the price of natural gas, the Company
      will
      periodically enter into financial instruments with a major financial
      institution. The Company has entered into swap instruments in order to hedge
      a
      portion of its production. The purpose of the swaps 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 reduces
      the Company’s exposure on the hedged volumes to decreases in commodity prices
      and limits the benefit the Company might otherwise receive from any increases
      in
      commodity prices on the hedged 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 swap contracts
      were
      in place at December 31, 2006:





Period
            
            Natural
                Gas Volume per Day
            
            Fixed
                Price per mmbtu
            
            Fair
                Value AssetApril
                2006—March 2007
            
            
            5,000
                mmbtu
            
            $
            8.59
            
            $
            1,055,835April
                2007—December 2008
            
            
            5,000
                mmbtu
            
            $
            9.00
            
            
            4,164,798$
            5,220,633





For
      the
      year ended December 31, 2006, the Company has recognized in Accumulated Other
      Comprehensive Income net unrealized gains of $7,903,933 on the swap contracts
      that have been designated as cash flow hedges on forecasted sales of natural
      gas. In addition, for the year ended December 31, 2006, the Company recognized
      $2,683,300 net gains from hedging activities included in oil and natural gas
      revenues. In 2005, the Company had no derivative instruments to manage price
      risk related to its natural gas production.





On
      January 29, 2007, the Company entered into a costless collar contract for 2,000
      mmbtu per day with a ceiling price of $9.00 per mmbtu and a floor price of
      $7.55
      per mmbtu for the period from April 1, 2007 through December 31,
      2008.





***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.




55


AURORA
        OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)
 **NOTE
                  6.**
                **ACQUISITIONS
                    AND DISPOSITIONS**
  **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 $27,600,000.
      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 $11,840,000. The Company
      was required to deposit into escrow for the seller $3,200,000.





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 $10,500,000. Pursuant to
      the
      terms of this sales agreement, $3,500,000 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 $4,750,000. 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.





**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 is 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.




56


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




**2005
      - New Albany**





On
      January 3, 2005, El Paso Corporation exercised an option to purchase 95% of
      the
      working interest in certain New Albany shale acreage in Indiana. As a result
      of
      this transaction, Aurora received gross proceeds in the amount of $7,373,737.
      After deducting a distribution to subsidiary members of $805,000 and an
      additional $1,000,000 set aside for the subsidiary’s share of anticipated future
      drilling expense, approximately $5,500,000 of net proceeds was retained by
      Aurora. In addition, the Company retained a 5% carried working interest in
      the
      first 50 wells drilled by El Paso Corporation.





**2005/2006
      - GeoPetra Partners, LLC Investment**





In
      June
      2005, the Company acquired a 33% interest in GeoPetra Partners, LLC (“GeoPetra”)
      for $14,000. GeoPetra is a limited liability company engaged primarily in the
      following activities: (i) identification and evaluation for acquisition of
      oil
      and natural gas properties and interest and entities which hold such properties
      and interests; (ii) areas to be explored and developed for the production of
      oil
      and natural gas; and (iii) providing consultation, advice, and recommendations
      to the members of GeoPetra in connection with other oil and natural gas
      properties and interests, operations, and activities. GeoPetra was formed April
      1, 2005. In July 2006, the Company finalized a sale of 18% of its 33% interest
      in GeoPetra to JetEX, LLC. This transaction reduced the gross investment made
      to
      GeoPetra by $199,000. Thus, as of December 31, 2006, the Company had contributed
      $1,192,987 to GeoPetra with net operating losses of $471,391 resulting in an
      investment balance of $721,596.





**2005-
      New Albany Corner #1 Project**





In
      July
      2005, the Company sold a 50% working interest in 28,610 leasehold acres located
      in the New Albany shale to Samson Resources Company for $344,100. This included
      an 80% net revenue interest in the existing leasehold acres.





**NOTE
              7.**
            **DEBT**





**Short-Term
      Bank Borrowings**





On
      October 12, 2005, the Company entered into a $7.5 million revolving line of
      credit agreement with Northwestern Bank for general corporate purposes. On
      January 31, 2006, the credit availability on this line of credit was reduced
      to
      $5.0 million to meet the requirements of the senior secured credit facility
      (as
      described below). To secure this line of credit, two trusts controlled by an
      executive officer pledged certain shares of the Company’s common stock under his
      control. The interest rate under the revolving line of credit is Wall Street
      prime (8.25% and 7.25% at December 31, 2006 and 2005, respectively) with
      interest payable monthly in arrears. Principal is payable at the expiration
      of
      the revolving line of credit agreement. Northwestern Bank has extended the
      expiration date to October 15, 2007. Northwestern Bank also provides letters
      of
      credit for the drilling program (as described in Note 11 “Commitments and
      Contingencies”). Interest expense on the Northwestern Bank revolving line for
      the years ended December 31, 2006, and 2005, were $283,163 and $37,326,
      respectively. As of March 2, 2007, the Company had no outstanding borrowings
      under this credit facility.




