**UNITED
      STATES**


**SECURITIES
      AND EXCHANGE COMMISSION**


**Washington,
      D.C. 20549**




**FORM
      10-K**




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




For
      the
      fiscal year ended March 31, 2007


or


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




For
      the
      transition period from __________ to __________




Commission
      file number: **000-51425**




**RANCHER
      ENERGY CORP.**


(Exact
      name of registrant as specified in its charter)




Nevada
            98-0422451(State
                or other jurisdiction of
              incorporation
                or organization)
            (I.R.S.
                Employer
              Identification
                Number)





999-18th
                Street, Suite 1740
              Denver,
                Colorado 80202(Address
                of principal executive offices, including zip
                code)





(303)
                629-1125(Telephone
                number, including area code)





**Securities
      registered pursuant to Section 12(b) of the Act:**  **None.**




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


Title
                of each classCommon
                Stock, par value $0.00001 per share




Indicate
      by check mark if the registrant is a well-known seasoned issuer, as defined
      in
      Rule 405 of the Securities Act.  Yes £ No R




Indicate
      by check mark if the registrant is not required to file reports pursuant to
      Section 13 or Section 15(d) of the Act.  Yes £ No R




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




Indicate
      by check mark if disclosure of delinquent filers pursuant to Item 405 of
      Regulation S-K (Section 229.405 of this chapter) is not contained herein, and
      will not be contained, to the best of registrant’s knowledge, in definitive
      proxy or information statements incorporated by reference in Part III of this
      Form 10-K or any amendment to this Form 10-K. £




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




Large
                accelerated filer £
            Accelerated
                filerR
            Non-accelerated
                filer £




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




The
      aggregate market value of the voting and non-voting common equity held by
      non-affiliates computed by reference to the price at which the common equity
      was
      last sold, or the average bid and asked price of such common equity, as of
      the
      last business day of the registrant’s most recently completed second fiscal
      quarter ended September 30, 2006 was $83,142,808.




The
      number of shares outstanding of the registrant’s common stock as of
      June 28, 2007 was 105,528,852.




**DOCUMENTS
      INCORPORATED BY REFERENCE**




Portions
      of the Registrant’s Proxy Statement for the 2007 Annual Meeting of Stockholders
      are incorporated by reference into Part III of this Report.















**TABLE
      OF CONTENTS**


**PAGE
      NO.**


PART
                  I
              
              1Item
                  1.
              Business.
              2Item
                  1A.
              Risk
                  Factors.
              8Item
                  1B.
              Unresolved
                  Staff Comments.
              15Item
                  2.
              Properties.
              16Item
                  3.
              Legal
                  Proceedings.
              19Item
                  4.
              Submission
                  of Matters to a Vote of Security Holders.
              19PART
                  II
              
              20Item
                  5.
              Market
                  for Registrant’s Common Equity, Related Stockholder Matters and Issuer
                  Purchases of Equity Securities.
              20Item
                  6.
              Selected
                  Financial Data.
              25Item
                  7.
              Management’s
                  Discussion and Analysis of Financial Condition and Results of
                  Operations.
              26Item
                  7A.
              Quantitative
                  and Qualitative Disclosures About Market Risk.
              42Item
                  8.
              Financial
                  Statements and Supplementary Data.
              43Item
                  9.
              Changes
                  in and Disagreements with Accountants on Accounting and Financial
                  Disclosure.
              43Item
                  9A.
              Controls
                  and Procedures.
              43Item
                  9B.
              Other
                  Information.
              52PART
                  III
              
              53Item
                  10.
              Directors,
                  Executive Officers and Corporate Governance.
              53Item
                  11.
              Executive
                  Compensation.
              53Item
                  12.
              Security
                  Ownership of Certain Beneficial Owners and Management and Related
                  Stockholder Matters.
              53Item
                  13.
              Certain
                  Relationships and Related Transactions, and Director
                  Independence.
              53Item
                  14.
              Principal
                  Accountant Fees and Services.
              53PART
                  IV
              
              54Item
                  15.
              Exhibits,
                  Financial Statement Schedules.
              54


For
      abbreviations on definitions of certain terms used in the oil & gas industry
      and in this Annual Report, please refer to the section entitled “Glossary of
      Abbreviations and Terms” in Item 1 Business.




As
      used
      in this document, references to “Rancher Energy”, “our company”, “the Company”,
“we”, “us”, and “our” refer to Rancher Energy Corp. and its wholly-owned
      subsidiary. In this Annual Report, the “Cole Creek South Field” also is referred
      to as the “South Cole Creek Field”.








**PART
      I**




**CAUTIONARY
      STATEMENT REGARDING FORWARD-LOOKING STATEMENTS**




The
      statements contained in this Annual Report on Form 10-K that are not historical
      are “forward-looking statements”, as that term is defined in 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), that involve a number of risks and uncertainties.




These
      forward-looking statements include, among others, the following:




•
            
            business
                strategy;




•
            
            CO2availability, deliverability, and tertiary production
                targets;




•
            
            inventories,
                projects, and programs;





•
            
            other
                anticipated capital expenditures and
                budgets;





•
            
            future
                cash flows and borrowings;





•
            
            the
                availability and terms of
                financing;




•
            
            oil
                reserves;





•
            
            reservoir
                response to CO2injection;




•
            
            ability
                to obtain permits and governmental approvals;




•
            
            technology;




•
            
            financial
                strategy;




•
            
            realized
                oil prices;




•
            
            production;




•
            
            lease
                operating expenses, general and administrative costs, and finding
                and
                development costs;




•
            
            availability
                and costs of drilling rigs and field services;




•
            
            future
                operating results; and




•
            
            plans,
                objectives, expectations, and intentions.





These
      statements may be found under “Risk Factors”, “Management’s Discussion and
      Analysis of Financial Condition and Results of Operations”, “Business”,
“Properties” and other sections of this Annual Report. Forward-looking
      statements are typically identified by use of terms such as “may”, “could”,
“should”, “expect”, “plan”, “project”, “intend”, “anticipate”, “believe”,
“estimate”, “predict”, “potential”, “pursue”, “target” or “continue”, the
      negative of such terms or other comparable terminology, although some
      forward-looking statements may be expressed differently.




The
      forward-looking statements contained in this Annual Report are largely based
      on
      our expectations, which reflect estimates and assumptions made by our
      management. These estimates and assumptions reflect our best judgment based
      on
      currently known market conditions and other factors. Although we believe such
      estimates and assumptions to be reasonable, they are inherently uncertain and
      involve a number of risks and uncertainties that are beyond our control. In
      addition, management’s assumptions about future events may prove to be
      inaccurate. Management cautions all readers that the forward-looking statements
      contained in this Annual Report are not guarantees of future performance, and
      we
      cannot assure any reader that such statements will be realized or the
      forward-looking events and circumstances will occur. Actual results may differ
      materially from those anticipated or implied in the forward-looking statements
      due to the factors listed in the “Risk Factors” section and elsewhere in this
      Annual Report. All forward-looking statements speak only as of the date of
      this
      Annual Report. We do not intend to publicly update or revise any forward-looking
      statements as a result of new information, future events or otherwise. These
      cautionary statements qualify all forward-looking statements attributable to
      us
      or persons acting on our behalf.




1




**ITEM
      1.**  **BUSINESS.**




**The
      Company**




We
      are an
      independent energy company engaged in the development, production, and marketing
      of oil & gas in North America. Our business strategy is to use modern
      tertiary recovery techniques on older, historically productive fields with
      proven in-place oil & gas. Higher oil & gas prices, and advances in
      technology such as 3-D seismic acquisition and evaluation and carbon dioxide
      (CO 2 ) injection, should enable us to capitalize on attractive sources of potentially
      recoverable oil & gas.




We
      operate three fields in the Powder River Basin, Wyoming, which is located in
      the
      Rocky Mountain region of the United States. The fields, acquired in
      December 2006 and January 2007, are the South Glenrock B Field, the
      Big Muddy Field, and the Cole Creek South Field. All three fields currently
      produce some oil and are CO 2 tertiary
      recovery candidates. We plan to substantially increase production in our fields
      by using CO 2 injection
      and other enhanced oil recovery (EOR) techniques. To
      fund
      the acquisition of the three fields and our operating expenses, from June 2006
      through January 2007, we sold $89,300,000 of our securities in two private
      placements. In December 2006, we also entered into an agreement with the
      Anadarko Petroleum Corporation to supply us with CO 2 needed
      to
      conduct CO 2 tertiary
      recovery operations in our three fields. We are in the process of planning
      for a
      pipeline to transport the CO 2 to our
      fields and for infrastructure improvements to implement EOR
      techniques.




Led
      by an
      experienced management team, our long term goal is to enhance stockholder value
      by identifying and further developing productive oil & gas assets across
      North America, particularly in the Rocky Mountains. Our headquarters office
      is
      located in Denver, Colorado and our field office is located in Glenrock,
      Wyoming. We have 25 employees.




Incorporation
      and Organization





We
      were
      incorporated on February 4, 2004, as Metalex Resources, Inc., in the State
      of Nevada. Prior to April 2006, we were engaged in the exploration of a
      gold prospect in British Columbia, Canada. Metalex found no commercially
      exploitable deposits or reserves of gold. During April 2006, our
      stockholders voted to change our name to Rancher Energy Corp. Since
      April 2006, we have employed a new Chief Executive Officer, Chief Operating
      Officer, Chief Financial Officer and Senior Vice President, Engineering, and
      have been actively pursuing oil & gas prospects in the Rocky Mountain
      region.




**Business
      Strategy**




As
      part
      of our corporate strategy, we believe in the following fundamental
      principles:




·
            Pursue
                attractive reserve and leasehold acquisitions that provide the opportunity
                for the use of EOR techniques, which offer significant upside potential
                while not exposing us to risks associated with drilling new field
                wildcat
                wells in frontier basins;




·
            Pursue
                selective complementary acquisitions of long-lived producing properties
                which include a high degree of operating control, and oil & gas
                entities that offer opportunities to profitably develop oil & gas
                reserves;




2




·
            Drive
                growth through technology and drilling by supplementing long-term
                reserve
                and production growth through the use of modern reservoir
                characterization, engineering, and production technology; and




·
            Maximize
                operational control by operating a significant portion of our assets
                and
                continuing to serve as operator of future properties when possible,
                giving
                us increased control over costs, timing, and all development, production,
                and exploration activities.




**Our
      Recent Acquisitions**




On
      January 4, 2007, we acquired the Big Muddy Field, which is located in the
      Powder River Basin east of Casper, Wyoming. The total purchase price was
      $25,000,000, and closing costs were $672,638.




On
      December 22, 2006, we purchased certain oil & gas properties for
      $46,750,000, before adjustments for the period from the effective date to the
      closing date, plus costs of $323,657 and warrants to purchase 250,000 shares
      of
      our common stock. The oil & gas properties consisted of (i) a 100% working
      interest (79.3% net revenue interest) in the Cole Creek South Field, which
      is
      located in Wyoming’s Powder River Basin; and (ii) a 93.6% working interest
      (74.5% net revenue interest) in the South Glenrock B Field, which also is
      located in Wyoming’s Powder River Basin.




**Our
      Development Program**




We
      have
      completed field studies and economic analyses of the Dakota, Lower Muddy, and
      Upper Muddy horizons in the South Glenrock B Field and the Wall Creek horizon
      of
      the Big Muddy Field, and have entered into a CO 2 supply
      agreement. We are also seeking arrangements for other CO 2 supplies.
      We are planning to proceed with the tertiary development of the South Glenrock
      B
      Field, subject to obtaining additional financing. Our planned order of
      development will be the South Glenrock B Field, the Big Muddy Field, and then
      the Cole Creek South Field.




**Oil
      & Gas Operations**




Our
      three
      fields are oil producing, as further described in Item 2, and are all candidates
      for EOR operations including CO 2 tertiary
      recovery.




CO 2 Tertiary
      Recovery




Our
      business strategy is to employ modern EOR technology to recover hydrocarbons
      that remain behind in mature reservoirs. The closing of our private placement
      of
      equity financing, the acquisition of the South Glenrock B Field, the Big Muddy
      Field, and the Cole Creek South Field located in the Powder River Basin, and
      entry into the CO 2 supply
      contract with Anadarko were important steps in executing our business strategy.
      Important next steps are to secure debt financing in a sufficient amount for
      our
      development program, complete the required environmental and regulatory
      permitting, build a spur pipeline to transport CO 2 from an
      existing CO 2 trunk
      pipeline to the Glenrock area, build out the field infrastructure appropriate
      for CO 2 flood
      operations, shoot 3-D seismic, and complete the necessary drilling and well
      work.




CO 2 injection is one of the most prevalent tertiary recovery mechanisms for
      producing light oil. The CO 2 ,
      at
      sufficient pressure, acts as a solvent for the oil causing the oil to be
      physically washed from the reservoir rock and produced. The CO 2 is then
      separated from the oil, compressed, and re-injected into the reservoir. This
      recycling process allows the reuse of the purchased CO 2 several
      times during the life of the tertiary operation. In a typical oil field, much
      of
      the original oil in place (OOIP) is left behind after primary production and
      waterflood operations. In many cases this is in the range of 50% to 75% of
      the
      OOIP. This oil, in mature reservoirs with extensive data and historic
      production, is the target of miscible EOR technology.




3




We
      intend
      to conduct a 3-D seismic survey on the South Glenrock B and Big Muddy Fields
      in
      conjunction with the CO 2 development program. The seismic information will be used to further define
      reservoir configuration and trapping, thus filling in gaps in the available
      information for our fields.




Anadarko
      CO 2 Supply Agreement




As
      part
      of our CO 2 tertiary
      recovery strategy, on December 15, 2006, we entered into a Product Sale and
      Purchase Contract (Purchase Contract) with Anadarko for the purchase of
      CO 2 (meeting
      certain quality specifications). We intend to use the CO 2 for our
      EOR projects.




The
      primary term of the Purchase Contract commences upon the later of
      January 1, 2008, or the date of the first CO 2 delivery,
      and terminates upon the earlier of the day on which we have taken and paid
      for
      the Total Contract Quantity, as defined, or 10 years from the commencement
      date.
      We have the right to terminate the Purchase Contract at any time with notice
      to
      Anadarko, subject to a termination payment as specified in the Purchase
      Contract.




During
      the primary term, the “Daily Contract Quantity” is 40 MMcf per day for a total
      of 146 Bcf. CO 2 deliveries are subject to a 25 MMcf per day take-or-pay provision. Anadarko
      has
      the right to satisfy its own needs before sales to us, which reduces our take
      or
      pay obligation. In the event the CO 2 does not
      meet certain quality specifications, we have the right to refuse delivery of
      such CO 2 .




For
      CO 2 deliveries, we have agreed to pay $1.50 per thousand cubic feet, to be adjusted
      by a factor that is indexed to the average posted price of Wyoming Sweet oil.
      From oil that is produced by CO 2 injection, we have also agreed to convey to Anadarko an overriding royalty
      interest that increases over time, not to exceed 5%.




In
      addition to the CO 2 supply
      arrangement with Anadarko, we plan to pursue the acquisition of additional
      daily
      volumes of CO 2 .
      Additional CO 2 supplies
      would be used to increase CO 2 injection rates, with the expectation that increased oil production rates would
      result.




CO 2 Pipeline Construction




Under
      the
      Purchase Contract with Anadarko, we have the responsibility for providing
      pipeline transportation of purchased CO 2 from a
      connection point on the Anadarko trunkline to our project area. We are
      evaluating alternatives to construct and operate the pipeline. We have engaged
      an engineering firm to study potential routes and configurations. Depending
      on
      the final route selection, the pipeline may range from 50 to 132 miles in
      length, and cost estimates range from $50 to $110 million.




We
      are
      exploring two options to finance construction of the pipeline. One option is
      to
      have a third party build, own, and operate the CO 2 pipeline. This operator would be reimbursed for operating expenses and capital
      investment by way of a transportation tariff on the CO 2 delivered, with the tariff varying as a function of throughput. The second
      option is for us to construct, own, and operate the pipeline. We would require
      additional capital for this option. We are currently planning to borrow funds
      to
      implement development of our fields, and we may include the funds necessary
      for
      construction of the CO 2 pipeline
      in a debt financing.




4




Anadarko
      currently is receiving CO 2 for its
      Salt Creek Field in Wyoming from the ExxonMobil Corporation through a 125-mile,
      16 inch pipeline constructed in 2004. ExxonMobil collects CO 2 from its
      natural gas fields at LaBarge, Wyoming, and processes the gas at its Shute
      Creek
      gas sweetening plant. ExxonMobil then transports the CO 2 to the
      origin of the pipeline for delivery to Anadarko’s Salt Creek Field.




**Financing
      Plans**




We
      are
      planning to obtain funding for the surface facility construction, 3-D seismic,
      well drilling and conversion, other development costs, the cost of purchasing
      and transporting CO 2 ,
      and
      potentially the CO 2 pipeline. We expect this financing will be primarily fixed term debt with a
      high
      interest rate secured by our properties. We also expect to arrange for a senior
      revolving debt facility supported by our proved oil reserves. Our goal is to
      close both debt financings in the third calendar quarter of 2007. Completion
      of
      these debt offerings will be subject to market conditions and Company-specific
      factors.




**Federal
      and State Regulations**




Numerous
      federal and state laws and regulations govern the oil & gas industry. These
      laws and regulations are often changed in response to changes in the political
      or economic environment. Compliance with this evolving regulatory burden is
      often difficult and costly, and substantial penalties may be incurred for
      noncompliance. The following section describes some specific laws and
      regulations that may affect us. We cannot predict the impact of these or future
      legislative or regulatory initiatives.




Based
      on
      current laws and regulations, management believes that we are and will be in
      substantial compliance with all laws and regulations applicable to our current
      and proposed operations and that continued compliance with existing requirements
      will not have a material adverse impact on us. The future annual capital costs
      of complying with the regulations applicable to our operations is uncertain
      and
      will be governed by several factors, including future changes to regulatory
      requirements. However, management does not currently anticipate that future
      compliance will have a material adverse effect on our consolidated financial
      position or results of operations.




Regulation
      of Oil Exploration and Production




Our
      operations are subject to various types of regulation at the federal, state,
      and
      local levels. Such 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 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 that may be drilled
      in
      those units and the unitization or pooling of oil & gas properties. In
      addition, state conservation laws establish maximum rates of production from
      oil
& gas wells and generally prohibit the venting or flaring of gas. The effect
      of these regulations may limit the amount of oil & gas we can produce from
      our wells and may limit the number of wells or the locations at which we can
      drill. The regulatory burden on the oil & gas industry increases our costs
      of doing business and, consequently, affects our profitability.




Federal
      Regulation of Sales Prices and Transportation




The
      transportation and certain sales of oil in interstate commerce are heavily
      regulated by agencies of the U.S. federal government and are affected by the
      availability, terms, and cost of transportation. In particular, the price and
      terms of access to pipeline transportation are subject to extensive U.S. federal
      and state regulation. The Federal Energy Regulatory Commission (FERC) is
      continually proposing and implementing new rules and regulations affecting
      the
      oil industry. The stated purpose of many of these regulatory changes is to
      promote competition among the various sectors of the oil & gas industry. The
      ultimate impact of the complex rules and regulations issued by FERC cannot
      be
      predicted. Some of FERC’s proposals may, however, adversely affect the
      availability and reliability of interruptible transportation service on
      interstate pipelines. While our sales of crude oil are not currently subject
      to
      FERC regulation, our ability to transport and sell such products is dependent
      on
      certain pipelines whose rates, terms, and conditions of service are subject
      to
      FERC regulation. Additional proposals and proceedings that might affect the
      oil
& gas 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.
      Historically, the oil & gas industry has been heavily regulated; therefore,
      there is no assurance that the less stringent regulatory approach recently
      pursued by FERC, Congress and the states will continue indefinitely into the
      future.




5




Federal
      or State Leases




Our
      operations on federal or state oil & gas leases are subject to numerous
      restrictions, including nondiscrimination statutes. Such operations must be
      conducted pursuant to certain on-site security regulations and other permits
      and
      authorizations issued by the Bureau of Land Management, Minerals Management
      Service (MMS), and other agencies.




Regulation
      of Proposed CO 2 Pipeline




Numerous
      federal and state regulations govern pipeline construction and operations.
      The
      primary pipeline construction permits may include environmental assessments
      for
      federal lands, right of way permits for fee and state lands, and oversight
      of
      ongoing pipeline operations by the U.S. Department of
      Transportation.




Environmental
      Regulations




Public
      interest in the protection of the environment has increased dramatically in
      recent years. Our oil production and CO 2 injection operations and our processing, handling, and disposal of hazardous
      materials such as hydrocarbons and naturally occurring radioactive materials
      (NORM) are subject to stringent regulation. 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 & gas exploration, development, and production
      operations, and consequently may impact our operations and costs. These
      regulations include, among others (i) regulations by the EPA and various state
      agencies regarding approved methods of disposal for certain hazardous and
      nonhazardous wastes; (ii) the Comprehensive Environmental Response,
      Compensation, and Liability Act, Federal Resource Conservation and Recovery
      Act,
      and analogous state laws that 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 result in the
      gradual imposition of certain pollution control requirements with respect to
      air
      emissions from the 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 naturally
      occurring radioactive material.




6




Management
      believes that we are in substantial compliance with applicable environmental
      laws and regulations and intend to remain in compliance in the future. To date,
      we have not expended any material amounts to comply with such regulations,
      and
      management does not currently anticipate that future compliance will have a
      material adverse effect on our consolidated financial position, results of
      operations, or cash flows.




**Available
      Information**




We
      make
      our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports
      on Form 8-K, and amendments to reports filed or furnished pursuant to Section
      13(a) or 15(d) of the Exchange Act available free of charge under the Investors
      Relations page on our website, www.rancher energy.com,
      as soon as reasonably practicable after such reports are electronically filed
      with, or furnished to, the SEC. Information on our website or any other website
      is not incorporated by reference in this Annual Report. Our SEC filings are
      also
      available through the SEC’s website, www.sec.gov ,
      and may
      be read and copied at the SEC’s Public Reference Room at 100 F Street, NE,
      Washington, D.C. 20549. Information regarding the operation of the Public
      Reference Room may be obtained by calling the SEC at
      1-800-SEC-0330.




**Glossary
      of Abbreviations and Terms**




**Anadarko.**
            The
                Anadarko Petroleum Corporation.**Bcf.**
            One
                billion cubic feet of natural gas at standard atmospheric
                conditions.**CO****2****.**
            Carbon
                Dioxide.**EOR.**
            Enhanced
                oil recovery.**Field.**
            An
                area consisting of either a single reservoir or multiple reservoirs,
                all
                grouped on or related to the same individual geological structural
                feature
                and/or stratigraphic condition.**MMcf.**
            One
                million cubic feet of natural gas.**Metalex.**
            Metalex
                Resources, Inc.**Miscible.**
            Capable
                of being mixed in all proportions. Water and oil are not miscible.
                Alcohol
                and water are miscible. CO2 and oil can be miscible under the
                proper conditions.**Proved
                reserves**.
            The
                estimated quantities of oil, natural gas, and natural gas liquids
                which
                geological and engineering data demonstrate with reasonable certainty
                to
                be commercially recoverable in future years from known reservoirs
                under
                existing economic and operating conditions.**Purchase
                Contract.**
            The
                Anadarko Product Sale and Purchase
                Contract.




7




**Tertiary
                recovery.**
            The
                third process used for oil recovery. Usually primary recovery is
                the
                result of depletion drive, secondary recovery is from a waterflood,
                and
                tertiary recovery is an enhanced oil recovery process such as
                CO2 flooding.**Working
                interest**.
            An
                interest in an oil & gas lease that gives the owner of the interest
                the right to drill and produce oil & gas on the leased acreage and
                requires the owner to pay a share of the costs of drilling and production
                operations. The share of production to which a working interest owner
                is
                entitled will always be smaller than the share of costs that the
                working
                interest owner is required to bear, with the balance of the production
                accruing to the owners of
                royalties.





**ITEM
      1A.**  **RISK
      FACTORS.**




You
      should carefully consider the risks described below, as well as the other
      information included or incorporated by reference in this Annual Report, before
      making an investment in our common stock. The risks described below are not
      the
      only ones we face in our business. Additional risks and uncertainties not
      presently known to us or that we currently believe to be immaterial may also
      impair our business operations. If any of the following risks occur, our
      business, financial condition, or operating results could be materially harmed.
      In such an event, our common stock could decline in price and you may lose
      all
      or part of your investment.




**Risks
      Related to our Industry, Business, and Strategy**




***We
      may not be able to develop the three Powder River Basin properties as we
      anticipate.***




Our
      plans
      to develop the properties are dependent on the construction of a CO 2 pipeline
      and a sufficient supply of CO 2 .
      We must
      arrange for the construction of a CO 2 pipeline
      on acceptable terms and build related infrastructure. The achievement of these
      objectives is subject to numerous uncertainties, including the raising of
      sufficient funding for the construction of key infrastructure and
      working capital, and our reliance on a third party to provide us the requisite
      CO 2 ,
      the
      supply of which is beyond our control. We may not be able to achieve these
      objectives on the schedule we anticipate or at all.




***Our
      production is dependent upon sufficient amounts of CO*** ***2*** ***and will decline if our access to sufficient amounts of
      CO*** ***2*** ***is limited.***




Our
      long-term growth strategy is focused on our CO 2 tertiary
      recovery operations. The crude oil production from our tertiary recovery
      projects depends on having access to sufficient amounts of CO 2 .
      Our
      ability to produce this oil would be hindered if our supply of CO 2 were
      limited due to problems with the supply, delivery, and quality of the supplied
      CO 2 ,
      problems with our facilities, including compression equipment, or catastrophic
      pipeline failure. Our agreement with our current sole supplier of CO 2 provides
      that before it delivers CO 2 to us,
      it may satisfy its own CO 2 needs.
      If we are not successful in obtaining the required amount of CO 2 to
      achieve crude oil production or the crude oil production in the future were
      to
      decline as a result of a decrease in delivered CO 2 supply,
      it could have a material adverse effect on our financial condition and results
      of operations and cash flows.




8




***If
      we are unable to obtain additional debt financing our business plans will not
      be
      achievable*** **.**




Our
      current cash position will not be sufficient to fund construction of the
      CO 2 pipeline, or the development of our three properties. We will require
      substantial additional funding. Our plan is to obtain debt financing. The terms
      of any debt financing may restrict our future business activities and
      expenditures. We do not know if additional financing will be available at all
      when needed or on acceptable terms. Insufficient funds will prevent us from
      implementing our tertiary recovery business strategy.




***Our
      development and tertiary recovery operations require substantial capital and
      we
      may be unable to obtain needed capital or financing on satisfactory terms,
      which
      could lead to a loss of properties and a decline in our oil reserves.***




The
      oil
      industry is capital intensive. We make and expect to continue to make
      substantial capital expenditures in our business and operations for the
      development, production, and acquisition of oil & gas reserves. To date, we
      have financed capital expenditures primarily with sales of our equity
      securities. We intend to finance our capital expenditures in the near term
      with
      debt financing. Our access to capital is subject to a number of variables,
      including:




·
            our
                proved reserves;


·
            the
                amount of oil we are able to produce from existing
                wells;


·
            the
                prices at which the oil is sold;
                and


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




We
      may,
      from time to time, need to seek additional financing following our anticipated
      debt financing, either in the form of increased bank borrowings, sales of debt
      or equity securities or other forms of financing, and there can be no assurance
      as to the availability or terms of any additional financing. Additionally,
      we
      may not be able to obtain debt or equity financing on terms favorable to us,
      or
      at all. A failure to obtain additional financing to meet our capital
      requirements could result in a curtailment of our operations relating to our
      tertiary recovery operations and development of our fields, which in turn could
      lead to a possible loss of properties, through foreclosure, if we are unable
      to
      meet the terms of our anticipated debt financing and/or forfeiture of the
      properties pursuant to the terms of their respective leases, and a decline
      in
      our oil reserves.




***We
      have a limited operating history in the oil business, and we cannot predict
      our
      future operations with any certainty.***




We
      were
      organized in 2004 to explore a gold prospect and in 2006 changed our business
      focus to oil & gas development using CO 2 injection technology. Our future financial results depend primarily on (i)
      our
      ability to finance and complete development of the required infrastructure
      associated with our three properties in the Powder River Basin, including having
      a pipeline built to deliver CO 2 to our
      fields and the construction of surface facilities on our fields; (ii) the
      success of our CO 2 injection program; and (iii) the market price for oil. We cannot predict that
      our future operations will be profitable. In addition, our operating results
      may
      vary significantly during any financial period.




***Oil
      prices are volatile and a decline in oil prices can significantly affect our
      financial results and impede our growth.***




Our
      revenues, profitability, and liquidity are substantially dependent upon prices
      for oil, which can be extremely volatile, and even relatively modest drops
      in
      prices can significantly affect our financial results and impede our growth.
      Prices for oil may fluctuate widely in response to relatively minor changes
      in
      the supply of and demand for oil, market uncertainty, and a wide variety of
      additional factors that are beyond our control, such as the domestic and foreign
      supply of oil; the price of foreign imports; the ability of members of the
      Organization of Petroleum Exporting Countries to agree to and maintain oil
      price
      and production controls; technological advances affecting energy consumption;
      domestic and foreign governmental regulations; and the variations between
      product prices at sales points and applicable index prices.




9




***We
      have incurred losses from operations in the past and expect to do so in the
      future.***




We
      have
      never been profitable. We incurred net losses of $8,702,255 and $124,453 for
      the
      fiscal years ended March 31, 2007 and March 31, 2006, respectively. We
      do not expect to be profitable during the fiscal year ending March 31,
      2008. Our acquisition and development of prospects will require substantial
      additional capital expenditures in the future. The uncertainty and factors
      described throughout this section may impede our ability to economically
      acquire, develop, and exploit oil reserves. As a result, we may not be able
      to
      achieve or sustain profitability or positive cash flows from operating
      activities in the future.




***We
      could be adversely impacted by changes in the oil
      market.***




The
      marketability of our oil production will depend in part upon the availability,
      proximity, and capacity of pipelines, and surface and processing facilities.
      Federal and state regulation of oil production and transportation, general
      economic conditions, changes in supply and changes in demand all could adversely
      affect our ability to produce and market oil. If market factors were to change
      dramatically, the financial impact could be substantial because we would incur
      expenses without receiving revenues from the sale of production. The
      availability of markets is beyond our control.




***We
      may be unable to develop additional reserves.***




Our
      ability to develop future revenues will depend on whether we can successfully
      implement our planned CO 2 injection program. We have no experience using CO 2 technology, the properties we plan to acquire have not been injected with
      CO 2 in the
      past, and recovery factors cannot be estimated with precision. Our planned
      projects may not result in significant proved reserves or in the production
      levels we anticipate.




***We
      are dependent on our management team and the loss of any of these individuals
      would harm our business.***




Our
      success is dependent, in large part, on the continued services of John Works,
      our President & Chief Executive Officer, John Dobitz, our Senior Vice
      President, Engineering, Andrew Casazza, our Chief Operating Officer, and Daniel
      P. Foley, our Chief Financial Officer. There is no guarantee that any of the
      members of our management team will remain employed by us. While we have
      employment agreements with them, their continued service cannot be assured.
      The
      loss of our senior executives could harm our business.




***Oil
      operations are inherently risky.***




The
      nature of the oil business involves a variety of risks, including the risks
      of
      operating hazards such as fires, explosions, cratering, blow-outs, encountering
      formations with abnormal pressure, pipeline ruptures and spills, and releases
      of
      toxic gas and other environmental hazards and pollution. The occurrence of
      any
      of these risks could result in losses. The occurrence of any one of these
      significant events, if it is not fully insured against, could have a material
      adverse effect on our financial position and results of operations.




10




***We
      are subject to extensive government regulations.***




Our
      business is affected by numerous federal, state, and local laws and regulations,
      including energy, environmental, conservation, tax and other laws and
      regulations relating to the oil industry. These include, but are not limited
      to:




·
            the
                prevention of waste;


·
            the
                discharge of materials into the
                environment;


·
            the
                conservation of oil;


·
            pollution;


·
            permits
                for drilling operations;


·
            underground
                gas injection permits;


·
            drilling
                bonds; and


·
            reports
                concerning operations, the spacing of wells, and the unitization
                and
                pooling of properties.




Failure
      to comply with any laws and regulations may result in the assessment of
      administrative, civil, and criminal penalties, the imposition of injunctive
      relief or both. Moreover, changes in any of these laws and regulations could
      have a material adverse effect on our business. In view of the many
      uncertainties with respect to current and future laws and regulations, including
      their applicability to us, we cannot predict the overall effect of such laws
      and
      regulations on our future operations.




***Government
      regulation and environmental risks could increase our
      costs.***




Many
      jurisdictions have at various times imposed limitations on the production of
      oil
      by restricting the rate of flow for oil wells below their actual capacity to
      produce. Our operations will be subject to stringent laws and regulations
      relating to environmental issues. These laws and regulations may require the
      acquisition of a permit before drilling commences, restrict the types,
      quantities, and concentration of materials that can be released into the
      environment in connection with drilling and production activities, limit or
      prohibit drilling activities in protected areas, and impose substantial
      liabilities for pollution resulting from our operations. Changes in
      environmental laws and regulations occur frequently, and changes could result
      in
      substantially increased costs. Because current regulations covering our
      operations are subject to change at any time, we may incur significant costs
      for
      compliance in the future.




