**UNITED
      STATES**


**SECURITIES
      AND EXCHANGE COMMISSION**


**Washington,
      D.C. 20549**




**FORM
      10-K**




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


For
      the
      fiscal year ended March 31, 2008


or




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


For
      the
      transition period from __________ to __________




Commission
      file number: **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 3400


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 class
            Name
                of Each Exchange
              On
                Which RegisteredCommon
                Stock, par value $0.00001 per share
            N/A




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




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




Indicate
      by check mark whether the registrant (1) has filed all reports required to
      be
      filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
      the
      preceding 12 months (or for such shorter period that the registrant was required
      to file such reports) and (2) has been subject to such filing requirements
      for
      the past 90 days. Yes xNo
o




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. o




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




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




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




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, 2007 was $44,836,845.




The
      number of shares outstanding of the registrant’s common stock as of  June
      27,
      2008 was 115,128,364.




**DOCUMENTS
      INCORPORATED BY REFERENCE**




Portions
      of the Proxy Statement for the
      2008
      Annual Meeting
      of Stockholders are incorporated by reference into Part III of this Form
      10-K.





**TABLE
      OF CONTENTS**





**PAGE
                NO.**PART
                I
            
            1ITEM
                1.
            BUSINESS
            2ITEM
                1A.
            RISK
                FACTORS
            8ITEM
                1B.
            UNRESOLVED
                STAFF COMMENTS
            13ITEM
                2.
            PROPERTIES
            13ITEM
                3.
            LEGAL
                PROCEEDINGS
            16ITEM
                4.
            SUBMISSION
                OF MATTERS TO A VOTE OF SECURITY HOLDERS
            16PART
                II
            
            16ITEM
                5.
            MARKET
                FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
                PURCHASES OF EQUITY SECURITIES
            16ITEM
                6.
            SELECTED
                FINANCIAL DATA
            20ITEM
                7.
            MANAGEMENT’S
                DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
                OPERATIONS
            20ITEM
                7A.
            QUANTITATIVE
                AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
            32ITEM
                8.
            FINANCIAL
                STATEMENTS AND SUPPLEMENTARY DATA
            32ITEM
                9.
            CHANGES
                IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
                DISCLOSURE
            32ITEM
                9A(T).
            CONTROLS
                AND PROCEDURES
            33ITEM
                9B.
            OTHER
                INFORMATION
            34PART
                III
            
            34ITEM
                10.
            DIRECTORS,
                EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
            34ITEM
                11.
            EXECUTIVE
                COMPENSATION
            35ITEM
                12.
            SECURITY
                OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
                STOCKHOLDER MATTERS
            35ITEM
                13.
            CERTAIN
                RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
                INDEPENDENCE
            35ITEM
                14.
            PRINCIPAL
                ACCOUNTING FEES AND SERVICES
            35PART
                IV
            
            35ITEM
                15.
            EXHIBITS,
                FINANCIAL STATEMENT SCHEDULES
            35




For
      abbreviations on definitions of certain terms used in the oil and 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”.


i


**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;


·ability
      to obtain the financial
      resources to repay secured debt and to conduct the EOR projects;


·water
      availability and
      waterflood production targets;


·carbon
      dioxide (CO 2 )
      availability, deliverability, and tertiary production targets;


·construction
      of surface
      facilities for waterflood and CO 2 operations and a CO 2 pipeline;


·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 water and
      CO 2 injection;


·ability
      to obtain permits and
      governmental approvals;


·technology;


·financial
      strategy;


·realized
      oil
      prices;


·production;


·lease
      operating expenses,
      general and administrative costs, 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 and gas in North America. Our business strategy is to use modern tertiary
      recovery techniques on older, historically productive fields with proven
      in-place oil and gas. Higher oil and gas prices and advances in technology
      such
      as 3-D seismic acquisition and evaluation and carbon dioxide (CO 2 )
      injection, should position us to capitalize on attractive sources of potentially
      recoverable oil and 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 Anadarko
      Petroleum Corporation (Anadarko) to supply us with CO 2 needed
      to conduct CO 2 tertiary
      recovery operations in our three fields. In February 2008, we entered into
      a
      Carbon Dioxide Sale and Purchase Agreement with ExxonMobil Gas and Power
      Marketing, (ExxonMobil), a division of ExxonMobil Corporation, to supply
      additional CO 2 to
      the
      three fields. We are seeking financing or strategic joint venture partners
      to
      enable us to construct a pipeline to deliver CO 2 to our
      fields and to drill additional wells and construct necessary infrastructure
      improvements in order to implement EOR techniques.




Led
      by an
      experienced management team and complimented by consultants with particular
      knowledge in each aspect of the EOR process, our long term goal is to enhance
      stockholder value by identifying and further developing productive oil and
      gas
      assets across North America, particularly in the Rocky Mountains. Our
      headquarters office is located in Denver, Colorado where we employ 11 persons
      and our field office is located in Glenrock, Wyoming, where we employ 5 persons.




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.




**Business
      Strategy**




We
      believe in these 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 complimentary acquisitions of long-lived producing properties
                which include a high degree of operating control, and oil and gas
                entities
                that offer opportunities to profitably develop oil and gas
                reserves;




·
            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;




·
            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; and




·
            Pursue
                strategic alliances with experienced oil and gas development partners
                to
                complement our existing asset base and expand our operational capabilities
                in the Powder River Basin.




**Property** **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 and 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 and 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.




2




**Our
      Development Program**




We
      have
      completed field studies and economic analysis 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 two CO 2 supply
      agreements. Subject to obtaining additional financing or entering into a
      strategic partnering arrangement with experienced industry partners, we are
      planning to proceed with the tertiary development of our fields. The current
      planned order of development is the South Glenrock B Field, the Big Muddy Field,
      and then the Cole Creek South Field.




**Oil
      and Gas Operations**




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




CO2Tertiary
      Recovery




Our
      business strategy is to employ modern EOR technology to recover hydrocarbons
      that remain behind in mature reservoirs. 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
      contracts with Anadarko and ExxonMobil were important steps in executing our
      business strategy. Important next steps are to either secure debt financing,
      or
      to enter into a strategic partnering arrangement with an experienced industry
      partner with the financial resources in a sufficient amount for our development
      program, complete the required environmental and regulatory permitting, build
      a
      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, if appropriate, 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.




We
      are
      evaluating the need to conduct a 3-D seismic survey on the South Glenrock B
      and
      Big Muddy Fields in conjunction with the CO2development program. The seismic information would be used to further define
      reservoir configuration and trapping, thus filling in gaps in the available
      information for our fields.




Anadarko
      CO2Supply
      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, which as of June 30, 2008 had not yet occurred 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%.




3




ExxonMobil
      CO2Supply
      Agreement




On
      February 12, 2008 we entered into a Carbon Dioxide Sale and Purchase Agreement
      with ExxonMobil that is to provide us with 70 MMscfd (million standard cubic
      feet per day) of CO 2 for an
      initial 10-year period. We intend to use the CO 2 for
      our
      EOR projects. The primary term of the agreement, which is ten years, will begin
      the first day of the month following ExxonMobil’s notice to us of the completion
      of the expansion of certain CO 2 delivery
      facilities by ExxonMobil and that it is prepared to deliver the required daily
      quantity as required under the agreement. Either party may extend the agreement
      for an additional ten year term following proper notice and agreement to certain
      applicable terms of the agreement. Following the commencement of the primary
      term, ExxonMobil is obligated to deliver to us at least 70 MMscfd of
      CO 2 per day.
      We have agreed to a “take-or-pay” provision under the agreement. For
      CO 2 deliveries from ExxonMobil, we have agreed to pay a base price plus an Oil
      Price
      Factor which is indexed to the price of West Texas Intermediate crude
      oil.





We
      may
      terminate the agreement if ExxonMobil fails to meet the Company’s quantity
      nomination of CO 2 (not to
      exceed 70 MMscfd per day) for 30 consecutive days except under certain
      circumstances. Either party has the right to terminate the agreement at any
      time
      with notice to the other party based on certain circumstances described in
      the
      agreement. ExxonMobil is not obligated to commence delivery of CO 2 until we
      provide a surety bond equal to four months’ supply of CO 2 .
      ExxonMobil may also request additional financial performance assurances if
      it
      has reasonable grounds for believing that we have ceased to have the financial
      resources to meet our obligations under the agreement and ExxonMobil may suspend
      delivery of CO 2 until
      the
      appropriate assurances are provided. ExxonMobil may terminate the agreement
      if a
      requested performance assurance is not provided by us within 30 days of a
      request.





Under
      the
      terms of the agreement, ExxonMobil is responsible for paying all taxes and
      royalties up to the delivery point except that we are obligated to reimburse
      ExxonMobil for 100% of any new, increased, or additional taxes or royalties
      incurred up to the delivery point. The CO 2 is to be
      supplied from ExxonMobil’s LaBarge gas field in Wyoming.