57


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




**Note
      Payable - Related Parties**





Through
      May 1, 2006, the Company was indebted under a note payable to a minority member
      of Indiana Royalty Trustory, L.L.C., an affiliated company, in the amount of
      $69,833. The interest rate was 10.5% per year. The note payable matured on
      May
      1, 2006, and was paid in full.





**Short-Term
      Bank Borrowings - Bach**





On
      October 6, 2006, the Company entered into a $175,100 revolving line of credit
      agreement with Northwestern Bank for general corporate purposes covering the
      Bach activities. This line of credit is secured by all of Bach’s personal
      property owned or hereafter acquired. The interest rate under the revolving
      line
      of credit is Wall Street prime (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, 2007.
      Interest expense for the year ended December 31, 2006, was $2,166.





**Mortgage
      and Notes Payable - Bach**





The
      following information details the loans assumed and entered into in connection
      with the Bach acquisition:





Description
                of Loan
            
            Date
                of Loan
            
            Maturity
              Date
            
            Interest
                Rate
            
            Principal
                Amount
            
            2006
                Interest ExpenseMortgage
                payable on building
            
            
            10/06/06
            
            
            10/15/09
            
            
            6.00
            %
            $
            383,026
            
            $
            5,352Notes
                payableVehicles
            
            
            10/06/06
            
            
            10/01/10
            
            
            7.50
            %
            
            95,087Equipment
            
            
            10/06/06
            
            
            09/01/07
            
            
            5.50
            %
            
            16,700Vehicles
            
            
            12/18/06
            
            
            12/20/09
            
            
            7.25
            %
            
            70,118Total
                notes payable
            
            
            
            
            
            
            
            
            
            
            $
            181,905
            
            $
            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. During September 2006, Northwestern Bank released
      the
      personal guaranties of three of the Company’s officers. The payment schedule is
      monthly interest only for the first 3 months starting on November 1, 2005,
      and,
      beginning on February 1, 2006, principal and interest in 32 monthly payments
      of
      $21,969 with one principal and interest payment of $2,733,994 on October 1,
      2008. The interest rate is 6.5% per year. The maturity date is October 1, 2008.
      Interest expense for the year ended December 31, 2006, and 2005, was
      $192,814 and $15,732, respectively.





**Mezzanine
      Financing**





On
      December 8, 2005, the Company entered into an Amended Note Purchase Agreement
      to
      increase its 5-year mezzanine credit facility with Trust Company of the West
      (“TCW”) from $30 million to $50 million for the Michigan Antrim drilling
      program. The borrower is North. Upon closing of the BNP Paribas (“BNP”) senior
      secured credit facility discussed below, TCW now holds a second lien position
      in
      the Michigan Antrim natural gas properties. The interest rate is fixed at 11.5%
      per year, compounded quarterly, and payable in arrears. Beginning September
      28,
      2006, and quarterly thereafter, the required principal payment is 75% (100%
      if
      coverage deficiency or default occurs) of adjusted net cash flow determined
      by
      deducting specific expenses, including capital expenditures from “gross cash
      revenue.” The Company estimates that no principal payments on the mezzanine
      financing will be required until maturity because of the level of anticipated
      capital expenditures. The maturity date is September 30, 2009. The borrowing
      base is impacted by, among other factors, the fair value of the Company’s
      natural gas reserves that are pledged to TCW. Changes in the fair value of
      the
      natural gas reserves are caused by changes in prices for natural gas, operating
      expenses, and the results of drilling activity. A significant decline in the
      fair value of these reserves could reduce the borrowing base, and the Company
      may not be able to meet certain facility covenants.




58


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




The
      mezzanine credit facility contains, among other things, certain covenants
      relating to restricted payments (as defined), loans or advances to others,
      additional indebtedness, and incurrence of liens and provides for the
      maintenance of certain financial and operating ratios, including current ratio
      and specified coverage ratios (collateral coverage and proved developed
      producing reserves coverage ratios).





As
      additional consideration to induce TCW to enter into the mezzanine facility,
      the
      Company provided an affiliate of TCW an overriding royalty interest in certain
      of properties drilled or developed in the Counties of Alcona, Alpena,
      Charlevoix, Cheboygan, Montmorency, and Otsego in the State of Michigan. The
      overriding royalty interest is 4%, subject to certain adjustments.





For
      the
      years ended December 31, 2006, and 2005, interest incurred for the mezzanine
      credit facility was $4,714,861, and $2,171,389, respectively. As of March 2,
      2007, the Company had total borrowings of $40 million under this credit
      facility.





**Senior
      Secured Credit Facility**





On
      January 31, 2006, the Company entered into a senior secured credit facility
      with
      BNP for drilling, development, and acquisitions, as well as other general
      corporate purposes. The borrower is North. The initial borrowing base was $40
      million without hedges. Effective July 14, 2006, the borrowing base was
      increased to $50 million. As proved reserves are added, this borrowing base
      may
      increase to $100 million with TCW consent. A required semiannual reserve report
      may result in an increase or decrease in credit availability. The security
      for
      this facility is a first lien position in certain Michigan Antrim assets; a
      guarantee from Aurora; and a guarantee from the Company secured by a pledge
      of
      its stock in Aurora. This facility matures the earlier of January 31, 2010,
      or
      91 days prior to the maturity of the mezzanine credit facility, unless the
      Company elects to terminate the commitment earlier pursuant to the terms of
      the
      senior secured credit facility.