***The
      properties we have acquired are located in the Powder River Basin in the Rocky
      Mountains, making us vulnerable to risks associated with operating in one major
      geographic area.***




Our
      activities are focused on the Powder River Basin in the Rocky Mountain region
      of
      the United States, which means our properties are geographically concentrated
      in
      that area. As a result, we may in the future be disproportionately exposed
      to
      the impact of delays or interruptions of production from these wells caused
      by
      significant governmental regulation, transportation capacity constraints,
      curtailment of production, or interruption of transportation of oil produced
      from the wells in this basin.




11




***Seasonal
      weather conditions adversely affect our ability to conduct drilling activities
      and tertiary recovery operations in some of the areas where we operate.***




Oil
&
      gas operations in the Rocky Mountains are adversely affected by seasonal weather
      conditions. In certain areas, drilling and other oil & gas activities can
      only be conducted during the spring and summer months. This limits our ability
      to operate in those areas and can intensify competition during those months
      for
      drilling rigs, oil field equipment, services, supplies, and qualified personnel,
      which may lead to periodic shortages. Resulting shortages or high costs could
      delay our operations and materially increase our operating and capital
      costs.




***Competition
      in the oil & gas industry is intense, which may adversely affect our ability
      to succeed.***




The
      oil
& gas industry is intensely competitive, and we compete with companies that
      are significantly larger and have greater resources. Many of these companies
      not
      only explore for and produce oil, but also carry on refining operations and
      market petroleum and other products on a regional, national, or worldwide basis.
      These companies may be able to pay more for oil properties and prospects or
      define, evaluate, bid for, and purchase a greater number of properties and
      prospects than our financial or human resources permit. Our larger competitors
      may be able to absorb the burden of present and future federal, state, local,
      and other laws and regulations more easily than we can, which would adversely
      affect our competitive position. Our ability to acquire additional properties
      and to increase reserves in the future will be dependent upon our ability to
      evaluate and select suitable properties and to consummate transactions in a
      highly competitive environment.




***Oil
      prices may be impacted adversely by new taxes.***




The
      federal, state, and local governments in which we operate impose taxes on the
      oil products we plan to sell. In the past, there has been a significant amount
      of discussion by legislators and presidential administrations concerning a
      variety of energy tax proposals. In addition, many states have raised state
      taxes on energy sources and additional increases may occur. We cannot predict
      whether any of these measures would have an adverse impact on oil
      prices.




***Shortages
      of equipment, supplies, and personnel, and delays in construction of the
      CO*** ***2***  ***pipeline,
      construction of surface facilities, and delivery of CO*** ***2***  ***could
      delay or otherwise adversely affect our cost of operations or our ability to
      operate according to our business plans.***




We
      may
      experience shortages of field equipment and qualified personnel and delays
      in
      the construction of the CO 2 pipeline, construction of surface facilities, and delivery of CO 2 ,
      which
      may cause delays in our ability to conduct tertiary recovery operations, and
      drill, complete, test, and connect wells to processing facilities. Additionally,
      these costs have sharply increased in various areas. The demand for and wage
      rates of qualified crews generally rise in response to the increased number
      of
      active rigs in service and could increase sharply in the event of a shortage.
      Shortages of field equipment or qualified personnel and delays in the
      construction of the CO 2 pipeline, construction of surface facilities, and delivery of CO 2 could
      delay, restrict, or curtail our exploration and development operations, which
      may materially adversely affect our business, financial condition, and results
      of operations.




***Shortages
      of transportation services and processing facilities may result in our receiving
      a discount in the price we receive for oil sales or may adversely affect our
      ability to sell our oil.***




We
      may
      experience limited access to transportation lines, trucks or rail cars in order
      to transport our oil to processing facilities. We may also experience limited
      processing capacity at our facilities. If either or both of these situations
      arise, we may not be able to sell our oil at prevailing market prices or we
      may
      be completely unable to sell our oil, which may materially adversely affect
      our
      business, financial condition, and results of operations.




12




***Estimating
      our reserves, production and future net cash flow is difficult to do with any
      certainty.***




Estimating
      quantities of proved oil & gas reserves is a complex process. It requires
      interpretations of available technical data and various assumptions, including
      assumptions relating to economic factors, such as future commodity prices,
      production costs, severance and excise taxes, capital expenditures and workover
      and remedial costs, and the assumed effect of governmental regulation. There
      are
      numerous uncertainties about when a property may have proved reserves as
      compared to potential or probable reserves, particularly relating to our
      tertiary recovery operations. Actual results most likely will vary from our
      estimates. Also, the use of a 10% discount factor for reporting purposes, as
      prescribed by the SEC, may not necessarily represent the most appropriate
      discount factor, given actual interest rates and risks to which our business
      or
      the oil & gas industry in general is subject. Any significant inaccuracies
      in these interpretations or assumptions or changes of conditions could result
      in
      a reduction of the quantities and net present value of our reserves.




Quantities
      of proved reserves are estimated based on economic conditions, including oil
      & gas prices in existence at the date of assessment. Our reserves and future
      cash flows may be subject to revisions based upon changes in economic
      conditions, including oil & gas prices, as well as due to production
      results, results of future development, operating and development costs, and
      other factors. Downward revisions of our reserves could have an adverse affect
      on our financial condition, operating results, and cash flows.




**Risks
      Related to our Common Stock**




***The
      trading market for our common stock is relatively new, so investors may have
      difficulty selling significant number of shares of our stock, and our stock
      price may decline.***




Our
      common stock is not traded on a national securities exchange. It has been traded
      on the OTC Bulletin Board since early 2006. The average daily trading volume
      of
      our common stock on the OTC Bulletin Board was approximately 219,000 shares
      per
      day over the three month period ended May 31, 2007. If there were only
      limited trading in our stock, the price of our common stock could be negatively
      affected and it could be difficult for investors to sell a significant number
      of
      shares in the public market.




Our
      capital raising activities are expected to involve the issuance of securities
      exercisable for or convertible into common stock, which would dilute the
      ownership of our existing stockholders and could result in a decline in the
      trading price of our common stock. We will need to obtain substantial additional
      financing, which may include sales of our securities, including common stock,
      warrants, and convertible debt securities, in order to fund our planned property
      acquisitions and development program. The issuance of such securities will
      result in the dilution of existing investors. Furthermore, we may enter into
      financing transactions at prices that represent a substantial discount to the
      market prices of our common stock. These transactions may have a negative impact
      on the trading price of our common stock.




***Sales
      of a substantial number of shares in the future may result in significant
      downward pressure on the price of our common stock and could affect the ability
      of our stockholders to realize the current trading price of our common stock.***




If
      our
      stockholders and new investors sell significant amounts of our stock, our stock
      price could drop. Even a perception by the market that the stockholders will
      sell in large amounts could place significant downward pressure on our stock
      price. In addition, the sale of these shares could impair our ability to raise
      capital through the sale of additional stock.




13




***Our
      stock price and trading volume may be volatile, which could result in losses
      for
      our stockholders.***




The
      equity trading markets may experience periods of volatility, which could result
      in highly variable and unpredictable pricing of equity securities. The market
      of
      our common stock could change in ways that may or may not be related to our
      business, our industry, or our operating performance and financial condition.
      In
      addition, the trading volume in our common stock may fluctuate and cause
      significant price variations to occur. Some of the factors that could negatively
      affect our share price or result in fluctuations in the price or trading volume
      of our common stock include:




·
            Actual
                or anticipated quarterly variations in our operating
                results;


·
            Changes
                in expectations as to our future financial performance or changes
                in
                financial estimates, if any;


·
            Announcements
                relating to our business or the business of our
                competitors;


·
            Conditions
                generally affecting the oil & gas
                industry;


·
            The
                success of our operating strategy;
                and


·
            The
                operating and stock performance of other comparable
                companies.




Many
      of
      these factors are beyond our control, and we cannot predict their potential
      effects on the price of our common stock. If the market price of our common
      stock declines significantly, you may be unable to resell your shares of common
      stock at or above the price you acquired those shares. We cannot assure you
      that
      the market price of our common stock will not fluctuate or decline
      significantly.




***There
      are risks associated with forward-looking statements made by us and actual
      results may differ.***




Some
      of
      the information in this Annual Report contains forward-looking statements that
      involve substantial risks and uncertainties. These statements can be identified
      by the use of forward-looking words such as “may”, “will”, “expect”,
“anticipate”, “believe”, “estimate”, and “continue”, or similar words.
      Statements that contain these words should be read carefully because
      they:




·
            discuss
                our future expectations;


·
            contain
                projections of our future results of operations or of our financial
                condition; and


·
            state
                other “forward-looking”
information.




We
      believe it is important to communicate our expectations. However, there may
      be
      events in the future that we are not able to accurately predict and/or over
      which we have no control. The risk factors listed in this section, other risk
      factors about which we may not be aware, as well as any cautionary language
      in
      this Annual Report, provide examples of risks, uncertainties, and events that
      may cause our actual results to differ materially from the expectations we
      describe in our forward-looking statements. The occurrence of the events
      described in these risk factors could have an adverse effect on our business,
      results of operations, and financial condition.




***NASD
      sales practice requirements limit a stockholders' ability to buy and sell our
      stock.***




The
      National Association of Securities Dealers, Inc. (NASD) has adopted rules that
      require that in recommending an investment to a customer, a broker-dealer must
      have reasonable grounds for believing that the investment is suitable for that
      customer. Prior to recommending speculative low priced securities to their
      non-institutional customers, broker-dealers must make reasonable efforts to
      obtain information about the customer’s financial status, tax status, investment
      objectives, and other information. Under interpretations of these rules, the
      NASD believes that there is a high probability that speculative low priced
      securities will not be suitable for at least some customers. The NASD
      requirements make it more difficult for broker-dealers to recommend that their
      customers buy our common stock, which has the effect of reducing the level
      of
      trading activity and liquidity of our common stock. Further, many brokers charge
      higher transactional fees for penny stock transactions. As a result, fewer
      broker-dealers are willing to make a market in our common stock, reducing a
      stockholders' ability to resell shares of our common stock.




14




***We
      do not expect to pay dividends in the foreseeable future. As a result, holders
      of our common stock must rely on stock appreciation for any return on their
      investment.***




We
      do not
      anticipate paying cash dividends on our common stock in the foreseeable future.
      Any payment of cash dividends will also depend on our financial condition,
      results of operations, capital requirements, and other factors and will be
      at
      the discretion of our Board of Directors. We also expect that if we obtain
      debt
      financing, there will be contractual restrictions on, or prohibitions against,
      the payment of dividends. Accordingly, holders of our common stock will have
      to
      rely on capital appreciation, if any, to earn a return on their investment
      in
      our common stock.




***If
      we are required to continue to make penalty payments with respect to
      registration and other obligations incurred as part of our recent private
      placement financing, such payments could have an adverse effect on our financial
      condition and liquidity and operating plans.***




In
      connection with our December 2006 and January 2007 equity private placement
      we
      entered into various agreements that obligate us to make payments to the
      investors if we fail to meet filing and other deadlines relating to the
      registration for resale of the shares of common stock and shares of common
      stock
      underlying the warrants sold in the private placement and other matters. The
      potential payments are detailed in Note 6 - Sale of Common Stock and
      Warrants to the Notes to Financial Statements of our audited financial
      statements for the fiscal year ended March 31, 2007 in Part IV,
      Item 15, of this Annual Report. We have recently made two penalty payments
      in shares due to a failure to obtain effectiveness of the registration statement
      and more penalty payments may need to be made in the future. The issuances
      of
      shares to the investors in the equity private placement will result in a
      dilution of the percentage ownership of the common stock held by our other
      stockholders. If we are required to make substantial payments, our liquidity
      and
      capital resources could be adversely affected as well as our operating
      plans.




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


On
        March
        19, 2007, we received a comment letter from the Staff of the SEC’s Division of
        Corporation Finance. The comments from the Staff were issued with respect
        to its
        review of (i) our Registration Statement on Form S-1 (File No. 333-141086)
        filed
        with the SEC on March 6, 2007 in conjunction with our December 2006 and January
        2007 equity private placement, (ii) our 10-Q for the quarter ended December
        31,
        2006, and (iii) our 8-K/A filed with the SEC on March 6, 2007 that included
        financial statements regarding our acquisitions of the Cole Creek South,
        South
        Glenrock B, and Big Muddy Fields. The Staff’s letter included comments relating
        to (i) the financial statements presented regarding the acquisitions of the
        properties, (ii) certain provisions, including penalty or liquidated damages
        provisions, set forth in the registration statement applicable to our December
        2006 and January 2007 equity private placement transaction documents, (iii)
        liability recognition for warrants, and (iv) the methodology for valuing
        stock
        options granted to our chief executive officer. Our receipt of the Staff’s
        comment letter has been followed by a series of discussions and exchanges
        of
        correspondence concerning the unresolved comments including clarification
        of the
        type of financial statements required to be presented and filed with the
        SEC
        concerning the properties we acquired in December 2006. Based on those
        discussions, we have included revised financial statements concerning the
        Cole
        Creek South and South Glenrock B Fields in this Annual Report and in an
        amendment to our 8-K Report. We are preparing a response to the other comments
        of the SEC which we expect to submit soon after the filing of this Annual
        Report.




15




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




**Field
      Summaries**




We
      currently operate three fields in the Powder River Basin: the South Glenrock
      B
      Field, the Big Muddy Field, and the Cole Creek South Field. The concentration
      of
      value in a relatively small number of fields should allow us to benefit
      substantially from any operating cost reductions or production enhancements
      we
      achieve and allows us to effectively manage the properties from our field office
      located in Glenrock, Wyoming.




We
      plan
      to make approximately $75 million of capital expenditures in the fiscal year
      ending March 31, 2008 on our three fields, building facilities, shooting
      3-D seismic, drilling wells, expanding production, and preparing the area for
      CO 2 delivery, which we expect will add both additional oil reserves and production
      for future operations. If we elect to own and operate the CO 2 pipeline, we will spend additional capital in fiscal years 2008 and 2009 for
      that purpose.




South
      Glenrock B Field




The
      South
      Glenrock B Field is in Wyoming’s Powder River Basin and is located in Converse
      County, about 20 miles east of Casper in the east-central region of the state.
      The field was discovered in 1950 by Conoco, Inc.




The
      South
      Glenrock B Field produces primarily from the Lower and Upper Muddy formations
      as
      well as the Dakota formation. All the formations are Cretaceous fluvial deltaic
      sands with extensive high reservoir quality channels. The structure dips from
      west to east with approximately 2,000 feet of relief.




The
      South
      Glenrock B Field is an active waterflood that currently produces approximately
      200 BOPD of sweet 35 degree API crude oil. There are 20 active producing wells.
      This waterflood unit was developed with a fairly regular 40 acre well spacing
      and drilled with modern rotary equipment. The South Glenrock B Field is slated
      to be the first of our fields for CO 2 development because the waterflood has maintained the reservoir pressure high
      enough for CO 2 operations, and the relative condition of the facilities, regular well spacing,
      and reservoir size make the field a good candidate for CO 2 operations. We plan to start CO 2 injection in the South Glenrock B Field in calendar year 2008.




Big
      Muddy Field




The
      Big
      Muddy Field is in Wyoming’s Powder River Basin and located in Converse County,
      17 miles east of Casper in the east-central region of the state. The field
      was
      discovered in 1916 and has produced approximately 52 million barrels of oil
      from
      several producing zones including the First Frontier, Stray, Shannon, Dakota,
      Lakota, Muddy and Niobrara formations. The Big Muddy Field was waterflooded
      starting in 1957.




The
      Big
      Muddy Field is currently producing about 20 BOPD of 36 degree API sweet crude
      oil, via a stripper operation, from five producing wells. The field was
      developed with an irregular well spacing and drilled mostly with cable tools.
      There are no facilities of any significance at the field.




The
      current reservoir pressure is very low and not sufficient for effective
      CO 2 flooding. Pending financing, our near-term plans for the Big Muddy Field are
      to
      build facilities and reactivate or drill new injection wells in order to inject
      disposal water produced as a result of CO 2 operations in the South Glenrock B Field. The injection of this water should
      have the effect of raising the Big Muddy reservoir pressure for the planned
      CO 2 flood.
      We also hope to drill or reactivate additional production wells in order to
      produce more oil from this reactivated waterflood. The Big Muddy Field requires
      unitization prior to a waterflood or a CO 2 flood.
      The State of Wyoming requires us to form two separate units, one for the Wall
      Creek formation and one for the Dakota formation, due to the different sizes
      of
      the productive horizons. It is expected that the unitization will be completed
      in calendar year 2008. We plan to start CO 2 injection in the Big Muddy Field in calendar year 2009.




16




Cole
      Creek South Field




The
      Cole
      Creek South Field is in Wyoming’s Powder River Basin and is located in Converse
      and Natrona counties, about 15 miles northeast of Casper in the east-central
      region of the state. The Cole Creek South Field was discovered in 1948 by the
      Phillips Petroleum Company.




Production
      at Cole Creek South was originally discovered on structure in the Lakota
      sandstone. After drilling a number of wells along the crest of the structure
      that had high water cuts, the Lakota zone was not developed in favor of the
      Dakota sandstone. Injection into the Dakota formation began in
      December 1968 and reached peak production in April 1972.




Production
      comes from two units at Cole Creek South. One unit is the Dakota Sand Unit
      which
      is under active waterflood. The other unit is the Cole Creek South Unit which
      is
      a primary production unit. Cole Creek South Field produces, in total,
      approximately 90 BOPD of 34 degree API sweet crude oil from 12 producing wells.
      Production is from the Dakota Sand Unit waterflood and from the Shannon, First
      Frontier, Second Frontier, Muddy, and Lakota formations.




The
      Cole
      Creek South Field is presently at reservoir pressure sufficient for miscible
      CO 2 flooding
      and the wells are in good working condition. Due to the small size, in
      comparison to the South Glenrock B Field and the Big Muddy Field, the Cole
      Creek
      South Field is planned to be the last of these three fields to undergo
      CO 2 flooding. We plan to start CO 2 injection in the Cole Creek South Field in either calendar year 2009 or
      2010.




**Oil
      & Gas Acreage and Productive Wells**




Our
      three
      properties in the Powder River Basin consist of the following
      acreage. ****


Developed
                    Acres
                
                Undeveloped
                    Acres
                
                Total
                    AcresField
                
                Gross
                
                Net
                
                Gross
                
                Net
                
                Gross
                
                NetBig
                    Muddy Field
                
                
                1,640
                
                
                972
                
                
                8,920
                
                
                8,908
                
                
                10,560
                
                
                9,880South
                    Glenrock B Field
                
                
                10,873
                
                
                10,177
                
                
                -
                
                
                -
                
                
                10,873
                
                
                10,177Cole
                    Creek South Field
                
                
                3,782
                
                
                3,782
                
                
                -
                
                
                -
                
                
                3,782
                
                
                3,782Total
                
                
                16,295
                
                
                14,931
                
                
                8,920
                
                
                8,908
                
                
                25,215
                
                
                23,839




We
      have
      producing wells located in our three Powder River Basin properties as identified
      below.




Field
            
            Number
                of
              Gross
                Oil Wells
            
            Number
                of
              Net
                Oil WellsBig
                Muddy Field
            
            
            5
            
            
            5.00South
                Glenrock B Field
            
            
            20
            
            
            18.74Cole
                Creek South Field
            
            
            12
            
            
            12.00Total
                Wells
            
            
            37
            
            
            35.74




17




**Production**




The
      following table summarizes average volumes and realized prices of oil produced
      from our properties and our production costs per barrel of oil. We acquired
      three oil fields in December 2006 and January 2007. We had no
      production in the years ending March 31, 2006 and March 31, 2005. We
      have not had any commodity price hedges in place.





For
                the Year
              Ended
                March 31, 2007Net
                oil production (barrels)
            
            
            23,838Average
                realized oil sales price per barrel
            
            $
            48.74Production
                costs per barrel:Production
                taxes
            
            $
            5.72Lease
                operating expenses
            
            $
            29.39




**Title
      to Properties**




As
      customary in the oil & gas industry, during acquisitions, substantive title
      reviews and curative work are performed on all properties. Generally, only
      a
      perfunctory title examination is conducted at the time properties believed
      to be
      suitable for drilling operations are first acquired. Prior to commencement
      of
      drilling operations, a thorough drill site title examination is normally
      conducted, and curative work is performed with respect to significant defects.
      We believe that we have good title to our oil & gas properties, some of
      which are subject to minor encumbrances, easements, and
      restrictions.




**Environmental
      Assessments**




We
      are
      cognizant of our environmental responsibilities to the communities in which
      we
      operate and to our shareholders. In addition, prior to the closing of our
      acquisitions, we obtained a Phase I environmental review of our properties
      from
      industry-recognized environmental consulting firms. These environmental reviews
      were commissioned and received prior to our acquisition of our three Wyoming
      fields, which revealed no material environmental problems.




**Geographic
      Segments**




All
      of
      our operations are in the continental United States.




**Significant
      Oil & Gas Purchasers and Product Marketing**




Due
      to
      the close proximity of our fields to one another, oil production from our three
      properties is sold to one purchaser under a month-to-month contract at the
      current area market price. The oil is currently transported by truck to pipeline
      connections in the area. The loss of that purchaser is not expected to have
      a
      material adverse effect upon our oil sales. We currently produce a nominal
      amount of natural gas, which is used in field operations and not sold to third
      parties.




Our
      ability to market oil depends on many factors beyond our control, including
      the
      extent of domestic production and imports of oil, the proximity of our oil
      production to pipelines, the available capacity in such pipelines, refinery
      capacity, the demand for oil, the effects of weather, and the effects of state
      and federal regulation. Our production is from fields close to major pipelines
      and established infrastructure. As a result, we have not experienced any
      difficulty to date in finding a market for all of our production as it becomes
      available or in transporting our production to those markets; however, there
      is
      no assurance that we will always be able to market all of our production or
      obtain favorable prices.




18




Oil
      Marketing




The
      oil
      production from our properties is relatively high quality, ranging in gravity
      from 34 to 36 degrees, and is low in sulfur. We sell our oil to a crude
      aggregator on a month-to-month term. The oil is transported by truck, with
      loads
      picked up daily. The prices we currently receive are based on posted prices
      for
      Wyoming Sweet crude oil, adjusted for gravity, plus approximately $3.50 to
      $4.25
      per barrel.




In
      recent
      months, Wyoming Sweet crude oil posted prices have declined in comparison to
      other oil price indexes, such as West Texas Intermediate crude oil spot prices.
      This has been due to disruptions in refinery throughput in the Rocky Mountain
      region, and increased imports of sour Canadian crude into the
      region.




Our
      long-term strategy is to find a dependable future transportation option to
      transport our high-quality oil to market at the highest price possible and
      to
      protect ourselves from downward pricing volatility. Options being explored
      include building a new crude oil pipeline to connect to a pipeline being
      considered by others for construction that is anticipated to run from Northern
      Colorado to Cushing, Oklahoma to transport Wyoming Sweet crude oil.




**Competition
      and Markets**




We
      face
      competition from other oil companies in all aspects of our business, including
      acquisition of producing properties and oil & gas leases, marketing of oil
& gas, and obtaining goods, services, and labor. Many of our competitors
      have substantially larger financial and other resources. Factors that affect
      our
      ability to acquire producing properties include available funds, available
      information about prospective properties, and our standards established for
      minimum projected return on investment. Competition is also presented by
      alternative fuel sources, including ethanol and other fossil fuels. Because
      of
      our use of EOR techniques and management’s experience and expertise in the oil
& gas industry, we believe that we are effective in competing in the market.




The
      demand for qualified and experienced field personnel to operate CO 2 EOR
      techniques, drill wells, and conduct field operations, geologists,
      geophysicists, engineers, and other professionals in the oil industry can
      fluctuate significantly, often in correlation with oil prices, causing periodic
      shortages. There have also been shortages of drilling rigs and other equipment,
      as demand for rigs and equipment has increased along with the number of wells
      being drilled. These factors also cause significant increases in costs for
      equipment, services, and personnel. Higher oil prices generally stimulate
      increased demand and result in increased prices for drilling rigs, crews and
      associated supplies, equipment, and services. We cannot be certain when we
      will
      experience these issues and these types of shortages or price increases could
      significantly decrease our profit margin, cash flow, and operating results,
      or
      restrict our ability to drill those wells and conduct those operations that
      we
      currently have planned and budgeted.




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




None.




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




On
      March 30, 2007, we held a Special Meeting of Stockholders at which
      70,980,492 shares were represented in person or by proxy. At this meeting,
      the
      stockholders were asked to consider and vote upon the proposals indicated below.
      The Special Meeting of Stockholders did not involve the election of directors.
      Each matter voted upon at the meeting, and the number of votes cast for, against
      or withheld, as well as the abstentions and broker non-votes as to each such
      matter, is indicated below:




19




(1)
            Proposal
                to amend our Articles of Incorporation to increase the authorized
                common
                stock from 100,000,000 shares to 275,000,000
                shares.





Number
                of Shares:70,971,992(For)
            8,500
                (Against)
            0
                (Abstain)
            0
                (Not Voting)





(2)
            Proposal
                to amend and restate our Articles of Incorporation in their entirety
                to,
                among other things, opt out of the application of business combination
                restrictions imposed under Nevada
                law.





Number
                of Shares:57,289,541(For)
            0
                (Against)
            0
                (Abstain)
            13,690,951
                (Not Voting)





(3)
            Proposal
                to consider and vote upon a proposal recommended by the Board of
                Directors
                to approve our 2006 Stock Incentive
                Plan.





Number
                of Shares:51,929,608
                (For)
            6,600
                (Against)
            5,353,333
                (Abstain)
            13,689,051
                (Not Voting)





PART
      II




**ITEM
      5.**  **MARKET
      FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS** **and Issuer Purchases of Equity Securities.**




Our
      Common Stock is quoted on the OTC Bulletin Board under the symbol “RNCH” since
      January 10, 2006. For the periods indicated, the following table sets forth
      the high and low bid prices per share of our common stock as reported by the
      OTC
      Bulletin Board. These prices represent inter-dealer quotations without retail
      markup, markdown, or commission and may not necessarily represent actual
      transactions.




**Fiscal
                Year 2007**
            
            **High
                Bid**
            
            **Low
                Bid**First
                Quarter
            
            $
            1.55
            
            $
            1.30Second
                Quarter
            
            $
            1.82
            
            $
            1.03Third
                Quarter
            
            $
            3.38
            
            $
            1.71Fourth
                Quarter
            
            $
            3.46
            
            $
            1.16**Fiscal
                Year 2006**First
                Quarter
            
            
            None
            
            
            NoneSecond
                Quarter
            
            
            None
            
            
            NoneThird
                Quarter
            
            
            None
            
            
            NoneFourth
                Quarter
            
            $
            1.65
            
            $
            0.02





20




**Stock
      Performance Graph**




The
      first
      day of public trading of our common stock was January 10, 2006. The graph
      below matches the cumulative total return since January 10, 2006 (or
      December 31, 2005 for the indexes) of holders of our common stock with the
      cumulative total returns of the NASDAQ Composite Index and the Dow Jones
      Wilshire MicroCap Exploration and Production Index. The graph assumes that
      the
      value of the investment in our common stock and in each of the indexes
      (including reinvestment of dividends) was $100 on January 10, 2006 (or
      December 31, 2005 for the indexes) and tracks it through March 31,
      2007. The reported closing stock price for our common stock on January 10,
      2006 was $0.012143, adjusting for a stock dividend which occurred after that
      date in January 2006, noted under “Dividends” below.











**Stock
                Performance Graph Data**1/10/06
            
            3/31/06
            
            3/31/07Rancher
                Energy Corp.
            
            
            100.0
            
            
            11,858.7
            
            
            10,952.8NASDAQ
                Composite
            
            
            100.0
            
            
            106.8
            
            
            112.3Dow
                Jones Wilshire MicroCap
              Exploration
                & Production
            
            
            100.0
            
            
            108.3
            
            
            86.7




21


**Holders**




As
      of
      June 28, 2007, there were approximately 243 record owners of our Common
      Stock. This does not include any beneficial owners for whom shares may be held
      in “nominee” or “street name”.




**Dividends**




We
      have
      not paid any cash dividends on our Common Stock since inception, and we do
      not
      anticipate declaring or paying any dividends at any time in the foreseeable
      future. In January 2006, we conducted a 14-for-1 forward stock
      split.




**Recent
      Sales of Unregistered Securities**




On
      May 15, 2006, in conjunction with his employment, we granted John Works,
      our President, Chief Executive Officer, and a member of our Board of Directors,
      an option to purchase 4,000,000 shares of our common stock at a price of
      $0.00001 per share. These options vest over time through May 31, 2009. In
      the event Mr. Works’ employment agreement is terminated, Mr. Works will be
      entitled to purchase all shares that have vested, and all unvested shares will
      be forfeited. On May 15, 2006, Mr. Works exercised a portion of his option
      to purchase 1,000,000 shares of common stock at an exercise price of $0.00001
      per share, for an aggregate purchase price of $10.00. On April 19, 2007,
      Mr. Works exercised a portion of his option to purchase 750,000 shares of common
      stock at an exercise price of $0.00001 per share, for an aggregate purchase
      price of $7.50. On May 31, 2007, Mr. Works exercised a portion of his
      option to purchase 250,000 shares of common stock at an exercise price of
      $0.00001 per share, for an aggregate purchase price of $2.50. Mr. Works is
      an
      accredited investor. The foregoing transaction was made pursuant to
      Section 4(2) of the Securities Act.




On
      June 6, 2006, we entered into a loan agreement with an institutional lender
      to borrow a principal amount of $150,000. The loan agreement provided that
      the
      lender had the option to convert all or a portion of the loan amount into shares
      of our common stock either (i) at a price per share equal to the closing price
      of our shares on NASDAQ on the day preceding notice from the lender of its
      intent to convert all or a portion of the loan into shares of our common stock,
      or (ii) in the event we offer shares or units to the general public, at the
      price such shares or units are being offered to the general public. On
      June 29, 2006 we paid the loan in full. The foregoing transaction was made
      pursuant to Section 4(2) of the Securities Act.




On
      June 9, 2006, we entered into a loan agreement with an institutional lender
      to borrow a principal amount of $500,000. The loan agreement provided that
      the
      lender had the option to convert all or a portion of the loan amount into units,
      each unit consisting of one share of our common stock and a warrant to purchase
      share one share of our common stock, either (i) at a price per share equal
      to
      the closing price of our shares on NASDAQ on the day preceding notice from
      the
      lender of its intent to convert all or a portion of the loan into shares of
      our
      common stock, or (ii) in the event we offer shares or units to the general
      public, at the price such shares or units are being offered to the general
      public. The lender subsequently elected to convert the entire loan amount and
      accrued interest into common stock at a price of $0.50 per unit. Accordingly,
      on
      July 19, 2006, we issued 1,006,905 shares of our common stock to the
      lender. In addition, as part of the conversion, we issued the lender warrants
      to
      purchase up to 1,006,905 shares of our common stock for a period of two years
      at
      an exercise price of $0.75 per share for the first year and $1.00 per share
      for
      the second year. The foregoing transactions were made pursuant to
      Section 4(2) of the Securities Act.




From
      June 2006 through October 2006, we sold 18,133,500 Units for $0.50 per
      Unit, totaling gross proceeds of $9,066,750. Each Unit sold in this offering
      consisted of one share of our common stock and a warrant to purchase one
      additional share of our common stock exercisable for a period of two years.
      For
      8,850,000 Units, we paid no underwriting commissions. For 9,283,500 Units,
      we
      paid a cash commission of $232,088, equal to 5% of the proceeds from the Units,
      and a stock-based commission of 464,175 shares of common stock, equal to 5%
      of
      the number of Units sold. The sum of the unregistered shares sold and the
      commission shares aggregated 18,597,675. All of the foregoing Units were sold
      outside the United States in offshore transactions to non-U.S. persons pursuant
      to the exemption from registration provided by Regulation S adopted under the
      Securities Act. Each of these investors was a sophisticated investor who
      provided customary investment representations and warranties as to suitability
      and against resales and distributions of the Units. The certificates issued
      bear
      a standard restrictive legend generally used in Regulation S
      transactions.




22




On
      October 2, 2006, pursuant to our 2006 Stock Incentive Plan (the 2006 Stock
      Incentive Plan), we granted options to purchase up to a total of 825,000 shares
      of common stock to one officer and one employee at an exercise price of $1.75,
      which was determined to be fair market value based upon our closing market
      price
      on October 2, 2006. Options in both of these grants vest over a three year
      period. On October 16, 2006, under the 2006 Stock Incentive Plan, we
      granted options to purchase up to a total of 1,500,000 shares of common stock
      to
      an officer at an exercise price of $2.10, which was determined to be fair market
      value based upon our closing market price on October 16, 2006. The options
      vest annually over a three-year period from the date of grant. The options
      in
      the foregoing grants will be exercisable for a term of five years, subject
      to
      early termination of the individual’s employment with us. The foregoing
      transactions were made pursuant to Section 4(2) of the Securities
      Act.