CO2Pipeline
      Construction and CO2EOR
      Related Field Development




Under
      the
      CO 2 contracts with Anadarko and ExxonMobil, we have the responsibility for providing
      pipeline transportation of purchased CO 2 to our
      project area. We plan to transport purchased CO 2 through
      a 12-inch pipeline and 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 $132
      million.




We
      have
      conducted an analysis of permitting requirements for the pipeline and associated
      surface facilities and have had discussions with Federal and state regulatory
      agencies. The shorter of the two proposed pipeline routes is almost entirely
      on
      state and privately-owned land, with only 0.8 mile on Bureau of Land Management
      (BLM) land. The BLM portion of the route has been impacted by previous railroad
      and pipeline development. Based on discussions to date with Federal agencies,
      we
      do not anticipate that environmental assessments will be required for the
      shorter pipeline route or for development of the three oil fields. Approval
      of
      permits from the BLM and state regulatory agencies will be required for pipeline
      construction and field development to proceed. The longer route includes
      approximately 65 miles on BLM lands and we anticipate we would be required
      to
      perform an environmental assessment or an environmental impact study for this
      route. This longer route has also been impacted by previous pipeline and utility
      development.




Pipeline
      construction is expected to take approximately 4 months for the shorter route
      and up to 9 months for the longer route. A number of long lead time items must
      be commenced simultaneously to successfully implement our CO 2 EOR
      plans, including, commencing and completing right of way acquisition - estimated
      7-12 months; ordering steel pipe, milling the steel pipe, and delivery of steel
      pipe to the construction site - estimated 6 months; finalizing pipeline
      engineering - estimated 4-8 months; completing various permitting processes
      -
      estimated 6-12 months, and completion of the environmental assessment for the
      longer route - estimated 12 months. In addition, the CO 2 surface
      facilities equipment must be ordered and then constructed. The lead times for
      surface facilities equipment can be 9-12 months and must be installed within
      1-2
      months after commencing with the CO 2 flood.
      Typically, beginning in November and lasting through March, the Wyoming winter
      conditions can freeze the ground and make installation and construction of
      pipelines and surface facilities increasingly more difficult and significantly
      more expensive.




Delays
      in
      financing may significantly impact the above timeline, given the seasonality
      of
      pipeline construction in Wyoming and the long lead time required for ordering
      surface facility equipment.




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
      substantial additional capital for this option. We are currently planning to
      either borrow funds in a debt financing or to enter into a strategic partnering
      arrangement with an experienced industry partner to fund the development of
      our
      fields and, if necessary, to fund the construction of the CO 2 pipeline.




4




Anadarko
      currently is receiving CO2 for its Salt Creek Field in Wyoming from
      ExxonMobil through a 125-mile, 16-inch pipeline constructed in 2004. Exxon
      collects CO2 from its natural gas fields at LaBarge, Wyoming and
      processes the gas at its Shute Creek gas sweetening plant. ExxonMobil then
      transports the CO2 to the origin of the pipeline for delivery to
      Anadarko’s Salt Creek Field. Our contract with Anadarko calls for the delivery
      of CO2 from a connection point near their Salt Creek Field. Our
      studies have indicated that a different delivery point along their pipeline
      would result in a shorter, less expensive pipeline over less difficult terrain.
      We have engaged in negotiations with Anadarko to modify the delivery point
      for
      CO2 and to establish a transportation agreement under which Anadarko
      would also deliver CO2 purchased from ExxonMobil. We have not
      been able to reach agreement with Anadarko on either issue. There is no
      assurance we will be successful in such negotiations and, in the event we are
      not successful, we may be forced to build the pipeline over the longer, more
      expensive route.




**Financing
      Plans**




Due
      to
      our limited capital resources, we must raise funds from external sources to
      implement our development plans. In
      October 2007, we borrowed approximately $11 million (after fees and expenses)
      from a financial institution. The loan bears interest at a rate equal to the
      greater of (a) 12% per annum and (b) the LIBOR rate plus 6% per annum. We are
      required to make monthly interest payments on the amounts outstanding under
      this
      loan. All principal payments and any other unpaid amounts are due on October
      31,
      2008, which is the maturity date of the loan. Our obligations under the loan
      are
      secured by a first priority security interest in all of our properties and
      assets, including all rights under our oil and gas leases in our three producing
      fields and all of our equipment on those properties. We have used a substantial
      portion of the funds from this loan to enhance production in two of our fields
      with existing waterflood operations, to prepare for waterflood operations on
      the
      Big Muddy Field, and to provide us with working capital and cash
      reserves.




Due
      to
      difficulties in the capital debt markets, fixed term debt financing has been
      unavailable to us to develop our fields. In November 2007 we began to explore
      strategic alliances with experienced industry partners under which we would
      assign a percentage of our interests in the three fields, in exchange for the
      partner’s investment in the fields. We executed a letter of intent with such a
      partner in February 2008, the terms of which called for the investment of up
      to
      $83.5 million to earn up to a 55% interest in the fields. That letter of intent
      expired on April 30, 2008. We subsequently entered into a second letter of
      intent with two different parties which included similar terms for the
      development of the fields, but which also included provisions for the
      construction of a pipeline from the source of the ExxonMobil CO 2to our
      three fields. Due diligence and formal contract negotiations are ongoing with
      these potential partners.




**Federal
      and State Regulations**




Numerous
      Federal and state laws and regulations govern the oil and 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 and gas properties. In
      addition, state conservation laws establish maximum rates of production from
      oil
      and gas wells and generally prohibit the venting or flaring of gas. The effect
      of these regulations may limit the amount of oil and 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 and gas industry increases our costs of doing
      business and, consequently, affects our profitability.




5




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 and 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
      and 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 and 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.




Federal
      or State Leases




Our
      operations on Federal or state oil and 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 CO2Pipeline




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 and 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.




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.rancherenergy.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.




6




**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.**ExxonMobil**
            
            ExxonMobil
                Gas & Power Marketing Company, a division of ExxonMobil
                Corporation.**EOR**
            
            Enhanced
                oil recovery.**Farmout**
            
            The
                transfer of all or part of the working interest in a property, in
                exchange
                for the transferee assuming all or part of the cost of developing
                the
                property.**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.**MMscfd**
            
            One
                million standard cubic feet per day 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. CO2and 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.**Sale
                and Purchase Agreement**
            
            The
                ExxonMobil Carbon Dioxide Sale and Purchase Agreement.**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
                CO2flooding.**Working
                interest**
            
            An
                interest in an oil and gas lease that gives the owner of the interest
                the
                right to drill and produce oil and 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.


7





**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 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**




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




The
      report of our independent registered public accounting firm on the financial
      statements for the year ended March 31, 2008, includes an explanatory paragraph
      relating to the uncertainty of our ability to continue as a going concern.
      Our
      current cash position will not be sufficient to fund the development of our
      three properties for CO 2 EOR
      operations. We will require substantial additional funding. Our plan is to
      obtain financing or to farmout or enter into another type of transaction to
      facilitate development of our properties. We entered into a letter of intent
      with a perspective industry partner. However, there is no assurance that we
      will
      be successful in entering into a definitive agreement with this industry
      partner. If we are unsuccessful in entering into a definitive agreement, we
      will
      need to seek other financing arrangements the availability of which is unknown.
      The terms of any financing arrangement may be on terms unfavorable to us and
      could restrict our future business activities and expenditures. A farmout will
      reduce our ultimate ownership interest in and future cash flows from the
      properties. Insufficient funds will prevent us from implementing our secondary
      and tertiary recovery business strategy.




***Our
      October 2007 short-term debt financing required the imposition of a mortgage
      interest in favor of our lender on our three fields and a default by us of
      the
      financing terms could result in the foreclosure and loss of one or more of
      our
      fields and other assets.***




We
      borrowed $12 million in October 2007, which is due in October 2008, and granted
      to the lender a mortgage on our interests in three fields and our other assets.
      We used a portion of these funds to increase oil production and for working
      capital. We do not have cash available to repay this loan. We plan to refinance
      this loan and borrow additional funds to pursue our business strategy. There
      is
      no assurance that such funding will be available, or that, if available, the
      terms will be satisfactory to us. If we are not successful in repaying this
      debt
      within the term of the loan, or default under the terms of the loan, the lender
      will be able to foreclose one or more of our three properties and other assets
      and we could lose the properties. A
      foreclosure could significantly reduce or eliminate our property interests,
      force us to alter our business strategy, which could involve the sale of
      properties or working interests in the properties and adversely affect our
      results of operations and financial condition.




***Our
      contracts with our CO*** **2** **suppliers include significant take-or-pay obligations.**




Our
      existing contracts with ExxonMobil and Anadarko contain provisions under which
      we are required to take delivery of certain volumes of CO 2 or
      pay
      the seller for the volume difference between the required quantity and the
      volume actually purchased. If we are unable to secure sufficient financing
      to
      construct a pipeline and to develop and prepare our properties for the injection
      of CO 2 we
      will
      be unable to take delivery of CO 2 and
      our
      cash position at that time will not be sufficient to pay for the take-or-pay
      volumes.