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. For the year ended December 31, 2006, interest incurred was
      $2,323,732. As of March 2, 2007, the Company had total borrowings of $25 million
      under this credit facility.





On
      July
      14, 2006, the senior secured credit facility was amended to defer the trailing
      12-month interest coverage ratio covenant until the fourth quarter of 2006
      and
      to provide for a reduced ratio for that quarter. The trailing 12-month interest
      coverage ratio amendment was intended to correct a previous error in the
      covenant, which failed to account for the fact that the acquisition of the
      Hudson Properties (as described in Note 6 “Acquisitions and Dispositions”) in
      the first quarter of 2006 would not have a full trailing 12 months of cash
      flow
      included in the financial statements until the first quarter of 2007. This
      amendment supersedes the waiver BNP issued regarding the interest coverage
      covenant for the first quarter of 2006.





On
      September 22, 2006, the Company agreed that BNP could establish a syndication
      thereby allowing various financial institutions to participate under the senior
      secured credit facility. In addition, effective December 21, 2006, the senior
      secured credit facility was amended to eliminate the interest coverage ratio
      covenant for the fiscal quarter ending December 31, 2006, and to modify the
      2007
      fiscal quarters’ interest coverage ratio covenants.




59


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




The
      senior secured credit facility contains, among other things, a number of
      financial and nonfinancial covenants relating to restricted payments (as
      defined), loans or advances to others, additional indebtedness, incurrence
      of
      liens, a prohibition on the Company’s ability to prepay the mezzanine credit
      facility, geographic limitations on operations to the United States, and
      maintenance of certain financial and operating ratios, including current ratio
      and specified coverage ratios (collateral coverage and proved developed
      producing reserves coverage ratios).





**Maturities
      of Debt**





Aggregate
      maturities of long-term debt at December 31, 2006, are as follows:





2007
            
            $
            817,4852008
            
            
            2,769,5172009
            
            
            50,406,4972010
            
            
            22,004Total
            
            $
            54,015,503





The
      Company has incurred deferred financing fees of approximately $406,000 from
      BNP
      and approximately $2,850,000 from TCW. These financing fees are being amortized
      on a straight-line basis over the remaining terms of each debt obligation.
      Amortization expense is estimated to be $0.8 million per year through
      2009.





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
      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 $3,896,645 and $1,146,084 for the years ended
      December 31, 2006 and 2005, respectively.





**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**





**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.




60


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




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.





**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. 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
      2006,
      a total of 34,984 shares of redeemable convertible preferred stock were
      converted into 34,984 shares of common stock.





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.





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.




61


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


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.





**Common
      Stock Warrants**





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





2006
            
            2005Number
                of Shares Underlying Warrants
            
            Number
                of Shares Underlying WarrantsOutstanding
                at the beginning of the period
            
            
            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
            
            
            (3,589,871
            )
            
            (2,596,677
            )Forfeitures
                and other adjustments
            
            
            (845,504
            )
            
            (8,323
            )Outstanding
                at the end of the period
            
            
            2,079,500
            
            
            19,697,500





As
      of
      December 31, 2006, these common stock warrants had an average remaining
      contractual life of 1.88 years and weighted average exercise price per share
      of
      $1.71.





**NOTE
              9.**
            **INCOME
                TAXES**





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





2006
            
            2005Current
                taxes
            
            $
            -
            
            $
            -Deferred
                taxes
            
            
            1,862,000
            
            
            175,500Less:
                change in valuation allowance
            
            
            (1,862,000
            )
            
            (175,500
            )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:





2006
            
            2005Federal
                statutory income tax rate
            
            $
            (661,000
            )
            $
            (175,500
            )Adjustment
                of estimated income tax provision of prior years(a)
            
            
            2,523,000Change
                in valuation allowance
            
            
            (1,862,000
            )
            
            175,500Net
                income tax expense (benefit)
            
            $
            -
            
            $
            -





(a)  Adjustment
      of estimated income tax provision of prior year is due primarily to intangible
      costs that were expensed in prior year calculation but capitalized and amortized
      in tax return.




62


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:





2006
            
            2005Deferred
                tax assets:Net
                operating loss carryover
            
            $
            11,661,000
            
            $
            12,324,600Stock
                options
            
            
            928,000
            
            
            -Section
                1231 carryover
            
            
            -
            
            
            146,900Capital
                loss carryover
            
            
            33,000
            
            
            66,000Less
                valuation allowance
            
            
            (530,000
            )
            
            (2,391,700
            )Deferred
                tax assets, net
            
            
            12,092,000
            
            
            10,145,800Deferred
                tax liabilities:Excess
                assigned acquisition value
            
            
            (4,339,000
            )
            
            (4,339,000
            )Intangible
                drilling costs and other
            
            
            (7,753,000
            )
            
            (5,806,800
            )Deferred
                tax liabilities, net
            
            
            (12,092,000
            )
            
            (10,145,800
            )Net
                deferred tax assets (liabilities)
            
            $
            -
            
            $
            -





The
      Company has net operating loss carryforwards available to offset future federal
      taxable income of approximately $34,297,000, which expire from 2010 through
      2026. Included in this amount is a premerger net operating loss carryforward
      incurred by Cadence of approximately $16,900,000. The valuation allowance
      decreased by approximately $1,862,000 and $175,500 as of December 31, 2006,
      and
      2005, respectively. Due to the net operating loss carryforwards, no income
      tax
      expense was recorded in 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.