On
      December 21, 2006, we entered into a Securities Purchase Agreement, as
      amended, with institutional and individual accredited investors to effect a
      $79,500,000 private placement of shares of our common stock and other securities
      in multiple closings. As part of this private placement, we raised an aggregate
      of $79,405,418 and issued (i) 45,940,510 shares of common stock, (ii) promissory
      notes that were convertible into 6,996,342 shares of common stock, and (iii)
      warrants to purchase 52,936,832 shares of common stock. The warrants issued
      to
      investors in the private placement are exercisable during the five year period
      beginning on the date we amended and restated our Articles of Incorporation
      to
      increase our authorized shares of common stock, which was March 30, 2007.
      The notes issued in the private placement automatically converted into shares
      of
      common stock on March 30, 2007. In conjunction with the private placement,
      we also used services of placement agents and have issued warrants to purchase
      3,633,313 shares of common stock to these agents or their designees. The
      warrants issued to the placement agents or their designees are exercisable
      during the two year period (warrants to purchase 2,187,580 shares of common
      stock) or the five year period (warrants to purchase 1,445,733 shares of common
      stock) beginning on the date we amended and restated our Articles of
      Incorporation to increase our authorized shares of common stock, which was
      March 30, 2007. All of the warrants issued in conjunction with the private
      placement have an exercise price of $1.50 per share. The securities issued
      in
      the private placement bear a standard restrictive legend generally used in
      accredited investor transactions. The foregoing transactions were made pursuant
      to Section 4(2) of the Securities Act.




In
      partial consideration for the extension of the closing date of our acquisition
      of the Cole Creek South Field and the South Glenrock B Field, we issued in
      December 2006 to the seller of the oil & gas properties a warrant to
      purchase up to 250,000 shares of our common stock at an exercise price of $1.50
      per share. The seller may exercise the warrant at any time beginning
      June 22, 2007 and ending December 22, 2011. The foregoing transaction
      was made pursuant to Section 4(2) of the Securities Act.




On
      January 12, 2007, in conjunction with his entry into an employment
      agreement and pursuant to our 2006 Stock Incentive Plan, we granted to an
      officer an option to purchase up to 1,000,000 shares of our common stock at
      an
      exercise price of $3.19 per share. The option will vest annually over a
      three-year period from the date of grant, and will be exercisable for a term
      of
      five years, subject to early termination of the officer’s employment with us.
      The foregoing transaction was made pursuant to Section 4(2) of the
      Securities Act.




23




On
      February 16, 2007, in connection with Mark Worthey’s election to our Board
      of Directors, Mr. Worthey was granted an option to purchase 10,000 shares of
      our
      common stock pursuant to our 2006 Stock Incentive Plan. The exercise price
      is
      $1.63 per share, the fair market value of our common stock on the date of grant.
      The options vest 50% on the first anniversary date of the grant and 50% on
      the
      second anniversary date of the grant, and have a five-year term. The foregoing
      transaction was made pursuant to Section 4(2) of the Securities
      Act.




On
      April 10, 2007, pursuant to our 2006 Stock Incentive Plan, we granted
      options to purchase up to a total of 248,000 shares of common stock to 18
      employees at an exercise price of $1.18 per share, the fair market value of
      our
      stock based on the closing market price on the date of grant, and to one
      consultant at an exercise price of $1.64 pursuant to an agreement between us
      and
      the consultant. The employee stock option grants vest over a three-year period,
      with 33-1/3% of the original number of shares respectively on the first, second,
      and third anniversaries of the grant date, and have a five-year term, subject
      to
      early termination of the individual’s employment with us. The consultant’s stock
      option grant vests 50% of the original number of shares on August 31, 2007
      and 50% of the original shares on February 28, 2008 and will be exercisable
      for a five-year term, pursuant to an agreement between us and the consultant
      entered into on March 1, 2007. The foregoing transactions were made
      pursuant to Section 4(2) of the Securities Act.




On
      April 20, 2007, our Board of Directors appointed William A. Anderson,
      Joseph P. McCoy, Patrick M. Murray, and Myron M. Sheinfeld as members of the
      Board to serve until the next annual meeting of stockholders or their successors
      are duly elected and qualified. We had no special arrangements, related party
      transactions or understandings with the foregoing appointed directors in
      connection with their appointment to the Board, except for compensation
      arrangements. On April 20, 2007, each newly appointed director was granted
      an option to purchase 10,000 shares of our common stock pursuant to our 2006
      Stock Incentive Plan. The exercise price of the initial grant was $1.02 per
      share, the fair market value of our common stock on the date of grant. The
      option vests 20% (2,000 shares) on each one year anniversary of the date of
      the
      initial grant and will be exercisable for a ten-year term. Each newly appointed
      director will be entitled to receive annual grants of options to purchase 10,000
      shares that will be priced at the future grant dates. Each newly appointed
      director also received a stock grant of 100,000 shares of our common stock
      that
      vests 20% (20,000 shares) on the date of grant with vesting 20% per year
      thereafter. The foregoing transactions were made pursuant to Section 4(2)
      of the Securities Act.




On
      May 18, 2007, we issued 933,458 shares of our common stock and on
      June 19, 2007, we issued 946,819 shares of our common stock to the
      investors who participated in our December 2006 and January 2007 equity private
      placement. Under the terms of the registration rights agreement, we are
      obligated to pay the holders of the registrable securities issued in that
      private placement liquidated damages if the registration statement filed in
      conjunction with the private placement has not been declared effective by the
      SEC within 150 days of the closing of the private placement and every 30 days
      thereafter until the registration statement is declared effective. The closing
      occurred on December 21, 2006. The amount due on each applicable date is 1%
      of the aggregate purchase price or $794,000. Pursuant to the terms of the
      registration rights agreement, the number of shares issued on May 18, 2007
      was
      based on the payment amount of $794,000 divided by $0.85 per share, which equals
      90% of the volume weighted average price of our common stock for the 10 days
      immediately preceding May 18, 2007. The foregoing transactions were made
      pursuant to Section 4(2) of the Securities Act. Pursuant to the terms of the
      registration rights agreement, the number of shares issued on June 19, 2007
      was based on the payment amount of $794,000 divided by approximately $0.84
      per
      share, which equals 90% of the volume weighted average price of our common
      stock
      for the 10 trading days immediately preceding June 19, 2007, the payment
      due date.




24




On
      May 31, 2007, we granted 100,000 shares of our common stock to Mark
      Worthey, a director, that vests 20% (20,000 shares) on the date of grant with
      vesting 20% per year thereafter. The foregoing transaction was made to align
      his
      stock ownership interests with our other directors and pursuant to
      Section 4(2) of the Securities Act.




Pursuant
      to the terms of a consulting agreement that we previously entered into with
      an
      executive search consulting firm, on June 27, 2007 we granted 107,143 shares
      of
      our common stock in the aggregate, pursuant to our 2006 Stock Incentive Plan,
      to
      the principals of the consulting firm as partial consideration for the services
      provided to us by the consulting firm. The foregoing transaction was made
      pursuant to Section 4(2) of the Securities Act.




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




In
        addition to the GAAP presentation of Rancher Energy Corp’s historical results
        for the years ended March 31, 2007. 2006, 2005, and 2004 we have
        provided the following combined results for Rancher Energy Corp, its Predecessor
        and its Pre-Predecessor because we believe such financial information may
        be
        useful in gaining an understanding of the impact of the acquisitions on Rancher
        Energy, Corp’s underlying historical performance and future financial results.
        The combined information is not presented on a GAAP basis and is not necessarily
        comparable between periods.


The
      following selected financial data reflects the following:


·
                Rancher
                    Energy Corp. revenues, loss from continuing operations, and loss
                    from
                    continuing operations per share for the years ended March 31, 2007,
                    2006, 2005, and 2004;
 
 ·
                Rancher
                    Energy Corp. total assets as of March 31, 2007, 2006, 2005, and
                    2004;
 
 ·
                Predecessor
                    (the Cole Creek South Field and the South Glenrock B Field) revenues,
                    lease operating expenses and production taxes for the period
                    from
                    January 1, 2006 through December 21, 2006 (the date of
                    acquisition of the Predecessor by Rancher Energy Corp.), the
                    year ended
                    December 31, 2005, and for the period from September 1, 2004
                    (the date that the Predecessor was acquired from the Pre-Predecessor)
                    through December 31, 2004;
 
 ·
                Our
                    Pre-Predecessor’s revenues and direct operating expenses for the period
                    from January 1, 2004 through August 31,
                    2004;
 
 ·
                Predecessor
                    total assets as of December 21, 2006 and December 31,
                    2005;
 
 ·
                Adjustments
                    to eliminate the Predecessor’s results for the three months ended March
                    31, 2006 from the Predecessor results for the year ended December
                    31,
                    2006, so that the combined results will reflect the results for
                    Rancher
                    Energy Corp’s fiscal year ended March 31, 2007;
                    and
 
 ·
                Combined
                    revenue, lease operating expenses and production
                    taxes.
  
 25




RancherEnergy
                  Corp.
              
              Predecessor
              
              Adjustments
              
              Combined(1)(2)(Unaudited)2007:Revenues
              
              $
              1,161,819
              
              $
              4,488,315
              
              $
              (1,148,825
              )
              $
              4,501,309Production
                  taxes
              
              
              136,305
              
              
              493,956
              
              
              (120,313
              )
              
              509,948Lease
                  operating expenses
              
              
              700,623
              
              
              2,944,287
              
              
              (574,756
              )
              
              3,070,154Income
                  (loss) from continuing operations
              
              
              (8,702,255
              )
              
              (577,740
              )
              
              N/A
              
              
              N/ALoss
                  from continuing operations per share
              
              
              (0.16
              )
              
              N/A
              
              
              N/A
              
              
              N/AWeighted
                  average shares outstanding
              
              
              53,782,291
              
              
              N/A
              
              
              N/A
              
              
              N/ATotal
                  assets
              
              
              81,478,031
              
              
              14,597,618
              
              
              N/A
              
              
              N/A2006:Revenues
              
              $
              -
              
              $
              3,713,973
              
              $
              N/A
              
              $
              3,713,973Production
                taxes
              
              
              N/A
              
              
              428,905
              
              
              N/A
              
              
              428,905Lease
                  operating expenses
              
              
              N/A
              
              
              1,537,992
              
              
              N/A
              
              
              1,537,992Income
                  (loss) from continuing operations
              
              
              (124,453
              )
              
              26,886
              
              
              N/A
              
              
              N/ALoss
                  from continuing operations per share
              
              
              (0.00
              )
              
              N/A
              
              
              N/A
              
              
              N/AWeighted
                  average shares outstanding
              
              
              32,819,623
              
              
              N/A
              
              
              N/A
              
              
              N/ATotal
                  assets
              
              
              46,557
              
              
              13,058,437
              
              
              N/A
              
              
              N/A2005:Revenues
              
              $
              -
              
              $
              1,997,663
              
              $
              N/A
              
              $
              1,997,663Production
                taxes
              
              
              N/A
              
              
              219,955
              
              
              N/A
              
              
              219,955Lease
                  operating expenses
              
              
              N/A
              
              
              944,149
              
              
              N/A
              
              
              944,149Income
                  (loss) from continuing operations
              
              
              (27,154
              )
              
              474,770
              
              
              N/A
              
              
              N/ALoss
                  from continuing operations per share
              
              
              (0.00
              )
              
              N/A
              
              
              N/A
              
              
              N/AWeighted
                  average shares outstanding
              
              
              70,000,000
              
              
              N/A
              
              
              N/A
              
              
              N/ATotal
                  assets
              
              
              4,749
              
              
              N/A
              
              
              N/A
              
              
              N/A2004:Revenues
              
              $
              -
              
              
              N/A
              
              
              N/A
              
              
              N/AIncome
                  (loss) from continuing operations
              
              
              (375,000
              )
              
              N/A
              
              
              N/A
              
              
              N/ALoss
                  from continuing operations per share
              
              
              (0.01
              )
              
              N/A
              
              
              N/A
              
              
              N/AWeighted
                  average shares outstanding
              
              
              
              
              
              N/A
              
              
              N/A
              
              
              N/ATotal
                  assets
              
              
              -
              
              
              N/A
              
              
              N/A
              
              
              N/A
 _____________________N/A
                  - Not Applicable.





W e do not
      have long-term obligations or redeemable preferred stock, and we have not
      declared any cash dividends.





(1)  We
      completed our acquisition of the Cole Creek South and the South Glenrock B
      fields on December 22, 2006.


(2)  We
      completed our acquisition of the Big Muddy Field on January 4,
      2007.





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




**Organization**




We
      are an
      independent energy company which explores for and develops, produces, and
      markets oil & gas in North America. Prior to April 2006, Rancher Energy
      Corp., formerly known as Metalex Resources, Inc. (Metalex), was engaged in
      the
      exploration of a gold prospect in British Columbia, Canada. Metalex found no
      commercially exploitable deposits or reserves of gold. During April 2006,
      stockholders voted to change the name to Rancher Energy Corp. Since
      April 2006, we have employed a new Chief Executive Officer, Chief Operating
      Officer, Chief Financial Officer, and Senior Vice President, Engineering, and
      are actively pursuing oil & gas prospects in the Rocky Mountain
      region.




26




**Oil
      & Gas Property Acquisitions**




The
      following is a summary of the property acquisitions we have recently
      completed:




Cole
      Creek South Field and South Glenrock B Field Acquisitions




On
      December 22, 2006, we purchased certain oil & gas properties for
      $46,750,000, before adjustments for the period from the effective date to the
      closing date, plus closing costs of $323,657. The oil & gas properties
      consisted of (i) a 100% working interest (79.3% net revenue interest) in the
      Cole Creek South Field, which is located in Wyoming’s Powder River Basin; and
      (ii) a 93.6% working interest (74.5% net revenue interest) in the South Glenrock
      B Field, which also is located in Wyoming’s Powder River Basin. In partial
      consideration for an extension of the closing date, we issued the seller of
      the
      oil & gas properties warrants to acquire 250,000 shares of our common stock
      for $1.50 per share for a period of five years. The estimated fair value of
      the
      warrants to purchase common stock of $616,140 was estimated as of the grant
      date
      using the Black-Scholes option pricing model, and is included in the acquisition
      cost.




The
      total
      adjusted purchase price was allocated as follows:




Acquisition
                costs:Cash
                consideration
            
            $
            46,750,000Direct
                acquisition costs
            
            
            323,657Estimated
                fair value of warrants to purchase common stock
            
            
            616,140Total
            
            $
            47,689,797Allocation
                of acquisition costs:Oil
                & gas properties:Unproved
            
            $
            31,569,778Proved
            
            
            16,682,101Other
                assets - long-term accounts receivable
            
            
            53,341Other
                assets - inventory
            
            
            227,220Asset
                retirement obligation
            
            
            (842,643
            )Total
            
            $
            47,689,797





The
      Cole
      Creek South Field is located in Converse County, Wyoming approximately six
      miles
      northwest of the town of Glenrock. The field was discovered in 1948 by the
      Phillips Petroleum Company. Current gross production from the Cole Creek South
      Field is approximately 90 barrels of oil per day (BOPD) of primarily 34 degree
      API sweet crude oil.




The
      South
      Glenrock B Field is also located in Converse County, Wyoming. The field was
      discovered in 1950 by Conoco, Inc. Bisected by Interstate 25, the field produces
      from the Dakota and Muddy sandstone reservoirs that are draped over a structural
      nose with 2,000 feet of relief. Production is maintained by secondary recovery
      efforts that were initiated in 1961. Current gross production from the South
      Glenrock B Field is approximately 200 BOPD of primarily 35 degree API sweet
      crude oil.




Big
      Muddy Field Acquisition




On
      January 4, 2007, we acquired the Big Muddy Field, which is located in the
      Powder River Basin east of Casper, Wyoming. The total purchase price was
      $25,000,000, and closing costs were $672,638. While the Big Muddy Field was
      discovered in 1916, future profitable operations are dependent on the
      application of tertiary recovery techniques requiring significant amounts of
      CO 2 .




27




The
      total
      adjusted purchase price was allocated as follows:




Acquisition
                costs:Cash
                consideration
            
            $
            25,000,000Direct
                acquisition costs
            
            
            672,638Total
            
            $
            25,672,638Allocation
                of acquisition costs:Oil
                & gas properties:Unproved
            
            $
            24,151,745Proved
            
            
            1,870,086Asset
                retirement obligation
            
            
            (349,193
            )Total
            
            $
            25,672,638




Water
      flooding was initiated in the Wall Creek formation in 1957 and later expanded
      to
      the Dakota and Lakota formations. Over 800 completions have occurred in the
      field. At the current time, only a few wells are active. The current production
      is approximately 20 BOPD of primarily 36 degree API sweet crude
      oil.




**Outlook
      for the Coming Year**




The
      following summarizes our goals and objectives for the next twelve
      months:




·
            Borrow
                funds to implement our development plans;·
            Initiate
                development activities in our fields; and·
            Pursue
                additional asset and project opportunities that are expected to be
                accretive to stockholder value.




Since
      late 2006 we have added operating staff and have engaged consultants to conduct
      field studies of tertiary development of the three Powder River Basin fields.
      To
      date, work has focused on field and engineering studies to prepare for
      development operations. We have also engaged an engineering firm to evaluate
      routes and undertake the required front end engineering and design for the
      required CO 2 pipeline, as well as another engineering firm to evaluate and design surface
      facilities appropriate for CO 2 injection .




Our
      plans
      for EOR development of our oil fields are dependent on our obtaining substantial
      additional funding. As discussed further under “Liquidity and Capital Resources”
below, we successfully raised equity financing in December 2006 and
      January 2007 to enable us to acquire the fields. The raising of
      that funding is dependent on many factors, some of which are outside our
      control and is not assured. One major factor is the level of and projected
      trends in oil prices, which we cannot protect against by using hedging at this
      time.




We
      plan
      to begin CO 2 development operations in the South Glenrock B Field, and preliminary
      development in the Big Muddy Field. We also plan to make capital expenditures
      relating to existing production in the three fields. The sum of our planned
      general and administrative costs, operating costs, CO 2 purchase
      costs, and field development capital expenditures for the fiscal years ending
      March 31, 2008 and 2009 are estimated to be approximately $90 to $95
      million and $70 to $75 million, respectively. Of the fiscal year 2008 costs,
      about $75 million is projected for the South Glenrock B Field and Big Muddy
      Field projects, with about two-thirds of this cost for 3-D seismic, and well
      drilling and conversion for CO 2 injection, and the remainder for compressors and facilities. Since the
      acquisition of the three fields, other than the agreement with Anadarko for
      supply of CO 2 ,
      we have
      made no major capital expenditures nor any firm commitments for future capital
      expenditures to date.




28




The
      capital expenditures discussed above do not include costs of construction of
      the
      CO 2 pipeline. The route and configuration of this pipeline are being evaluated,
      and
      decisions on those factors have not been finalized. In addition, we are
      evaluating whether we will own and operate the line, or whether a third party
      will do so. That decision is also dependent on financing availability and
      certain other strategic factors.




**Commitments**




As
      part
      of our CO 2 tertiary
      recovery strategy, on December 15, 2006, we entered into a Product Sale and
      Purchase Contract with Anadarko for the purchase of CO 2 (meeting
      certain quality specifications) from Anadarko. We intend to use the
      CO 2 for our
      EOR projects.




The
      primary term of the Purchase Contract commences upon the later of
      January 1, 2008, or the date of the first CO 2 delivery,
      and terminates upon the earlier of the day on which we have taken and paid
      for
      the Total Contract Quantity, as defined, or 10 years from the commencement
      date.
      We have the right to terminate the Purchase Contract at any time with notice
      to
      Anadarko, subject to a termination payment as specified in the Purchase
      Contract.




During
      the primary term the “Daily Contract Quantity” is 40 MMcf per day for a total of
      146 Bcf. CO 2 deliveries are subject to a 25 MMcf per day take-or-pay provision. Anadarko
      has
      the right to satisfy its own needs before sales to us, which reduces our
      take-or-pay obligation. In the event the CO 2 does not
      meet certain quality specifications, we have the right to refuse delivery of
      such CO 2 .




For
      CO 2 deliveries, we have agreed to pay $1.50 per thousand cubic feet, to be adjusted
      by a factor that is indexed to the price of Wyoming Sweet oil. From oil that
      is
      produced by CO 2 injection, we also agreed to convey to Anadarko an overriding royalty interest
      that increases over time, not to exceed 5%.


**Results
        of Operations, Including Combined Results**
 
 In
        addition to the GAAP presentation of Rancher Energy Corp’s historical results
        for the years ended March 31, 2007. 2006 and 2005, we have provided the
        following combined results for Rancher Energy Corp, its Predecessor and its
        Pre-Predecessor because we believe such financial information may be useful
        in
        gaining an understanding of the impact of the acquisitions on Rancher Energy,
        Corp’s underlying historical performance and future financial results. The
        combined information is not presented on a GAAP basis and is not necessarily
        comparable between periods.


The
          following data includes:


·
              Our
                  results of operations for the years ended March 31, 2007, 2006, and
                  2005;
 
 ·
              Our
                  Predecessor’s (the Cole Creek South Field and the South Glenrock B Field)
                  results of operations for the period from January 1, 2006 through
                  December 21, 2006 (the date of acquisition of the Predecessor by
                  Rancher Energy Corp.), the year ended December 31, 2005, and for the
                  period from September 1, 2004 (the date that the Predecessor was
                  acquired from the Pre-Predecessor) through December 31,
                  2004;


29


·
              Our
                  Pre-Predecessor’s revenues and direct operating expenses for the period
                  from January 1, 2004 through August 31, 2004
                  ;
 
 ·
              Adjustments
                  to eliminate the Predecessor’s results for the three months ended March
                  31, 2006 from the Predecessor results for the year ended December
                  31,
                  2006, so that the combined results will reflect the results for
                  Rancher
                  Energy Corp’s fiscal year ended March 31, 2007 ;
                  and
 
 ·
              Combined
                  results of operations.
 Year
                    Ended March 31, 2007 (Unaudited)RancherEnergy
                    Corp.
                
                Predecessor
                
                Adjustments
                
                CombinedRevenue:Oil
                    production (in barrels)
                
                
                23,838
                
                
                73,076
                
                
                (18,631
                )
                
                78,283Oil
                    price (per barrel)
                
                
                48.74
                
                
                61.42
                
                
                61.66
                
                
                57.50Oil
                    & gas sales
                
                $
                1,161,819
                
                $
                4,488,315
                
                $
                (1,148,825
                )
                $
                4,501,309Operating
                    expenses:Production
                    taxes
                
                
                136,305
                
                
                493,956
                
                
                (120,313
                )
                
                509,948Lease
                    operating expenses
                
                
                700,623
                
                
                2,944,287
                
                
                (574,756
                )
                
                3,070,154Depreciation,
                    depletion, and amortization
                
                
                375,701
                
                
                952,784
                
                
                (267,050
                )
                
                1,061,435Impairment
                    of unproved properties
                
                
                734,383
                
                
                -
                
                
                -
                
                
                734,383Accretion
                    expense
                
                
                29,730
                
                
                107,504
                
                
                (26,876
                )
                
                110,358Exploration
                    expense
                
                
                333,919
                
                
                -
                
                
                -
                
                
                333,919General
                    and administrative
                
                
                4,501,737
                
                
                567,524
                
                
                (141,881
                )
                
                4,927,380Total
                    operating expenses
                
                
                6,812,398
                
                
                5,066,055
                
                
                (1,130,876
                )
                
                10,747,577(5,650,579
                )
                
                (577,740
                )
                
                (17,949
                )
                
                (6,246,268
                )Other
                    income (expense):Liquidated
                    damages pursuant to registration rights agreement
                
                
                (2,705,531
                )
                
                -
                
                
                -
                
                
                (2,705,531
                )Interest
                    expense
                
                
                (37,654
                )
                
                -
                
                
                -
                
                
                (37,654
                )Amortization
                    of deferred financing costs
                
                
                (537,822
                )
                
                -
                
                
                -
                
                
                (537,822
                )Interest
                    and other income
                
                
                229,331
                
                
                -
                
                
                -
                
                
                229,331Total
                    other income (expense)
                
                
                (3,051,676
                )
                
                -
                
                
                -
                
                
                (3,051,676
                )$
                (8,702,255
                )
                $
                (577,740
                )
                $
                (17,949
                )
                $
                (9,297,944
                )




30


Year
                  Ended March 31, 2006 (Unaudited)RancherEnergy
                  Corp.
              
              Predecessor
              
              CombinedRevenue:Oil
                  production (in barrels)
              
              
              -
              
              
              67,321
              
              
              67,321Oil
                  price (per barrel)
              
              
              -
              
              
              55.17
              
              
              55.17Oil
                  & gas sales
              
              
              -
              
              
              3,713,973
              
              
              3,713,973Operating
                  expenses:Production
                  taxes
              
              
              -
              
              
              428,905
              
              
              428,905Lease
                  operating expenses
              
              
              -
              
              
              1,537,992
              
              
              1,537,992Depreciation,
                  depletion and amortization
              
              
              213
              
              
              567,345
              
              
              567,558Accretion
                  expense
              
              
              -
              
              
              107,712
              
              
              107,712General
                  and administrative
              
              
              74,240
              
              
              1,045,133
              
              
              1,119,373Exploration
                  expense - mining
              
              
              50,000
              
              
              -
              
              
              50,000Total
                  operating expenses
              
              
              124,453
              
              
              3,687,087
              
              
              3,811,540$
              (124,453
              )
              $
              26,886
              
              $
              (97,567
              )


31




Year
                  Ended March 31, 2005 (Unaudited)RancherEnergy
                  Corp.
              
              Predecessor
              
              Pre-
                Predecessor
              
              CombinedRevenue:Oil
                  production (in barrels)
              
              
              -
              
              
              16,234
              
              
              35,882
              
              
              52,116Oil
                  price (per barrel)
              
              
              -
              
              
              44.50
              
              
              35.54
              
              
              38.33Oil
                  & gas sales
              
              
              -
              
              
              722,449
              
              
              1,275,214
              
              
              1,997,663Operating
                  expenses:Production
                  taxes
              
              
              -
              
              
              81,868
              
              
              138,087
              
              
              219,955Lease
                  operating expenses
              
              
              -
              
              
              360,207
              
              
              583,942
              
              
              944,149Depreciation,
                  depletion and amortization
              
              
              201
              
              
              62,542
              
              
              -
              
              
              62,473Accretion
                  expense
              
              
              -
              
              
              12,990
              
              
              -
              
              
              12,990General
                  and administrative
              
              
              26,953
              
              
              283,257
              
              
              -
              
              
              310,210Total
                  operating expenses
              
              
              27,154
              
              
              800,864
              
              
              722,029
              
              
              1,550,047$
              (27,154
              )
              $
              (78,415
              )
              $
              553,185
              
              $
              447,616


The
        following provides explanations of changes in our results of operations,
        and our
        results of operations on a combined basis.


**Rancher
      Energy Corp.**




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




*Overview* .
      For the
      year ended March 31, 2007, we reflected a net loss of $8,702,255, or
      $(0.16) per basic and fully diluted share, as compared to a loss of $124,453,
      or
      $(0.00) per basic and fully diluted share, for the corresponding year ended
      March 31, 2006. During the year ended March 31, 2007, we completed our
      December 22, 2006 acquisition of the Cole Creek South Field and South
      Glenrock B Field, and our January 4, 2007 acquisition of the Big Muddy
      Field. We did not have any oil & gas properties during fiscal 2006. During
      fiscal year 2007 we directed our efforts to raising capital to finance the
      acquisitions, and to increase our operational and administrative
      infrastructure.




*Revenue,
      Production Taxes, and Lease Operating Expenses* .
      For the
      year ended March 31, 2007, we reflected oil & gas sales of $1,161,819
      on 23,838 barrels of oil at $48.74 per barrel, production taxes (including
      ad
      valorem taxes) of $136,305 and lease operating expenses of $700,623, as compared
      to $0, $0 and $0, respectively, for the corresponding year ended March 31,
      2006. Lease operating expenses per barrel of production were $29.39 and
      production taxes were $5.72 per barrel for the fiscal year ended March 31,
      2007.




32




*Depreciation,
      depletion, and amortization* .
      For the
      year ended March 31, 2007, we reflected depreciation, depletion, and
      amortization of $375,701 as compared to $213 for the corresponding year ended
      March 31, 2006. Depreciation, depletion, and amortization was $14.59 per
      barrel of production for the fiscal year ended March 31, 2007.




*Impairment
      of unproved properties* .
      For the
      year ended March 31, 2007, we reflected impairment of unproved properties
      of $734,383 as compared to $0 for the corresponding year ended March 31,
      2006. We determined we would not develop certain properties, and the carrying
      value would not be realized.




*Exploration
      expense* .
      For the
      year ended March 31, 2007, we reflected exploration expense of $333,919 as
      compared to $0 for the corresponding year ended March 31, 2006. Exploration
      expenses were for geological and geophysical analysis of certain projects,
      all
      of which we elected not to pursue.




*General
      and administrative expense* .
      For the
      year ended March 31, 2007, we reflected general and administrative expenses
      of $4,501,737 as compared to $74,240 for the corresponding year ended
      March 31, 2006. The increase is primarily attributed to focusing our
      efforts on building our oil & gas infrastructure. Included in general and
      administrative expenses for fiscal 2007 is stock-based compensation of
      $1,501,908. Other key elements comprising the increase include corporate
      promotion, Sarbanes-Oxley compliance, audit fees, legal, and reservoir
      engineering.




*Liquidated
      damages pursuant to registration rights agreement* .
      In
      connection with our equity private placement in December 2006 and
      January 2007, we entered into a registration rights agreement and agreed to
      file a registration statement to register for resale the shares of common stock.
      The agreement includes provisions for payment if the registration statement
      is
      not declared effective by May 20, 2007, and additional payments are due if
      there are additional delays in obtaining effectiveness. We have determined
      that
      the obligation to pay liquidated damages is both probable and can be estimated.
      Our estimate of $2,705,531 is equal to three months of damages. One month’s
      damages were paid on May 18, 2007 by the issuance of 933,458 shares, valued
      at $1.04 per share, with a present value of $953,431. The damages for the two
      additional months were estimated to have a present value of $876,050 per month,
      or a total for those months of $1,752,100. A second month’s damages were paid on
      June 19, 2007 by the issuance of 946,819 shares, and the present value
      approximated the previously established obligation.




*Amortization
      of deferred financing costs* .
      For the
      year ended March 31, 2007, we reflected amortization of deferred financing
      costs of $537,822 as compared to $0 for the corresponding year ended
      March 31, 2006. We incurred financing costs of $921,821 in connection with
      the private placement of convertible notes payable with a term of four months.
      The amortization of those costs was based on the period from the date of the
      notes through March 30, 2007, the date the notes automatically converted to
      shares of common stock. When converted, proceeds from the placement were
      reflected net of the unamortized deferred financing costs.




*Interest
      income* .
      For the
      year ended March 31, 2007, we reflected interest income of $229,331 as
      compared to $0 for the corresponding year ended March 31, 2006. The
      interest income was derived from earnings on excess cash derived from the
      private placement of units, consisting of common stock and warrants to acquire
      shares of common stock.




33




*Year
      Ended**March 31,
      2006 Compared to Year Ended March 31, 2005*




During
      the year ended March 31, 2006, we had a net loss of $124,453, which was an
      increase from a net loss of $27,154 for the year ended March 31, 2005.
      Legal and accounting fees increased to $47,809 from $8,795 in 2006 due to our
      increased activity. In addition, our increase in activity resulted in increased
      auditing and review fees. Mining exploration expenses of $50,000 were recognized
      in the year ended March 31, 2006 which related to expenditures on a mining
      project that we abandoned subsequent to year end.




**Rancher
      Energy Corp. Combined with Predecessor and
      Pre-Predecessor**




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




*Revenue,
      Production Taxes, and Lease Operating Expenses* .
      For the
      year ended March 31, 2007, oil & gas sales were $4,501,309 on 78,283
      barrels of oil at $57.50 per barrel, production taxes (including ad valorem
      taxes) were $509,948, or $6.51 per barrel, and lease operating expenses were
      $3,070,154, or $39.22 per barrel, as compared to oil & gas sales of
      $3,713,973 on 67,321 barrels of oil at $55.17 per barrel, production taxes
      (including ad valorem taxes) of $428,905, or $6.37 per barrel, and lease
      operating expenses of $1,537,992, or $22.85 per barrel, respectively, for the
      corresponding year ended March 31, 2006.




*Depreciation,
      depletion, and amortization* .
      For the
      year ended March 31, 2007, depreciation, depletion, and amortization was
      $1,061,435, or $13.56 per barrel of oil, as compared to $567,558, or $8.43
      per
      barrel of oil, for the corresponding year ended March 31, 2006. The
      depreciation, depletion and amortization is not comparable between periods
      because the oil and gas properties have a different basis of accounting as
      a
      result of applying purchase accounting, which resulted in depreciation,
      depletion and amortization rates that are different before and after the
      acquisition of the properties.




*Impairment
      of unproved properties* .
      For the
      year ended March 31, 2007, impairment of unproved properties was $734,383,
      as compared to $0 for the corresponding year ended March 31, 2006. We
      determined that certain properties would not be developed, and the carrying
      value would not be realized.




*Exploration
      expense* .
      For the
      year ended March 31, 2007, exploration expense was $333,919 as compared to
      $0 for the corresponding year ended March 31, 2006. Exploration expenses
      were for geological and geophysical analysis of certain projects, all of which
      were not pursued.




*General
      and administrative expense* .
      For the
      year ended March 31, 2007, general and administrative expenses were
      $4,927,380 as compared to $1,119,373 for the corresponding year ended
      March 31, 2006. The increase was primarily attributed to focusing efforts
      on building our oil & gas infrastructure. Included in general and
      administrative expenses for fiscal 2007 is stock-based compensation of
      $1,501,908. Other key elements comprising the increase include corporate
      promotion, Sarbanes-Oxley compliance, audit fees, legal, and reservoir
      engineering.