***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 $13,164,826 and $8,702,255
      for
      the fiscal years ended March 31, 2008 and 2007, respectively. We do not
      expect to be profitable during the fiscal year ending March 31, 2009. 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
      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.




8




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




O ur
      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, quality of the supplied
      CO 2, problems
      with our facilities, including compression equipment, or catastrophic pipeline
      failure. We
      have
      received no CO 2 to
      date.
      We have agreements with two CO 2 suppliers. Our
      agreement wit h
      one of our
      suppliers of CO 2 is
      complex and subject to differing interpretations. It provides that before it
      delivers CO 2 to
      us, it
      may satisfy its own CO 2 needs. We
      also
      have had discussions with that supplier regarding a different delivery point
      that is not resolved. If we are
      not successful in obtaining the required amount of CO2  to
      achieve crude oil production or the crude oil production in the future were
      to
      decline as a result if a decrease in delivered CO 2 supply,
      it could have a material adverse effect on our financial condition and results
      of operations and cash flow s.




***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 and 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, 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
      plan to conduct our secondary and tertiary recovery operations on older fields
      that may be significantly depleted of oil, which could lead to an adverse impact
      on our future results.***




We
      operate three fields in the Powder River Basin, Wyoming. Oil in all three fields
      was discovered over fifty years ago and production has been ongoing. Our
      strategy is to substantially increase production and reserves in these fields
      by
      using waterflood and CO 2 EOR
      techniques. However, there is a risk that the properties may be significantly
      depleted of oil, and if so, our future results could be impacted negatively.




***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 and 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.




***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, 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.




9




***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 Company's properties 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, Richard Kurtenbach our Chief
      Accounting Officer and Denise Greer our Land and Operations Manager. 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, spills, 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.




***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 these 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.




10




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




Oil
      and
      gas operations in the Rocky Mountains are adversely affected by seasonal weather
      conditions. In certain areas, drilling and other oil and 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 and gas industry is intense, which may adversely affect our ability
      to succeed.***




The
      oil
      and 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, 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, 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.




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




Estimating
      quantities of proved oil and 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, 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 and 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.




11


Quantities
      of proved reserves are estimated based on economic conditions, including oil
      and
      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 and 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 308,000 shares
      per
      day over the three month period ended March 31, 2008. 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 may 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.




***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 and 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.




12


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 affect on our business,
      results of operations, and financial condition.




***Our
      failure to maintain effective internal control over financial reporting may
      not
      allow us to accurately report our financial results, which could cause our
      financial statements to become materially misleading and adversely affect the
      trading price of our stock.***




In
      our
      annual report on Form 10-K for the fiscal year ended March 31, 2008, we reported
      the determination of our management that we had a material weakness in our
      internal control over financial reporting. The determination was made by
      management that we did not adequately segregate duties of different personnel
      in
      our accounting department due to an insufficient complement of staff and
      inadequate management oversight. If we fail to correct the material
      weaknesses in our internal control over financial reporting, our business could
      be harmed and the stock price of our common stock could be adversely
      affected.




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




The
      Financial Industry Regulatory Authority, Inc. (FINRA) has adopted rules which
      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
      FINRA believes that there is a high probability that speculative low priced
      securities will not be suitable for at least some customers. The FINRA
      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.




***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.




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




None.




**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.




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 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.




13


The
      South
      Glenrock B Field is an active waterflood that currently produces approximately
      160 BOPD of sweet 35 degree API crude oil. There are 13 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. Subject to obtaining financing, we plan to start CO 2 injection in the South Glenrock B Field in calendar year 2010.




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 and subject to obtaining financing, we plan to start
      CO 2 injection in the Big Muddy Field in calendar year 2012.




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. Subject to obtaining financing, we plan to start CO 2 injection in the Cole Creek South Field in either calendar year 2014 or
      2015.




**Oil
      and 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.


14





Field
            
            Number of
              Gross Oil Wells
            
            Number of
              Net Oil WellsBig
                Muddy Field
            
            
            5
            
            
            5.00South
                Glenrock B Field
            
            
            13
            
            
            12.19Cole
                Creek South Field
            
            
            12
            
            
            12.00Total
                Wells
            
            
            30
            
            
            29.19




**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.




For the Year
              Ended March 31, 2008
            
            For the Year
              Ended March 31, 2007Net
                oil production (barrels)
            
            
            86,626
            
            
            
            
            
            23,838Average
                realized oil sales price per barrel
            
            $
            73.24
            
            
            
            
            $
            48.74Production
                costs per barrel:Production
                taxes
            
            $
            8.91
            
            
            
            
            $
            5.72Lease
                operating expenses
            
            $
            33.55
            
            
            
            
            $
            28.04





**Title
      to Properties**




As
      customary in the oil and 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 and 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. 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. As part of our plans
      to construct a pipeline to transport CO 2 to our
      fields we will be required to perform either an environmental assessment or
      a
      more comprehensive environmental impact study of the proposed
      pipeline.




**Geographic
      Segments**




All
      of
      our operations are in the continental United States.




**Significant
      Oil and 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.




15


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.




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 and gas leases, marketing of oil
      and
      gas, 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
      and 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, such as 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,
      which 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**




None.




**PART
      II**




**ITEM 5.**
            **MARKET
                FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
                PURCHASES OF EQUITY
                SECURITIES**




Our
      Common Stock has been 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 2008**
            
            **High
                Bid**
            
            **Low
                Bid**First
                Quarter
            
            $
            1.30
            
            $
            0.68Second
                Quarter
            
            $
            0.75
            
            $
            0.31Third
                Quarter
            
            $
            0.84
            
            $
            0.20Fourth
                Quarter
            
            $
            0.69
            
            $
            0.26**Fiscal
                Year 2007**First
                Quarter
            
            $
            1.55
            
            $
            1.30Second
                Quarter
            
            $
            1.82
            
            $
            1.03Third
                Quarter
            
            $
            3.38
            
            $
            1.71Fourth
                Quarter
            
            $
            3.46
            
            $
            1.16




16





**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, 2008. 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**
            
            **3/31/07**
            
            **3/31/08**Rancher
                Energy Corp.
            
            
            100.0
            
            
            11,858.7
            
            
            10,952.8
            
            
            3,211.73NASDAQ
                Composite
            
            
            100.0
            
            
            106.8
            
            
            112.3
            
            
            104.67Dow
                Jones Wilshire MicroCap Exploration & Production
            
            
            100.0
            
            
            108.3
            
            
            86.7
            
            
            69.50





**Holders**





As
      of
      June 18, 2008, there were approximately 229 record owners of our Common Stock.
      This does not include any beneficial owners for whom shares may be held in
      “nominee” or “street name”.




17




**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. The table that follows summarizes the exercise of Mr. Works’
options:




Exercise
                Date
            
            Number of Options Exercised
            
            Exercise Price
            
            Aggregate Purchase PriceMay
                15, 2006
            
            
            1,000,000
            
            $
            0.00001
            
            $
            10.00April
                19, 2007
            
            
            750,000
            
            $
            0.00001
            
            $
            7.50May
                31, 2007
            
            
            250,000
            
            $
            0.00001
            
            $
            2.50August
                31, 2007
            
            
            250,000
            
            $
            0.00001
            
            $
            2.50November
                30, 2007
            
            
            250,000
            
            $
            0.00001
            
            $
            2.50February
                29, 2008
            
            
            250,000
            
            $
            0.00001
            
            $
            2.50





Mr.
      Works
      is an accredited investor. The foregoing transaction was made pursuant to
      Section 4(2) of the Securities Act.


Pursuant
      to our 2006 Stock Incentive Plan (the 2006 Stock Incentive Plan), we granted
      options to purchase shares of common stock to officers employees, directors
      and
      a consultant as summarized below:




**Date**
            
            **Granted
                To**
            
            **No.
                of**
              **Options**
            
            **Exercise**
              **Price**
            
            **Vesting**
            
            **Term**Oct
                2, 2006
            
            
            Officer
                and Employee
            
            
            825,000
            
            $
            1.75
            
            
            Annually
                over a 3 year period
            
            
            5
                YearsOct
                16, 2006
            
            
            Officer
            
            
            1,500,000
            
            $
            2.10
            
            
            Annually
                over a 3 year period
            
            
            5
                YearsJan
                12, 2007
            
            
            Officer
            
            
            1,000,000
            
            $
            3.19
            
            
            Annually
                over a 3 year period
            
            
            5
                YearsFeb
                16, 2007
            
            
            Director
            
            
            10,000
            
            $
            1.63
            
            
            50%
                at 1stand 2ndanniversary of grant
            
            
            5
                YearsApr
                10, 2007
            
            
            Employees
            
            
            223,000
            
            $
            1.18
            
            
            33.3%
                on 1st,
                2ndand 3rdanniversary of grant
            
            
            5
                YearsApr
                10, 2007
            
            
            Consultant
            
            
            25,000
            
            $
            1.64
            
            
            50%
                at Aug 31, 2007; 50% at Feb 29, 2008
            
            
            5
                YearsApr
                20, 2007
            
            
            Directors
            
            
            40,000
            
            $
            1.02
            
            
            20%
                on 1st,
                2nd,
                3rd,
                4thand 5thanniversary
                of grant
            
            
            10
                YearsAug
                27, 2007
            
            
            Officer
            
            
            450,000
            
            $
            0.45
            
            
            33.3%
                on 1st,
                2ndand 3rdanniversary of grant
            
            
            5
                YearsFeb
                2, 2008
            
            
            Employee
            
            
            15,000
            
            $
            0.39
            
            
            33.3%
                on 1st,
                2ndand 3rdanniversary of grant
            
            
            5
                Years





The
      options granted to officers and employees are 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.