63


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, 2006, and 2005:





2006
            
            2005Options
                outstanding at beginning of period
            
            
            1,804,994
            
            
            943,994Options
                granted
            
            
            2,727,500
            
            
            146,000Assumed
                upon merger:2
                for 1 exchange of Aurora options
            
            
            -
            
            
            490,000Cadence
                options
            
            
            -
            
            
            400,000Options
                exercised
            
            
            (592,732
            )
            
            (195,000
            )Options
                forfeited and other adjustments
            
            
            (507,266
            )
            
            20,000Options
                outstanding at end of period
            
            
            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:





2006
            
            2005Risk-free
                interest rate
            
            
            4.1
            %
            
            
            4
            %Expected
                years until exercise
            
            
            2.5-6.0
            
            
            
            10Expected
                stock volatility
            
            
            41
            %
            
            
            41
            %Dividend
                yield
            
            
            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 compensatory 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. Activity with respect to all stock options is presented
      below for the years ended December 31, 2006, and 2005:




64


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


2006
              
              2005Shares
              
              Weighted
                  Average Exercise Price
              
              Shares
              
              Weighted
                  Average Exercise PriceOptions
                  outstanding at the beginning of period
              
              
              6,448,468
              
              $
              0.72
              
              
              2,700,664
              
              $
              0.99Options
                  granted
              
              
              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
              
              
              (3,800,926
              )
              
              0.67
              
              
              (357,500
              )
              
              1.20Forfeitures
                  and other adjustments
              
              
              (512,266
              )
              
              3.65
              
              
              (31,709
              )
              
              0.43Options
                  outstanding at end of period
              
              
              4,862,776
              
              $
              2.23
              
              
              6,448,468
              
              $
              0.72Exercisable
                  at end of period
              
              
              2,775,609
              
              $
              1.01Weighted
                  average fair value of options granted during the period
              
              $
              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, 2006, was
      approximately $6,577,000 and the intrinsic value of the options exercisable
      at
      December 31, 2006, was approximately $6,440,000. The intrinsic value of the
      options exercised during the year ended December 31, 2006, was
      approximately $4,647,000.





The
      weighted average remaining life by exercise price as of December 31, 2006,
      is
      summarized below:





Range
                of
              Exercise
                Prices
            
            Outstanding
                Shares
            
            Weighted
                Average Life
            
            Exercisable
                Shares
            
            Weighted
                Average Life$0.25
                - $0.38
            
            
            749,996
            
            
            3.7
            
            
            749,996
            
            
            3.7$0.50
                - $0.75
            
            
            1,440,000
            
            
            2.1
            
            
            1,440,000
            
            
            2.1$1.25
                - $1.75
            
            
            352,000
            
            
            7.7
            
            
            352,000
            
            
            7.7$2.23
                - $3.55
            
            
            453,280
            
            
            7.0
            
            
            80,280
            
            
            2.6$3.62
            
            
            1,000,000
            
            
            3.9
            
            
            -
            
            
            -$4.45
                - $4.70
            
            
            667,500
            
            
            8.9
            
            
            13,333
            
            
            5.1$5.19
                - $5.54
            
            
            200,000
            
            
            4.9
            
            
            140,000
            
            
            4.2$0.25
                - $5.54
            
            
            4,862,776
            
            
            4.6
            
            
            2,775,609
            
            
            3.4





**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, 2006.




65


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 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, 2006, letters
      of credit in the amount of $1,116,100 were outstanding to the Michigan
      Supervisor of Wells.





**Employment
      Agreement**





Effective
      June 19, 2006, the Company hired Ronald E. Huff to serve as Chief Financial
      Officer of the Company. The Company has entered into 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 remains 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. If his
      employment with the Company is terminated prior to this date without just cause
      or if the Company undergoes a change in control, he will nonetheless be awarded
      the full 500,000 shares. If his employment is terminated prior to June 18,
      2008,
      due to death or disability, he will receive a prorated stock award. Mr. Huff
      forfeited the option to purchase 200,000 shares that he was previously awarded
      for his service as a director of the Company. Mr. Huff remains a director of
      the
      Company.





**Expiration
      of Pending Acquisition**





On
      May 9,
      2006, North signed a letter of intent with a third party to acquire oil and
      natural gas leases, working interests, and interests in related pipelines and
      production facilities that are located in the Michigan Antrim shale. This
      encompasses two projects that were still in development, but already are
      generating some production. On June 30, 2006, the letter of intent was amended
      to extend the due diligence effort through September 30, 2006, with
      anticipated closing of the transaction on or before November 15, 2006. Based
      upon further evaluation, the Company allowed the letter of intent to expire
      and
      does not intend to pursue the acquisition.