*Liquidated
      damages pursuant to registration rights agreement* .
      In
      connection with our equity private placement in December 2006 and
      January 2007, we entered into a registration rights agreement and agreed to
      file a registration statement to register for resale the shares of common stock.
      The agreement includes provisions for payment if the registration statement
      is
      not declared effective by May 20, 2007, and additional payments are due if
      there are additional delays in obtaining effectiveness. We have determined
      that
      the obligation to pay liquidated damages is both probable and can be estimated.
      Our estimate of $2,705,531 is equal to three months of damages. One month’s
      damages were paid on May 18, 2007 by the issuance of 933,458 shares, valued
      at $1.04 per share, with a present value of $953,431. The damages for the two
      additional months were estimated to have a present value of $876,050 per month,
      or a total for those months of $1,752,100. A second month’s damages were paid on
      June 19, 2007 by the issuance of 946,819 shares, and the present value
      approximated the previously established obligation.




34




*Amortization
      of deferred financing costs* .
      For the
      year ended March 31, 2007, we reflected amortization of deferred financing
      costs of $537,822 as compared to $0 for the corresponding year ended
      March 31, 2006. We incurred financing costs of $921,821 in connection with
      the private placement of convertible notes payable with a term of four months.
      The amortization of those costs was based on the period from the date of the
      notes through March 30, 2007, the date the notes automatically converted to
      shares of common stock. When converted, proceeds from the placement were
      reflected net of the unamortized deferred financing costs.




*Interest
      income* .
      For the
      year ended March 31, 2007, interest income was $229,331 as compared to $0
      for the corresponding year ended March 31, 2006. The interest income was
      derived from earnings on excess cash derived from the private placement of
      units, consisting of common stock and warrants to acquire shares of common
      stock.




*Year
      Ended**March 31,
      2006 Compared to Year Ended March 31, 2005*




*Revenue,
      Production Taxes, and Lease Operating Expenses* .
      For the
      year ended March 31, 2006, oil & gas sales were $3,713,973 on 67,321
      barrels of oil at $55.17 per barrel, production taxes (including ad valorem
      taxes) were $428,905, or $6.37 per barrel, and lease operating expenses were
      $1,537,992, or $22.85 per barrel, as compared to oil & gas sales of
      $1,997,663 on 52,116 barrels of oil at $38.33 per barrel, production taxes
      (including ad valorem taxes) of $219,955, or $4.22 per barrel, and lease
      operating expenses of $944,149, or $18.12 per barrel, respectively, for the
      corresponding year ended March 31, 2005.




**Liquidity
      and Capital Resources**




As
      of
      March 31, 2007, we had working capital of $889,221. Current liabilities
      include $2,705,531 for penalty payments pursuant to the Registration Rights
      Agreement, part of which has already been paid in stock. We anticipate that
      the
      remaining accrued payment will also be made in stock. If the penalty payments
      amount was excluded, working capital would be $3,594,752.




Our
      primary source of liquidity to meet operating expenses and fund capital
      expenditures is our access to debt and equity markets. The debt and equity
      markets, public, private, and institutional, have been our principal source
      of
      capital used to finance a significant amount of growth, including acquisitions.
      We will need substantial additional funding to pursue our business
      plan.




35




We
      have
      working capital and have revenue from production operations in our three fields.
      However, these currently available cash sources are not sufficient to fund
      our
      planned expenditures for the tertiary development of the fields. Essentially
      all
      of the funding for tertiary development is expected to come from, and is
      dependent on, successful completion of a debt financing.


We
        currently have negative cash flow from operating activities. Monthly oil
&
gas production revenue is adequate to cover monthly field operating costs
        and
        production taxes at the current time. Only a portion of the remaining cash
        costs, which consist primarily of general and administrative expenses, are
        covered by cash flow. At current staffing levels, the negative cash flow
        is
        projected to be covered by available cash, assuming no additional financing
        is
        obtained by us, through fiscal year 2008. However, in the event we are not
        successful in raising financing adequate to begin our CO 2 development projects, we do not plan to allow negative monthly cash flow
        to
        remain at current levels. Rather, we plan to address the situation at that
        time
        by reducing staffing levels to reduce cash requirements, and using proceeds
        of a
        senior revolving debt facility, if available, to pursue development projects
        to
        enhance near term production rates and cash flow.




We
      may
      have to pay liquidated damages pursuant to the registration rights agreement
      in
      connection with our December 2006 and January 2007 equity private placement
      that
      are in excess of the amounts that we have already incurred or accrued. We
      anticipate that we will make any payments due related to the registration rights
      agreement in stock, rather than cash, subject to our meeting certain
      requirements. If we are required to make payments in cash rather than stock,
      our
      liquidity would be negatively affected.




Change
      in Financial Condition




We
      entered into a number of debt and equity transactions in fiscal year 2007,
      which
      dramatically increased our financial capability. The following is a summary
      of
      debt and equity transactions completed during fiscal 2007:




*Convertible
      Debt Transactions*




Venture
      Capital First LLC




On
      June 9, 2006, we borrowed $500,000 from Venture Capital First LLC (Venture
      Capital). Principal and interest at an annual rate of 6% were due
      December 9, 2006. The agreement provided that Venture Capital had the
      option to convert all or a portion of the loan into common stock and warrants
      to
      purchase common stock, either (i) at the closing price of our shares on the
      day
      preceding notice from Venture Capital of its intent to convert all or a portion
      of the loan into common stock or, (ii) in the event we conducted an offering
      of
      common stock, or units consisting of common stock and warrants to purchase
      stock, at the price of such shares or units in the offering.




36




On
      July 19, 2006, Venture Capital elected to convert its entire loan and
      accrued interest into 1,006,905 shares of common stock and warrants to purchase
      1,006,905 shares of common stock at a price of $0.50 per unit, the price per
      unit in the offering discussed in *Equity
      Transactions* below.
      The warrants are exercisable over a two-year period, at a price of $0.75 per
      share for the first year, and $1.00 per share for the second year. On
      December 21, 2006, the warrant holder agreed not to exercise its right to
      acquire shares of common stock until we received stockholder approval to
      increase the number of authorized shares, and the exercise price of $0.75 per
      share was extended by us through the second year.




Private
      Placement - Convertible Notes Payable




As
      part
      of the December 2006 and January 2007 equity private placement, which is further
      discussed below, in December 2006 and January 2007, we received
      $10,494,582 from certain investors, who received convertible notes payable.
      Upon
      stockholder approval of an amendment to the Articles of Incorporation increasing
      the authorized shares of our common stock, which occurred on March 30,
      2007, the notes automatically converted into shares of common stock. The number
      of shares issued upon conversion of the notes was equal to the face amount
      of
      the notes divided by $1.50 per share, which is the price that the shares were
      simultaneously sold in a private placement as discussed below, or 6,996,342
      shares. Had the notes not converted, the notes would have accrued interest
      at an
      annual rate of 12% beginning 120 days after issuance, which was the maturity
      date of the notes.




Consistent
      with the terms and conditions of the Units sold in the private placement (as
      further discussed below under the heading “Private Placement” and in Note 6 -
      Sale of Common Stock and Warrants to the Notes to Financial Statements of our
      audited financial statements for the fiscal year ended March 31, 2007 in
      Part IV, Item 15 of this Annual Report), the convertible notes payable were
      issued with warrants to acquire 6,996,322 shares of common stock at $1.50 per
      share.




*Equity
      Transactions*




Units
      Issued Pursuant to Regulation S




For
      the
      period from June 2006 through October 2006, we sold 18,133,500 Units
      for $0.50 per Unit, totaling gross proceeds of $9,066,750, pursuant to the
      exemption from registration of securities under the Securities Act of 1933
      as
      provided by Regulation S. Each Unit consisted of one share of common stock
      and a
      warrant to purchase one additional share of common stock.




For
      8,850,000 Units, we paid no underwriting commissions. For 9,283,500 Units,
      we
      paid a cash commission of $232,088, equal to 5% of the proceeds from the units,
      and a stock-based commission of 464,175 shares of common stock, equal to 5%
      of
      the number of Units sold. The sum of the shares sold and the commission shares
      aggregated 18,597,675. All warrants were originally exercisable for a period
      of
      two years from the date of issuance. During the first year, the exercise price
      was $0.75 per share; during the second year, the exercise price was $1.00 per
      share. The warrants are redeemable by us for no consideration upon 30 days
      prior
      notice. A portion of these warrants were modified as discussed
      below.




Warrant
      Modification - Warrants Issued Pursuant to Regulation S




On
      December 21, 2006, holders of 13,192,000 warrants issued pursuant to
      Regulation S in a private placement from June through October 2006
      agreed not to exercise their right to acquire shares of common stock until
      we
      received stockholder approval, which was obtained on March 30, 2007, to
      increase the number of our authorized shares. Pursuant to this agreement, the
      exercise price of $0.75 per share was extended by us through the second year.
      Terms for the remaining 4,941,500 warrants were unchanged.




37




Private
      Placement




On
      December 21, 2006, we entered into a Securities Purchase Agreement, as
      amended, with institutional and individual accredited investors to effect a
      $79,500,000 private placement of shares of our common stock and other securities
      in multiple closings. As part of this private placement, we raised an aggregate
      of $79,405,418 and issued (i) 45,940,510 shares of common stock, (ii) promissory
      notes that were convertible into 6,996,342 shares of common stock, and (iii)
      warrants to purchase 52,936,832 shares of common stock. The warrants issued
      to
      investors in the private placement are exercisable during the five year period
      beginning on the date we amended and restated our Articles of Incorporation
      to
      increase our authorized shares of common stock, which was March 30, 2007.
      The notes issued in the private placement automatically converted into shares
      of
      common stock on March 30, 2007. In conjunction with the private placement,
      we also used the services of placement agents and have issued warrants to
      purchase 3,633,313 shares of common stock to these agents or their designees.
      The warrants issued to the placement agents or their designees are exercisable
      during the two year period (warrants to purchase 2,187,580 shares of common
      stock) or the five year period (warrants to purchase 1,445,733 shares of common
      stock) beginning on the date we amended and restated our Articles of
      Incorporation to increase our authorized shares of common stock, which was
      March 30, 2007. All of the warrants issued in conjunction with the private
      placement have an exercise price of $1.50 per share.




In
      connection with the private placement, we also entered into a Registration
      Rights Agreement with the investors in which we agreed to register for resale
      the shares of common stock issued in the private placement as well as the shares
      underlying the warrants and convertible notes issued in the private placement.
      There are liquidated damages payable pursuant to the Securities Purchase
      Agreement and Registration Rights Agreement relating to these registration
      provisions and other obligations, as described in Note 6 - Sale of Common
      Stock and Warrants to the Notes to Financial Statements of our audited financial
      statements for the fiscal year ended March 31, 2007 in Part IV,
      Item 15, of this Annual Report, which, if triggered, could result in
      substantial amounts to be due to the investors.




Summary
      of Warrants




We
      have
      19,140,405 warrants outstanding to acquire our common stock at an exercise
      price
      of $0.75 per share, all of which expire by October 18, 2008. The exercise
      of the full amount of these warrants, which is not assured, would add
      $14,355,304 to our liquidity. In the longer term, the exercise of the remaining
      56,820,165 warrants outstanding to acquire our common stock at an exercise
      price
      of $1.50 per share would add $85,230,247 to our liquidity, if all were
      exercised. These options expire by March 30, 2012.




The
      following is a summary of warrants as of March 31, 2007.




38




Warrants
            
            Exercise
                Price
            
            Expiration
                DateWarrants
                issued in connection with the
              following:Sale
                of common stock pursuant to
              Regulation
                S
            
            
            18,133,500
            
            $
            0.75-$1.00
            
            
            July
                5, 2008
              to
                October 18, 2008Conversion
                of notes payable into common stock
            
            
            1,006,905
            
            $
            0.75
            
            
            July
                19, 2008Private
                placement of common stock
            
            
            45,940,510
            
            $
            1.50
            
            
            March
                30, 2012Private
                placement of convertible notes payable
            
            
            6,996,322
            
            $
            1.50
            
            
            March
                30, 2012Private
                placement agent commissions
            
            
            2,187,580
            
            $
            1.50
            
            
            March
                30, 2009Private
                placement agent commissions
            
            
            1,445,733
            
            $
            1.50
            
            
            March
                30, 2012Acquisition
                of oil & gas properties
            
            
            250,000
            
            $
            1.50
            
            
            December
                22, 2011Total
                warrants outstanding at March 31, 2007
            
            
            75,960,550


Cash
      Flows




The
      following is a summary of our comparative cash flows:




For
                the Years Ended March 31,2007
            
            2006
            
            2005Cash
                flows from:Operating
                activities
            
            $
            (2,285,430
            )
            $
            (124,073
            )
            $
            (25,050
            )Investing
                activities
            
            
            (74,357,306
            )
            
            -
            
            
            (890
            )Financing
                activities
            
            
            81,726,538
            
            
            166,094
            
            
            30,000





Analysis
      of cash flow changes between 2007 and 2006




Cash
      flows used for operating activities increased primarily as a result of general
      and administrative expenses incurred in connection with the expansion of our
      oil
& gas operations.




Cash
      flows used for investing activities increased primarily as a result of expending
      $47,073,657 in connection with the acquisition of the Cole Creek South and
      South
      Glenrock B Fields, and $25,672,638 in connection with the acquisition of the
      Big
      Muddy Field. We expended $841,993 for other oil & gas property capital
      expenditures and $769,018 for other equipment.




Cash
      flows provided by financing activities increased primarily as a result of
      certain private placements of equity securities aggregating net proceeds of
      $71,653,937. In connection with the private placement of equity securities,
      we
      also received net proceeds of $10,494,582 from the issuance of convertible
      notes
      payable and warrants to acquire shares of our common stock. The notes payable
      were converted to equity on March 30, 2007.




Capital
      Expenditures




The
      following table sets forth certain historical information regarding costs
      incurred in oil & gas property acquisition, exploration and development
      activities, whether capitalized or expensed.




39




For
                the Year Ended March 31,2007
            
            2006
            
            2005Exploration
            
            $
            333,919
            
            $
            -
            
            $
            -Development
            
            
            -
            
            
            -
            
            
            -Acquisitions:Unproved
            
            
            56,813,516
            
            
            -
            
            
            -Proved
            
            
            18,552,188
            
            
            -
            
            
            -Total
            
            
            75,699,623
            
            
            -
            
            
            -Costs
                associated with asset retirement obligations
            
            $
            1,191,837
            
            $
            -
            
            $
            -




Schedule
      of Contractual Obligations




The
      following table summarizes our future estimated minimum lease payments for
      our
      office space for the periods specified.




Total
            
            Less
                than 1 year
            
            1
                -
                3 years
            
            3
                -
                5 years
            
            More
                than 5 yearsOperating
                lease
            
            $
            1,907,640
            
            $
            280,859
            
            $
            733,061
            
            $
            765,773
            
            $
            127,947




Off-Balance
      Sheet Arrangements




We
      do not
      have any off-balance sheet financing nor do we have any unconsolidated
      subsidiaries.




**Critical
      Accounting Policies and Estimates**




We
      are
      engaged in the exploration, exploitation, development, acquisition, and
      production of natural gas and crude oil. Our discussion of financial condition
      and results of operations is based upon the information reported in our
      financial statements. The preparation of these financial statements requires
      us
      to make assumptions and estimates that affect the reported amounts of assets,
      liabilities, revenues, and expenses as well as the disclosure of contingent
      assets and liabilities as of the date of our financial statements. We base
      our
      decisions, which affect the estimates we use, on historical experience and
      various other sources that are believed to be reasonable under the
      circumstances. Actual results may differ from the estimates we calculate due
      to
      changing business conditions or unexpected circumstances. Policies we believe
      are critical to understanding our business operations and results of operations
      are detailed below. For additional information on our significant accounting
      policies see Note 1—Organization and Summary of Significant Accounting
      Policies, Note 3—Asset Retirement Obligations, and Note 7—Disclosures About Oil
& Gas Producing Activities to the Notes to Financial Statements of our
      audited financial statements for the fiscal year ended March 31, 2007 in
      Part IV, Item 15, of this Annual Report.




*Oil
      & gas reserve quantities.*  Estimated
      reserve quantities and the related estimates of future net cash flows are the
      most important estimates for an exploration and production company because
      they
      affect our perceived value, are used in comparative financial analysis ratios
      and are used as the basis for the most significant accounting estimates in
      our
      financial statements. This includes the periodic calculations of depletion,
      depreciation, and impairment for our proved oil & gas assets. Proved oil
& gas reserves are the estimated quantities of crude oil, natural gas, and
      natural gas liquids which geological and engineering data demonstrate with
      reasonable certainty to be recoverable in future periods from known reservoirs
      under existing economic and operating conditions. Future cash inflows and future
      production and development costs are determined by applying benchmark prices
      and
      costs, including transportation, quality, and basis differentials, in effect
      at
      the end of each period to the estimated quantities of oil & gas remaining to
      be produced as of the end of that period. Expected cash flows are reduced to
      present value using a discount rate that depends upon the purpose for which
      the
      reserve estimates will be used. For example, the standardized measure
      calculation required by SFAS No. 69, Disclosures About Oil & Gas
      Producing Activities, requires a 10% discount rate to be applied. Although
      reserve estimates are inherently imprecise, and estimates of new discoveries
      and
      undeveloped locations are more imprecise than those of established producing
      oil
& gas properties, we make a considerable effort in estimating our reserves,
      which are prepared by independent reserve engineering consultants. We expect
      that periodic reserve estimates will change in the future as additional
      information becomes available or as oil & gas prices and operating and
      capital costs change. We evaluate and estimate our oil & gas reserves at
      March 31 of each year. For purposes of depletion, depreciation, and
      impairment, reserve quantities are adjusted at all interim periods for the
      estimated impact of additions and dispositions. Changes in depletion,
      depreciation, or impairment calculations caused by changes in reserve quantities
      or net cash flows are recorded in the period that the reserve estimates
      change.




40




*Successful
      efforts method of accounting.* ** Generally
      accepted accounting principles provide for two alternative methods for the
      oil
& gas industry to use in accounting for oil & gas producing activities.
      These two methods are generally known in our industry as the full cost method
      and the successful efforts method. Both methods are widely used. The methods
      are
      different enough that in many circumstances the same set of facts will provide
      materially different financial statement results within a given year. We have
      chosen the successful efforts method of accounting for our oil & gas
      producing activities, and a detailed description is included in Note 1 -
      Organization and Summary of Significant Accounting Policies to the Notes to
      Financial Statements of our audited financial statements for the fiscal year
      ended March 31, 2007 in Part IV, Item 15, of this Annual
      Report.




*Revenue
      recognition.*  Our
      revenue recognition policy is significant because revenue is a key component
      of
      our results of operations and our forward-looking statements contained in our
      analyses of liquidity and capital resources. We derive our revenue primarily
      from the sale of produced crude oil. We report revenue as the gross amounts
      we
      receive for our net revenue interest before taking into account production
      taxes
      and transportation costs, which are reported as separate expenses. Revenue
      is
      recorded in the month our production is delivered to the purchaser, but payment
      is generally received between 30 and 90 days after the date of production.
      No
      revenue is recognized unless it is determined that title to the product has
      transferred to a purchaser. At the end of each month we make estimates of the
      amount of production delivered to the purchaser and the price we will receive.
      We use our knowledge of our properties, their historical performance, the
      anticipated effect of weather conditions during the month of production, NYMEX
      and local spot market prices, and other factors as the basis for these
      estimates. Variances  between
      our estimates and the actual amounts received are recorded in the month payment
      is received.




*Asset
      retirement obligations.* ** We
      are
      required to recognize an estimated liability for future costs associated with
      the abandonment of our oil & gas properties. We base our estimate of the
      liability on our historical experience in abandoning oil & gas wells
      projected into the future based on our current understanding of federal and
      state regulatory requirements. Our present value calculations require us to
      estimate the economic lives of our properties, assume what future inflation
      rates apply to external estimates, and determine what credit adjusted risk-free
      rate to use. The statement of operations impact of these estimates is reflected
      in our depreciation, depletion, and amortization and accretion calculations
      and
      occurs over the remaining life of our oil & gas properties.




*Valuation
      of long-lived and intangible assets.* ** Our
      property and equipment is recorded at cost. An impairment allowance is provided
      on unproved property when we determine that the property will not be developed
      or the carrying value will not be realized. We evaluate the realizability of
      our
      proved properties and other long-lived assets whenever events or changes in
      circumstances indicate that impairment may be appropriate. Our impairment test
      compares the expected undiscounted future net revenues from a property, using
      escalated pricing, with the related net capitalized costs of the property at
      the
      end of each period. When the net capitalized costs exceed the undiscounted
      future net revenue of a property, the cost of the property is written down
      to
      our estimate of fair value, which is determined by applying a discount rate
      that
      we believe is indicative of the current market. Our criteria for an acceptable
      internal rate of return are subject to change over time. Different pricing
      assumptions or discount rates could result in a different calculated
      impairment.




41




*Income
      taxes.*  We
      provide for deferred income taxes on the difference between the tax basis of
      an
      asset or liability and its carrying amount in our financial statements in
      accordance with SFAS No. 109, *Accounting
      for Income Taxes* .
      This
      difference will result in taxable income or deductions in future years when
      the
      reported amount of the asset or liability is recovered or settled, respectively.
      Considerable judgment is required in determining when these events may occur
      and
      whether recovery of an asset is more likely than not. Additionally, our federal
      and state income tax returns are generally not filed before the financial
      statements are prepared, therefore we estimate the tax basis of our assets
      and
      liabilities at the end of each period as well as the effects of tax rate
      changes, tax credits, and net operating and capital loss carryforwards and
      carrybacks. Adjustments related to differences between the estimates we used
      and
      actual amounts we reported are recorded in the period in which we file our
      income tax returns. These adjustments and changes in our estimates of asset
      recovery could have an impact on our results of operations. Deferred tax assets
      are reduced by a valuation allowance when, in the opinion of management, it
      is
      more likely than not that some portion or all of the deferred tax assets will
      not be realized. To date, we have not recorded any deferred tax assets because
      of the historical losses that we have incurred.




*Stock-based
      compensation.* ** As
      of
      April 1, 2006, we adopted the provisions of SFAS No. 123(R). This
      statement requires us to record expense associated with the fair value of
      stock-based compensation. As a result of adoption of this statement, we recorded
      compensation expense associated with stock options totaling $1,501,908 under
      the
      modified-prospective adoption method.




*Registration
      Payment Arrangements.*  During
      the year ended March 31, 2007, we adopted Staff Position (FSP) EITF (Emerging
      Issues Task Force) 00-19-2, *Accounting
      for Registration Payment Arrangements* .
      FSP
      EITF 00-19-2 specifies that the contingent obligation to make future payments
      or
      otherwise transfer consideration under a registration payment arrangement,
      whether issued as a separate agreement or included as a provision of a financial
      instrument or other agreement, should be separately recognized and measured
      in
      accordance with FASB Statement No. 5, *Accounting
      for Contingencies* .
      As a
      result of the adoption of the FSP we recorded $2,705,531 in liquidated damages
      as an expense in the consolidated statement of operations and in accrued
      liabilities at March 31, 2007.




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




**Commodity
      Price Risk**




Because
      of our relatively low level of current oil & gas production, we are not
      exposed to a great degree of market risk relating to the pricing applicable
      to
      our oil production. However, our ability to raise additional capital at
attractive pricing, our future revenues from oil & gas operations, our
      future profitability and future rate of growth depend substantially upon the
      market prices of oil and natural gas, which fluctuate widely. With increases
      to
      our production, exposure to this risk will become more significant. We expect
      commodity price volatility to continue. We do not currently utilize hedging
      contracts or derivative instruments to protect against commodity price risk.
      Terms of a debt facility may require that we hedge a portion of our expected
      future production.




42




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




Our
      Consolidated Financial Statements and Supplementary Data required by this Item
      8
      are set forth following the signature page and exhibit index of this Annual
      Report, and are incorporated herein by reference.




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




On
      July 31, 2006, our Board of Directors approved a change in our registered
      independent accounting firm to audit our financial statements. We appointed
      Hein
& Associates, LLP to serve as our registered independent accounting firm
      effective August 1, 2006 to replace Williams & Webster P.S. The change
      was made to further consolidate our accounting and auditing functions in Denver,
      Colorado.




There
      were no “disagreements” (as such term is defined in Item 304(a)(1)(iv) of
      Regulation S-K) with Williams & Webster P.S. at any time during our most
      recent two fiscal years and through July 31, 2006 regarding any matter of
      accounting principles or practices, financial statement disclosure, or auditing
      scope or procedures that if not resolved to the satisfaction of Williams &
Webster P.S. would have caused it to make reference to such disagreements in
      its
      reports.




The
      reports of Williams & Webster P.S. on our financial statements for the years
      March 31, 2005 and 2006 did not contain an adverse opinion or a disclaimer
      of opinion, and were not modified as to audit scope or accounting principles.
      However, the reports did contain an explanatory paragraph related to the
      uncertainty about our ability to continue as a going concern. There are no
      other
“reportable events” (as such term is defined in Item 304(a)(1)(v)(A) through (D)
      of Regulation S-K and its related instructions) in context of our relationship
      with Williams & Webster P.S. during the relevant periods.




During
      each of the two most recent fiscal years and through July 31, 2006, neither
      we nor anyone on our behalf consulted with Hein & Associates, LLP with
      respect to any accounting or auditing issues involving us. In particular, there
      was no discussion with us regarding the type of audit opinion that might be
      rendered on our financial statements, the application of accounting principles
      applied to a specified transaction, or any matter that was the subject of a
      disagreement or a “reportable event” as defined in Item 304(a)(1) of Regulation
      S-K and its related instructions.




Williams
      & Webster P.S. has reviewed the disclosures above, which were previously
      included in a Form 8-K filing made by us in 2006. In 2006, Williams &
Webster P.S. furnished us with a letter addressed to the Securities and Exchange
      Commission (SEC), which was filed as Exhibit 16.1 to the Current Report on
      Form 8-K filed by the Company with the SEC on August 10, 2006 and is
      incorporated herein by reference in accordance with Item 304(a)(3) of Regulation
      S-K.




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




**Disclosure
      Controls and Procedures.**




We
      maintain controls and procedures designed to ensure that information required
      to
      be disclosed in the reports that we file or submit under the Securities Exchange
      Act of 1934 (Exchange Act) is recorded, processed, summarized, and reported
      within the time periods specified in the rules and forms of the SEC. Evaluations
      have been performed under the supervision and with the participation of our
      management, including the Chief Executive Officer and Chief Financial Officer,
      of the effectiveness of the design and operation of our disclosure controls
      and
      procedures (as such terms are defined in Rule 13a-15(e) and 15d-15(e) of the
      Exchange Act). We view internal control over financial reporting to be an
      integral part of our disclosure control over financial reporting. Based on
      the
      evaluation of our Chief Executive Officer and Chief Financial Officer that
      there
      are material weaknesses in our internal control over financial reporting, we
      concluded that our disclosure controls and procedures are not effective. The
      weaknesses and our remediation efforts are discussed below.




43




Our
      management does not expect that our disclosure controls and procedures will
      prevent all errors and all fraud. The design of a control system must reflect
      the fact that there are resource constraints, and the benefits of controls
      must
      be considered relative to their costs. Based on the inherent limitations in
      all
      control systems, no evaluation of controls can provide absolute assurance that
      all control issues and instances of fraud, if any, within the Company have
      been
      detected. These inherent limitations include the realties that judgments in
      decision-making can be faulty and that breakdowns can occur because of simple
      errors or mistakes. Additionally, controls can be circumvented by the individual
      acts of some persons, by collusion of two or more people, or by management
      override of the controls. The design of any system of controls also is based
      in
      part upon certain assumptions about the likelihood of future events. Therefore,
      a control system, no matter how well conceived and operated, can provide only
      reasonable, not absolute, assurance that the objectives of the control system
      are met.




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




Our
      management, including the Chief Executive Officer and Chief Financial Officer,
      are responsible for establishing and maintaining adequate internal control
      over
      financial reporting. Our internal control over financial reporting was designed
      to provide reasonable assurance regarding the fair presentation of our financial
      statements in accordance with accounting principles generally accepted in the
      United States (GAAP). Our internal control over financial reporting includes
      those policies and procedures that:


·
              Establish
                  and maintain adequate internal control over financial reporting,




·
            Assess
                the effectiveness of internal control over financing
                reporting,




·
            Pertain
                to the maintenance of records that, in reasonable detail, accurately
                and
                fairly reflect the transactions and dispositions of our
                assets,




·
            Provide
                reasonable assurance that transactions are recorded as to permit
                preparation of financial statements in accordance with GAAP, and
                that our
                receipts and expenditures are being made only in accordance with
                authorization of our management and Board of Directors,
                and




·
            Provide
                reasonable assurance regarding prevention or timely detection of
                unauthorized acquisition, use, or disposition of our assets that
                could
                have a material effect on our financial statements.


Management
        has excluded from its assessment of internal control over financial reporting
        as
        of March 31, 2007, the internal control processes specifically related to
        the
        accounting for the acquisitions of the South Glenrock B, Cole Creek South,
        and
        Big Muddy oil & gas producing properties because they were acquired in the
        latter part of our third fiscal quarter and the early part of our fourth
        fiscal
        quarter of 2007. The acquisitions represented the first purchases of oil
&
gas producing properties for the Company. The processes that were specifically
        excluded were the accounting for the acquisition purchase price, depletion,
        and
        depreciation of the properties, oil & gas sales and receivables, production
        taxes, lease operating expenses and receivables, and the FAS143 asset retirement
        obligation. The acquisitions represent approximately $74.7 million, or 92%,
        $1.2
        million, or 21%, and $1.2 million, or 100%, of the Company’s total assets, total
        liabilities, and total revenues, respectively, as of and for the year ended
        March 31, 2007.




44


Management
        assessed the effectiveness of our internal control over financial reporting
        as
        of March 31, 2007 based on criteria issued by the Committee of Sponsoring
        Organizations of the Treadway Commission (COSO) in its *Internal
        Control-Integrated Framework* .
        Management’s assessment included an evaluation of the design of our internal
        control over financial reporting and testing of the operational effectiveness
        of
        our internal control over financial reporting. Based on our assessment,
        management has concluded that our internal control over financial reporting
        as
        of March 31, 2007 is not effective due to the identification of the material
        weaknesses discussed below. It is reasonably possible that, if not remediated,
        one or more of the material weaknesses could result in a material misstatement
        in our reported financial statements in a future annual or interim period.


A
        material weakness in internal control over financial reporting is defined
        by the
        Public Company Accounting Oversight Board’s Audit Standard No. 2 as being a
        significant deficiency, or combination of significant deficiencies, that
        results
        in more than a remote likelihood that a material misstatement of the financial
        statements would not be prevented or detected. A significant deficiency is
        a
        control deficiency, or combination of control deficiencies, that adversely
        affects the company’s ability to initiate, authorize, record, process, or report
        external financial data reliably in accordance with GAAP such that there
        is more
        than a remote likelihood that a misstatement of the company’s annual or interim
        financial statements that is more than inconsequential will not be prevented
        or
        detected.


Management’s
        assessment of our internal control over financial reporting is not effective
        as
        of March 31, 2007 due to the identification of the following material
        weaknesses.
  *(A)
        Our operating environment did not sufficiently promote effective internal
        control over financial reporting throughout the organization.*
  During
        the year, the Company changed focus from one engaged in the exploration of
        a
        gold prospect in British Columbia, Canada which found no commercially
        exploitable deposits or reserves of gold, to an oil & gas company focused on
        using CO 2 enhanced
        oil recovery methods in the Powder River Basin, Wyoming.




45


The
        change in operating environment is evidenced by the
        following:




·
            the
                small amount of cash on hand in the Company totaling approximately
                $15,000
                one year ago as compared to over $89,300,000 of equity capital raised
                by
                the Company by mid-January 2007,




·
            the
                rapid asset growth of the Company from one small undeveloped oil
& gas
                property valued at approximately $250,000 one year ago to the acquisition
                of three large producing oil fields that we purchased for approximately
                $73,000,000 in December 2006 and January 2007,




·
            the
                rapid employee growth of the Company from two employees one year
                ago to
                over 25 employees as of the date of filing of this Annual Report,
                including the employment of a new Chief Executive Officer, Chief
                Operating
                Officer, Chief Financial Officer, and Senior Vice President, Engineering,




·
            the
                short operating period of the Company during which, beginning on
                September
                30, 2006, we became an accelerated filer for SEC purposes and became
                subject to Sarbanes-Oxley rules concerning our internal control over
                financial reporting,




·
            the
                short period within which to test our internal controls over financial
                reporting resulting in a small sample size upon which the internal
                controls and financial reporting could be tested,
                and




·
            the
                hiring of four additional members of our Board of Directors in April
                2007,
                which increased our Board to six members from the two members in
                place
                throughout most of the year, and the absence of the establishment
                of the
                Company’s Audit Committee until May 2007.