18




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 and 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
      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, as
      summarized in the table above. 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.




Under
      the
      terms of the registration rights agreement, we were obligated to pay the holders
      of the registrable securities issued in December 21, 2006 private placement
      liquidated damages if the registration statement filed in conjunction with
      the
      private placement was not 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 each payment date is based on the payment amount
      of $794,000 divided by an amount that equals 90% of the volume weighted average
      price of our common stock for the 10 days immediately preceding the payment
      date. The table below summarize the shares issued pursuant to the terms of
      the
      registration rights agreement:




**Payment
                    Date**
                
                **90% of Volume**
                  **Weighted**
                  **Average Price for**
                  **10 Days**
                  **Preceding**
                  **Payment**
                
                **Shares Issued**
                
                **Closing Price at**
                  **Payment Date**
                
                **Value of Shares Issued**May
                    18, 2007
                
                $
                0.85
                
                
                933,458
                
                $
                1.04
                
                $
                970,797June
                    19, 2007
                
                $
                0.84
                
                
                946,819
                
                $
                0.88
                
                $
                833,201July
                    19, 2007
                
                $
                0.60
                
                
                1,321,799
                
                $
                0.66
                
                $
                872,387August
                    17, 2007
                
                $
                0.45
                
                
                1,757,212
                
                $
                0.41
                
                $
                720,457September
                    17, 2007
                
                $
                0.32
                
                
                2,467,484
                
                $
                0.34
                
                $
                838,945October
                    17, 2007
                
                $
                0.55
                
                
                1,443,712
                
                $
                0.57
                
                $
                822,915October
                    31, 2007
                
                $
                0.43
                
                
                861,085
                
                $
                0.47
                
                $
                404,7109,731,569
                
                
                
                
                $
                5,463,412





The
      foregoing transaction was made pursuant to Section 4(2) of the Securities
      Act.




On
      May
      31, 2007, we granted 100,000 shares of our common stock to Mark Worthey, a
      director, which 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.




19




Pursuant
      to a Board of Directors resolution adopted April 20, 2007, Directors may receive
      common stock in lieu of cash for Board Meeting Fees, Committee Fees and
      Committee Chairman Fees. The number of shares granted under the terms of the
      resolution were computed based upon the amount of fees due to the directors
      and
      the fair market value of our common stock on the date of issuance. The following
      table summarizes issuances of common stock pursuant to such
      resolution:




**Date
                  of Issue**
              
              **Number of Shares Issued**
              
              **Fair Market Value Per**
                **Share at Issue Date**Jun
                  30, 2007
              
              
              101,713
              
              $
              0.73Sep
                  30, 2007
              
              
              181,098
              
              $
              0.41Dec
                  31, 2007
              
              
              275,001
              
              $
              0.27Mar
                  31, 2008
              
              
              190,385
              
              $
              0.39





The
      foregoing transactions were made pursuant to Section 4(2) of the Securities
      Act.




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





Not
      applicable.





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




**Organization**




We
      are an
      independent energy company that explores for and develops, produces, and markets
      oil and gas in North America. We were known as Metalex Resources, Inc. until
      April 2006 when our name was changed to Rancher Energy Corp. We operate three
      oil fields in the Powder River Basin, Wyoming. Our business plan is to use
      CO 2 injection to increase oil production in these oil fields.




**Oil
      and Gas Property Acquisitions**




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




Cole
      Creek South Field and South Glenrock B Field Acquisitions




On
      December 22, 2006, we purchased certain oil and 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 and 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 and 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
                and 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




20





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 160 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 .




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
                and 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:





·
            Continue
                to seek long term financing or strategic partnering arrangements
                with
                experienced industry partners to repay the debt due in October 2008
                and to
                provide funding for a CO2pipeline and our EOR development plan for our three
                fields;


·
            Maintain
                and enhance crude oil production from our existing
                wells;


·
            Initiate
                development activities in our fields;
                and


·
            Pursue
                additional asset and project opportunities that are expected to be
                accretive to stockholder value.





In
      late
      2006 we added operating staff and engaged consultants to conduct field studies
      of tertiary development of the three Powder River Basin fields. Through the
      early part of 2008 work has focused on field and engineering studies to prepare
      for development operations. We 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. In February 2008, we executed a letter of intent with a potential
      industry partner the terms of which called for the partner to invest up to
      $83.5
      million to earn up to a 55% working interest in our three fields. This letter
      of
      intent expired in April 2008. We entered into a letter of intent in April 2008
      with two different industry partners under terms similar to the first letter
      of
      intent; however, this second letter of intent included provisions for one of
      the
      partners to build, own and operate a pipeline to transport CO 2 to our
      fields. We continue to negotiate the terms of a definitive agreement, but there
      is no assurance that we will be successful in these negotiations and in closing
      the transaction. In anticipation of finalizing an arrangement with industry
      partners, under which a partner would provide financing and operational control
      or our fields, we reduced our operating staff in late March 2008. Under the
      terms of the letter of intent, if the parties have not entered into a definitive
      agreement by June 30, 2008, either party may terminate the letter of intent
      upon
      ten days notice. If we are not successful in consummating a transaction with
      an
      industry partner, we will need to obtain other sources of financing. Our plans
      for EOR development of our oil fields are dependent on our obtaining substantial
      additional funding. In October 2007 we raised approximately $12.2 million in
      short-term debt financing to enhance production and provide cash reserves. While
      we
      had intended to raise a
      long-term debt financing in 2007
      to further our waterflood
      and CO 2 EOR
      plans, weakness in the capital market conditions contributed to our change
      in
      strategy to raise the short-term
      financing first,
      followed by either long-term
      debt financing ,
      or a
      strategic partnering arrangement with experienced industry partners. The raising
      of future 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.




21




If
      we are
      successful in raising long term debt financing we plan to begin CO 2 development operations in the South Glenrock B Field followed by the Big Muddy
      Field and then Cole Creek South Field. Capital expenditures to implement our
      CO 2 EOR plan
      include:




·
            Construct
                a pipeline to transport CO2from
                the source to our South Glenrock B Field at a cost of approximately
                $50 to
                $132 million;




·
            Acquire
                and construct surface facilities at our South Glenrock B Field to
                inject
                and recycle CO2at
                a cost of approximately $8.5 million;




·
            Drill,
                complete and equip 70-80 wells as CO2injectors or oil producers on our South Glenrock B Field at a cost
                of
                approximately $48 million;




·
            Drill,
                complete and equip 70 wells as water injectors or oil producers on
                our Big
                Muddy Field at a cost of approximately $46 million;
                and




·
            Acquire
                and construct waterflood surface facilities, at a cost of approximately
                $11.5 million.




If
      we are
      successful closing a strategic partnering arrangement with experienced industry
      partners, we anticipate those partners would be responsible for financial and
      operational control of pipeline construction and field development for up to
      three years, after which we would again be responsible for our share of future
      development expenditures.




Since
      the
      acquisition of the three fields, other than the agreements with Anadarko and
      ExxonMobil for supply of CO 2 ,
      we have
      made no major capital expenditures nor any firm commitments for future capital
      expenditures to date.




**Commitments**




Anadarko
      CO2Supply
      Agreement




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. Carbon dioxide (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 .




22


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%.




ExxonMobil
      CO2Supply
      Agreement




On
      February 12, 2008 we entered into a Carbon Dioxide Sale and Purchase Agreement
      with ExxonMobil Gas & Power Marketing Company, a division of ExxonMobil
      Corporation, which is to provide us with 70 MMscfd (million standard cubic
      feet
      per day) of CO 2 for an
      initial 10-year period. We intend to use the CO 2 for
      our
      EOR projects. The primary term of the agreement, which is ten years, will begin
      the first day of the month following ExxonMobil’s notice to us of the completion
      of the expansion of certain CO 2 delivery
      facilities by ExxonMobil and that it is prepared to deliver the required daily
      quantity as required under the agreement. Either party may extend the agreement
      for an additional ten year term following proper notice and agreement to certain
      applicable terms of the agreement. Following the commencement of the primary
      term, ExxonMobil is obligated to deliver to us at least 70 MMscfd of
      CO 2 per day.
      We have agreed to a “take-or-pay” provision under the agreement. For
      CO 2 deliveries from ExxonMobil, we have agreed to pay a base price plus an Oil
      Price
      Factor which is indexed to the price of West Texas Intermediate crude
      oil.