**NOTE
              12.**
            **R****ELATED
                PARTY TRANSACTIONS**





William Deneau,
      Thomas Tucker, and John Miller, who are officers , are all 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.





On
      September 7, 2004, the Patricia A. Deneau Trust, DTD 10/12/95, borrowed
      $100,000 from an Aurora subsidiary to purchase shares of Aurora common stock
      from an Aurora shareholder. This trust is controlled by William W. Deneau.
      The
      loan was evidenced by an unsecured demand promissory note bearing interest
      at
      the rate of 4.5% per year. The promissory note has been repaid in full as
      of May 2006. The shares purchased by the trust were subsequently sold by the
      trust to a company employee.




66


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


Kevin
      D.
      Stulp, a director, owns a 33 1/3% working interest in ten wells drilled and
      operated by TN Oil Company (six of which are dry). The Company owns
      650,000 shares of TN Oil Company at a cost of $65,000, which represents
      approximately a 14% equity interest in TN Oil Company.





In
      order
      to replace the collateral pledged to Northwestern Bank for the revolving line
      of
      credit, on December 21, 2005, The Denthorn Trust, which is controlled by William
      W. Deneau, executed a Commercial Guaranty of the Company’s obligation on the
      Northwestern Bank revolving line of credit, and a Commercial Pledge Agreement
      pursuant to which The Denthorn Trust has pledged to Northwestern Bank 306,450
      shares of our common stock to secure payment of the Company’s indebtedness. Also
      on December 21, 2005, the Patricia A. Deneau Trust, DTD 10/12/95, which is
      controlled by William W. Deneau, executed a Commercial Guaranty and a Commercial
      Pledge Agreement, pursuant to which it pledged 2,944,800 shares of our common
      stock to Northwestern Bank to secure payment of the Company’s indebtedness. (See
      Note 7 “Debt.”)





At
      the
      time of the merger, Aurora had a lease for office and storage space from
      South 31, L.L.C. William W. Deneau and Thomas W. Tucker each 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.





**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 year ended December 31, 2006, the Company contributed $42,350 as a
      discretionary matching contribution.





***2007
      Incentive Bonus Plan***





The
      Company has adopted an incentive bonus plan for the year 2007. The incentive
      bonus plan is available to all full-time employees, excluding officers and
      employees of subsidiaries. The bonus will be up to 10% of eligible employees’
compensation during the year 2007 if certain objectives are met.





**NOTE
              14.**
            **OIL
                AND NATURAL GAS PROPERTIES HELD FOR
                SALE**





Management
      is currently in the process of evaluating the Company’s property portfolio to
      ensure that the oil and natural gas properties portfolio properly matches the
      Company’s long-term strategic plan. During the second quarter of 2006, the
      Company identified certain leasehold properties as held for sale due to their
      high probability of being sold within the next 12 months. Total oil and natural
      gas properties held for sale before depletion amounted to $8,896,568 at December
      31, 2006, of which $7,202,622 is proved and $1,693,946 is unproved. (See Note
      6
“Acquisitions and Dispositions.”) These properties are carried at the lower of
      historical cost or fair value. Under the full cost method, sales of oil and
      natural gas properties, whether or not being amortized currently, are accounted
      for as adjustments of capitalized costs with no gain or loss recognized unless
      such adjustments would significantly alter the relationship between capitalized
      costs and proved reserves. The Company has evaluated the proved reserves of
      these properties (1,046 mmcfe as of December 31, 2006) and determined that
      there
      is no significant effect on the proved reserves regarding the assets held for
      sale. In 2005, no properties were classified as held for sale.




67


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


**NOTE
              15.**
            **FOURTH
                QUARTER ADJUSTMENTS**





During
      the fourth quarter of 2006, the Company modified its approach to estimating
      capitalized interest. The Company’s original accounting approach was to estimate
      capitalized interest by identifying specific assets to specific debt. Thus,
      if
      debt was not drawn down in a month, no interest was capitalized. However,
      applicable accounting principles and related guidance provide that the debt
      need
      not be specific debt incurred on the asset. Therefore, a company may capitalize
      interest cost even though the entire development or construction cost of the
      asset was paid in cash, so long as the company has incurred some form of cost
      of
      capital. This change in estimate resulted in additional $3.2 million of
      capitalized interest for the entire fiscal year which was recorded in the fourth
      quarter; of this amount, $1.9 million related to prior quarters.





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
              16.**
            **SUBSEQUENT
                EVENT**





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. As of
      December 31, 2006, the properties included two net wells and approximately
      23,110 net acres. This transaction closed on March 9, 2007.