Because
        of the rapid change in our operating environment, we did not effectively
        implement a system of entity-level internal controls by March 31, 2007, as
        evidenced by the following deficiencies:


*We
        did not maintain sufficient auditable evidence of management’s review and
        analysis of the reports that we file or submit under the Exchange
        Act.* We have
        implemented measures to retain copies of comments from our personnel evidencing
        such review and analysis. We anticipate that this deficiency will be remediated
        December 31, 2007.
  *We
        did not make available to management timely internal management reports,
        or to
        the extent available, we maintained insufficient auditable evidence of
        management’s review and analysis of those reports.* Management has directed that key performance indicators and other financial
        information be gathered and reported to our Chief Executive Officer and other
        appropriate senior managers on a monthly basis. We expect that the timing
        of
        this remediation effort will be partly dependent on the timing of our hiring
        of
        a Chief Accounting Officer and a Financial Controller. However, we anticipate
        that the steps necessary to address this deficiency will be fully implemented
        by
        December 31, 2007.


*We
      had no formal written policy governing delegation of approval authority levels
      for financial transactions.* While
      prior to March 2007 we had an informal policy governing delegation of approval
      authority levels for financial transactions, including contracts, expenditures,
      and payments, due to the low level of operations of the Company and its small
      size, we had no formal written policy governing delegation of approval authority
      levels for financial transactions. In March 2007 our policy governing such
      approval authority levels was adopted by our management and Board of Directors,
      and this policy was again reviewed and approved by our Board of Directors in
      May
      2007.


*We
        did not obtain attestations by management or our employees regarding their
        compliance with our Code of Business Conduct and Ethics.* While
        we
        did receive, by March 31, 2007, from all officers and employees attestations
        as
        to their understanding of and compliance with Company policies related to
        their
        employment, we did not obtain attestations regarding their compliance with
        our
        Code of Business Conduct and Ethics. We adopted a new Code of Business Conduct
        and Ethics in May 2007, and that policy has been posted on our website. We
        have
        distributed the policy document to all employees and Directors, and as of
        the
        date of filing of this Annual Report, we received from all employees and
        Directors attestations as to their understanding of and compliance with this
        policy.




46


*We
        did not conduct a full fraud assessment process prior to year end.* In
        May
        2007 we initiated a formal fraud assessment process. Our policies call for
        a
        quarterly fraud assessment as part of our financial closing procedures and
        an
        annual fraud assessment as part of the business planning process carried
        out by
        our management. We anticipate that the steps necessary to address this
        deficiency will be fully implemented by December 31, 2007.
  *We
        did not obtain prescribed attestations by management regarding their compliance
        with an insider trading policy or attestations from our employees as to their
        understanding of and compliance with the company policies related to insider
        trading.* We
        adopted a formal Insider Trading Policy on May 31, 2007. This policy document
        has been posted on our website and we have distributed the policy document
        to
        all employees and Directors, and as of the date of filing of this Annual
        Report
        we received from all employees and Directors attestations as to their
        understanding of and compliance with this policy.
  *(B)*  *We
        did not have a sufficient complement of personnel with appropriate training
        and
        experience in GAAP, as evidenced by the following deficiencies* :
  The
        rapid
        employee growth of the Company from two employees one year ago to over 25
        employees as of the date of filing of this Annual Report resulted in the
        Company
        not having a sufficient complement of personnel with appropriate training
        and
        experience in GAAP during the past fiscal year. We did not have any significant
        properties or operations until we completed our equity private placement
        in
        mid-January 2007 and acquired our three properties in Wyoming. In January
        2007
        we hired a Chief Financial Officer with an M.B.A. in Finance from the Wharton
        School, University of Pennsylvania, and with B.S. and Master’s degrees in civil
        engineering from Rice University. He has over twenty years of experience
        in
        financial management and strategic planning in the energy industry, including
        serving most recently as treasurer and acting chief financial officer of
        a
        privately held energy and production company. Although both our Chief Executive
        Officer and Chief Financial Officer have substantial financial experience,
        they
        do not have significant experience in preparing financial statements of a
        publicly held company or in implementing internal control over financing
        reporting for a public company. As a result, during the year we relied primarily
        on consultants for preparation of our financial statements and for our internal
        control over financial reporting. For example, the reconciliation of payroll,
        among other items, to the general ledger was not performed throughout the
        year.
        Management, in coordination with the Audit Committee, has undertaken steps
        to
        reorganize our Accounting Department, and management is allocating significant
        additional resources to our Accounting Department, including retaining
        additional consultants and hiring new full-time personnel.
  In
        June
        2007, our Financial Controller, who was hired in March 2007, announced her
        intention to leave the Company. Management, in coordination with the Audit
        Committee, has begun an executive search for a new Financial Controller.
        We
        expect this deficiency will be remediated by December 31, 2007.


In
      June
      2007, Management, in coordination with the Audit Committee, implemented the
      following remediation plans:




·
            retained
                a national executive services and consulting firm, to provide immediate
                assistance to the Company with respect to our internal financial
                reporting, reports that we file or submit under the Exchange Act,
                and our
                internal control over financial reporting. They have supplied the
                Company
                with two senior-level executives experienced in financial reporting,
                Exchange Act reporting, and control over financial reporting. In
                addition
                they will assist the Company to strategically identify its
                requirements for additional full-time Accounting Department personnel,
                and
                locating and recruiting such personnel.




47




·
            began
                an executive search in June 2007 for a Chief Accounting Officer who
                would
                have the requisite GAAP training and experience to supplement our
                Chief
                Financial Officer’s other finance experience. We expect that this
                deficiency will be remediated by December 31,
                2007.




Management,
      in coordination with the Audit Committee, intends to provide our Operations
      Controller with additional training in GAAP. We anticipate that this deficiency
      will be remediated by December 31, 2007.




*(C)*  *We
      did not adequately segregate the duties of different personnel within our
      Accounting Department due to an insufficient complement of staff and inadequate
      management oversight* .




Our
      Operations Controller performed all of the following functions: (i) operations
      accounting system set-up, (ii) administration, (iii) data input, and (iv)
      reporting. Activities that were not adequately segregated included (i)
      processing of deposits and making payments, and (ii) payroll calculation and
      payroll processing. We are addressing these segregation issues through revised
      desk procedures and management and staff training. We anticipate that this
      deficiency will be remediated by December 31, 2007.




Our
      Financial Controller, who was responsible for our financial reporting,
      established and maintained the internal controls over financial reporting ,
      and
      also identified which tests should be performed over our internal control over
      financial reporting We anticipate that this deficiency will be remediated
      byDecember 31, 2007.




48




*Changes
      in Internal Control over Financial Reporting*




The
      changes noted above are the only changes during our most recently completed
      fiscal year that have materially affected or are reasonably likely to materially
      affect our internal control over financial reporting.




Hein
      & Associates, LLP, the independent registered public accounting firm that
      audited our financial statements included in this Annual Report, has also issued
      an attestation on our management’s assessment of the effectiveness of our
      internal control over financial reporting and the effectiveness of our internal
      control over financial reporting as of March 31, 2007, which follows.




49


**REPORT
        OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**
 
  To
        the
        Board of Directors
 Rancher
        Energy Corp.
 Denver,
        Colorado
 
 We
        have
        audited management’s assessment, included in the accompanying Management’s
        Report on Internal Control, that Rancher Energy Corp. did not maintain effective
        internal control over financial reporting as of March 31, 2007, because of
        the
        effect of the material weaknesses identified in management’s assessment, based
        on criteria established in *Internal Control—Integrated Framework* issued
        by
        the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
        Rancher Energy Corp.’s management is responsible for maintaining effective
        internal control over financial reporting and for its assessment of the
        effectiveness of internal control over financial reporting. Our responsibility
        is to express an opinion on management’s assessment and an opinion on the
        effectiveness of the company’s internal control over financial reporting based
        on our audit.
 
 We
        conducted our audit in accordance with the standards of the Public Company
        Accounting Oversight Board (United States). Those standards require that
        we plan
        and perform the audit to obtain reasonable assurance about whether effective
        internal control over financial reporting was maintained in all material
        respects. Our audit included obtaining an understanding of internal control
        over
        financial reporting, evaluating management’s assessment, testing and evaluating
        the design and operating effectiveness of internal control, and performing
        such
        other procedures as we considered necessary in the circumstances. We believe
        that our audit provides a reasonable basis for our opinion.
 
 A
        company’s internal control over financial reporting is a process designed to
        provide reasonable assurance regarding the reliability of financial reporting
        and the preparation of financial statements for external purposes in accordance
        with generally accepted accounting principles. A company’s internal control over
        financial reporting includes those policies and procedures that (1) pertain
        to
        the maintenance of records that, in reasonable detail, accurately and fairly
        reflect the transactions and dispositions of the assets of the company; (2)
        provide reasonable assurance that transactions are recorded as necessary
        to
        permit preparation of financial statements in accordance with generally accepted
        accounting principles, and that receipts and expenditures of the company
        are
        being made only in accordance with authorizations of management and directors
        of
        the company; and (3) provide reasonable assurance regarding prevention or
        timely
        detection of unauthorized acquisition, use, or disposition of the company’s
        assets that could have a material effect on the financial
        statements.
  50
 To
          the
          Board of Directors
 Rancher
          Energy Corp.
 Page
          2
 Because
        of its inherent limitations, internal control over financial reporting may
        not
        prevent or detect misstatements. Also, projections of any evaluation of
        effectiveness to future periods are subject to the risk that controls may
        become
        inadequate because of changes in conditions, or that the degree of compliance
        with the policies or procedures may deteriorate.
 
 A
        material weakness is a control deficiency, or combination of control
        deficiencies, that results in more than a remote likelihood that a material
        misstatement of the annual or interim financial statements will not be prevented
        or detected. The following material weaknesses have been identified and included
        in management’s assessment as of March 31, 2007.
 
 1)
            The
                Company’s control environment did not sufficiently promote effective
                internal control over financial reporting throughout the
                organization. 
 2)
            The
                Company did not have in place adequate competent accounting personnel
                with
                the appropriate training and expertise in generally accepted accounting
                principles (“GAAP”). 
 3)
            The
                Company did not adequately segregate the duties in the accounting
                department, due to an insufficient complement of personnel and inadequate
                management oversight. 
 These
        material weaknesses were considered in determining the nature, timing, and
        extent of audit tests applied in our audit of the 2007 financial statements,
        and
        this report does not affect our report dated June 28, 2007 on those
        financial statements.
 
 In
        our
        opinion, management’s assessment that Rancher Energy Corp. did not maintain
        effective internal control over financial reporting as of March 31, 2007,
        is
        fairly stated, in all material respects, based on criteria established
        in *Internal Control—Integrated Framework* issued
        by
        COSO *.* Also, in
        our opinion, because of the effect of the material weaknesses described above
        on
        the achievement of the objectives of the control criteria, Rancher Energy
        Corp.
        did not maintain effective internal control over financial reporting as of
        March
        31, 2007, based on criteria established in *Internal Control—Integrated Framework* issued
        by
        COSO.
  
 */s/
        HEIN* *&
        ASSOCIATES LLP*
 
 Denver,
        Colorado
 June
        28,
        2007




51


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




None.




52


**PART
      III**




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




Except
      as
      set forth below, the information required by Item 10 is hereby incorporated
      herein by reference to the definitive Proxy Statement for our 2007 Annual
      Meeting of Stockholders.




We
      have
      adopted a Code of Business Conduct and Ethics for Directors, Officers, and
      Employees. We undertake to provide any person, without charge, a copy of the
      Code of Business Conduct and Ethics. Requests should be submitted in writing
      to
      the attention of our Chief Financial Officer, Rancher Energy Corp.,
      999-18 th Street,
      Suite 1740, Denver, Colorado 80202.




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




The
      information required by Item 11 is hereby incorporated herein by reference
      to
      the definitive Proxy Statement for our 2007 Annual Meeting of
      Stockholders.




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




The
      information required by Item 12, as to certain beneficial owners and management,
      is hereby incorporated herein by reference to the definitive Proxy Statement
      for
      our 2007 Annual Meeting of Stockholders.




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




The
      information required by Item 13 is hereby incorporated herein by reference
      to
      the definitive Proxy Statement for our 2007 Annual Meeting of
      Stockholders.




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




The
      information required by Item 14 is hereby incorporated herein by reference
      to
      the definitive Proxy Statement for our 2007 Annual Meeting of
      Stockholders.




53




PART
      IV




**ITEM
      15.**  **EXHIBITS** **,
      Financial Statement Schedules.**




(a)
      Documents filed as a part of the report:





(1)  Index
      to
      Consolidated Financial Statements of the Company





An
“Index
      to Consolidated Financial Statements” has been filed as a part of this Report
      beginning on page F-1 hereof.





(2)  All
      schedules for which provision is made in the applicable accounting regulation
      of
      the SEC have been omitted because of the absence of the conditions under which
      they would be required or because the information required is included in the
      consolidated financial statements of the Registrant or the notes
      thereto.





(3)  Exhibits





**Exhibit**
            
            **Description**3.1
            
            Amended
                and Restated Articles of Incorporation(17)3.4
            
            Amended
                and Restated Bylaws(2)4.1
            
            Form
                of Stock Certificate for Fully Paid, Non-Assessable Common Stock
                of the
                Company(1)4.2
            
            Form
                of Unit Purchase Agreement(2)4.3
            
            Form
                of Warrant Certificate(2)4.4
            
            Form
                of Registration Rights Agreement, dated December 21, 2006(3)4.5
            
            Form
                of Warrant to Purchase Common Stock(3)10.1
            
            Burke
                Ranch Unit Purchase and Participation Agreement between Hot Springs
                Resources Ltd. and PIN Petroleum Partners Ltd., dated February 6,
                2006(4)10.2
            
            Employment
                Agreement between John Works and Rancher Energy Corp., dated June 1,
                2006(5)10.3
            
            Assignment
                Agreement between PIN Petroleum Partners Ltd. and Rancher Energy
                Corp.,
                dated June 6, 2006(5)10.4
            
            Loan
                Agreement between Enerex Capital, Corp. and Rancher Energy Corp.,
                dated
                June 6, 2006(5)10.5
            
            Letter
                Agreement between NITEC LLC and Rancher Energy Corp., dated June 7,
                2006(5)10.6
            
            Loan
                Agreement between Venture Capital First LLC and Rancher Energy Corp.,
                dated June 9, 2006(6)10.7
            
            Exploration
                and Development Agreement between Big Snowy Resources, LP and Rancher
                Energy Corp., dated June 15, 2006(5)10.8
            
            Assignment
                Agreement between PIN Petroleum Partners Ltd. and Rancher Energy
                Corp.,
                dated June 21, 2006(5)10.9
            
            Purchase
                and Sale Agreement between Wyoming Mineral Exploration, LLC and Rancher
                Energy Corp., dated August 10, 2006(4)10.10
            
            South
                Glenrock and South Cole Creek Purchase and Sale Agreement by and
                between
                Nielson & Associates, Inc. and Rancher Energy Corp., dated
                October 1, 2006(7)10.11
            
            Rancher
                Energy Corp. 2006 Stock Incentive Plan(7)10.12
            
            Rancher
                Energy Corp. 2006 Stock Incentive Plan Form of Option Agreement(7)10.13
            
            Employment
                Agreement by and between John Dobitz and Rancher Energy Corp., dated
                October 2, 2006(7)




54




**Exhibit**
            
            **Description**10.14
            
            Denver
                Place Office Lease between Rancher Energy Corp. and Denver Place
                Associates Limited Partnership, dated October 30, 2006(8)10.15
            
            Employment
                Agreement between Andrew Casazza and Rancher Energy Corp., dated
                October 23, 2006(9)10.16
            
            Finder’s
                Fee Agreement between Falcon Capital and Rancher Energy Corp.(10)10.17
            
            Amendment
                to Purchase and Sale Agreement between Wyoming Mineral Exploration,
                LLC
                and Rancher Energy Corp.(11)10.18
            
            Letter
                Agreement between Certain Unit Holders and Rancher Energy Corp.,
                dated
                December 8, 2006(2)10.19
            
            Letter
                Agreement between Certain Option Holders and Rancher Energy Corp.,
                dated
                December 13, 2006(2)10.20
            
            Product
                Sale and Purchase Contract by and between Rancher Energy Corp. and
                the
                Anadarko Petroleum Corporation, dated December 15, 2006(12)10.21
            
            Amendment
                to Purchase and Sale Agreement between Nielson & Associates, Inc. and
                Rancher Energy Corp.(13)10.22
            
            Securities
                Purchase Agreement by and among Rancher Energy Corp. and the Buyers
                identified therein, dated December 21, 2006(3)10.23
            
            Lock-Up
                Agreement between Rancher Energy Corp. and Stockholders identified
                therein, dated December 21, 2006(3)10.24
            
            Voting
                Agreement between Rancher Energy Corp. and Stockholders identified
                therein, dated as of December 13, 2006(3)10.25
            
            Form
                of Convertible Note(14)10.26
            
            Employment
                Agreement between Daniel Foley and Rancher Energy Corp., dated
                January 12, 2007(15)10.27
            
            First
                Amendment to Securities Purchase Agreement by and among Rancher Energy
                Corp. and the Buyers identified therein, dated as of January 18, 2007(16)10.28
            
            Rancher
                Energy Corp. 2006 Stock Incentive Plan form of Restricted Stock Agreement(20)14.1
            
            Code
                of Business Conduct and Ethics(18)16.1
            
            Letter
                from Williams & Webster, P.S. regarding change in certifying
                accountant(19)21.1
            
            List
                of Subsidiaries(20)23.1
            
            Consent
                of Ryder Scott Company, L.P., Independent Petroleum Engineers(20)31.1
            
            Certification
                Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Executive Officer)(20)31.2
            
            Certification
                Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Financial Officer)(20)32.1
            
            Certification
                pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
                906 of
                the Sarbanes-Oxley Act of 2002(20)32.2
            
            Certification
                pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
                906 of
                the Sarbanes-Oxley Act of 2002(20)





(1)
            Incorporated
                by reference from our Form SB-2 Registration Statement filed on
                June 9, 2004 (File No.
                333-116307).




(2)
            Incorporated
                by reference from our Current Report on Form 8-K filed on
                December 18, 2006 (File No.
                000-51425).




(3)
            Incorporated
                by reference from our Current Report on Form 8-K filed on
                December 27, 2006 (File No.
                000-51425).




(4)
            Incorporated
                by reference from our Quarterly Report on Form 10-Q/A filed on
                August 28, 2006 (File No.
                000-51425).




55




(5)
            Incorporated
                by reference from our Annual Report on Form 10-K filed on June 30,
                2006 (File No. 000-51425).




(6)
            Incorporated
                by reference from our Current Report on Form 8-K filed on June 21,
                2006 (File No. 000-51425).




(7)
            Incorporated
                by reference from our Current Report on Form 8-K filed on October 6,
                2006 (File No. 000-51425).




(8)
            Incorporated
                by reference from our Current Report on Form 8-K filed on November 9,
                2006 (File No. 000-51425).




(9)
            Incorporated
                by reference from our Current Report on Form 8-K filed on
                November 14,2006 (File No.
                000-51425).




(10)
            Incorporated
                by reference from our Current Report on Form 8-K/A filed on
                November 14, 2006 (File No.
                000-51425).




(11)
            Incorporated
                by reference from our Current Report on Form 8-K filed on December 4,
                2006 (File No. 000-51425).




(12)
            Incorporated
                by reference from our Current Report on Form 8-K filed on
                December 22, 2006 (File No.
                000-51425).




(13)
            Incorporated
                by reference from our Current Report on Form 8-K filed on
                December 27, 2006 (File No.
                000-51425).




(14)
            Incorporated
                by reference from our Current Report on Form 8-K filed on January 8,
                2007 (File No. 000-51425).




(15)
            Incorporated
                by reference from our Current Report on Form 8-K filed on January 16,
                2007 (File No. 000-51425).




(16)
            Incorporated
                by reference from our Current Report on Form 8-K filed on January 25,
                2007 (File No. 000-51425).




(17)
            Incorporated
                by reference from our Current Report on Form 8-K filed on April 3,
                2007 (File No. 000-51425).




(18)
            Incorporated
                by reference from our Current Report on Form 8-K filed on June 6,
                2007 (File No. 000-51425).




(19)
            Incorporated
                by reference from our Current Report on Form 8-K/A filed on August 9,
                2006 (File No. 000-51425)




(20)
            Filed
                herewith.




56


**SIGNATURES**




Pursuant
      to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
      1934, the registrant has duly caused this Annual
      Report to be signed on its behalf by the undersigned, thereunto duly authorized,
      this 29 th day of
      June, 2007.






**RANCHER ENERGY
              CORP.**/s/
              John WorksJohn Works, President,
                Chief Executive Officer,
              Principal
                Executive Officer, Director, Secretary,
              and
                Treasurer







Pursuant
      to the requirements of the Securities Exchange Act of 1934, this Annual Report
      has been signed below by the following persons on behalf of the Registrant
      and
      in the capacities and on the dates indicated.




Signature
            
            Title
            
            Date/s/
John
              Works
            
            President,
              Chief Executive Officer,John
                Works
            
            Principal
                Executive Officer, Director, Secretary,
              and
                Treasurer
            
            June 29,
                2007/s/
                Daniel P. Foley
            
            Chief
              Financial Officer,
              PrincipalDaniel
                P. Foley
            
            \Financial
                Officer, and Principal
              Accounting
                Officer
            
            June 29,
                2007/s/
                William A. AndersonWilliam
                A. Anderson
            
            Director
            
            June 29,
                2007/s/
                Joseph P. McCoyJoseph
                P. McCoy
            
            Director
            
            June 29,
                2007/s/
                Patrick M. MurrayPatrick
                M. Murray
            
            Director
            
            June 29,
                2007/s/
                Myron M. SheinfeldMyron
                M. Sheinfeld
            
            Director
            
            June 29,
                2007/s/
                Mark WortheyMark
                Worthey
            
            Director
            
            June 29,
                2007











**EXHIBIT
      INDEX**





**Exhibit**
            
            **Description**3.1
            
            Amended
                and Restated Articles of Incorporation(17)3.4
            
            Amended
                and Restated Bylaws(2)4.1
            
            Form
                of Stock Certificate for Fully Paid, Non-Assessable Common Stock
                of the
                Company(1)4.2
            
            Form
                of Unit Purchase Agreement(2)4.3
            
            Form
                of Warrant Certificate(2)4.4
            
            Form
                of Registration Rights Agreement, dated December 21, 2006(3)4.5
            
            Form
                of Warrant to Purchase Common Stock(3)10.1
            
            Burke
                Ranch Unit Purchase and Participation Agreement between Hot Springs
                Resources Ltd. and PIN Petroleum Partners Ltd., dated February 6,
                2006(4)10.2
            
            Employment
                Agreement between John Works and Rancher Energy Corp., dated June 1,
                2006(5)10.3
            
            Assignment
                Agreement between PIN Petroleum Partners Ltd. and Rancher Energy
                Corp.,
                dated June 6, 2006(5)10.4
            
            Loan
                Agreement between Enerex Capital, Corp. and Rancher Energy Corp.,
                dated
                June 6, 2006(5)10.5
            
            Letter
                Agreement between NITEC LLC and Rancher Energy Corp., dated June 7,
                2006(5)10.6
            
            Loan
                Agreement between Venture Capital First LLC and Rancher Energy Corp.,
                dated June 9, 2006(6)10.7
            
            Exploration
                and Development Agreement between Big Snowy Resources, LP and Rancher
                Energy Corp., dated June 15, 2006(5)10.8
            
            Assignment
                Agreement between PIN Petroleum Partners Ltd. and Rancher Energy
                Corp.,
                dated June 21, 2006(5)10.9
            
            Purchase
                and Sale Agreement between Wyoming Mineral Exploration, LLC and Rancher
                Energy Corp., dated August 10, 2006(4)10.10
            
            South
                Glenrock and South Cole Creek Purchase and Sale Agreement by and
                between
                Nielson & Associates, Inc. and Rancher Energy Corp., dated
                October 1, 2006(7)10.11
            
            Rancher
                Energy Corp. 2006 Stock Incentive Plan(7)10.12
            
            Rancher
                Energy Corp. 2006 Stock Incentive Plan Form of Option Agreement(7)10.13
            
            Employment
                Agreement by and between John Dobitz and Rancher Energy Corp., dated
                October 2, 2006(7)10.14
            
            Denver
                Place Office Lease between Rancher Energy Corp. and Denver Place
                Associates Limited Partnership, dated October 30, 2006(8)10.15
            
            Employment
                Agreement between Andrew Casazza and Rancher Energy Corp., dated
                October 23, 2006(9)10.16
            
            Finder’s
                Fee Agreement between Falcon Capital and Rancher Energy Corp.(10)10.17
            
            Amendment
                to Purchase and Sale Agreement between Wyoming Mineral Exploration,
                LLC
                and Rancher Energy Corp.(11)10.18
            
            Letter
                Agreement between Certain Unit Holders and Rancher Energy Corp.,
                dated
                December 8, 2006(2)10.19
            
            Letter
                Agreement between Certain Option Holders and Rancher Energy Corp.,
                dated
                December 13, 2006(2)10.20
            
            Product
                Sale and Purchase Contract by and between Rancher Energy Corp. and
                the
                Anadarko Petroleum Corporation, dated December 15, 2006(12)10.21
            
            Amendment
                to Purchase and Sale Agreement between Nielson & Associates, Inc. and
                Rancher Energy Corp.(13)10.22
            
            Securities
                Purchase Agreement by and among Rancher Energy Corp. and the Buyers
                identified therein, dated December 21, 2006(3)




E-1




**Exhibit**
            
            **Description**10.23
            
            Lock-Up
                Agreement between Rancher Energy Corp. and Stockholders identified
                therein, dated December 21, 2006(3)10.24
            
            Voting
                Agreement between Rancher Energy Corp. and Stockholders identified
                therein, dated as of December 13, 2006(3)10.25
            
            Form
                of Convertible Note(14)10.26
            
            Employment
                Agreement between Daniel Foley and Rancher Energy Corp., dated
                January 12, 2007(15)10.27
            
            First
                Amendment to Securities Purchase Agreement by and among Rancher Energy
                Corp. and the Buyers identified therein, dated as of January 18, 2007(16)10.28
            
            Rancher
                Energy Corp. 2006 Stock Incentive Plan form of Restricted Stock Agreement(20)14.1
            
            Code
                of Business Conduct and Ethics(18)16.1
            
            Letter
                from Williams & Webster, P.S. regarding change in certifying
                accountant(19)21.1
            
            List
                of Subsidiaries(20)23.1
            
            Consent
                of Ryder Scott Company, L.P., Independent Petroleum Engineers(20)31.1
            
            Certification
                Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Executive Officer)(20)31.2
            
            Certification
                Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Financial Officer)(20)32.1
            
            Certification
                pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
                906 of
                the Sarbanes-Oxley Act of 2002(20)32.2
            
            Certification
                pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
                906 of
                the Sarbanes-Oxley Act of 2002(20)





(1)
            Incorporated
                by reference from the Company's Form SB-2 Registration Statement
                filed on
                June 9, 2004 (File No.
                333-116307).




(2)
            Incorporated
                by reference from the Company's Current Report on Form 8-K filed
                on
                December 18, 2006 (File No.
                000-51425).




(3)
            Incorporated
                by reference from the Company's Current Report on Form 8-K filed
                on
                December 27, 2006 (File No.
                000-51425).




(4)
            Incorporated
                by reference from the Company's Quarterly Report on Form 10-Q/A filed
                on
                August 28, 2006 (File No.
                000-51425).




(5)
            Incorporated
                by reference from the Company's Annual Report on Form 10-K filed
                on
                June 30, 2006 (File No.
                000-51425).




(6)
            Incorporated
                by reference from the Company's Current Report on Form 8-K filed
                on
                June 21, 2006 (File No.
                000-51425).




(7)
            Incorporated
                by reference from the Company's Current Report on Form 8-K filed
                on
                October 6, 2006 (File No.
                000-51425).




(8)
            Incorporated
                by reference from the Company's Current Report on Form 8-K filed
                on
                November 9, 2006 (File No.
                000-51425).




(9)
            Incorporated
                by reference from the Company's Current Report on Form 8-K filed
                on
                November 14,2006 (File No.
                000-51425).




E-2




(10)
            Incorporated
                by reference from the Company's Current Report on Form 8-K/A filed
                on
                November 14, 2006 (File No.
                000-51425).




(11)
            Incorporated
                by reference from the Company's Current Report on Form 8-K filed
                on
                December 4, 2006 (File No.
                000-51425).




(12)
            Incorporated
                by reference from the Company's Current Report on Form 8-K filed
                on
                December 22, 2006 (File No.
                000-51425).




(13)
            Incorporated
                by reference from the Company's Current Report on Form 8-K filed
                on
                December 27, 2006 (File No.
                000-51425).




(14)
            Incorporated
                by reference from the Company's Current Report on Form 8-K filed
                on
                January 8, 2007 (File No.
                000-51425).




(15)
            Incorporated
                by reference from the Company's Current Report on Form 8-K filed
                on
                January 16, 2007 (File No.
                000-51425).




(16)
            Incorporated
                by reference from the Company's Current Report on Form 8-K filed
                on
                January 25, 2007 (File No.
                000-51425).




(17)
            Incorporated
                by reference from the Company's Current Report on Form 8-K filed
                on
                April 3, 2007 (File No.
                000-51425).




(18)
            Incorporated
                by reference from the Company's Current Report on Form 8-K filed
                on
                June 6, 2007 (File No.
                000-51425).




(19)
            Incorporated
                by reference from our Current Report on Form 8-K/A filed on August 9,
                2006 (File No. 000-51425).




(20)
            Filed
                herewith.




E-3


**INDEX
      TO FINANCIAL STATEMENTS**


**Audited
                  Financial Statements - Rancher Energy Corp.**Report
                  of Independent Registered Public Accounting Firm
              F-2Report
                  of Independent Registered Public Accounting Firm
              F-3Balance
                  Sheets as of March 31, 2007 and 2006
              F-4Statements
                  of Operations for the Years Ended March 31, 2007, 2006, and
                  2005
              F-5Statement
                  of Changes in Stockholders’ Equity (Deficit) for the Years Ended
                  March 31, 2007, 2006, and 2005
              F-6Statements
                  of Cash Flows for the Years Ended March 31, 2007, 2006, and
                  2005
              F-7Notes
                  to Financial Statements
              F-8**Audited
                  Carve Out Financial Statements - Cole Creek South and South Glenrock
                  Operations**Report
                  of Independent Registered Public Accounting Firm
              F-29Carve
                  Out Balance Sheets as of December 21, 2006 and December 31, 2005
              F-30Carve
                  Out Statements of Operations for the Period from January 1, 2006
                  through December 21, 2006, the year ended December 31, 2005 and
                  for the Period from September 1, 2004 (inception) through
                  December 31, 2004
              F-31Carve
                  Out Statement of Changes in Owner’s Net Investment for the Period from
                  September 1, 2004 (inception) through December 31, 2004, the
                  year ended December 31, 2005, and for the Period from January 1,
                  2006 through December 21, 2006
              F-32Carve
                  Out Statements of Cash Flows for the Period from January 1, 2006
                  through December 21, 2006, the year ended December 31, 2005 and
                  the Period from September 1, 2004 (inception) through
                  December 31, 2004
              F-33Notes
                  to Carve Out Financial Statements
              F-34**Audited
                  Statement of Revenues and Direct Operating Expenses - Cole Creek
                  South and
                  South Glenrock Operations**Report
                    of Independent Registered Public Accounting Firm
              F-42Statement
                  of Revenues and Direct Operating Expenses for the Period from
                  January 1, 2004 through August 31, 2004
              F-43Notes
                  to Statement of Revenues and Direct Operating Expenses
              F-44




F-1




**REPORT
      OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**








Board
      of
      Directors and Stockholders of Rancher Energy Corp.


Denver,
      Colorado








We
      have
      audited the accompanying balance sheet of Rancher Energy Corp. (the Company)
      as
      of March 31, 2007, and the related statements of operations, stockholders’
equity, and cash flows for the year then ended. These financial statements
      are
      the responsibility of the Company’s management. Our responsibility is to express
      an opinion on these financial statements based on our audit.





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





In
      our
      opinion, the financial statements referred to above present fairly, in all
      material respects, the financial position of the Company as of March 31,
      2007, and the results of its operations and cash flows for the year then ended,
      in conformity with U.S. generally accepted accounting principles.





As
      discussed in Note 1 to the accompanying financial statements, effective
      April 1, 2006, the Company adopted Statement of Financial Accounting
      Standards No. 123(R), Share-Based Payment.





We
      also
      have audited, in accordance with the standards of the Public Company Accounting
      Oversight Board (United States), the effectiveness of the Company’s internal
      control over financial reporting as of March 31, 2007, based on criteria
      established in Internal Control-Integrated Framework issued by the Committee
      of
      Sponsoring Organizations of the Treadway Commission (COSO) and our report
      dated June 28, 2007 expressed an unqualified opinion on management’s
      assessment of the effectiveness of the Company’s internal control over financial
      reporting and an adverse opinion on the effectiveness of the Company’s internal
      control over financial reporting.








/s/
      Hein
& Associates LLP


Denver,
      Colorado


June 28,
      2007




F-2




To
        the
        Board of Directors
 Rancher
        Energy Corp.
 (fka
        Metalex Resources, Inc.)
 Spokane,
        Washington
  
 **REPORT
        OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**
 
 We
        have
        audited the accompanying balance sheets of Rancher Energy Corp. (fka Metalex
        Resources, Inc. and a Nevada corporation and an exploration stage company)
        as of
        March 31, 2006 and 2005, and the related statements of operations, stockholder’s
        deficit and cash flows for the years then ended. These financial statements
        are
        the responsibility of the Company’s management. Our responsibility is to express
        an opinion on these financial statements based on our audit.
 