We
      may
      terminate the agreement if ExxonMobil fails to meet the Company’s quantity
      nomination of CO 2 (not to
      exceed 70 MMscfd per day) for 30 consecutive days except under certain
      circumstances. Either party has the right to terminate the agreement at any
      time
      with notice to the other party based on certain circumstances described in
      the
      agreement. ExxonMobil is not obligated to commence delivery of CO 2 until we
      provide a surety bond equal to four months’ supply of CO 2 .
      ExxonMobil may also request additional financial performance assurances if
      it
      has reasonable grounds for believing that we have ceased to have the financial
      resources to meet our obligations under the agreement and ExxonMobil may suspend
      delivery of CO 2 until
      the
      appropriate assurances are provided. ExxonMobil may terminate the agreement
      if a
      requested performance assurance is not provided by us within 30 days of a
      request.





Under
      the
      terms of the agreement, ExxonMobil is responsible for paying all taxes and
      royalties up to the delivery point except that we are obligated to reimburse
      ExxonMobil for 100% of any new, increased, or additional taxes or royalties
      incurred up to the delivery point. The CO 2 is to be
      supplied from ExxonMobil’s LaBarge gas field in Wyoming.




Initially,
      the source of funds to fulfill our commitment to purchase CO 2 from
      Anadarko and ExxonMobil will be either the long term debt financing or our
      strategic partner. As crude oil production from the fields into which
      CO 2 is
      injected increases, we anticipate utilizing a portion of the proceeds from
      the
      sale of such crude oil to pay for the CO 2 .




**R** **esults
      of Operations, Including Combined Results**




In
      addition to the GAAP presentation of Rancher Energy Corp.’s historical results
      for the years ended March 31, 2008 and 2007, we have provided combined revenues,
      production taxes and lease operating expenses for Rancher Energy Corp., its
      Predecessor (the Cole Creek South Field and the South Glenrock B Field) and
      its
      Predecessor’s Predecessor (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, 2008 and
                2007;




·
            Our
                Predecessor’s 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.);




·
            Adjustments
                to eliminate the Predecessor’s revenues, production taxes and lease
                operating expenses for the three months ended March 31, 2006 from
                the
                Predecessor revenues, production taxes and lease operating expenses
                for
                the year ended December 31, 2006, so that the combined information
                reflects the revenues, production taxes and lease operating expenses
                for
                the fiscal year ended March 31, 2007;
                and




·
            Combined
                revenues, production taxes and lease operating expenses for the years
                ended March 31, 2008 and 2007.




23




**Year
      Ended March 31, 2008**




**Rancher
      Energy Corp.**




Revenue:Oil
                production (in barrels)
            
            
            86,626Oil
                price (per barrel)
            
            $
            73.24Oil
                and gas sales
            
            $
            6,344,414Derivative
                losses
            
            
            (956,142
            )5,388,272Operating
                expenses:Production
                taxes
            
            
            772,010Lease
                operating expenses
            
            
            2,906,210Depreciation,
                depletion, and amortization
            
            
            1,360,737Impairment
                of unproved properties
            
            
            -Accretion
                expense
            
            
            121,740Exploration
                expense
            
            
            223,564General
                and administrative
            
            
            7,538,242Total
                operating expenses
            
            
            12,922,503(7,534,231
            )Other
                income (expense):Liquidated
                damages pursuant to registration rights agreement
            
            
            (2,645,393
            )Interest
                expense
            
            
            (794,693
            )Amortization
                of deferred financing costs
            
            
            (2,423,389
            )Interest
                and other income
            
            
            232,880Total
                other income (expense)
            
            
            (5,630,595
            )$
            (13,164,826
            )




**Year
                Ended March 31, 2007 (Unaudited)****Rancher
                Energy Corp.**
            
            **Predecessor**
            
            **Adjustments**
            
            **Combined**Revenue:Oil
                production (in barrels)
            
            
            23,838
            
            
            73,076
            
            
            (18,631
            )
            
            78,283Oil
                price (per barrel)
            
            
            48.74
            
            
            61.42
            
            
            61.66
            
            
            57.50Oil
                and 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
            
            
            668,457
            
            
            2,944,287
            
            
            (574,756
            )
            
            3,037,988Depreciation,
                depletion, and amortization
            
            
            375,701
            
            
            952,784Impairment
                of unproved properties
            
            
            734,383
            
            
            -Accretion
                expense
            
            
            29,730
            
            
            107,504Exploration
                expense
            
            
            333,919
            
            
            -General
                and administrative
            
            
            4,512,427
            
            
            567,524Total
                operating expenses
            
            
            6,790,922
            
            
            5,066,055(5,629,103
            )
            
            (577,740
            )Other
                income (expense):Liquidated
                damages pursuant to registration rights agreement
            
            
            (2,705,531
            )
            
            -Interest
                expense
            
            
            (37,647
            )
            
            -Amortization
                of deferred financing costs
            
            
            (537,822
            )
            
            -Interest
                and other income
            
            
            207,848
            
            
            -Total
                other income (expense)
            
            
            (3,073,152
            )
            
            -$
            (8,702,255
            )
            $
            (577,740
            )




24




**Adjustments:**




Revenue,
      production taxes, and lease operating expenses — represents
      oil
      production volumes, oil sales, production taxes, and lease operating expenses
      for the three months ended March 31, 2006 to derive combined oil production
      volumes, oil sales, production taxes, and lease operating expenses for the
      year
      ended March 31, 2007.




**Rancher
      Energy Corp.**




*Year
      Ended March 31, 2008 Compared to Year Ended March 31, 2007*




*Overview* .
      For the
      year ended March 31, 2008, we reflected a net loss of $13,164,826, or $(0.12)
      per basic and fully diluted share, as compared to a loss of $8,702,255, or
      $(0.16) per basic and fully diluted share, for the corresponding year ended
      March 31, 2007. Fiscal 2008 reflected our first full year as an oil and gas
      operating entity, following our acquisition of the three Powder River Basin
      Fields. As a result, crude oil production volumes and nearly all items of
      revenue and expense reflect significant increases in 2008 as compared to 2007.




*Revenue,
      production taxes, and lease operating expenses* .
      For the
      year ended March 31, 2008, we recorded crude oil sales of $6,344,414 on 86,626
      barrels of oil at an average price of $73.24, as compared to revenues of
      $1,161,819 on 23,838 barrels of oil at an average price of $48.74 per barrel
      in
      2007. The year-to-year variance reflects a volume variance of $4,591,172 and
      a
      price variance of $591,423. The increased volume in 2008 reflects the fact
      we
      owned the three fields the entire year as compared to only three months of
      ownership in 2007. Production taxes (including ad valorem taxes) of $772,010
      in
      2008 as compared to $136,305 in 2007, remained constant at 12% of crude oil
      sales revenues. Lease operating expenses increased to $2,906,210
      ($33.55/bbl) in 2008 as compared to $668,457 ($28.06/bbl) principally reflecting
      the fact we owned and operated the three fields for the entire year in 2008
      as
      compared to 3 months in 2007. The per barrel increase in 2008 compared to 2007
      reflects the significant level of repair and maintenance work carried out on
      wells in the three fields to maintain and increase production
      levels.




*Depreciation,
      depletion, and amortization* .
      Depreciation, depletion, and amortization increased (DD&A) to $1,360,737 in
      2008 as compared to $375,701 in 2007. In 2008 DD&A is comprised of
      $1,183,798 of DD&A of oil and gas properties ($13.66/ bbl) and depreciation
      of furniture and fixtures of $176,939. Corresponding amounts for 2007 were
      $347,821 of DD&A of oil and gas properties ($14.60/ bbl) and depreciation of
      furniture and fixtures of $27,880.




*Impairment
      of unproved properties* .
      No
      impairment of unproved properties was recorded for the year ended March 31,
      2008. In year ended March 31, 2007, we recorded impairment of unproved
      properties of $734,383, reflecting our determination to not develop certain
      properties and the carrying value would not be realized.




*Exploration
      expense* .
      For the
      year ended March 31, 2008, we reflected exploration expense of $223,564 as
      compared to $333,919 for the year ended March 31, 2007. Exploration expenses
      were for geological and geophysical analysis of certain projects, all of which
      we elected not to pursue. The decrease in 2008 reflects our decision to focus
      resources on the development of the three fields we acquired in December 2006
      and January 2007.