68


AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


SUPPLEMENTAL
      INFORMATION ON OIL AND NATURAL


GAS
      EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES


(Unaudited)





***Supplemental
      Reserve Information*** .
      The
      following information presents estimates of our proved oil and natural gas
      reserves. 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, 2006,
      and 2005. Included in the tables that follow 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 acquired proved reserves were estimated by Netherland,
      Sewell & Associates, Inc. and Ralph E. Davis Associates, Inc., respectively.
      Crude oil and natural gas reserves at December 31, 2006, and 2005, were
      estimated under the Securities and Exchange Commission (“SEC”) reporting
      standards.





Estimates
                of Proved Reserves
            
            Oil
                (mbbl)
            
            Natural
                Gas (mmcf)Proved
                reserves as of December 31, 2004
            
            
            -
            
            
            34,949Revisions
                of previous estimates
            
            
            6
            
            
            5,382Purchases
                of minerals in place
            
            
            103
            
            
            1,572Extensions
                and discoveries
            
            
            -
            
            
            22,107Production
            
            
            (10
            )
            
            (688
            )Proved
                reserves as of December 31, 2005
            
            
            99
            
            
            63,322Revisions
                of previous estimates
            
            
            (40
            )
            
            4,880Purchases
                of minerals in place
            
            
            -
            
            
            22,843Extensions
                and discoveries
            
            
            45
            
            
            65,095Production(a)
            
            
            (23
            )
            
            (2,511
            )Sales
                of minerals in place
            
            
            -
            
            
            (665
            )Proved
                reserves as of December 31, 2006
            
            
            81
            
            
            152,964Proved
                developed reserves:December
                31, 2005
            
            
            70
            
            
            45,205December
                31, 2006
            
            
            54
            
            
            82,580





(a)  Production
      for 2006 does not reflect 142 mcfe of production the Company received in
      association with certain non-operated wells excluded in the year end reserve
      report.





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





2006
            
            2005Natural
                gas (per mmbtu)
            
            $
            5.84
            
            $
            9.89Oil
                (per barrel)
            
            $
            57.81
            
            $
            56.41





69


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


**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 crude 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 crude 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 crude 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.





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 Standardized Measure of Discounted Future Net
      Cash Flows from projected production of the Company’s crude oil and natural gas
      reserves for the years ended December 31, 2006, and 2005.





2006
            
            2005Future
                gross revenues (1)
            
            $
            884,186,810
            
            $
            632,058,720Future
                production costs (2)
            
            
            (378,345,360
            )
            
            (182,710,406
            )Future
                development costs (2)
            
            
            (37,324,420
            )
            
            (15,073,590
            )Future
                net cash flows before income taxes
            
            $
            468,517,030
            
            $
            434,274,724Future
                income tax expense (3)
            
            
            (83,566,133
            )
            
            (101,521,160
            )Future
                net cash flows after income taxes
            
            $
            384,950,897
            
            $
            332,753,564Discount
                at 10% per annum
            
            
            (254,489,076
            )
            
            (179,885,324
            )Standardized
                measure of discounted future net cash flows relating to proved oil
                and
                natural gas reserves
            
            $
            130,461,821
            
            $
            152,868,240





(1)
            Crude
                oil and natural gas revenues are based on year-end prices 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. 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 tax carryforwards.




70




AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES


SUPPLEMENTAL
      INFORMATION ON OIL AND NATURAL


GAS
      EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES


(Unaudited)





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





The
      following table sets forth the changes in Standardized Measure of Discounted
      Future Net Cash Flows for the years ended December 31, 2006, and
      2005.





2006
            
            2005Beginning
                balance
            
            $
            152,868,240
            
            $
            32,159,710Revisions
                to reserves proved in prior years:Net
                change in prices and production costs
            
            
            (113,774,170
            )
            
            85,425,515Net
                changes in future development costs
            
            
            (802,360
            )
            
            6,299,524Net
                changes due to revisions in quantity estimates
            
            
            3,484,229
            
            
            33,335,739Net
                change in accretion of discount
            
            
            19,950,751
            
            
            (66,761,600
            )Other
            
            
            (15,976,530
            )
            
            38,137,602Total
                revisions to reserves provided in prior years
            
            
            (107,118,080
            )
            
            96,436,780New
                discoveries and extensions, net of future development and production
                costs
            
            
            62,343,872
            
            
            76,487,826Purchases
                of minerals in place
            
            
            23,605,950
            
            
            11,834,500Sales
                of oil and natural gas produced, net of production costs
            
            
            (4,756,826
            )
            
            (4,696,416
            )Previously
                estimated development costs incurred
            
            
            (14,436,361
            )
            
            -Net
                change in income taxes
            
            
            17,955,026
            
            
            (59,354,160
            )Net
                change in standardized measure of discounted cash flows
            
            
            (22,406,419
            )
            
            120,708,530Ending
                balance
            
            $
            130,461,821
            
            $
            152,868,240





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





The
      following table sets forth the capitalized costs relating to the Company’s
      natural gas and crude oil producing activities at December 31, 2006, and
      2005.