 We
        conducted our audit in accordance with auditing standards of the Public Company
        Accounting Oversight Board (United States). Those standards require that
        we plan
        and perform the audit to obtain reasonable assurance about whether the financial
        statements are free of material misstatement. An audit includes examining,
        on a
        test basis, evidence supporting the amounts and disclosures in the financial
        statements. An audit also includes assessing the accounting principles used
        and
        significant estimates made by management, as well as evaluating the overall
        financial statement presentation. We believe that our audit provides a
        reasonable basis for our opinion.
 
 In
        our
        opinion, the financial statements referred to above present fairly, in all
        material respects, the financial position of Rancher Energy Corp. as of March
        31, 2006 and 2005, and the results of its operations, stockholder’s deficit and
        cash flows for the years then ended in conformity with accounting principles
        generally accepted in the United States of America.
 
 The
        accompanying financial statements have been prepared assuming that the Company
        will continue as a going concern. As discussed in Note 1 to the financial
        statements, the Company’s operating losses raise substantial doubt about its
        ability to continue as a going concern. Management’s plans regarding those
        matters also are described in Note 1. The financial statements do not include
        any adjustments that might result from the outcome of this
        uncertainty.
 
 
 /s/Williams
        & Webster, P.S.
 
 Williams
        & Webster, P.S.
 *Certified
        Public Accountants*
 Spokane,
        Washington
 June
        19,
        2006


F-3




**Rancher
      Energy Corp.**




**Balance
      Sheets**





March 31,2007
            
            2006**ASSETS**Current
                assets:Cash
                and cash equivalents
            
            $
            5,129,883
            
            $
            46,081Accounts
                receivable
            
            
            453,709
            
            
            -Total
                current assets
            
            
            5,583,592
            
            
            46,081Oil
                & gas properties (successful efforts method):Unproved
            
            
            56,079,133
            
            
            -Proved
            
            
            18,552,188
            
            
            -Less:
                Accumulated depletion, depreciation, and amortization
            
            
            (347,821
            )
            
            -Net
                oil & gas properties
            
            
            74,283,500
            
            
            -Other
                assets, net of accumulated depreciation of $27,880 and $414,
                respectively
            
            
            1,610,939
            
            
            476Total
                assets
            
            $
            81,478,031
            
            $
            46,557**LIABILITIES
                AND STOCKHOLDERS’ EQUITY**Current
                liabilities:Accounts
                payable and accrued liabilities
            
            $
            1,542,840
            
            $
            2,070Accrued
                oil & gas property costs
            
            
            250,000
            
            
            -Asset
                retirement obligation
            
            
            196,000
            
            
            -Liquidated
                damages pursuant to registration rights arrangement
            
            
            2,705,531
            
            
            -Total
                current liabilities
            
            
            4,694,371
            
            
            2,070Long-term
                liabilities:Asset
                retirement obligation
            
            
            1,025,567
            
            
            -Commitments
                and contingencies (Note 5)Stockholders’
                equity:Common
                stock, $0.00001 par value, 275,000,000 and 100,000,000 shares authorized
                at March 31, 2007 and 2006, respectively; 102,041,432 and 28,500,000
                shares issued and outstanding at March 31, 2007 and 2006,
                respectively
            
            
            1,021
            
            
            285Additional
                paid-in capital
            
            
            84,985,934
            
            
            570,809Accumulated
                deficit
            
            
            (
                9,228,862
            )
            
            (526,607
            )Total
                stockholders’ equity
            
            
            75,758,093
            
            
            44,487Total
                liabilities and stockholders’ equity
            
            $
            81,478,031
            
            $
            46,557





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




F-4


**Rancher
      Energy Corp.**


**Statements
      of Operations**





For
                the Years Ended March 31,2007
            
            2006
            
            2005Revenue:Oil
                & gas sales
            
            $
            1,161,819
            
            $
            -
            
            $
            -Operating
                expenses:Production
                taxes
            
            
            136,305
            
            
            -
            
            
            -Lease
                operating expenses
            
            
            700,623
            
            
            -
            
            
            -Depreciation,
                depletion, and amortization
            
            
            375,701
            
            
            213
            
            
            201Impairment
                of unproved properties
            
            
            734,383
            
            
            -
            
            
            -Accretion
                expense
            
            
            29,730
            
            
            -
            
            
            -Exploration
                expense
            
            
            333,919
            
            
            -
            
            
            -General
                and administrative
            
            
            4,501,737
            
            
            74,240
            
            
            26,953Exploration
                expense - mining
            
            
            -
            
            
            50,000
            
            
            -Total operating expenses
            
            
            6,812,398
            
            
            124,453
            
            
            27,154Loss
                from operations
            
            
            (5,650,579
            )
            
            (124,453
            )
            
            (27,154
            )Other
                income (expense):Liquidated
                damages pursuant to registration rights arrangement
            
            
            (
                2,705,531
            )
            
            -
            
            
            -Amortization
                of deferred financing costs
            
            
            (
                537,822
            )
            
            -
            
            
            -Interest
                expense
            
            
            (37,654
            )
            
            -
            
            
            -Interest
                and other income
            
            
            229,331
            
            
            -
            
            
            -Total other income (expense)
            
            
            (
                3,051,676
            )
            
            -
            
            
            -Net
                loss
            
            $
            (
                8,702,255
            )
            $
            (124,453
            )
            $
            (27,154
            )Basic
                and fully diluted net loss per share
            
            $
            (0.16
            )
            $
            (0.00
            )
            $
            (0.00
            )Weighted
                average shares outstanding
            
            
            53,782,291
            
            
            32,819,623
            
            
            70,000,000





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




F-5







**Rancher
      Energy Corp.**


**Statement
      of Changes in Stockholders’ Equity (Deficit)**




Shares
            
            Amount
            
            Additional
                Paid- In Capital
            
            Accumulated
              Deficit
            
            Total
              Stockholders’
              Equity
                (Deficit)Balance,
                April 1, 2004
            
            
            70,000,000
            
            $
            700
            
            $
            374,300
            
            $
            (375,000
            )
            $
            -Net
                loss
            
            
            -
            
            
            -
            
            
            -
            
            
            (27,154
            )
            
            (27,154
            )Balance,
                March 31, 2005
            
            
            70,000,000
            
            
            700
            
            
            374,300
            
            
            (402,154
            )
            
            (27,154
            )Common
                stock issued for cash, net of offering costs of $3,906
            
            
            28,000,000
            
            
            280
            
            
            195,814
            
            
            -
            
            
            196,094Shares
                returned by founding stockholder
            
            
            (69,500,000
            )
            
            (695
            )
            
            695
            
            
            -
            
            
            -Net
                loss
            
            
            -
            
            
            -
            
            
            -
            
            
            (124,453
            )
            
            (124,453
            )Balance,
                March 31, 2006
            
            
            28,500,000
            
            
            285
            
            
            570,809
            
            
            (526,607
            )
            
            44,487Common
                stock issued for cash, net of offering costs of $529,749
            
            
            17,075,221
            
            
            171
            
            
            8,106,967
            
            
            -
            
            
            8,107,138Common
                stock issued on conversion of note payable
            
            
            1,006,905
            
            
            10
            
            
            503,443
            
            
            -
            
            
            503,453Common
                stock issued on exercise of stock options
            
            
            1,000,000
            
            
            10
            
            
            -
            
            
            -
            
            
            10Common
                stock issued for cash, net of offering costs of $41,212
            
            
            1,522,454
            
            
            15
            
            
            720,001
            
            
            -
            
            
            720,016Warrants
                issued in exchange for acquisition of oil & gas
                properties
            
            
            -
            
            
            -
            
            
            616,140
            
            
            -
            
            
            616,140Common
                stock issued for cash, net of offering costs of $6,054,063
            
            
            45,940,510
            
            
            460
            
            
            62,856,243
            
            
            -
            
            
            62,856,703Common
                stock issued for conversion of notes payable, net of offering costs
                of
                $384,159
            
            
            6,996,342
            
            
            70
            
            
            10,110,423
            
            
            -
            
            
            10,110,493Stock-based
                compensation
            
            
            -
            
            
            -
            
            
            1,501,908
            
            
            -
            
            
            1,501,908Net
                loss
            
            
            -
            
            
            -
            
            
            -
            
            
            (
                8,702,255
            )
            
            (
                8,702,255
            )Balance,
                March 31, 2007
            
            
            102,041,432
            
            $
            1,021
            
            $
            84,985,934
            
            $
            (
                9,228,862
            )
            $
            75,758,093





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




F-6




**Rancher
      Energy Corp.**


**Statements
      of Cash Flows**





For
                the Years Ended March 31,2007
            
            2006
            
            2005Cash
                flows from operating activities:Net
                loss
            
            $
            (
                8,702,255
            )
            $
            (124,453
            )
            $
            (27,154
            )Adjustments
                to reconcile net loss to net cash used for operating
                activities:Liquidated
                damages pursuant to registration rights arrangements
            
            
            2,705,531
            
            
            -
            
            
            -Depreciation,
                depletion, and amortization
            
            
            375,701
            
            
            213
            
            
            201Impairment
                of unproved properties
            
            
            734,383
            
            
            -
            
            
            -Accretion
                expense
            
            
            29,730
            
            
            -
            
            
            -Stock-based
                compensation expense
            
            
            1,501,908
            
            
            -
            
            
            -Amortization
                of deferred financing costs
            
            
            537,822
            
            
            -
            
            
            -Interest
                expense on convertible note payable beneficial conversion
            
            
            30,000
            
            
            -
            
            
            -Interest
                expense on debt converted to equity
            
            
            3,453
            
            
            -
            
            
            -Changes
                in operating assets and liabilities:Accounts
                receivable
            
            
            (453,709
            )
            
            -
            
            
            -Other
                assets
            
            
            (588,764
            )
            
            -
            
            
            -Accounts
                payable and accrued liabilities
            
            
            1,540,770
            
            
            167
            
            
            1,903Net
                cash used for operating activities
            
            
            (2,285,430
            )
            
            (124,073
            )
            
            (25,050
            )Cash
                flows from investing activities:Acquisition
                of Cole Creek South and South Glenrock B Fields
            
            
            (47,073,657
            )
            
            -
            
            
            -Acquisition
                of Big Muddy Field
            
            
            (25,672,638
            )
            
            -
            
            
            -Capital
                expenditures for oil & gas properties
            
            
            (841,993
            )
            
            -
            
            
            -Increase
                in other assets
            
            
            (769,018
            )
            
            -
            
            
            (890
            )Net
                cash used for investing activities
            
            
            (74,357,306
            )
            
            -
            
            
            (890
            )Cash
                flows from financing activities:Increase
                in deferred financing costs
            
            
            (
                921,981
            )
            
            -
            
            
            -Proceeds
                from issuance of convertible notes payable
            
            
            11,144,582
            
            
            -
            
            
            -Payment
                of convertible note payable
            
            
            (150,000
            )Proceeds
                from shareholder loans
            
            
            -
            
            
            -
            
            
            30,000Payment
                of shareholder loans
            
            
            -
            
            
            (30,000
            )
            
            -Proceeds
                from sale of common stock and warrants
            
            
            71,653,937
            
            
            196,094
            
            
            -Net
                cash provided by financing activities
            
            
            81,726,538
            
            
            166,094
            
            
            30,000Increase
                in cash and cash equivalents
            
            
            5,083,802
            
            
            42,021
            
            
            4,060Cash
                and cash equivalents, beginning of year
            
            
            46,081
            
            
            4,060
            
            
            -Cash
                and cash equivalents, end of year
            
            $
            5,129,883
            
            $
            46,081
            
            $
            4,060Non-cash
                investing and financing activities:Payables
                for purchase of oil & gas properties
            
            $
            250,000
            
            $
            -
            
            $
            -Asset
                retirement asset and obligation
            
            $
            1,191,837
            
            $
            -
            
            $
            -Value
                of warrants issued in connection with acquisition of Cole Creek South
                and
                South Glenrock B Fields
            
            $
            616,140
            
            $
            -
            
            $
            -Common
                stock and warrants issued on conversion of notes payable
            
            $
            10,613,876
            
            $
            -
            
            $
            -





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




F-7




Rancher
      Energy Corp.


Notes
      to
      Financial Statements




**Note
      1—Organization and Summary of Significant Accounting
      Policies**




Organization




Rancher
      Energy Corp. (Rancher Energy or the Company), formerly known as Metalex
      Resources, Inc. (Metalex), was incorporated in Nevada on February 4, 2004.
      The Company acquires, explores for, develops and produces oil & natural gas,
      concentrating on applying secondary and tertiary recovery technology to older,
      historically productive fields in North America.




Metalex
      was formed for the purpose of acquiring, exploring and developing mining
      properties. On April 18, 2006, the stockholders of Metalex voted to change
      its name to Rancher Energy Corp. and announced that it changed its business
      plan
      and focus from mining to oil & gas.





From
      February 4, 2004 (inception) through the third fiscal quarter ended
      December 31, 2006, the Company was a development stage company. Commencing
      with the fourth fiscal quarter ended March 31, 2007, the Company was no
      longer in the development stage.




As
      reflected in the Company’s Annual Report on Form 10-K for the year ended
      March 31, 2006, the Company had no revenues, had incurred a net loss of
      $526,607 for the period from February 4, 2004 (inception) through
      March 31, 2006, and had an accumulated deficit. Those factors indicated
      that the Company may not have been able to continue in existence. The financial
      statements did not include any adjustments related to the recoverability and
      classification of recorded assets, or the amounts and classification of
      liabilities that might have been necessary in the event the Company could not
      have continued in existence.


During
        the year ended March 31, 2007, the Company generated net cash from
        financing activities of $81,726,538, of which $74,357,306 and $2,285,430
        were
        used for investing and operating activities, respectively. The Company has
        never
        been profitable and does not expect to be profitable during the coming year.
        Our
        acquisition and development of prospects will require substantial additional
        capital expenditures in the future and, consequently, will require an additional
        infusion of debt or equity. There are uncertainties and factors that may
        impede
        our ability to achieve or sustain profitability in the future. The Company
        believes that available cash, and earnings thereon, and cash generated from
        its
        oil operations (oil sales net of production taxes and lease operating expenses)
        should be sufficient to fund its operating activities for the coming year.




Use
      of
      Estimates in the Preparation of Financial Statements




The
      preparation of financial statements in conformity with accounting principles
      generally accepted in the United States requires management to make estimates
      and assumptions that affect the reported amounts of oil & gas reserves,
      assets and liabilities, disclosure of contingent assets and liabilities at
      the
      date of the financial statements, and the reported amounts of revenues and
      expenses during the reporting periods. Actual results could differ from those
      estimates. Estimates of oil & gas reserve quantities provide the basis for
      calculations of depletion, depreciation, and amortization (DD&A) and
      impairment, each of which represents a significant component of the financial
      statements.




Revenue
      Recognition




The
      Company derives revenue primarily from the sale of produced crude oil. The
      Company reports revenue at its net revenue interests as the amount received
      before taking into account production taxes and transportation costs, which
      are
      reported as separate expenses. Revenue is recorded in the month the Company’s
      production is delivered to the purchaser, but payment is generally received
      between 30 and 60 days after the date of production. No revenue is recognized
      unless it is determined that title to the product has transferred to a
      purchaser. At the end of each month the Company estimates the amount of
      production delivered to the purchaser and the price the Company will receive.
      The Company uses its knowledge of properties, their historical performance,
      the
      anticipated effect of weather conditions during the month of production, NYMEX
      and local spot market prices, and other factors as the basis for these
      estimates.




F-8




Cash
      and Cash Equivalents




The
      Company considers all liquid investments purchased with an initial maturity
      of
      three months or less to be cash equivalents. The carrying value of cash and
      cash
      equivalents approximates fair value due to the short-term nature of these
      instruments.




Concentration
      of Credit Risk


Substantially
        all of the Company’s receivables are from purchasers of oil & gas and from
        joint interest owners. Although diversified among a number of companies,
        collectability is dependent upon the financial wherewithal of each individual
        company as well as the general economic conditions of the industry. The
        receivables are not collateralized. To date the Company has had no bad
        debts.


Oil
      & Gas Producing Activities




The
      Company uses the successful efforts method of accounting for its oil & gas
      properties. Under this method of accounting, all property acquisition costs
      and
      costs of exploratory and development wells are capitalized when incurred,
      pending determination of whether the well has found proved reserves. If an
      exploratory well does not find proved reserves, the costs of drilling the well
      are charged to expense. Exploratory dry hole costs are included in cash flows
      from investing activities as part of capital expenditures within the
      consolidated statements of cash flows. The costs of development wells are
      capitalized whether or not proved reserves are found. Costs of unproved leases,
      which may become productive, are reclassified to proved properties when proved
      reserves are discovered on the property. Unproved oil & gas interests are
      carried at the lower of cost or estimated fair value and are not subject to
      amortization.




Geological
      and geophysical costs and the costs of carrying and retaining unproved
      properties are expensed as incurred. DD&A of capitalized costs related to
      proved oil & gas properties is calculated on a property-by-property basis
      using the units-of-production method based upon proved reserves. The computation
      of DD&A takes into consideration restoration, dismantlement, and abandonment
      costs and the anticipated proceeds from salvaging equipment.




The
      Company complies with Statement of Financial Accounting Standards Staff Position
      No. FAS 19-1, *Accounting
      for Suspended Well Costs* ,
      (FSP
      FAS 19-1). The Company currently does not have any existing capitalized
      exploratory well costs, and has therefore determined that no suspended well
      costs should be impaired.




The
      Company reviews its long-lived assets for impairments when events or changes
      in
      circumstances indicate that impairment may have occurred. The impairment test
      for proved properties compares the expected undiscounted future net cash flows
      on a property-by-property basis with the related net capitalized costs,
      including costs associated with asset retirement obligations, at the end of
      each
      reporting period. Expected future cash flows are calculated on all proved
      reserves using a discount rate and price forecasts selected by the Company’s
      management. The discount rate is a rate that management believes is
      representative of current market conditions. The price forecast is based on
      NYMEX strip pricing for the first three to five years and is held constant
      thereafter. Operating costs are also adjusted as deemed appropriate for these
      estimates. When the net capitalized costs exceed the undiscounted future net
      revenues of a field, the cost of the field is reduced to fair value, which
      is
      determined using discounted future net revenues. An impairment allowance is
      provided on unproved property when the Company determines the property will
      not
      be developed or the carrying value is not realizable.




F-9




Sales
      of Proved and Unproved Properties




The
      sale
      of a partial interest in a proved oil & gas property is accounted for as
      normal retirement, and no gain or loss is recognized as long as this treatment
      does not significantly affect the units-of-production DD&A rate. A gain or
      loss is recognized for all other sales of producing properties and is reflected
      in results of operations.




The
      sale
      of a partial interest in an unproved property is accounted for as a recovery
      of
      cost when substantial uncertainty exists as to recovery of the cost applicable
      to the interest retained. A gain on the sale is recognized to the extent the
      sales price exceeds the carrying amount of the unproved property. A gain or
      loss
      is recognized for all other sales of nonproducing properties and is reflected
      in
      results of operations.




Other
      Property and Equipment




Other
      property and equipment, such as office furniture and equipment, automobiles,
      and
      computer hardware and software, is recorded at cost. Costs of renewals and
      improvements that substantially extend the useful lives of the assets are
      capitalized. Maintenance and repair costs are expensed when incurred.
      Depreciation is calculated using the straight-line method over the estimated
      useful lives of the assets from three to seven years. When other property and
      equipment is sold or retired, the capitalized costs and related accumulated
      depreciation are removed from the accounts.




Fair
      Value of Financial Instruments




The
      Company’s financial instruments, including cash and cash equivalents, accounts
      receivable, and accounts payable, are carried at cost, which approximates fair
      value due to the short-term maturity of these instruments. The Company does
      not
      currently have any credit facilities. Because considerable judgment is required
      to develop estimates of fair value, the estimates provided are not necessarily
      indicative of the amounts the Company could realize upon the sale or refinancing
      of such instruments.




Income
      Taxes




Deferred
      income taxes are provided on the difference between the tax basis of an asset
      or
      liability and its carrying amount in the financial statements, in accordance
      with SFAS No. 109, *Accounting
      for Income Taxes* .
      This
      difference may result in taxable income or deductions in future years when
      the
      reported amount of the asset or liability is recovered or settled,
      respectively.




Net
      Income (Loss) per Share




Basic
      net
      income (loss) per common share of stock is calculated by dividing net income
      (loss) available to common stockholders by the weighted-average of common shares
      outstanding during each period.




Diluted
      net income per common share of stock is calculated by dividing adjusted net
      income by the weighted-average of common shares outstanding, including the
      effect of other dilutive securities. The Company’s potentially dilutive
      securities consist of in-the-money outstanding options and warrants to purchase
      the Company’s common stock. Diluted net loss per common share does not give
      effect to dilutive securities as their effect would be
      anti-dilutive.




F-10




The
      treasury stock method is used to measure the dilutive impact of stock options
      and warrants. The following table details the weighted-average dilutive and
      anti-dilutive securities related to stock options and warrants for the periods
      presented:




For the Years Ended March 31,2007
            
            2006
            
            2005Dilutive
            
            
            -
            
            
            -
            
            
            -Anti-dilutive
            
            
            14,214,461
            
            
            -
            
            
            -






Stock
      options and warrants were not considered in the detailed calculations below
      as
      their effect would be anti-dilutive.




The
      following table sets forth the calculation of basic and diluted loss per
      share:




For
                the Year Ended March 31,2007
            
            2006
            
            2005Net
                loss
            
            $
            (
                8,702,255
            )
            $
            (124,453
            )
            $
            (27,154
            )Basic
                weighted average common shares outstanding
            
            
            53,782,291
            
            
            32,819,623
            
            
            70,000,000Basic
                and diluted net loss per common share
            
            
            (0.16
            )
            
            (0.00
            )
            
            (0.00
            )


Share-Based
      Payment




Effective
      April 1, 2006, Rancher Energy adopted Statement of Financial Accounting
      Standard 123(R) *Share-Based
      Payment* using
      the modified prospective transition method. In addition, the Securities and
      Exchange Commission (the SEC) issued Staff Accounting Bulletin No. 107 *Share-Based
      Payment* in
      March, 2005, which provides supplemental application guidance on Statement
      123(R) based on the views of the SEC. Under the modified prospective transition
      method, compensation cost recognized for the year ended March 31, 2007,
      includes: (i) compensation cost for all share-based payments granted prior
      to, but not yet vested as of April 1, 2006, based on the grant date fair
      value estimated in accordance with the original provisions of
      Statement 123, and (ii) compensation cost for all share-based payments
      granted beginning April 1, 2006, based on the grant date fair value
      estimated in accordance with Statement 123(R). In accordance with the modified
      prospective transition method, results for prior periods have not been
      restated.




Registration
      Payment Arrangements




In
      December 2006, FASB issued Staff Position (FSP) EITF (Emerging Issues
      Task Force) 00-19-2, *Accounting
      for Registration Payment Arrangements.* FSP
      EITF
      00-19-2 specifies that the contingent obligation to make future payments or
      otherwise transfer consideration under a registration payment arrangement,
      whether issued as a separate agreement or included as a provision of a financial
      instrument or other agreement, should be separately recognized and measured
      in
      accordance with FASB Statement No. 5, *Accounting
      for Contingencies* .
      This
      FSP is effective for fiscal years beginning after December 15, 2006. We
      adopted this FSP during the year March 31, 2007 and recorded $2,705,531 in
      liquidated damages as an expense in the consolidated statement of operations
      and
      in accrued liabilities at March 31, 2007.




F-11




Recently
      Issued Accounting Standards




In
      September 2006, the Securities and Exchange Commission (SEC) issued Staff
      Accounting Bulletin No. 108, *Considering
      the Effects of Prior Year Misstatements when Quantifying Misstatements in
      Current Year Financial Statements* (SAB
      108), to address diversity in practice in quantifying financial statement
      misstatements. SAB 108 requires misstatements to be quantified based on their
      impact on each of the Company’s financial statements and related disclosures.
      SAB 108 provides for registrants to correct prior year financial statements
      for
      immaterial errors in subsequent filings of prior year financial statements
      and
      does not require previously filed reports to be amended. SAB 108 is effective
      for the Company as of March 31, 2007. The SAB also allows for a one-time
      transitional cumulative effect adjustment to accumulated deficit, as of
      April 1, 2006, for errors that were not previously deemed material,
      but are material under the guidance in SAB 108. Based on the Company’s
      evaluation as of March 31, 2007, the Company’s historical financial
      statements were not affected by the adoption of this standard.




In
      September 2006, the Financial Accounting Standards Board (FASB) issued
      Statement of Financial Accounting Standards No. 157, *Fair
      Value Measurements* (SFAS
      No. 157), which defines fair value, establishes a framework for measuring
      fair value, and expands disclosures about fair value measurements. The
      provisions of SFAS No. 157 will be effective as of the beginning of the
      Company’s 2008 fiscal year. The Company is currently evaluating the impact SFAS
      No. 157 will have on its financial statements.


In
        July 2006 the Financial Accounting Standards Board (FASB) issued FASB
        Interpretation No. 48, *Accounting
        for Uncertainty in Income Taxes—an interpretation of FASB Statement
        No. 109* (FIN 48), which clarifies the accounting for uncertainty of tax positions.
        FIN 48 will require the Company to recognize the impact of a tax position
        in its
        financial statements only if the technical merits of that position indicate
        that
        the position is more likely than not of being sustained upon audit. FIN 48
        will
        be effective for the Company’s 2008 fiscal year. The Company is currently
        evaluating the impact that FIN 48 will have on its financial
        statements.




In
      February 2007, the FASB issued SFAS 159, *The
      Fair Value Option for Financial Assets and Financial Liabilities* (SFAS 159).
      SFAS 159 permits an entity to elect fair value as the initial and subsequent
      measurement attribute for many financial assets and liabilities. Entities
      electing the fair value option are required to distinguish on the face of the
      balance sheet, the fair value of assets and liabilities for which the fair
      value
      option has been elected and similar assets and liabilities measured using
      another measurement attribute. SFAS 159 is effective for the Company’s fiscal
      year ending March 31, 2008. The adjustment to reflect the difference
      between the fair value and the carrying amount would be accounted for as a
      cumulative-effect adjustment to accumulated deficit as of the date of initial
      adoption. The Company does not expect the adoption of this statement will have
      a
      material impact on its financial position or results of operations.




Comprehensive
      Income (Loss)




The
      Company does not have revenue, expenses, gains or losses that are reflected
      in
      equity rather than in results of operations. Consequently, for all periods
      presented, comprehensive loss is equal to net loss.




Major
      Customers




For
      the
      year ended March 31, 2007, one customer accounted for 100% of the Company’s
      oil & gas sales. The Company did not have revenue for the years ended
      March 31, 2006 and 2005. The loss of that customer would not be expected to
      have a material adverse effect upon our sales and would not be expected to
      reduce the competition for our oil production, which in turn would not be
      expected to negatively impact the price we receive.




F-12




Industry
      Segment and Geographic Information




The
      Company operates in one industry segment, which is the exploration,
      exploitation, development, acquisition, and production of crude oil &
natural gas. All of the Company’s operations are conducted in the continental
      United States. Consequently, the Company currently reports as a single industry
      segment.




Off—Balance
      Sheet Arrangements




As
      part
      of its ongoing business, the Company has not participated in transactions that
      generate relationships with unconsolidated entities or financial partnerships,
      such as entities often referred to as structured finance or special purpose
      entities (SPEs), which would have been established for the purpose of
      facilitating off-balance sheet arrangements or other contractually narrow or
      limited purposes. From February 4, 2004 (inception) through
      March 31, 2007, the Company has not been involved in any
      unconsolidated SPE transactions.




**Note
      2—Oil & Gas Properties**




**Acquisitions**




Cole
      Creek South Field and South Glenrock B Field Acquisitions




On
      December 22, 2006, the Company purchased certain oil & gas properties
      for $46,750,000, before adjustments for the period from the effective date
      to
      the closing date, and closing costs. The oil & gas properties consisted of
      (i) a 100% working interest (79.3% net revenue interest) in the Cole Creek
      South
      Field, which is located in Wyoming’s Powder River Basin; and (ii) a 93.6%
      working interest (74.5% net revenue interest) in the South Glenrock B Field,
      which is also located in Wyoming’s Powder River Basin.




The
      total
      adjusted purchase price was allocated as follows:




Acquisition
                costs:Cash
                consideration
            
            $
            46,750,000Direct
                acquisition costs
            
            
            323,657Estimated
                fair value of warrants to purchase common stock
            
            
            616,140Total
            
            $
            47,689,797Allocation
                of acquisition costs:Oil
                & gas properties:Unproved
            
            $
            31,569,778Proved
            
            
            16,682,101Other
                assets - long-term accounts receivable
            
            
            53,341Other
                assets - inventory
            
            
            227,220Asset
                retirement obligation
            
            
            (842,643
            )Total
            
            $
            47,689,797





In
      partial consideration for an extension of the closing date, the Company issued
      the seller of the oil & gas properties warrants to acquire 250,000 shares of
      its common stock for $1.50 per share for a period of five years. The estimated
      fair value of the warrants to purchase common stock was estimated as of the
      grant date using the Black-Scholes option pricing model with the following
      assumptions:




F-13




Volatility
            
            
            76.00
            %Expected
                option term
            
            
            5
                yearsRisk-free
                interest rate
            
            
            4.51
            %Expected
                dividend yield
            
            
            0.00
            %





As
      of
      March 31, 2007, there are no acquisition contingencies subject to
      determination.




Big
      Muddy Field Acquisition




On
      January 4, 2007, Rancher Energy acquired the Big Muddy Field, consisting of
      approximately 8,500 acres located in the Powder River Basin east of Casper,
      Wyoming. The total purchase price was $25,000,000, before adjustments for the
      period from the effective date to the closing date, and closing costs. While
      the
      Big Muddy Field was discovered in 1916, future profitable operations are
      dependent on the application of tertiary recovery techniques requiring
      significant amounts of  CO 2 .




The
      total
      adjusted purchase price was allocated as follows:




Acquisition
                costs:Cash
                consideration
            
            $
            25,000,000Direct
                acquisition costs
            
            
            672,638Total
            
            $
            25,672,638Allocation
                of acquisition costs:Oil
                & gas properties:Unproved
            
            $
            24,151,745Proved
            
            
            1,870,086Asset
                retirement obligation
            
            
            (349,193
            )Total
            
            $
            25,672,638





As
      of
      March 31, 2007, there are no acquisition contingencies subject to
      determination.




Pro
      Forma Results of Operations




The
      following table reflects the pro forma results of operations for the years
      ended
      March 31, 2007 and 2006, as though the acquisitions had occurred
      on April 1, 2005. The pro forma amounts include certain adjustments,
      including recognition of depreciation, depletion and amortization based on
      the
      allocated purchase price.




The
      pro
      forma results do not necessarily reflect the actual results that would have
      occurred had the acquisitions been combined during the periods presented, nor
      does it necessarily indicate the future results of the Company and the
      acquisitions.




For
                the Year Ended March 31,2007
            
            2006(Unaudited)Revenue
            
            $
            4,959,813
            
            $
            4,602,601Net
                income (loss)
            
            
            (8,688,062
            )
            
            427,344Net
                income (loss) per basic and diluted share
            
            
            (0.09
            )
            
            0.00





Carbon
      Dioxide Product Sale and Purchase Contract




As
      part
      of our CO 2 tertiary
      recovery strategy, on December 15, 2006, the Company entered into a Product
      Sale and Purchase Contract (Purchase Contract) with the Anadarko Petroleum
      Corporation (Anadarko) for the purchase of CO 2 (meeting
      certain quality specifications identified in the agreement) from Anadarko.
      The
      Company intends to use the CO 2 for its
      enhanced oil recovery (EOR) projects.




F-14




The
      primary term of the Agreement commences upon the later of January 1, 2008,
      or the date of the first CO 2 delivery,
      and terminates upon the earlier of the day on which the Company has taken and
      paid for the Total Contract Quantity, as defined, or 10 years from the
      commencement date. The Company has the right to terminate the Purchase Contract
      at any time with notice to Anadarko, subject to a termination payment as
      specified in the Purchase Contract.




During
      the primary term the “Daily Contract Quantity” is 40 MMcf per day for a total of
      146 Bcf. CO 2 deliveries are subject to a 25 MMcf per day take-or-pay provision. Anadarko
      has
      the right to satisfy its own needs before sales to the Company, which reduces
      our take-or-pay obligation. In the event the CO 2 does not
      meet certain quality specifications, we have the right to refuse delivery of
      such CO 2 .




For
      CO 2 deliveries, the Company has agreed to pay $1.50 per thousand cubic feet, to
      be
      adjusted by a factor that is indexed to the average posted price of Wyoming
      Sweet oil. From oil that is produced by CO 2 injection, the Company also agreed to convey to Anadarko an overriding royalty
      interest of 1% in year one, increasing 1% on each of the next four anniversaries
      to a maximum of 5% for the remainder of the 10-year term.




**Impairment
      of Unproved Properties**




In
      June 2006, the Company acquired 10,104 acres in the Burke Ranch field and
      adjacent property in Natrona County, Wyoming. The Company subsequently had
      engineering studies performed on the property and concluded that the property’s
      potential reserves did not warrant further development expenditures. In
      June 2006, the Company also acquired Broadview Dome Prospect, which is
      located in the Crazy Mountain Basin in Montana and is comprised of approximately
      7,600 acres. The Company determined it would not develop the property, and
      the
      carrying value would not be realized. Consequently, the Company impaired the
      full carrying amounts of both properties totaling $734,383, which is reflected
      as impairment of unproved properties in the statement of
      operations.