*General
      and administrative expense* .
      For the
      year ended March 31, 2008 we reflected general and administrative expenses
      of
      $7,538,242 as compared to $4,512,427 for the corresponding year ended March
      31,
      2007. Significant components of the year-to-year variance include:




·
            salaries
                and benefits - increase of $2,615,000 reflecting significantly higher
                staff count (274 worker months in 2008 compared to 62 worker months
                in
                2007);




25






·
            accounting
                and financial reporting consultants – increase of $316,000 reflecting
                expenses associated with filing of Form 10-K and three amendments
                thereto;
                filing of four amendments to our Form S-1 registration statement,
                along
                with the filing of three Forms 10-Q, and numerous Forms 8-K, as well
                expenses associated with Sarbanes-Oxley compliance
                efforts;




·
            audit
                fees – increase of $225,000 reflecting costs of auditing of a much larger
                company following the property acquisitions in December 2006 and
                January
                2007, costs associated with the audit of the Company’s internal control
                over financial reporting and the costs associated with predecessor
                and
                pre-predecessor audits.




·
            office
                rent – increase of $243,000, reflecting a relocation of our corporate
                headquarters to larger office space in August
                2007.




*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 was
      not
      declared effective by May 20, 2007 and additional payments are due if there
      are
      additional delays in obtaining effectiveness. The registration statement was
      declared effective on October 31, 2007. Prior to that we paid liquidated damages
      of $2,645,393 and $2,705,531 for the years ended March 31, 2008 and 2007
      respectively, by issuing a total of 9,731,569 shares of our common
      stock.




*Amortization
      of deferred financing costs* .
      For the
      year ended March 31, 2008, we reflected amortization of deferred financing
      costs
      of $2,423,389 as compared to $537,822 for the corresponding year ended March
      31,
      2007. The year-to-year increase reflects amortization of costs incurred with
      the
      issuance of short term debt in October 2007 ($326,685), amortization of the
      discount on the note payable associated with the overriding royalty interest
      assigned to the lender ($1,972,450). The 2007 amount reflects the amortization
      of financing costs incurred in connection with the private placement of
      convertible notes payable issued in the 2007 period.




*Interest
      expense.* For
      the
      year ended March 31, 2008 we reflected interest expense of $794,693 as compared
      to $37,647 reflected in the comparable period of 2007. The 2008 amount was
      comprised of interest paid on the October 2007 short term financing of $682,000
      and $112,600 of imputed interest on liquidated damages relating to the
      Registration Rights A greement
      as discussed above. The 2007 amount includes $30,000 of imputed interest on
      the
      registration rights payments and $7,647 of other interest expense.




*Interest
      income* .
      For the
      year ended March 31, 2008, we reflected interest income of $232,880 as compared
      to $207,848 for the corresponding year ended March 31, 2007. 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.




The
      following provides explanations of changes in revenues, production taxes and
      lease operating expenses on a combined basis.




**Rancher
      Energy Corp. Combined With Predecessor**




*Year
      Ended March 31, 2008 Compared to Year Ended March 31, 2007*




*Revenue,
      production taxes, and lease operating expenses* .
      For the
      year ended March 31, 2008 (2008), oil and gas sales were $6,344,414 on 86,626
      barrels of oil at $73.24 per barrel, as compared to $4,501,309 on 78,283 barrels
      of oil at $57.50 per barrel, for the year ended March 31, 2007 (2007). The
      year-to-year increase in sales of $1,843,105 reflects a price variance of
      $1,363,379 and a volume variance of $479,726. The increased volumes in 2008
      resulted from our efforts to minimize well downtime by monitoring each well
      on a
      daily basis to maintain each at its maximum operating capacity. Production
      taxes
      (including ad valorem taxes) of $772,010 in 2008 as compared to $509,948 in
      2007, remained constant at approximately 12% of crude oil sales revenues. Lease
      operating expenses decreased in 2008 to $2,906,210 or $33.55 per barrel, as
      compared to $3,037,988, or $39.22 per barrel, in 2007. This year-to-year
      decrease of $131,778, is comprised of $323,773 of volume variance and $(455,550)
      of cost variance. The cost variance primarily reflects the costs associated
      with
      workovers, restimulation and repairs carried out the by the Predecessor in
      2007
      whereas we minimized such operations while focusing on day-to-day operational
      efficiencies to maintain and increase production levels..




**Liquidity
      and Capital Resources**




Going
      Concern




The
      report of our independent registered public accounting firm on the financial
      statements for the year ended March 31, 2008 includes an explanatory paragraph
      relating to the uncertainty of our ability to continue as a going concern.
      We
      have incurred a cumulative net loss of $22.4 million for the period from
      inception (February 4, 2004) to March 31, 2008 and have a working capital
      deficit of approximately $5.0 million as of March 31, 2007 and have short
      term debt in the amount of $12.2 million scheduled to mature on October 31,
      2008. We require significant additional funding to repay the short term debt
      and
      sustain our operations for our planned EOR operations. Our ability to establish
      the Company as a going concern is dependent upon our ability to obtain
      additional funding in order to pay our short term debt and finance our planned
      operations .


26





As
      of
      March 31, 2008, we had a working capital deficit of $4,991,812.




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.




In
      October 2007, we issued $12,240,000 of short term debt the proceeds of which
      were intended to enhance our existing production and to provide cash reserves
      for operations. The
      debt
      matures in October 2008 and as part of the loan, we granted to the lender a
      mortgage on our interests in three fields and our other assets. We
      had
      planned to secure longer term fixed rate financing to repay the short term
      debt
      and to commence our EOR development activities in the three fields of the Powder
      River Basin; however due to difficulties in the capital debt markets, we have
      been unable to secure such financing. We
      do not
      have cash available to repay this loan. We plan to refinance this loan and
      borrow additional funds to pursue our business strategy. If we are not
      successful in repaying this debt within the term of the loan, or default under
      the terms of the loan, the lender will be able to foreclose one or more of
      our
      three properties and other assets and we could lose the properties. A
      foreclosure could significantly reduce or eliminate our property interests,
      force us to alter our business strategy, which could involve the sale of
      properties or working interests in the properties and adversely affect our
      results of operations and financial condition.




In
      April
      2008 we entered into a letter of intent with two perspective industry partners
      for them to invest up to $83.5 million (including $12.2 million up front to
      retire our short term debt), and to earn up to 55% working interest in our
      fields. It also calls for them to build, own and operate a 132 mile
      CO 2 pipeline
      to deliver CO 2 to
      our
      fields. We are continuing negotiations with them but there is no assurance
      that
      we will be successful in closing the transaction. Under the terms of the letter
      of intent, if the parties have not entered into a definitive agreement by June
      30, 2008, either party may terminate the letter of intent upon ten days notice.
      If we are not successful in consummating this transaction, we will need to
      make
      other financing arrangements to carry out our EOR business strategy.




Management
      believes the proposed transaction is an indication of the viability of our
      EOR
      projects and our ability to generate additional capital to meet our obligations
      and to commence our EOR projects during the next year. If we are not successful
      in closing the transaction discussed above or in raising capital through other
      means, we may sell assets to meet our obligations. If we are forced to sell
      assets to meet our obligations we may not realize the full market value of
      the
      assets and the sales price could be less than our carrying value of the
      assets.




Beginning
      in March 2008, we began to reduce our level of staffing by laying off several
      employees whose positions were considered to be redundant based upon the
      anticipated closing of a farmout transaction with experienced industry
      operators. Following these staff reductions and other cost-cutting measures
      in
      both the field and in our corporate headquarters, our monthly oil and gas
      production revenue should be adequate to cover expected monthly field operating
      costs, production taxes and general and administrative expenses; however, the
      monthly interest payments required on the short term debt and payments relating
      to our crude oil hedging position currently result in negative cash flow each
      month.




Change
      in Financial Condition




In
      October 2007 we issued short term debt in the amount of $12.24 million the
      proceeds of which were intended to enhance our existing production and to
      provide cash reserves for operations. The debt bears interest at 12% per annum
      and is scheduled to mature on October 31, 2008.




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 year 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.




27




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 to
      the Notes to Financial Statements of our audited financial statements for the
      fiscal year ended March 31, 2008 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.




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.




28




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.
      In fiscal year 2008 we paid liquidated damages in the form of shares of our
      common stock pursuant to the Registration Rights Agreement relating to these
      registration provisions and other obligations, as described in Item 5 of this
      Annual Report and in Note 6 to the Notes to Financial Statements of our audited
      financial statements for the fiscal year ended March 31, 2008 in Part IV, Item
      15, of this Annual Report.




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, 2008.