2006
            
            2005Proved
                properties
            
            $
            128,381,121
            
            $
            39,643,003Unproved
                properties
            
            
            43,541,472
            
            
            37,279,889Total
                oil and natural gas properties
            
            
            171,922,593
            
            
            76,922,892Less
                accumulated depreciation, depletion, and amortization
            
            
            (10,628,438
            )
            
            (7,962,138
            )Oil
                and natural gas properties—net
            
            $
            161,294,155
            
            $
            68,960,754





71


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




**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.





The
      following table sets forth capitalized costs incurred related to the Company’s
      oil and natural gas activities for the years ended December 31, 2006, and
      2005.




2006
              
              2005Property
                  acquisition costsProved
              
              $
              24,011,335
              
              $
              22,763,734Unproved
              
              
              27,554,145
              
              
              19,607,099Exploration
              
              
              8,347,848
              
              
              781,586Development
              
              
              46,575,829
              
              
              29,707,367Total
                  costs incurred(a)
              
              
              106,489,157
              
              
              72,859,786Sales
                  of oil and natural gas properties
              
              
              (11,489,456
              )
              
              (11,504,428
              )Total
              
              $
              94,999,701
              
              $
              61,355,358





(a)  Total
      costs incurred include (i) capitalized general and administrative costs
      directly associated with the acquisition, exploration, and development efforts
      of approximately $1.3 million and $0 million for years ended December 31, 2006,
      and 2005, respectively, and (ii) interest expense on unproven properties of
      $3.9 million and $1.1 million for years ended December 31, 2006, and 2005,
      respectively. Certain non-cash transactions are included as follows:
      (1) 2006 asset retirement obligation and capitalized stock compensation of
      $1.3 million and $0.45 million, respectively, (2) net transfer of $0.31 million
      from 2005 deposits to 2006 oil and natural gas properties, and (3) the 2005
      fair market value of properties received from Cadence in the merger valued
      at
      $22.4 million.




**Results
      of Operations**





The
      following table sets forth the results of operations related to natural gas
      activities for the Company for the years ended December 31, 2006, and
      2005.





2006
            
            2005Oil
                and natural gas sales
            
            $
            21,591,811
            
            $
            6,743,444Production
                and lease operating costs
            
            
            (7,155,450
            )
            
            (2,093,840
            )Depreciation
                and depletion
            
            
            (2,681,290
            )
            
            (767,511
            )Results
                of producing activities
            
            $
            11,755,071
            
            $
            3,882,093





These
      results of operations do not include a provision for income taxes due to the
      net
      operating loss carryforward available to offset taxable income during both
      2006
      and 2005.




72


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




None.





**ITEM
      8A.**  **CONTROLS
      AND PROCEDURES**




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




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, 2006, 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 Annual
      Report on Form 10-KSB 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.





***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. Our management continues to review our internal controls and
      procedures and the effectiveness of those controls. In the fourth quarter,
      the
      Company formally initiated the process of documenting internal controls over
      financial reporting in an effort to be in compliance with the evaluation and
      reporting requirements of the Sarbanes-Oxley Act of 2002 Section 404 by December
      31, 2007.





**ITEM
      8B.**  **OTHER
      INFORMATION**




Not
      applicable.




73


**PART
      III**




**ITEM
      9.**  **DIRECTORS,
      EXECUTIVE OFFICERS, PROMOTERS, AND CONTROL PERSONS; COMPLIANCE WITH SECTION
      16(a) OF THE EXCHANGE ACT**




Pursuant
      to instruction E.3 of Form 10-KSB, the information required by this Item will
      be
      set forth in the Company’s definitive proxy statement which will be filed not
      later than 120 days after the end of the Company’s fiscal year.





**ITEM
      10.**  **EXECUTIVE
      COMPENSATION**




Pursuant
      to instruction E.3 of Form 10-KSB, the information required by this Item will
      be
      set forth in the Company’s definitive proxy statement which will be filed not
      later than 120 days after the end of the Company’s fiscal year.





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




Pursuant
      to instruction E.3 of Form 10-KSB, the information required by this Item will
      be
      set forth in the Company’s definitive proxy statement which will be filed not
      later than 120 days after the end of the Company’s fiscal year.





**ITEM
      12.**  **CERTAIN
      RELATIONSHIPS AND RELATED TRANSACTIONS**




Pursuant
      to instruction E.3 of Form 10-KSB, the information required by this Item will
      be
      set forth in the Company’s definitive proxy statement which will be filed not
      later than 120 days after the end of the Company’s fiscal year.