**Note
      3—Asset Retirement Obligations**




The
      Company recognizes an estimated liability for future costs associated with
      the
      abandonment of its oil & gas properties. A liability for the fair value of
      an asset retirement obligation and a corresponding increase to the carrying
      value of the related long-lived asset are recorded at the time a well is
      completed or acquired. The increase in carrying value is included in proved
      oil
& gas properties in the balance sheets. The Company depletes the amount
      added to proved oil & gas property costs and recognizes accretion expense in
      connection with the discounted liability over the remaining estimated economic
      lives of the respective oil & gas properties. Cash paid to settle asset
      retirement obligations is included in the operating section of the Company’s
      statement of cash flows.


The
        Company’s estimated asset retirement obligation liability is based on our
        historical experience in abandoning wells, estimated economic lives, estimates
        as to the cost to abandon the wells in the future, and federal and state
        regulatory requirements. The liability is discounted using a credit-adjusted
        risk-free rate estimated at the time the liability is incurred or revised.
        The
        credit-adjusted risk-free rate used to discount the Company’s abandonment
        liabilities was 13.1%. Revisions to the liability are due to changes in
        estimated abandonment costs and changes in well economic lives, or if federal
        or
        state regulators enact new requirements regarding the abandonment of
        wells.




The
      Company did not have any oil & gas properties during the years ended
      March 31, 2006 and 2005 and, consequently, did not have any asset
      retirement obligation liability. A reconciliation of the Company’s asset
      retirement obligation liability during the year ended March 31, 2007 is as
      follows:




F-15




Beginning
                asset retirement obligation
            
            $
            -Liabilities
                incurred
            
            
            1,191,837Accretion
                expense
            
            
            29,730Ending
                asset retirement obligation
            
            $
            1,221,567Current
            
            $
            196,000Long-term
            
            
            1,025,567$
            1,221,567




**Note
      4—Convertible Notes Payable**




Enerex
      Capital Corp.




On
      June 6, 2006, the Company entered into a loan agreement with Enerex Capital
      Corp. (Enerex) to borrow from Enerex the principal amount of $150,000 (the
      Enerex Loan) for the Company’s working capital purposes to be repaid in full
      plus two percent (2%) interest on the principal amount on or before
      June 30, 2006. The Enerex Loan agreement provided that Enerex had the
      option to convert all or a portion of the loan into shares of common stock
      of
      the Company, either (i) at a price per share equal to the closing price of
      the
      Company’s shares on the day preceding notice from Enerex of its intent to
      convert all or a portion of the loan into shares of the Company, or (ii) in
      the
      event the Company offered shares or units to the general public, at the price
      such shares or units were offered to the general public. On June 29, 2006,
      the loan was paid in full.




Venture
      Capital First LLC




On
      June 9, 2006, the Company borrowed $500,000 from Venture Capital First LLC
      (Venture Capital). Principal and interest at an annual rate of 6% were due
      December 9, 2006. The agreement provided that Venture Capital had the
      option to convert all or a portion of the loan into common stock and warrants
      to
      purchase common stock, either (i) at the closing price of the Company’s shares
      on the day preceding notice from Venture Capital of its intent to convert all
      or
      a portion of the loan into common stock or, (ii) in the event the Company
      conducted an offering of common stock, or units consisting of common stock
      and
      warrants to purchase stock, at the price of such shares or units in the
      offering.




On
      July 19, 2006, Venture Capital elected to convert its entire loan and
      accrued interest into 1,006,905 shares of common stock and warrants to purchase
      1,006,905 shares of common stock at a price of $0.50 per unit, the price per
      unit in the offering discussed in Note 6 below. The warrants were exercisable
      over a two-year period, at a price of $0.75 per share for the first year, and
      $1.00 per share for the second year. On December 21, 2006, the warrant
      holder agreed not to exercise its right to acquire shares of common stock until
      the Company received stockholder approval to increase the number of authorized
      shares, and the exercise price of $0.75 per share was extended by the Company
      through the second year. On March 30, 2007, the Company amended its
      Articles of Incorporation increasing its authorized shares of common
      stock.




Private
      Placement




The
      Company received $10,494,582 from investors in exchange for convertible notes
      payable and warrants to acquire 6,996,322 shares of common stock at $1.50 per
      share. The warrants have the same terms and conditions as the warrants discussed
      in Note 6 below. The notes accrued interest at an annual rate of 12% beginning
      120 days after issuance, which was the maturity date, if not converted or paid
      before that date.




F-16




Upon
      stockholder approval of an amendment to the Articles of Incorporation to
      increase the authorized shares of the Company’s common stock, which occurred on
      March 30, 2007, the notes automatically converted into
      6,996,342  shares
      of
      common stock. The number of shares issued was equal to the face amount of the
      notes divided by $1.50 per share, the price that shares were simultaneously
      sold
      in a private placement as discussed in Note 6 below.




The
      Company incurred deferred financing costs of $921,981 to be amortized over
      the
      life of the loan. Through March 30, 2007, the date the notes automatically
      converted, the Company reflected $537,822 of amortization of deferred financing
      costs in the statements of operations. At that date, deferred financing costs,
      net of accumulated amortization, of $384,159 were reflected as a reduction
      to
      the proceeds from the offering.




**Note
      5—Commitments and Contingencies**




The
      Company leases office space under a non-cancellable operating lease that expires
      July 31, 2012. Rent expense was $35,766, $0 and $0 during the years
      ended March 31, 2007, 2006 and 2005, respectively. The annual minimum lease
      payments for the next five years and thereafter are presented
      below:




Years Ending March 31,2008
            
            $
            280,8592009
            
            
            362,4032010
            
            
            370,6582011
            
            
            381,9312012
            
            
            383,842Thereafter
            
            
            127,947Total
            
            $
            1,907,640




The
      Company has entered into a Product Purchase and Sale Agreement with Anadarko
      as
      discussed in Note 2 above. The Company has also entered into a Registration
      Rights Agreement as discussed in Note 6 below.




The
      Company may be subject to litigation and claims that may arise in the ordinary
      course of business. The Company accrues for such items when a liability is
      both
      probable and the amount can be reasonably estimated. The Company is not
      currently the subject of any litigation.




**Note
      6—Sale of Common Stock and Warrants**




*For
      the Year Ended March 31, 2007*




Units
      Issued Pursuant to Regulation S




For
      the
      period from June 2006 through October 2006, we sold 18,133,500 Units
      for $0.50 per Unit, totaling gross proceeds of $9,066,750, pursuant to the
      exemption from registration of securities under the Securities Act of 1933
      as
      provided by Regulation S. Each Unit consisted of one share of common stock
      and a
      warrant to purchase one additional share of common stock.




For
      8,850,000 Units, Rancher Energy paid no underwriting commissions. For 9,283,500
      Units, Rancher Energy paid a cash commission of $232,088, equal to 5% of the
      proceeds from the units, and a stock-based commission of 464,175 shares of
      common stock, equal to 5% of the number of Units sold. The sum of the shares
      sold and the commission shares aggregated 18,597,675. All
      warrants were originally exercisable for a period of two years from the
      date of issuance. During the first year, the exercise price was $0.75 per share;
      during the second year, the exercise price was $1.00 per share. The
      warrants are redeemable by us for no consideration upon 30 days prior notice.
      A
      portion of these warrants were modified as discussed below.




F-17




Warrant
      Modification - Warrants Issued Pursuant to Regulation S




On
      December 21, 2006, holders of 13,192,000 warrants issued pursuant to
      Regulation S in a private placement from June through October 2006
      agreed not to exercise their right to acquire shares of common stock until
      the
      Company received stockholder approval, which it obtained on March 30, 2007,
      to increase the number of its authorized shares from 100,000,000 to 275,000,000,
      and the exercise price of $0.75 per share was extended by the Company through
      the second year. Terms for the remaining 4,941,500 warrants were
      unchanged.




Private
      Placement




On
      December 21, 2006, we entered into a Securities Purchase Agreement, as
      amended, with institutional and individual accredited investors to effect a
      $79,500,000 private placement of shares of our common stock and other securities
      in multiple closings. As part of this private placement, we raised an aggregate
      of $79,405,418 and issued (i) 45,940,510 shares of common stock, (ii) promissory
      notes that were convertible into 6,996,342 shares of common stock, and (iii)
      warrants to purchase 52,936,832 shares of common stock. The warrants issued
      to
      investors in the private placement are exercisable during the five year period
      beginning on the date we amended and restated our Articles of Incorporation
      to
      increase our authorized shares of common stock, which was March 30, 2007.
      The notes issued in the private placement automatically converted into shares
      of
      common stock on March 30, 2007. In conjunction with the private placement,
      we also used services of placement agents and have issued warrants to purchase
      3,633,313 shares of common stock to these agents or their designees. The
      warrants issued to the placement agents or their designees are exercisable
      during the two year period (warrants to purchase 2,187,580 shares of common
      stock) or the five year period (warrants to purchase 1,445,733 shares of common
      stock) beginning on the date we amended and restated our Articles of
      Incorporation to increase our authorized shares of common stock, which was
      March 30, 2007. All of the warrants issued in conjunction with the private
      placement have an exercise price of $1.50 per share.




In
      connection with the private placement, the Company also entered into a
      Registration Rights Agreement with the investors in which the Company agreed
      to
      register for resale the shares of common stock issued in the private placement
      as well as the shares underlying the warrants and convertible notes issued
      in
      the private placement. There are liquidated damages payable pursuant to the
      Securities Purchase Agreement and Registration Rights Agreement relating to
      these registration provisions and other obligations which, if triggered, could
      result in substantial amounts to be due to the investors, as discussed further
      below.




Summary
      of Warrants




The
      following is a summary of warrants as of March 31, 2007.




Warrants
            
            Exercise
                Price
            
            Expiration
                DateWarrants
                issued in connection with the
              following:Sale
                of common stock pursuant to
              Regulation
                S
            
            
            18,133,500
            
            $
            0.75-$1.00
            
            
            July
                5, 2008
              to
                October 18, 2008Conversion
                of notes payable into common stock
            
            
            1,006,905
            
            $
            0.75
            
            
            July
                19, 2008Private
                placement of common stock
            
            
            45,940,510
            
            $
            1.50
            
            
            March
                30, 2012Private
                placement of convertible notes payable
            
            
            6,996,322
            
            $
            1.50
            
            
            March
                30, 2012Private
                placement agent commissions
            
            
            2,187,580
            
            $
            1.50
            
            
            March
                30, 2009Private
                placement agent commissions
            
            
            1,445,733
            
            $
            1.50
            
            
            March
                30, 2012Acquisition
                of oil & gas properties
            
            
            250,000
            
            $
            1.50
            
            
            December
                22, 2011Total
                warrants outstanding at March 31, 2007
            
            
            75,960,550




F-18




Registration
      and Other Payment Arrangements




In
      connection with the sale of certain Units discussed above, the Company has
      entered into agreements that require the transfer of consideration under
      registration and other payment arrangements, if certain conditions are not
      met.
      The following is a description of the conditions and those that have not been
      met as of March 31, 2007.




Under
      the
      terms of the Registration Rights Agreement, the Company must pay the holders
      of
      the registrable securities issued in the December 2006 and January 2007 equity
      private placement, liquidated damages if the registration statement that was
      filed in conjunction with the private placement has not been declared effective
      by the U.S. Securities and Exchange Commission (SEC) within 150 days of the
      closing of the private placement (December 21, 2006). The liquidated
      damages are due on or before the day of the failure (May 20, 2007) and
      every 30 days thereafter, or three business days after the failure is cured,
      if
      earlier. The amount due is 1% of the aggregate purchase price, or $794,000
      per
      month. If the Company fails to make the payments timely, interest accrues at
      a
      rate of 1.5% per month. All payments pursuant to the registration rights
      agreement and the private placement agreement cannot exceed 24% of the aggregate
      purchase price, or $19,057,000 in total. The payment may be made in cash, notes,
      or shares of common stock, at the Company’s option, as long as the Company does
      not have an equity condition failure. The equity condition failures are
      described further below. Pursuant to the terms of the registration rights
      agreement, if the Company opts to pay the liquidated damages in shares of common
      stock, the number of shares issued is based on the payment amount of $794,000
      divided by 90% of the volume weighted average price of the Company’s common
      stock for the 10 trading days immediately preceding the payment due
      date.




The
      Company made its first penalty payment by issuing 933,458 shares of Company
      common stock on May 18, 2007. The number of shares issued was based on 90%
      of the weighted average price for the 10 trading days preceding May 18,
      2007, or $0.85 per share. The Company made its second penalty payment by issuing
      946,819 shares of Company common stock on June 19, 2007. The number of
      shares issued was based on 90% of the weighted average price for the 10 trading
      days preceding June 19, 2007, or approximately $0.84 per share. In
      accordance with FSP EITF 00-19-2, *Accounting
      for Registration Payment Arrangements* ,
      as of
      the date of this Annual Report, the Company believes that it is probable that
      it
      will incur the obligation to pay liquidated damages on July 19, 2007 and,
      consequently, the Company has recorded a contingent liability for these
      arrangements. At March 31, 2007, the Company accrued a total of $2,705,531
      for the May, June, and July liquidated damages payments, which is reflected
      as “Liquidated Damages Pursuant to Registration Rights Arrangements” in its
      statements of operations, and as a current liability in its balance sheets.
      The
      amount of the estimated contingent liability is based on the assumption that
      all
      of the payments will be settled in Company shares. Upon issuance of the shares,
      the portion of the current liability attributable to the issuance will be
      reclassified to stockholders’ equity.




F-19




Once
      the
      SEC declares the Company’s registration statement effective, the Company must
      maintain effectiveness, provide the information necessary for sale of shares
      to
      be made, register a sufficient number of shares, and maintain the listing of
      the
      shares. Lack of compliance requires the Company to pay the holders of the
      registrable securities liquidated damages under the same terms discussed
      above.




It
      is
      possible that the SEC will object to and reduce the number of shares being
      registered. If that happens, the Company is obligated to pay liquidated damages
      to the holders of the registrable shares under the same terms discussed above.




Failure
      to maintain the equity conditions, a description of which follows, negates
      the
      Company’s ability to settle the liquidated damages in shares of common stock.
      The Company must ensure that:




o
            Common
                stock is designated for quotation on OTC Bulletin Board, the New
                York
                Stock Exchange, the NASDAQ Global Select Market, the NASDAQ Global
                Market,
                the NASDAQ Capital Market, or the American Stock
                Exchange;




§
            Common
                stock has not been suspended from trading, other than for two days
                due to
                business announcements; and




§
            Delisting
                or suspension has not been threatened, or is not
                pending.




o
            Shares
                of common stock have been delivered upon conversion of Notes and
                Warrants
                on a timely basis;




o
            Shares
                may be issued in full without violating the rules and regulations
                of the
                exchange or market upon which they are listed or
                quoted;




o
            Payments
                have been made within five business days of when due pursuant to
                the
                Securities Purchase Agreement, the Convertible Notes, the Registration
                Rights Agreement, the Transfer Agent Instructions, or the Warrants
                (Transaction Documents);




o
            There
                has not been a change in control of the company, a merger of the
                company
                or an event of default as defined in the Notes;
                and




o
            There
                is material compliance with the provisions, covenants, representations
                or
                warranties of all Transaction
                Documents.




There
      is
      an equity conditions failure if, on any day during the 10 trading days prior
      to
      when a registration-delay payment is due, the equity conditions have not been
      satisfied or waived.




Under
      the
      terms of the Securities Purchase Agreement, liquidated damages are due to the
      holders of the securities if the Company does not meet the applicable listing
      requirements on an approved exchange or market, and the registrable shares
      are
      not listed by December 21, 2007 on an approved exchange or market. The
      liquidated damages are equal to 0.25% of the aggregate purchase price, or
      $198,000, payable in cash. The payments are due on the day of the listing
      failure.




Currently,
      there are no equity conditions failures.




F-20




*For
      the Year Ended March 31, 2006*




During
      the three months ended June 30, 2005 the Company issued 28,000,000 shares
      of common stock for cash in the amount of approximately $0.007 per share, or
      $200,000 before offering costs of $3,906.




During
      the year ended March 31, 2006, the Company approved a 14-for-1 stock split.
      All share amounts prior to the stock split have been retroactively restated.




In
      March 2006, in anticipation of certain management changes and
      reorganization of the Company’s activities, the Company’s president and majority
      shareholder returned 69,500,000 shares of his common stock and retained 500,000
      shares of common stock. The capital restructuring was in anticipation of a
      change to the Company’s direction and business focus. There was no established
      secondary market for the Company’s common stock, and the cancellation reduced
      the shares issued for the president’s initial investment of $375,000 during the
      year ended March 31, 2004.




**Note
      7—Share-Based Compensation**




Effective
      April 1, 2006, the Company adopted Statement of Financial Accounting
      Standard 123(R) (SFAS 123(R)), *Share-Based
      Payment* .
      Pursuant to SFAS 123(R), compensation expense is measured at the grant date
      based on fair value of the award and recognized as an expense in earnings over
      the service period as the award vests. The adoption of SFAS 123(R) using the
      modified prospective transition method resulted in stock compensation expense
      for the year ended March 31, 2007 of $1,501,908. The Company did not
      recognize a tax benefit from the stock compensation expense because it is more
      likely than not that the related deferred tax assets, which have been reduced
      by
      a full valuation allowance, will not be realized.





The
      Black-Scholes option-pricing model was used to estimate the option fair values.
      The option-pricing model requires a number of assumptions, of which the most
      significant are the stock price at the valuation date, the expected stock price
      volatility, and the expected option term (the amount of time from the grant
      date
      until the options are exercised or expire).





Prior
      to
      the adoption of SFAS 123(R), the Company reflected tax benefits from deductions
      resulting from the exercise of stock options as operating activities in the
      statements of cash flows. SFAS 123(R) requires tax benefits resulting from
      tax
      deductions in excess of the compensation cost recognized for those options
      (excess tax benefits) be classified and reported as both an operating cash
      outflow and a financing cash inflow upon adoption of SFAS 123(R). As a result
      of
      the Company’s net operating losses, the excess tax benefits, which would
      otherwise be available to reduce income taxes payable, have the effect of
      increasing the Company’s net operating loss carry forwards. Accordingly, because
      the Company is not able to realize these excess tax benefits, such benefits
      have
      not been recognized in the statements of cash flows for the year ended
      March 31, 2007 .




Chief
      Executive Officer (CEO) Option Grant





On
      May 15, 2006, in connection with an employment agreement, the Company
      granted its President & CEO options to purchase up to 4,000,000 shares of
      Company common stock at an exercise price of $0.00001 per share. The options
      vest as follows: (i) 1,000,000 shares upon execution of the employment
      agreement, (ii) 1,000,000 shares from June 1, 2006 to May 31, 2007 at
      the rate of 250,000 shares per completed quarter of service, (iii) 1,000,000
      shares from June 1, 2007 to May 31, 2008 at the rate of 250,000 shares
      per completed quarter of service, and (iv) 1,000,000 shares from June 1,
      2008 to May 31, 2009 at the rate of 250,000 shares per completed quarter of
      service. In the event the employment agreement is terminated, the CEO will
      be
      entitled to purchase all shares that have vested. All unvested shares shall
      be
      forfeited. The  options
      have no expiration date.




F-21




The
      Company determined the fair value of the options to be $0.4235 per underlying
      common share. The value was determined by using the Black-Scholes valuation
      model using assumptions which resulted in the value of one Unit (one common
      share and one warrant to purchase a common share) equaling $0.50, the price
      of
      the most recently issued securities at the time of the calculation. The combined
      value was allocated between the value of the common stock and the value of
      the
      warrant. The value of one common share from this analysis ($0.4235) was used
      to
      calculate the resulting compensation expense under the provisions of SFAS
      123(R). The assumptions used in the valuation of the CEO options were as
      follows:




Volatility
            87.00%Expected option term
            One yearRisk-free interest rate
            5.22%Expected dividend yield
            0.00%




The
      expected term of options granted was based on the expected term of the warrants
      included in the Units described above. The expected volatility was based on
      historical volatility of the Company’s common stock price. The risk free rate
      was based on the one-year U.S Treasury bond rate for the month of
      July 2006.





The
      Company recognized stock compensation expense attributable to the CEO options
      of
      $741,125 for the year ended March 31, 2007. The company expects to
      recognize the remaining compensation expense of $952,875 related to the unvested
      shares over the next 2.3 years.





2006
      Stock Incentive Plan





On
      March 30, 2007, the 2006 Stock Incentive Plan (the 2006 Stock Incentive
      Plan) was approved by the shareholders and was effective October 2, 2006.
      The 2006 Stock Incentive Plan had previously been approved by the Company’s
      Board of Directors. Under the 2006 Stock Incentive Plan, the Board of Directors
      may grant awards of options to purchase common stock, restricted stock, or
      restricted stock units to officers, employees, and other persons who provide
      services to the Company or any related company. The participants to whom awards
      are granted, the type of awards granted, the number of shares covered for each
      award, and the purchase price, conditions and other terms of each award are
      determined by the Board of Directors, except that the term of the options shall
      not exceed 10 years. A total of 10,000,000 shares of Rancher Energy common
      stock
      are subject to the 2006 Stock Incentive Plan. The shares issued for the 2006
      Stock Incentive Plan may be either treasury or authorized and unissued shares.
      During the year ended March 31, 2007, options to purchase up to 3,335,000
      shares of common stock were granted under the 2006 Stock Incentive Plan to
      officers, directors, and employees. The options granted have exercise prices
      ranging from $1.63 to $3.19, generally  vest
      over
      three years, and have a maximum term of five years.





The
      fair
      value of the options granted under the 2006 Stock Incentive Plan was estimated
      as of the grant date using the Black-Scholes option pricing model with the
      following assumptions:





Volatility
            76.00%Expected
                option term
            5
                yearsRisk-free
                interest rate
            4.34%
                to 4.75%Expected
                dividend yield
            0.00%





The
      expected term of options granted was estimated to be the contractual term.
      The
      expected volatility was based on an average of the volatility disclosed by
      other
      comparable companies who had similar expected option terms. The risk free rate
      was based on the five-year U.S Treasury bond rate.




F-22




The
        following table summarizes stock option activity for the year ended
        March 31, 2007:




Outstanding
                OptionsNumber
                of Shares
            
            Weighted
                Average Exercise Price
            
            Weighted
                Average Remaining
              Contractual
                Term
              (in
                Years)
            
            Total
              Intrinsic
              ValueOutstanding,
                April 1, 2006
            
            
            —Granted—CEO
            
            
            4,000,000
            
            $
            0.00001
            
            
            2.25Plan
            
            
            3,335,000
            
            $
            2.34
            
            
            4.61Total
            
            
            7,335,000
            
            $
            1.06
            
            
            3.32Exercised—CEO
            
            
            (1,000,000
            )
            
            0.00001
            
            
            —Outstanding,
                March 31, 2007CEO
            
            
            3,000,000
            
            
            0.00001
            
            
            2.25
            
            $
            3,989,970Plan
            
            
            3,335,000
            
            
            2.34
            
            
            4.61
            
            $
            (4,593,750
            )Total
            
            
            6,335,000
            
            
            1.23
            
            
            3.49
            
            $
            (603,780
            )Vested
                or expected to vest at
              March 31,
                2007—CEO
            
            
            1,750,000
            
            $
            0.00001
            
            
            2.25
            
            $
            2,327,483Plan
            
            
            187,500
            
            $
            1.75
            
            
            4.50
            
            $
            (78,750
            )Total
            
            
            1,937,500
            
            $
            0.19
            
            
            2.47
            
            $
            2,248,733Exercisable,
                March 31, 2007—CEO
            
            
            750,000
            
            $
            0.00001
            
            
            2.25
            
            $
            997,493Plan
            
            
            187,500
            
            $
            1.75
            
            
            4.50
            
            $
            (328,125
            )Total
            
            
            937,500
            
            $
            0.35
            
            
            2.70
            
            $
            669,368




F-23




The
      following table summarizes changes in the unvested shares for the year ended
      March 31, 2007:





Number
                of Shares
            
            Grant
                Date
              Fair
                ValueNon-vested,
                April 1, 2006
            
            
            __
            
            $
            __Granted—CEO
            
            
            4,000,000
            
            
            0.42Plan
            
            
            3,335,000
            
            
            1.52Total
            
            
            7,335,000
            
            
            0.92Vested—CEO
            
            
            (750,000
            )
            
            0.42Plan
            
            
            (187,500
            )
            
            1.13Total
            
            
            (937,500
            )
            
            0.56Exercised—CEO
            
            
            (1,000,000
            )
            
            0.42Non-vested,
                March 31, 2007CEO
            
            
            2,250,000
            
            $
            0.42Plan
            
            
            3,147,500
            
            $
            1.54Total
            
            
            5,397,500
            
            $
            1.07




The
      weighted-average grant-date fair values of the stock options granted during
      the
      year ended March 31, 2007 were $0.42, $1.52, and $0.92 for the CEO, the
      2006 Stock Incentive Plan and in total, respectively. The total intrinsic value,
      calculated as the difference between the exercise price and the market price
      on
      the date of exercise of all options exercised during the year ended
      March 31, 2007, was approximately $1,450,000. The Company received $10 from
      stock options exercised during the year ended March 31, 2007. The Company
      did not realize any tax deductions related to the exercise of stock options
      during year.





Total
      estimated unrecognized compensation cost from unvested stock options as of
      March 31, 2007 was approximately $5,250,480 which the Company expects to
      recognize over 2.6 years.




On
      December 21, 2006, all option holders entered into an agreement whereby
      they were precluded from exercising any options until the Company amended its
      Articles of Incorporation to increase its authorized shares of common stock.
      The
      increase in the number of authorized shares was approved by the shareholders
      on
      March 30, 2007.





Subsequent
      Events





On
      April 10, 2007, pursuant to our 2006 Stock Incentive Plan, we granted
      options to purchase up to a total of 248,000 shares of common stock to 18
      employees at an exercise price of $1.18 per share, the fair market value of
      our
      stock based on the closing market price on the date of grant, and to one
      consultant at an exercise price of $1.64 pursuant to an agreement between us
      and
      the consultant. The employee stock option grants vest over a three-year period,
      with 33-1/3% of the original number of shares respectively on the first, second,
      and third anniversaries of the grant date, and will be exercisable for a
      five-year term. The consultant’s stock option grant vests 50% of the original
      number of shares on August 31, 2007 and 50% of the original shares on
      February 28, 2008 pursuant to an agreement between us and the consultant
      entered into on March 1, 2007, and will be exercisable for a five-year
      term.




F-24




On
      April 19 and May 31, 2007, John Works, our President, Chief Executive
      Officer, and a member of our Board of Directors, exercised a portion of his
      option to purchase 750,000 shares of common stock and 250,000 shares of common
      stock, respectively, at an exercise price of $0.00001 per share. The aggregate
      purchase price for the two exercises was $10.00.




On
      April 20, 2007, our Board of Directors appointed four new members of the
      Board. On that date, each newly appointed director was granted an option to
      purchase 10,000 shares of our common stock pursuant to our 2006 Stock Incentive
      Plan. The exercise price of the grant was $1.02 per share, the fair market
      value
      of our common stock on the date of grant. The option vests 20% (2,000 shares)
      on
      each one year anniversary of the date of the initial grant and will be
      exercisable for a ten-year term. Each newly appointed director also received
      a
      stock grant of 100,000 shares of the Company’s common stock that vests 20%
      (20,000 shares) on the date of grant with vesting 20% per year
      thereafter.





As
      discussed in Note 6, on May 18 and June 19, 2007, we issued 933,458 shares
      and 946,819 shares, respectively, of our common stock to the investors who
      participated in our December 2006 and January 2007 equity private placement.





On
      May 31, 2007, the remaining independent Board member not covered by the
      April 20, 2007 award received a stock grant of 100,000 shares of the
      Company’s common stock that vests 20% (20,000 shares) on the date of grant with
      vesting 20% per year thereafter.





Pursuant
      to the terms of a consulting agreement that we previously entered into with
      an
      executive search consulting firm, on June 27, 2007 we granted 107,143 shares
      of
      our common stock in the aggregate, pursuant to our 2006 Stock Incentive Plan,
      to
      the principals of the consulting firm as partial consideration for the services
      provided to us by the consulting firm.





**Note
      8—Income Taxes**





For
      the
      years ended March 31, 2007, 2006 and 2005, there was no provision or
      benefit for income taxes. Our income tax is different than the expected amount
      computed using the applicable federal and state statutory income tax rates
      of
      35%. The reasons for and effects of such differences are as
      follows:




For
                the Year Ended March 31,2007
            
            2006
            
            2005Expected
                amount
            
            $
            3,045,789
            
            $
            43,559
            
            $
            9,504Permanent
                items
            
            
            (183,726
            )
            
            -
            
            
            -Other
            
            
            128,087
            
            
            -
            
            
            -Change
                in valuation allowance
            
            
            (2,990,150
            )
            
            (43,559
            )
            
            (9,504
            )$
            -
            
            $
            -
            
            $
            -




F-25




The
      deferred tax assets and liabilities resulting from temporary differences between
      book and tax basis of assets and liabilities are comprised of the
      following:




For
                the Year Ended March 31,2007
            
            2006Current
                deferred tax assets:Liquidated
                damages pursuant to registration rights agreement
            
            $
            946,936
            
            $
            -Valuation
                allowance
            
            
            (946,936
            )
            
            -Net
                current deferred tax assets
            
            
            -
            
            
            -Long-term
                deferred tax assets:Federal
                net operating loss carryforwards
            
            
            1,786,119
            
            
            55,500Asset
                retirement obligation
            
            
            427,548
            
            
            -Stock-based
                compensation
            
            
            245,313
            
            
            -Valuation
                allowance
            
            
            (2,098,714
            )
            
            (55,500
            )Net
                long-term deferred tax assets
            
            
            360,266
            
            
            -Long-term
                deferred tax liabilities:Oil
                & gas properties
            
            
            360,266
            
            
            -$
            -
            
            $
            -




As
      of
      March 31, 2007, we had federal net operating loss carryforwards of
      $5,103,000 that expire between 2024 and 2026.




As
      of December 31, 2006 and 2005, because the Company
      believes that it is more likely than not that its net deferred tax assets will
      not be utilized in the future, the Company has fully provided for a valuation
      of
      its net deferred tax assets.




**Note
      9—Disclosures about Oil & Gas Producing Activities**




Prior
      to
      the year ended March 31, 2007, the Company did not have any oil & gas
      properties.




*Costs
      Incurred in Oil & Gas Producing Activities:*




Costs
      incurred in oil & gas property acquisition, exploration and development
      activities, whether capitalized or expensed, are summarized as follows.




For
                the Year Ended March 31,2007
            
            2006
            
            2005Exploration
            
            $
            333,919
            
            $
            -
            
            $
            -Development
            
            
            -
            
            
            -
            
            
            -Acquisitions:Unproved
            
            
            56,813,516
            
            
            -
            
            
            -Proved
            
            
            18,552,188
            
            
            -
            
            
            -Total
            
            
            75,699,623
            
            
            -
            
            
            -Costs
                associated with asset retirement obligations
            
            $
            1,191,837
            
            $
            -
            
            $
            -




*Oil
      & Gas Reserve Quantities (Unaudited):*




For
      the
      year ended March 31, 2007, Ryder Scott Company, L.P. prepared the reserve
      information for the Company’s Cole Creek South, South Glenrock B, and Big Muddy
      Fields in the Powder River Basin. The Company did not have oil & gas
      reserves as of and for the years ended March 31, 2006 and
      2005.




F-26




The
      Company emphasizes that reserve estimates are inherently imprecise and that
      estimates of new discoveries and undeveloped locations are more imprecise than
      estimates of established proved producing oil & gas properties. Accordingly,
      these estimates are expected to change as future information becomes
      available.




Proved
      oil & gas reserves are the estimated quantities of crude oil, natural gas,
      and natural gas liquids that geological and engineering data demonstrate with
      reasonable certainty to be recoverable in future years from known reservoirs
      under existing economic and operating conditions. Proved developed oil & gas
      reserves are those expected to be recovered through existing wells with existing
      equipment and operating methods. All of the Company’s proved reserves are
      located in the continental United States.




Presented
      below is a summary of the changes in estimated oil reserves (in barrels) of
      the
      Company for the year ended March 31, 2007 (the Company did not have any
      natural gas reserves):




Total
                proved:Beginning
                of year
            
            
            -Purchases
                of minerals in-place
            
            
            1,073,138Production
            
            
            (23,838
            )Revisions
                of previous estimates
            
            
            229,864End
                of year
            
            
            1,279,164Proved
                developed reserves:
            
            
            1,062,206


*Standardized
      Measure of Discounted Future Net Cash Flows (Unaudited):*




SFAS
      No. 69, *Disclosures
      about Oil & Gas Producing Activities* (SFAS
      No. 69), prescribes guidelines for computing a standardized measure of
      future net cash flows and changes therein relating to estimated proved reserves.
      The Company has followed these guidelines, which are briefly discussed
      below.




Future
      cash inflows and future production and development costs are determined by
      applying benchmark prices and costs, including transportation, quality, and
      basis differentials, in effect at year-end to the year-end estimated quantities
      of oil & gas to be produced in the future. Each property the Company
      operates is also charged with field-level overhead in the estimated reserve
      calculation. Estimated future income taxes are computed using current statutory
      income tax rates, including consideration for estimated future statutory
      depletion. The resulting future net cash flows are reduced to present value
      amounts by applying a 10% annual discount factor.