**Warrants**
            
            **Exercise
                Price**
            
            **Expiration
                Date**Warrants
                issued in connection with the following:Sale
                of common stock pursuant to Regulation S
            
            
            18,133,500
            
            $
            0.75
            
            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 and gas properties
            
            
            250,000
            
            $
            1.50
            
            December
                22, 2011Total
                warrants outstanding at March 31, 2008
            
            
            75,960,550




Cash
      Flows




The
      following is a summary of our comparative cash flows:




For the Years Ended March 31,2008
              
              2007Cash
                  flows from (used by):Operating
                  activities
              
              $
              (4,586,423
              )
              $
              (2,285,430
              )Investing
                  activities
              
              
              (4,681,280
              )
              
              (74,357,306
              )Financing
                  activities
              
              
              10,980,185
              
              
              81,726,538





Analysis
      of cash flow changes between 2008 and 2007




Cash
      flows used for operating activities increased primarily as a result of increased
      general and administrative expenses reflecting staffing increases to ready
      the
      fields for EOR activities, office rent, audit, accounting and other consulting
      fees associated with SEC filings and increase level of operational
      activity




Cash
      flows used for investing activities in 2008 reflect expenditures on oil and
      gas
      assets to enhance production and preliminary studies and engineering relating
      to
      the planned CO 2 pipeline
      of $4,245,011 and $927,769 of other equipment and deposits. In addition we
      received $491,500 of proceeds upon the disposition of idle oil field equipment
      in the year. Cash flows used for investing activities in 2007 reflect
      $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 and gas property capital
      expenditures and $769,018 for other equipment.




29




Cash
      flows provided by financing activities in 2008, $10,980,185, reflect net
      proceeds after finance and offering costs of the short term debt issuance in
      October 2007. Cash flows provided by financing activities reflect 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 and gas property acquisition, exploration and development
      activities, whether capitalized or expensed.




For the Year Ended March 31,2008
              
              2007Exploration
              
              $
              223,564
              
              $
              333,919Development
              
              
              4,758,783
              
              
              -Acquisitions:Unproved
              
              
              43,088
              
              
              56,813,516Proved
              
              
              -
              
              
              18,552,188Total
              
              
              5,025,435
              
              
              75,699,623Capitalized
                  costs associated with asset retirement obligations
              
              $
              213,756
              
              $
              1,191,837




Off-Balance
      Sheet Arrangements




Under
      the
      terms of the Term Credit Agreement entered into in October 2007 we were required
      hedge a portion of our expected production and we entered into a costless collar
      agreement for a portion of our anticipated future crude oil production. The
      costless collar contains a fixed floor price (put) and ceiling price
      (call). If the index price exceeds the call strike price or falls below the
      put
      strike price, we receive the fixed price and pay the market price. If the market
      price is between the call and the put strike price, no payments are due from
      either party. During the year ended March 31, 2008 we reflected realized losses
      of $184,535 and unrecognized losses of $771,607 from the hedging activity.





We
      have
      no other 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 9—Disclosures About Oil and Gas
      Producing Activities to the Notes to Financial Statements of our audited
      financial statements for the fiscal year ended March 31, 2008 in Part IV, Item
      15, of this Annual Report.




30




*Oil
      and 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 and gas assets.
      Proved oil and 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 and 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 and 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
      and 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 and gas prices and operating and capital
      costs change. We evaluate and estimate our oil and 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.




*Successful
      efforts method of accounting.*Generally accepted accounting principles provide for two alternative methods
      for
      the oil and gas industry to use in accounting for oil and 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
      and
      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, 2008 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
      analysis 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 and gas properties. We base our estimate of the
      liability on our historical experience in abandoning oil and 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 and 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.




31




*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 SFASNo.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




*Commodity
      Derivatives* .   The
      Company accounts for derivative instruments or hedging activities under the
      provisions of Statement of Financial Accounting Standards (“SFAS”) No.133,
“Accounting for Derivative Instruments and Hedging Activities”. SFASNo.133
      requires the Company to record derivative instruments at their fair value.
      The
      Company’s risk management strategy is to enter into commodity derivatives that
      set “price floors” and “price ceilings” for its crude oil production. The
      objective is to reduce the Company’s exposure to commodity price risk associated
      with expected crude oil production.




The
      Company has elected not to designate the commodity derivatives to which they
      are
      a party as cash flow hedges, and accordingly, such contracts are recorded at
      fair value on its consolidated balance sheets and changes in such fair value
      are
      recognized in current earnings as income or expense as they occur.




The
      Company does not hold or issue commodity derivatives for speculative or trading
      purposes. The Company is exposed to credit losses in the event of nonperformance
      by the counterparty to its commodity derivatives. It is anticipated, however,
      that its counterparty will be able to fully satisfy its obligations under the
      commodity derivatives contracts. The Company does not obtain collateral or
      other
      security to support its commodity derivatives contracts subject to credit risk
      but does monitor the credit standing of the counterparty. The
      price
      we receive for production in our three fields is indexed to Wyoming Sweet crude
      oil posted price. The
      Company has not hedged the basis differential between the NYMEX price and the
      Wyoming Sweet price.




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




**Commodity
      Price Risk**




Because
      of our relatively low level of current oil and 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 and 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. Under the terms of our Term Credit
      Agreement we entered into in October 2007, we were required hedge a portion
      of
      our expected future production.




**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 the fiscal
      years ended March 31, 2005 and March 31, 2006 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.


32




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 fiscal years ended March 31, 2005 and March 31, 2006 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. previously reviewed the above disclosures that were
      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(T).**
            **CONTROLS
                AND PROCEDURES**





**Controls
      and Procedures.**





We
      conducted an evaluation under the supervision and with the participation of
      our
      management, including our Chief Executive Officer and Chief Accounting Officer,
      of the effectiveness of the design and operation of our disclosure controls
      and
      procedures. The term “disclosure controls and procedures,” as defined in Rules
      13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended
      (Exchange Act), means controls and other procedures of a company that are
      designed to ensure that information required to be disclosed by the company
      in
      the reports it files or submits under the Exchange Act is recorded, processed,
      summarized and reported, within the time periods specified in the Securities
      and
      Exchange Commission’s rules and forms. Disclosure controls and procedures also
      include, without limitation, controls and procedures designed to ensure that
      information required to be disclosed by a company in the reports that it files
      or submits under the Exchange Act is accumulated and communicated to the
      company’s management, including its principal executive and principal financial
      officers, or persons performing similar functions, as appropriate to allow
      timely decisions regarding required disclosure. We identified a material
      weakness in our internal control over financial reporting and, as a result
      of
      this material weakness, we concluded as of March 31, 2008 that our disclosure
      controls and procedures were not effective.





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





Our
      management is responsible for establishing and maintaining adequate internal
      control over financial reporting. Internal control over financial reporting
      (as
      defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) is defined as a process
      designed by, or under the supervision of, a company’s principal executive and
      financial officers, or persons performing similar functions, and effected by
      a
      company’s board of directors, management and other personnel, to provide
      reasonable assurance regarding the reliability of financial reporting and the
      preparation of financial statements for external reporting purposes in
      accordance with generally acceptable accounting principles and includes those
      policies and procedures that:





a)
            pertain
                to the maintenance of records that, in reasonable detail, accurately
                and
                fairly reflect the transactions and dispositions of the assets of
                the
                company;


b)
            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


c)
            provide
                reasonable assurance regarding prevention or timely detection of
                unauthorized acquisition, use or disposition of the company’s assets that
                could have a material effect on the financial
                statements.





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


33





Management
      assessed the effectiveness of the Company’s internal control over financial
      reporting as of March 31, 2008. In making this assessment, management used
      the
      criteria set forth by the Committee of Sponsoring Organizations of the Treadway
      Commission (COSO) in *Internal
      Control-Integrated Framework.*





A
      material weakness is a control deficiency, or combination of control
      deficiencies, that result in more than a remote likelihood that a material
      misstatement of annual or interim financial statements will not be prevented
      or
      detected. As of March 31, 2008, the Company identified the following material
      weakness:





*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.*





We
      have
      limited accounting personnel with sufficient expertise in generally accepted
      accounting principles to enable effective segregation of duties with respect
      to
      recording journal entries and to allow for appropriate monitoring of financial
      reporting matters and internal control over financial reporting. Specifically,
      the Chief Accounting Officer has involvement in the creation and review of
      journal entries and note disclosures without adequate independent review and
      authorization. This control deficiency is pervasive in nature and impacts all
      significant accounts. This control deficiency also affects the financial
      reporting process including financial statement preparation and the related
      note
      disclosures.




As
      a
      result of the aforementioned material weakness, management concluded that the
      Company’s internal control over financial reporting as of March 31, 2008 was not
      effective.





**Management’s
      Corrective Actions**





In
      relation to the material weakness identified above, and subject to obtaining
      permanent financing, our management and the board of directors intend to work
      to
      remediate the risk of a material misstatement in financial reporting. We intend
      to implement the following plan to address the risk of a material misstatement
      in the financial statements:





·
            Engage
                qualified third-party accountants and consultants to assist us in
                the
                preparation and review of our financial
                information,





·
            Ensure
                employees, third-party accountants and consultants who are performing
                controls understand responsibilities and how to perform said
                responsibilities, and





·
            Consult
                with qualified third-party accountants and consultants on the appropriate
                application of generally accepted accounting principles for complex
                and
                non-routine transactions.





**Auditors
      Attestation**





This
      annual report does not include an attestation report of the Company’s registered
      public accounting firm regarding internal control over financial reporting.
      Management’s report was not subject to attestation by the Company’s registered
      public accounting firm pursuant to temporary rules of the Securities and
      Exchange Commission that permit the Company to provide only management’s report
      in this annual report.