**ITEM
      13.**  **EXHIBITS**


3.1(1)
              
              Restated
                  Articles of Incorporation of Aurora Oil & Gas
                  Corporation.*3.2
              
              Bylaws
                  of Aurora Oil & Gas Corporation.10.1
              
              Securities
                  Purchase Agreement between Cadence Resources Corporation and the
                  investors
                  signatory thereto, dated April 2, 2004 (filed as Exhibit 99.3 to
                  our
                  Current Report on Form 8-K filed with the SEC on April 5, 2004,
                  and
                  incorporated herein by reference.)10.2
              
              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.)10.3(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, 2006.10.4
              
              Note
                  Purchase Agreement between Aurora Antrim North, LLC et al. and
                  TCW Asset
                  Management Company, dated August 12, 2004 (filed as an Exhibit to our
                  Form S-4 registration statement filed with the SEC on May 13, 2005,
                  and incorporated herein by reference.)10.5
              
              First
                  Amended and Restated Note Purchase Agreement between Aurora Antrim
                  North,
                  LLC et al. and TCW Asset Management Company, dated December 8, 2005
                  (filed as an Exhibit to our Annual 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.)10.6(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, 2006.10.7(2)
              
              Credit
                  Agreement among Aurora Antrim North, L.L.C., et al. and BNP Paribas,
                  et al., dated January 31, 2006.10.8(2)
              
              Intercreditor
                  and Subordination Agreement among BNP Paribas, et al., TCW Asset
                  Management Company, and Aurora Antrim North, L.L.C., dated
                  January 31, 2006.10.9(2)
              
              Promissory
                  Note from Aurora Energy, Ltd. to Northwestern Bank dated January 31,
                  2006.10.10(2)
              
              Confirmation
                  from BNP Paribas to Aurora Antrim North, L.L.C., dated February 22,
                  2006 relating to gas sale commitment.10.11
              
              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.)
  74
  10.12(1)
              
              Employment
                  Agreement with Ronald E. Huff dated June 19, 2006.10.13(1)
              
              Letter
                Agreement with Bach Enterprises dated July 10, 2006.  This Agreement
                is confidential and has been filed separately with SEC.10.14(1)
              
              First
                  Amendment to Credit Agreement between Aurora Antrim North, L.L.C.,
                  et al. and BNP Paribas dated July 14, 2006.10.15(1)
              
              The
                  Denthorn Trust Commercial Guaranty of obligations to Northwestern
                  Bank.10.16(1)
              
              William
                  W. Deneau Commercial Guaranty of obligations to Northwestern
                  Bank.10.17(1)
              
              The
                  Denthorn Trust Commercial Pledge Agreement to Northwestern
                  Bank.10.18(3)
              
              LLC
                  Membership Interest Purchase Agreement dated October 6, 2006 relating
                  to
                  Kingsley Development Company, L.L.C.10.19(3)
              
              Asset
                  Purchase Agreement with Bach Enterprises, Inc., et al., dated October
                  6,
                  2006.10.20(3)
              
              Promissory
                  Note from Aurora Energy, Ltd. to Northwestern Bank dated October
                  15,
                  2006.10.21(3)
              
              Form
                  of indemnification letter agreement between Aurora Oil & Gas
                  Corporation and Rubicon Master Fund.10.22(3)
              
              Patricia
                  A. Deneau Trust Commercial Guaranty of obligations to Northwestern
                  Bank.10.23(3)
              
              Patricia
                  A. Deneau Trust Commercial Pledge Agreement to Northwestern
                  Bank.*10.24
              
              Second
                  Amendment to Credit Agreement between Aurora Antrim North, L.L.C.,
                  et al
                  and BNP Paribas dated December 21, 200614.1
              
              Code
                  of Conduct and Ethics (filed as an exhibit to our Current Report
                  on Form
                  8-K filed with the SEC on February 15, 2006, and incorporated herein
                  by
                  reference.)21.1(3)
              
              List
                  of Subsidiaries.*23.1
              
              Consent
                  of Rachlin Cohen & Holtz LLP.*31.1
              
              Rule
                  13a-14(a) Certifications 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.




*
      Filed
      with this Form 10-KSB.




(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.





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




Pursuant
      to instruction E.3 of Form 10-KSB, the information required by this Item will
      be
      set forth in the Company’s definitive proxy statement which will be filed not
      later than 120 days after the end of the Company’s fiscal year.




75





**SIGNATURES**





In
      accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934,
      the
      registrant has duly caused this annual report on Form 10-KSB to be signed on
      its
      behalf by the undersigned thereto duly authorized.


**AURORA
              OIL
              & GAS CORPORATION**Date:
              March 15, 2007
            By:
            /s/
              William W. DeneauName:William
              W. DeneauTitle:President





Pursuant
      to the requirements of the Securities Exchange Act of 1934, this annual report
      on Form 10-KSB 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
              
              President,
                  Chairman and Director
              
              March
                  15, 2007William
                  W. Deneau
              
              (Principal
                  Executive Officer)/s/
                  Ronald E Huff
              
              Chief
                  Financial Officer
              
              March
                  15, 2007Ronald
                  E. Huff
              
              (Principal
                  Financial Officer and Principal Accounting Officer)/s/
                  Richard M. Deneau
              
              Director
              
              March
                  15, 2007Richard
                  M. Deneau/s/
                  Gary J. Myles
              
              Director
              
              March
                  15, 2007Gary
                  J. Myles/s/
                  Wayne G. Schaeffer
              
              Director
              
              March
                  15, 2007Wayne
                  G. Schaeffer/s/
                  Kevin D. Stulp
              
              Director
              
              March
                  15, 2007Kevin
                  D. Stulp/s/
                  Earl V. Young
              
              Director
              
              March
                  15, 2007Earl
                  V. Young
 76