Future
      operating costs are determined based on estimates of expenditures to be incurred
      in developing and producing the proved oil & gas reserves in place at the
      end of the period, using year-end costs and assuming continuation of existing
      economic conditions, plus Company overhead incurred by the central
      administrative office attributable to operating activities.




The
      assumptions used to compute the standardized measure are those prescribed by
      the
      FASB and the SEC. These assumptions do not necessarily reflect the Company’s
      expectations of actual revenues to be derived from those reserves, nor their
      present value. The limitations inherent in the reserve quantity estimation
      process, as discussed previously, are equally applicable to the standardized
      measure computations since these estimates are the basis for the valuation
      process. The price, as adjusted for transportation, quality, and basis
      differentials, used in the calculation of the standardized measure was $53.47
      per barrel of oil for the year ended March 31, 2007. The Company did not
      have natural gas reserves during the year ended March 31, 2007, and did not
      have crude oil or natural gas reserves during the years ended March 31,
      2006 and 2005.




F-27




The
      following summary sets forth the Company’s future net cash flows relating to
      proved oil & gas reserves based on the standardized measure prescribed in
      SFAS No. 69:




As
                of
              March 31,
              2007Future
                cash inflows
            
            $
            68,396,874Future
                production costs
            
            
            (38,185,216
            )Future
                development costs
            
            
            (2,004,287
            )Future
                income taxes
            
            
            -Future
                net cash flows
            
            
            28,207,37110%
                annual discount
            
            
            (15,088,423
            )Standardized
                measure of discounted future net cash flows
            
            $
            13,118,948




The
      principal sources of change in the standardized measure of discounted future
      net
      cash flows are:




For
                the year
              ended
              March 31,
              2007Standardized
                measure of discounted future net cash flows, beginning of
                year
            
            $
            -Sales
                of oil & gas produced, net of production costs
            
            
            (324,891
            )Net
                changes in prices and production costs
            
            
            3,412,974Purchase
                of minerals in-place
            
            
            8,479,171Revisions
                of previous quantity estimates
            
            
            2,611,204Accretion
                of discount
            
            
            211,979Changes
                in timing and other
            
            
            (1,271,489
            )Standardized
                measure of discounted future net cash flows, end of year
            
            $
            13,118,948




**Note
      10—Related Party Transaction**





In
        December 2006, the Company acquired  artwork for $7,500 from our President,
        Chief Executive Officer, and a member of the Board of
        Directors.




F-28


**Report
        of Independent Registered Public Accounting Firm**
 
 
 
 The
        Board
        of Directors and Stockholders
 Nielson
        & Associates, Inc.:
 
 We
        have
        audited the accompanying carve out balance sheets of South Cole Creek and
        South
        Glenrock operations as of December 21, 2006 and December 31, 2005, and the
        related carve out statements of operations, changes in owner’s net investment,
        and cash flows for the period from January 1, 2006 to December 21, 2006,
        the
        year ended December 31, 2005, and the period from September 1, 2004 to December
        31, 2004. These financial statements are the responsibility of Nielson &
Associates, Inc.’s management. Our responsibility is to express an opinion on
        these financial statements based on our audits.
 
 We
        conducted our audits in accordance with the standards of the Public Company
        Accounting Oversight Board (United States). Those standards require that
        we plan
        and perform the audit to obtain reasonable assurance about whether the financial
        statements are free of material misstatement. An audit includes examining,
        on a
        test basis, evidence supporting the amounts and disclosures in the financial
        statements. An audit also includes assessing the accounting principles used
        and
        significant estimates made by management, as well as evaluating the overall
        financial statement presentation. We believe that our audits provide a
        reasonable basis for our opinion.
 
 In
        our
        opinion, the financial statements referred to above present fairly, in all
        material respects, the carve out financial position of South Cole Creek and
        South Glenrock operations as of December 21, 2006 and December 31, 2005,
        and the
        carve out results of their operations and their cash flows for the period
        from
        January 1, 2006 to December 21, 2006, the year ended December 31, 2005, and
        the
        period from September 1, 2004 to December 31, 2004, in conformity with U.S.
        generally accepted accounting principles.
 
 
 /s/
        KPMG
        LLP
  Billings,
        Montana
 June
        29,
        2007




F-29


**South
      Cole Creek and South Glenrock****Operations**




**Carve
      Out Balance Sheets**




December
                21, 2006
            
            December
                31, 2005**Assets**Current
                assets:Accounts
                receivable:Revenue
            
            $
            281,142
            
            $
            359,903Joint
                interest
            
            
            91,024
            
            
            12,036Total
                current assets
            
            
            372,166
            
            
            371,939Property
                and equipment, at cost:Oil
                and gas properties, successful efforts method of
                accountingProved
                properties
            
            
            15,634,302
            
            
            13,142,564Unproved
                properties
            
            
            173,821
            
            
            173,82115,808,123
            
            
            13,316,385Less
                accumulated depreciation, depletion, and amortization
            
            
            (1,582,671
            )
            
            (629,887
            )Net
                property and equipment
            
            
            14,225,452
            
            
            12,686,498Total
                assets
            
            $
            14,597,618
            
            $
            13,058,437




**Liabilities
                and Owner’s Net Investment**Current
                liabilities:Accounts
                payable and accrued liabilities
            
            $
            663,922
            
            $
            359,319Production
                taxes
            
            
            368,088
            
            
            238,093Asset
                retirement obligations
            
            
            10,916
            
            
            482,369Total
                current liabilities
            
            
            1,042,926
            
            
            1,079,781Production
                taxes
            
            
            163,700
            
            
            165,957Asset
                retirement obligations
            
            
            958,023
            
            
            861,435Owner’s
                net investment
            
            
            12,432,969
            
            
            10,951,264Total
                liabilities and owner’s net investment
            
            $
            14,597,618
            
            $
            13,058,437


See
        accompanying notes to carve
        out
        financial statements.
  F-30




**South
      Cole Creek and South Glenrock Operations**




**Carve
      Out Statements of Operations**




FromJanuary
                1, 2006 to
              December
                21, 2006
            
            Year
                EndedDecember 31, 2005
            
            FromSeptember
                1, 2004 to
              December
                31, 2004Revenue:Oil
                sales
            
            $
            4,488,315
            
            $
            3,713,973
            
            $
            722,449Operating
                expenses:Lease
                operating expense
            
            
            2,944,287
            
            
            1,537,992
            
            
            360,207Production
                taxes
            
            
            493,956
            
            
            428,905
            
            
            81,868General
                and administrative
            
            
            567,524
            
            
            1,045,133
            
            
            283,257Depreciation,
                depletion, and amortization
            
            
            952,784
            
            
            567,345
            
            
            62,542Accretion
                of asset retirement obligations
            
            
            107,504
            
            
            107,712
            
            
            12,990Total
                operating expenses
            
            
            5,066,055
            
            
            3,687,087
            
            
            800,864Net
                income (loss)
            
            $
            (577,740
            )
            $
            26,886
            
            $
            (78,415
            )







See
      accompanying notes to carve
      out
      financial statements.




F-31




**South
      Cole Creek and South Glenrock Operations**




**Carve
      Out Statement of Changes in Owner’s Net Investment**




Balance
                at September 1, 2004 (inception)
            
            $
            -Owner’s
                contributions, net
            
            
            2,468,305Net
                loss
            
            
            (78,415
            )Balance
                at December 31, 2004
            
            
            2,389,890Owner’s
                contributions, net
            
            
            8,534,488Net
                income
            
            
            26,886Balance
                at December 31, 2005
            
            
            10,951,264Owner’s
                contributions, net
            
            
            2,059,445Net
                loss
            
            
            (577,740
            )Balance
                at December 21, 2006
            
            $
            12,432,969




See
        accompanying notes to carve
        out
        financial statements.
  F-32


**South
      Cole Creek and South Glenrock Operations**




**Carve
      Out Statements of Cash Flows**




FromJanuary 1,
                2006 to December 21, 2006
            
            Year
                EndedDecember 31, 2005
            
            FromSeptember 1,
                2004 toDecember 31, 2004Operating
                activities:Net
                income (loss)
            
            $
            (577,740
            )
            $
            26,886
            
            $
            (78,415
            )Adjustments
                to reconcile net income (loss) to
              net
                cash provided by operating activitiesDepreciation,
                depletion and amortization
            
            
            952,784
            
            
            567,345
            
            
            62,542Accretion
                of asset retirement obligations
            
            
            107,504
            
            
            107,712
            
            
            12,990Change
                in operating assets and liabilities:Accounts
                receivable
            
            
            (227
            )
            
            (51,094
            )
            
            (320,845
            )Accounts
                payable and accrued expenses
            
            
            304,603
            
            
            103,287
            
            
            256,032Production
                taxes payable
            
            
            127,738
            
            
            306,150
            
            
            97,900Settlement
                of asset retirement obligations
            
            
            (482,369
            )
            
            (110,314
            )
            
            -Net
                cash provided by operating activities
            
            
            432,293
            
            
            949,972
            
            
            30,204Investing
                activities:Acquisition
                of oil and gas properties
            
            
            -
            
            
            (2,299,715
            )
            
            (2,498,509
            )Exploration
                and development expenditures
            
            
            (2,491,738
            )
            
            (7,184,745
            )
            
            -Net
                cash used for investing activities
            
            
            (2,491,738
            )
            
            (9,484,460
            )
            
            (2,498,509
            )Financing
                activities:Contributions
                from owner, net
            
            
            2,059,445
            
            
            8,534,488
            
            
            2,468,305Net
                cash provided by financing activities
            
            
            2,059,445
            
            
            8,534,488
            
            
            2,468,305Net
                increase (decrease) in cash and cash equivalents
            
            
            -
            
            
            -
            
            
            -Cash
                and cash equivalents at beginning of period
            
            
            -
            
            
            -
            
            
            -Cash
                and cash equivalents at end of period
            
            $
            -
            
            $
            -
            
            $
            -Non-cash
                investing activities:Increase
                in asset retirement obligations
            
            $
            -
            
            $
            507,748
            
            $
            825,668


See
        accompanying notes to carve
        out
        financial statements.







F-33


**South
        Cole Creek and South Glenrock Operations**
  **Notes
        to Carve Out Financial Statements**
 **December 21,
        2006**





**Note
      1 - Basis of Presentation**





The
      accompanying Historical Financial Statements (the “Historical Statements”) and
      related notes there to are presented on an accrual basis, and represent the
      financial position, results of operations, cash flows, and changes in owner’s
      net investment attributable to Nielson & Associates, Inc.’s (“Nielson” or
      the “Company”) interests in certain producing oil properties located in Converse
      County, Wyoming (the “Acquisition Properties”). Nielson acquired the Acquisition
      Properties from Continental Industries, LC on September 1, 2004 and subsequently
      sold the Acquisition Properties to Rancher Energy Corp. on December 22, 2006.
      The Historical Statements were prepared from the historical accounting records
      of Nielson and reflect the financial position, results of operations and cash
      flows for the period of time the Acquisition Properties were owned by Nielson.
      Accordingly, the Historical Statements do not give effect to the sale of the
      properties to Rancher Energy Corp.





The
      Acquisition Properties were not operated as a separate business unit within
      Nielson. Accordingly, the Historical Statements have been prepared on a “carve
      out” basis and Owner’s Net Investment is presented in place of stockholders’
equity. The Historical Statements have been prepared in accordance with
      Regulation S-X, Article 3 “General instructions to financial statements” and
      Staff Accounting Bulletin (“SAB”) Topic 1-B1 “Costs reflected in historical
      financial statements.” The accompanying Historical Statements include an
      allocation of certain corporate services, including accounting, finance, legal,
      information systems and human resources. As a result, certain assumptions and
      estimates were made in order to allocate a reasonable share of such expenses
      so
      that the accompanying Historical Statements reflect substantially all the costs
      of doing business. The allocations and related estimates and assumptions are
      described more fully in Note 2, Summary of Significant Accounting
      Policies.





The
      operating results and cash flows included in the Historical Statements are
      not
      necessarily indicative of future results due to the change in business and
      in
      operating expenses.








**Note
      2 - Summary of Significant Accounting Policies**





Cash
      and Cash Equivalents





The
      Acquisition Properties did not have separate bank accounts and accordingly,
      all
      cash receipts and disbursements are recorded through the Owner’s Net Investment
      account in the accompanying Historical Statements. Cash received or paid by
      Nielson related to the Acquisition Properties is reflected as owner’s
      contributions, net in the accompanying Statement of Changes in Owner’s Net
      Investment.





F-34





**South
        Cole Creek and South Glenrock Operations**
  **Notes
        to Carve Out Financial Statements**
 **December 21,
        2006**


**Note
      2 - Summary of Significant Accounting Policies
      (continued)**





Use
      of
      Estimates





Preparing
      Historical Statements in accordance with accounting principles generally
      accepted in the United States requires management to make estimates and
      assumptions that affect certain reported amounts and disclosures. The more
      significant areas that required the use of management’s estimates and judgments
      relate to preparation of estimates of oil and gas reserves, the use of these
      oil
      and gas reserves in calculating depreciation, depletion and amortization, the
      use of estimates of future net revenues in computing impairments and estimates
      of abandonment obligations used in such calculations and in recording asset
      retirement obligations. Accordingly, actual results could differ from those
      estimates.





Revenue
      Recognition and Receivables





The
      Company recognizes revenues from oil sales based upon actual volumes sold to
      purchasers. Receivables represent accrued oil sales and amounts due from other
      working interest owners. No allowance for doubtful accounts was, in the opinion
      of management, necessary at December 21, 2006 and December 31,
      2005.





Oil
      Properties





The
      Acquisition Properties are accounted for using the successful efforts method
      of
      accounting for oil properties under Statement of Accounting Standards (“SFAS”)
      No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies”
(“SFAS 19”). Under this method, costs of productive exploratory wells,
      development wells and undeveloped leases are capitalized. Oil and gas lease
      acquisition costs are also capitalized. Exploration costs, including personnel
      costs, geological and geophysical expenses and delay rentals for oil and gas
      leases, are charged to expense as incurred. Costs associated with drilling
      exploratory wells are initially capitalized pending determination of whether
      the
      well is economically productive or nonproductive.





If
      an
      exploratory well does not find reserves or does not find reserves in a
      sufficient quantity as to make them economically producible, the previously
      capitalized costs are expensed in the accompanying Historical Statements of
      Operations in the period in which the determination was made. If a determination
      cannot be made within one year of the exploratory well being drilled and no
      other drilling or exploration activities to evaluate the discovery are firmly
      planned, all previously capitalized costs associated with the exploratory well
      are expensed. Expenditures for repairs and maintenance to sustain or increase
      production from the existing producing reservoir are charged to expense as
      incurred. Expenditures to recomplete a current well in a different unproved
      reservoir are capitalized pending determination that economic reserves have
      been
      added. If the recompletion is not successful, the expenditures are charged
      to
      expense.





Significant
      tangible equipment added or replaced is capitalized. Expenditures to construct
      facilities or increase the productive capacity from existing reserves are
      capitalized. Capitalized costs are amortized on a unit-of-production basis
      based
      on the proved reserves attributable to the properties.




F-35




**South
        Cole Creek and South Glenrock Operations**
  **Notes
        to Carve Out Financial Statements**
 **December 21,
        2006**


**Note
      2 - Summary of Significant Accounting Policies
      (continued)**





Oil
      Properties (continued)





The
      costs
      of retired, sold, or abandoned properties that constitute part of an
      amortization base are charged or credited, net of proceeds received, to the
      accumulated depletion, depreciation, and amortization (“DD&A”) reserve.
      Gains or losses from the disposal of other properties are recognized currently.





Independent
      reserve engineers estimate reserves once a year as of December 31. These reserve
      estimates have been used to calculate DD&A expense for each of the periods
      presented in the accompanying carve out financial statements.





In
      accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of
      Long-Lived Assets”, an impairment of capitalized costs of long-lived assets to
      be held and used, including proved oil and natural gas properties, must be
      assessed whenever events and circumstances indicate that the carrying value
      of
      the asset may not be recoverable. If impairment is indicated based on a
      comparison of the asset’s carrying value to its undiscounted expected future net
      cash flows, then it is recognized to the extent that the carrying value exceeds
      fair value. Expected future net cash flows are based on existing proved reserves
      and production information and pricing assumptions that management believes
      are
      reasonable. There have been no impairments of oil and gas properties recorded
      in
      the Historical Statements.





Asset
      Retirement Obligations





The
      Company has adopted the provisions of Statement of Financial Accounting
      Standards No. 143 (SFAS 143), *Accounting
      for Asset Retirement Obligations.* SFAS
      143
      requires entities to record the fair value of a liability for an asset
      retirement obligation in the period in which it is incurred. For oil and natural
      gas properties, this is the period in which an oil or natural gas property
      is
      acquired or a new well is drilled. An amount equal to and offsetting the
      liability is capitalized as part of the carrying amount of oil and natural
      gas
      properties at its discounted fair value. The liability is then accreted up
      by
      recording accretion expense each period until the liability is settled or the
      well is sold. Estimates are based on historical experience in plugging and
      abandoning wells and estimated remaining lives of those wells based on reserve
      estimates.





Income
      Taxes





The
      operations of Acquisition Properties are currently included in the federal
      income tax return of Nielson, which is a limited partnership that is not subject
      to federal income taxes. Therefore, no income taxes have been provided for
      in
      the Historical Statements.




F-36


**South
        Cole Creek and South Glenrock Operations**
  **Notes
        to Carve Out Financial Statements**
 **December 21,
        2006**





**Note
      2 - Summary of Significant Accounting Policies
      (continued)**





Allocation
      of Costs





A
      related-party entity provides general and administrative (G&A) services to
      Nielson and charges the associated cost of salaries and benefits, depreciation,
      rent, accounting and legal services and other G&A expenses to Nielson under
      agreed-upon terms. The accompanying financial statements include an allocation
      of G&A expenses incurred by Nielson in the management of the Acquisition
      Properties.





The
      allocation of G&A expense is based on a combination of factors including
      production, revenue, operating expenses and capital expenditures attributable
      to
      the Acquisition Properties as compared to those factors for all properties
      owned
      by Nielson during the respective periods. In management’s opinion, the
      allocation methodologies used are reasonable and result in an allocation of
      the
      cost of doing business borne by Nielson on behalf of the Acquisition Properties;
      however, these allocations may not be indicative of the cost of future
      operations.





Earnings
      Per Share





During
      the periods presented, the Acquisition Properties were wholly owned by Nielson.
      Accordingly, earnings per share amounts have not been presented.





**Note
      3 - Asset Retirement Obligations**





The
      Company’s asset retirement obligations consist of costs related to the plugging
      of wells, the removal of facilities and equipment, and site restoration of
      oil
      and gas properties. The following table summarizes the activity in the Company’s
      asset retirement obligation (ARO) liability:





From
              January
                1, 2006 to
              December
                21, 2006
            
            Year
                Ended December 31, 2005
            
            From
              September
                1, 2004 to
              December
                31, 2004ARO
                liability- beginning of period
            
            $
            1,343,804
            
            $
            838,658
            
            $
            -ARO
                liabilities assumed in acquisitions
            
            
            -
            
            
            484,922
            
            
            825,668ARO
                liabilities incurred in the current period
            
            
            -
            
            
            22,826
            
            
            -ARO
                liabilities settled in the current period
            
            
            (482,369
            )
            
            (110,314
            )
            
            -Accretion
                expense
            
            
            107,504
            
            
            107,712
            
            
            12,990ARO
                liability - end of period
            
            $
            968,939
            
            $
            1,343,804
            
            $
            838,658




F-37


**South
        Cole Creek and South Glenrock Operations**
  **Notes
        to Carve Out Financial Statements**
 **December 21,
        2006**





**Note
      4 - Concentrations**





Major
      purchasers, and the approximate percentage of revenue for each, during the
      respective periods are as follows:





From
              January
                1, 2006to
              December
                21, 2006
            
            Year
                Ended December 31, 2005
            
            From
              September
                1, 2004 to
              December
                31, 2004Customer
                A
            
            
            -
            
            
            11
            %
            
            46
            %Customer
                B
            
            
            58
            %
            
            62
            %
            
            54
            %Customer
                C
            
            
            42
            %
            
            27
            %
            
            -





At
      December 21, 2006 and December 31, 2005 these major customers accounted for
      100
      percent of revenue accounts receivable.








**Note
      5 - Supplemental Disclosures Regarding Oil Properties Reserves
      (Unaudited)**





Supplemental
      oil reserve information related to the operations of the Acquisition Properties
      is presented in accordance with the requirements of Statement of Financial
      Accounting Standards No. 69, “Disclosures about Oil and Gas Producing
      Activities” (SFAS No. 69). There are numerous uncertainties inherent in
      estimating quantities of proved reserves and in projecting the future rates
      of
      production and timing of development expenditures.





***Costs
      Incurred -*** The
      following table sets forth the capitalized costs incurred in the Company’s oil
      production, exploration, and development activities:





From
              January
                1, 2006 to
              December
                21, 2006
            
            Year
                EndedDecember 31, 2005
            
            From
              September
                1, 2004 to
              December
                31, 2004Acquisition
                of proved properties
            
            $
            -
            
            $
            2,807,433
            
            $
            3,306,967Acquisition
                of unproved properties
            
            
            -
            
            
            156,611
            
            
            17,210Exploration
                costs
            
            
            -
            
            
            -
            
            
            -Development
                costs
            
            
            2,491,738
            
            
            7,028,164
            
            
            -Total
                costs incurred for acquisition, exploration and development
                activities
            
            $
            2,491,738
            
            $
            9,992,208
            
            $
            3,324,177




F-38


**South
        Cole Creek and South Glenrock Operations**
  **Notes
        to Carve Out Financial Statements**
 **December 21,
        2006**





**Note
      5 - Supplemental Disclosures Regarding Oil Properties Reserves (Unaudited)
      (continued)**





***Estimated
      Proved Reserves -*** Proved
      oil reserves are the estimated quantities of crude oil that geological and
      engineering data demonstrate with reasonable certainty to be recoverable in
      future years from known reservoirs under existing economic and operating
      conditions, i.e. prices and costs at the date the estimate is made.





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





Following
      is a summary of the proved developed and total proved oil reserves, in barrels
      of oil, attributed to the operations of the Acquisition Properties. In
      management’s opinion, the reserves estimates at December 31, 2006 were
      approximately the same as those at December 21, 2006, the date the Acquisition
      Properties were sold.





*Proved
      developed and undeveloped reserves:*





Proved
                reserves:
            
            Year
                EndedDecember 31, 2006
            
            Year
                EndedDecember 31, 2005
            
            FromSeptember
                1, 2004 to December 31, 2004Beginning
                of period
            
            
            1,588,713
            
            
            837,846
            
            
            -Purchases
                of minerals in place
            
            
            -
            
            
            633,384
            
            
            854,080Revisions
                of estimates
            
            
            (487,469
            )
            
            94,280
            
            
            -Extensions
                and discoveries
            
            
            -
            
            
            90,524
            
            
            -Production
            
            
            (73,076
            )
            
            (67,321
            )
            
            (16,234
            )End
                of period
            
            
            1,028,168
            
            
            1,588,713
            
            
            837,846Proved
                Developed Reserves
            
            
            827,487
            
            
            1,372,989
            
            
            837,846





***Standardized
      Measure of Discounted Future Net Cash Flows***





Future
      oil sales and production and development costs have been estimated using prices
      and costs in effect at the end of the periods indicated. The weighted average
      period-end prices used for the Acquisition Properties at December 31, 2006,
      2005
      and 2004 were $47.94, $56.71 and $41.49 per barrel of oil, respectively. Future
      cash inflows were reduced by estimated future development, abandonment and
      production costs based on period-end costs. No deductions were made for general
      overhead, depreciation, depletion and amortization, or any indirect costs.
      All
      cash flows amounts are discounted at 10 percent.




F-39


**South
        Cole Creek and South Glenrock Operations**
  **Notes
        to Carve Out Financial Statements**
 **December 21,
        2006**


**Note
      5 - Supplemental Disclosures Regarding Oil Properties Reserves (Unaudited)
      (continued)**





***Standardized
      Measure of Discounted Future Net Cash Flows
      (continued)***





Changes
      in the demand for oil, inflation, and other factors made such estimates
      inherently imprecise and subject to substantial revision. This table should
      not
      be construed to be an estimate of current market value of the proved reserves
      attributable to the Acquisition Properties.





The
      estimated standardized measure of discounted future net cash flows relating
      to
      proved reserves at December 31, 2006, 2005 and 2004 is shown below:





December
                31, 2006
            
            December
                31, 2005
            
            December
                31, 2004Future
                cash inflows
            
            $
            47,317,344
            
            $
            86,488,888
            
            $
            33,157,864Future
                production costs
            
            
            (29,851,344
            )
            
            (46,837,348
            )
            
            (19,815,423
            )Future
                development costs
            
            
            (2,004,287
            )
            
            (2,304,287
            )
            
            -Future
                net cash flows
            
            
            15,461,713
            
            
            37,347,253
            
            
            13,342,44110
                percent annual discount
            
            
            (7,666,089
            )
            
            (20,374,454
            )
            
            (6,595,775
            )Standardized
                measure of discounted future net
              cash
                flows relating to proved reserves
            
            $
            7,795,624
            
            $
            16,972,799
            
            $
            6,746,666




F-40


**South
        Cole Creek and South Glenrock Operations**
  **Notes
        to Carve Out Financial Statements**
 **December 21,
        2006**





**Note
      5 - Supplemental Disclosures Regarding Oil Properties Reserves (Unaudited)
      (continued)**





***Standardized
      Measure of Discounted Future Net Cash Flows
      (continued)***





The
      following reconciles the change in the standardized measure of discounted future
      net cash flows during the periods ended December 31, 2006 and December 31,
      2005
      and 2004:





From
              January
                1, 2006 to
              December
                31, 2006
            
            Year
                EndedDecember 31, 2005
            
            From
              September
                1, 2004 to
              December
                31, 2004Beginning
                of period
            
            $
            16,972,799
            
            $
            6,746,666
            
            $
            -Purchases
                of reserves in place
            
            
            -
            
            
            6,264,995
            
            
            7,016,351Revisions
                of previous estimates
            
            
            (3,763,013
            )
            
            1,176,659
            
            
            -Extensions
                and discoveries
            
            
            -
            
            
            1,958,102
            
            
            -Changes
                in future development costs, net
            
            
            300,000
            
            
            (671,511
            )
            
            -Net
                change in prices
            
            
            (5,731,580
            )
            
            3,757,911
            
            
            -Sales
                of oil, net of production costs
            
            
            (1,050,072
            )
            
            (1,747,076
            )
            
            (280,374
            )Changes
                in timing and other
            
            
            (629,790
            )
            
            (1,187,614
            )
            
            10,689Accretion
                of discount
            
            
            1,697,280
            
            
            674,667
            
            
            -End
                of period
            
            $
            7,795,624
            
            $
            16,972,799
            
            $
            6,746,666





F-41





**REPORT
      OF INDEPENDENT REGISTERED**


**PUBLIC
      ACCOUNTING FIRM**





Board
      of
      Directors


Rancher
      Energy Corp.


Denver,
      Colorado





We
      have
      audited the accompanying historical summary of revenue and direct operating
      expenses of properties acquired in December 2006 by Rancher Energy Corp., for
      the period from January 1, 2004 through August 31, 2004. The
      historical summary are the responsibility of the Company’s management. Our
      responsibility is to express an opinion on the historical summary based on
      our
      audits.





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





The
      accompanying historical summary was prepared for the purpose of complying with
      the rules and regulations of the Securities and Exchange Commission (for
      inclusion in the Form 10-K of Rancher Energy Corp. as described in Note 1)
      and is not intended to be a complete presentation of the properties’
revenues and expenses.





In
      our
      opinion, the historical summary referred to above presents fairly, in all
      material respects, the revenue and direct operating expenses of the properties
      acquired in December 2006 by Rancher Energy Corp. for the period from January
      1,
      2004 through August 31, 2004, in conformity with U. S. generally accepted
      accounting principles.








*/s/
      HEIN* *&
      ASSOCIATES LLP*





Denver,
      Colorado


June
      28,
      2007




F-42





**South
      Cole Creek and South Glenrock Operations**





**Statement
      of Revenues and Direct Operating Expenses**








For
                the Period January 1 through August 31, 2004Revenue:Oil
                sales
            
            $
            1,275,214Direct
                operating expenses:Lease
                operating expense
            
            
            583,942Production
                taxes
            
            
            138,087Total
                direct operating expenses
            
            
            722,029Revenues
                in excess of direct operating expenses
            
            $
            553,185







See
      Accompanying Notes to Statement of Revenues and Direct Operating
      Expenses.







F-43


**South
      Cole Creek and South Glenrock Operations**





**Notes
      to Statement of Revenues and Direct Operating Expenses**





**Note
      1 - Basis of Presentation**





The
      accompanying financial statement presents the revenues and direct operating
      expenses of the oil properties (the Acquisition Properties) acquired by Nielson
      & Associates, Inc. (the Company) from Continental Industries, LC
      (Continental) for the period January 1, 2004 to August 31, 2004. The
      Acquisition Properties were purchased by the Company in September 2004 and
      were subsequently sold to Rancher Energy Corp. (Rancher) on December 22,
      2006.





The
      accompanying statement of revenues and direct operating expenses of the
      Acquisition Properties do not include indirect general and administrative
      expenses, interest expense, depreciation, depletion and amortization, or any
      provision for income taxes. Management of Rancher believes historical expenses
      of this nature incurred by Continental are not indicative of the costs to be
      incurred by Rancher.





The
      Company recognizes revenues from oil sales based upon actual volumes sold to
      purchasers. The direct operating expenses are recognized on the accrual basis
      and consist of the direct costs of operating the Acquisition Properties
      including severance and ad valorem (property) taxes, lifting costs, well repair
      and well workover costs. Direct costs do not include general corporate
      overhead.





Complete
      financial statements, including a balance sheet, are not presented as the
      Acquisition Properties were not operated as a separate business unit within
      Continental. Accordingly, it is not practicable to identify all assets and
      liabilities, or the indirect operating costs applicable to the Acquisition
      Properties. As such, the historical statement of revenues and direct operating
      expenses have been presented in lieu of financial statements prescribed by
      Rule
      3-01-04 of Securities and Exchange Commission Regulation S-X.




The
      preparation of financial statements in accordance with generally accepted
      accounting principles requires management to make estimates and assumptions
      that
      affect the reported amounts of revenue and expense during the reported period.
      Accordingly, actual results could differ from those estimates.





**Note
      2 - Supplemental Disclosures Regarding Oil Properties Reserves
      (Unaudited)**





***Estimated
      Proved Reserves -*** Proved
      oil reserves are the estimated quantities of crude oil that geological and
      engineering data demonstrate with reasonable certainty to be recoverable in
      future years from known reservoirs under existing economic and operating
      conditions, i.e. prices and costs at the date the estimate is made. Prices
      include consideration of changes in existing prices provided only by contractual
      arrangement, but not on escalations based on future conditions.





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





Following
      is a summary of the proved developed and total proved oil reserves, in barrels
      of oil, attributed to the Acquisition Properties:





*Proved
      developed and undeveloped reserves:*




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August 31,
                2004Beginning
                of period
            
            
            836,759Purchases
                of minerals in place
            
            
            -Revisions
                of estimates
            
            
            135,800Extensions
                and discoveries
            
            
            -Production
            
            
            (35,882
            )End
                of period
            
            
            936,677Proved
                Developed
            
            
            936,677Total
                Proved
            
            
            936,677





***Standardized
      Measure of Discounted Future Net Cash Flows***





Future
      oil sales and production and development costs have been estimated using prices
      and costs in effect at the end of the period indicated. The weight average
      period-end price used for the Acquisition Properties at August 31, 2004 was
      $39.83 per barrel of oil. Future cash inflows were reduced by estimated future
      development, abandonment and production costs based on period-end costs. No
      deductions were made for general overhead, depreciation, depletion and
      amortization, or any indirect costs. All cash flow amounts are discounted at
      10
      percent.





Changes
      in the demand for oil, inflation, and other factors made such estimates
      inherently imprecise and subject to substantial revision. This table should
      not
      be construed to be an estimate of current market value of the proved reserves
      attributable to the Acquisition Properties.





The
      estimated standardized measure of discounted future net cash flows relating
      to
      proved reserves at August 31, 2004 is shown below:





August 31,
                2004Future
                cash inflows
            
            $
            37,307,874Future
                production costs
            
            
            (14,681,028
            )Future
                development costs
            
            
            -Future
                net cash flows
            
            
            22,626,84610%
                annual discount
            
            
            (12,460,123
            )Standardized
                measure of discounted future net
              cash
                flows
            
            $
            10,166,723





The
      following reconciles the change in the standardized measure of discounted future
      net cash flows during the period ended August 31, 2004:





For
                the Period Ended
              August 31,
                2004Beginning
                of period
            
            $
            8,987,287Purchases
                of reserves in place
            
            
            -Revisions
                of previous estimates
            
            
            1,441,810Extensions
                and discoveries
            
            
            -Changes
                in future development costs, net
            
            
            -Net
                change in prices
            
            
            (221,934
            )Sales
                of oil, net of production costs
            
            
            (553,185
            )Changes
                in timing and other
            
            
            (385,984
            )Accretion
                of discount
            
            
            898,729End
                of period
            
            $
            10,166,723





F-45