**Changes
      in Internal Control over Financial Reporting**




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





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




None.




**PART
      III**




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




Information
      required by this Item with respect to the Company’s directors, executive
      officers, certain family relationships, and compliance by the Company’s
      directors, executive officers and certain beneficial owners of the Company’s
      common stock with Section 16(a) of the Exchange Act is incorporated by
      reference to all information under the captions entitled “Directors, Officers
      and Corporate Governance” and “Compliance with Section 16(a) of the Securities
      Act of 1934” from our Proxy Statement relating to our 2008 Annual Meeting of
      Stockholders (“Proxy Statement”).




34




The
      information regarding our Audit Committee, including our audit committee
      financial expert, and our director nomination process is incorporated herein
      by
      reference to all information under the caption entitled “Audit Committee”
included in our Proxy Statement.




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 Accounting Officer, Rancher Energy Corp.,
      999-18th Street, Suite 3400, Denver, Colorado 80202.




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




The
      information required by Item 11 is hereby incorporated herein by reference
      to
      the information under the caption “Executive Compensation” included in the Proxy
      Statement.




**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 information under the caption
      “Security Ownership of Directors and Executive Officers” included in the Proxy
      Statement.




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




The
      information required by Item 13 is hereby incorporated herein by reference
      to
      the information under the caption “Certain Relationships and Related
      Transactions” and “Director Independence” included in 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 information under “Proposal #2 - Ratification of the Appointment of
      Independent Registered Accountant” included in the Proxy Statement.




**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(1)3.2
            
            Articles
                of Correction(2)3.3
            
            Amended
                and Restated Bylaws(3)4.1
            
            Form
                of Stock Certificate for Fully Paid, Non-Assessable Common Stock
                of the
                Company(4)4.2
            
            Form
                of Unit Purchase Agreement(3)4.3
            
            Form
                of Warrant Certificate(3)




35





**Exhibit**
            
            **Description**4.4
            
            Form
                of Registration Rights Agreement, dated December 21, 2006(5)4.5
            
            Form
                of Warrant to Purchase Common Stock(5)10.1
            
            Burke
                Ranch Unit Purchase and Participation Agreement between Hot Springs
                Resources Ltd. and PIN Petroleum Partners Ltd., dated February 6,
                2006(6)10.2
            
            Employment
                Agreement between John Works and Rancher Energy Corp., dated June 1,
                2006(7)10.3
            
            Assignment
                Agreement between PIN Petroleum Partners Ltd. and Rancher Energy
                Corp.,
                dated June 6, 2006(7)10.4
            
            Loan
                Agreement between Enerex Capital Corp. and Rancher Energy Corp.,
                dated
                June 6, 2006(7)10.5
            
            Letter
                Agreement between NITEC LLC and Rancher Energy Corp., dated June 7,
                2006(7)10.6
            
            Loan
                Agreement between Venture Capital First LLC and Rancher Energy Corp.,
                dated June 9, 2006(8)10.7
            
            Exploration
                and Development Agreement between Big Snowy Resources, LP and Rancher
                Energy Corp., dated June 15, 2006(7)10.8
            
            Assignment
                Agreement between PIN Petroleum Partners Ltd. and Rancher Energy
                Corp.,
                dated June 21, 2006(7)10.9
            
            Purchase
                and Sale Agreement between Wyoming Mineral Exploration, LLC and Rancher
                Energy Corp., dated August 10, 2006(6)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(9)10.11
            
            Rancher
                Energy Corp. 2006 Stock Incentive Plan(9)10.12
            
            Rancher
                Energy Corp. 2006 Stock Incentive Plan Form of Option Agreement(9)10.13
            
            Denver
                Place Office Lease between Rancher Energy Corp. and Denver Place
                Associates Limited Partnership, dated October 30, 2006(10)10.14
            
            Finder’s
                Fee Agreement between Falcon Capital and Rancher Energy Corp.(11)10.15
            
            Amendment
                to Purchase and Sale Agreement between Wyoming Mineral Exploration,
                LLC
                and Rancher Energy Corp.(12)10.16
            
            Letter
                Agreement between Certain Unit Holders and Rancher Energy Corp.,
                dated
                December 8, 2006(3)10.17
            
            Letter
                Agreement between Certain Option Holders and Rancher Energy Corp.,
                dated
                December 13, 2006(3)10.18
            
            Product
                Sale and Purchase Contract by and between Rancher Energy Corp. and
                the
                Anadarko Petroleum Corporation, dated December 15, 2006(13)10.19
            
            Amendment
                to Purchase and Sale Agreement between Nielson & Associates, Inc. and
                Rancher Energy Corp.(14)10.18
            
            Securities
                Purchase Agreement by and among Rancher Energy Corp. and the Buyers
                identified therein, dated December 21, 2006(5)10.19
            
            Lock-Up
                Agreement between Rancher Energy Corp. and Stockholders identified
                therein, dated December 21, 2006(5)10.20
            
            Voting
                Agreement between Rancher Energy Corp. and Stockholders identified
                therein, dated as of December 13, 2006(5)10.21
            
            Form
                of Convertible Note(15)10.22
            
            Employment
                Agreement between Daniel Foley and Rancher Energy Corp., dated
                January 12, 2007(16)10.23
            
            First
                Amendment to Securities Purchase Agreement by and among Rancher Energy
                Corp. and the Buyers identified therein, dated as of January 18, 2007(17)10.24
            
            Rancher
                Energy Corp. 2006 Stock Incentive Plan Form of Restricted Stock Agreement(18)10.25
            
            First
                Amendment to Employment Agreement by and between John Works and Rancher
                Energy Corp., dated March 14, 2007(19)10.26
            
            Employment
                Agreement between Richard Kurtenbach and Rancher Energy Corp., dated
                August 3, 2007(20)10.27
            
            Term
                Credit Agreement between Rancher Energy Corp. and GasRock Capital
                LLC,
                dated as of October 16, 2007(21)10.28
            
            Term
                Note made by Rancher Energy Corp. in favor of GasRock Capital LLC,
                dated
                October 16, 2007(21)10.29
            
            Mortgage,
                Security Agreement, Financing Statement and Assignment of Production
                and
                Revenues from Rancher Energy Corp. to GasRock Capital LLC, dated
                as of
                October 16, 2007(22)10.30
            
            Security
                Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated
                as
                of October 16, 2007(21)10.31
            
            Conveyance
                of Overriding Royalty Interest by Rancher Energy Corp. in favor of
                GasRock
                Capital LLC, dated as of October 16, 2007(21)10.32
            
            ISDA
                Master Agreement between Rancher Energy Corp. and BP Corporation
                North
                America Inc., dated as of October 16, 2007(21)10.33
            
            Restricted
                Account and Securities Account Control Agreement by and among Rancher
                Energy Corp., GasRock Capital LLC, and Wells Fargo Bank, National
                Association, dated as of October 16, 2007(21)10.34
            
            Intercreditor
                Agreement by and among Rancher Energy Corp., GasRock Capital LLC,
                and BP
                Corporation North America Inc., dated as of October 16, 2007(21)10.35
            
            First
                Amendment to Denver Place Office lease between Rancher Energy Corp.
                and
                Denver Place Associates Limited Partnership, dated March 6, 2007(19)10.36
            
            Carbon
                Dioxide Sale & Purchase Agreement between Rancher Energy Corp. and
                ExxonMobil Gas & Power Marketing Company, dated effective as of
                February 1, 2008 (Certain portions of this agreement have been redacted
                and have been filed separately with the Securities and Exchange Commission
                pursuant to a Confidential Treatment Request).(22)23.1
            
            Consent of
              Ryder Scott
              Company, L.P., Independent Petroleum
              Engineers.*




36





**Exhibit**
            
            **Description**31.1
            
            Certification
                Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Executive
                Officer)*31.2
            
            Certification
                Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Accounting
                Officer)*32.1
            
            Certification
                pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
                906 of
                the Sarbanes-Oxley Act of 2002*32.2
            
            Certification
                pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
                906 of
                the Sarbanes-Oxley Act of 2002*


*
      Filed
      herewith.




(1)
            Incorporated
                by reference from our Current Report on Form 8-K filed on April 3,
                2007.(2)
            Incorporated
                by reference from our Form 10-Q for the quarterly period ended September
                30, 2007.




(3)
            Incorporated
                by reference from our Current Report on Form 8-K filed on
                December 18, 2006.




(4)
            Incorporated
                by reference from our Form SB-2 Registration Statement filed on
                June 9, 2004.(5)
            Incorporated
                by reference from our Current Report on Form 8-K filed on
                December 27, 2006.





(6)
            Incorporated
                by reference from our Quarterly Report on Form 10-Q/A filed on
                August 28, 2006.




(7)
            Incorporated
                by reference from our Annual Report on Form 10-K filed on June 30,
                2006.




(8)
            Incorporated
                by reference from our Current Report on Form 8-K filed on June 21,
                2006.




(9)
            Incorporated
                by reference from our Current Report on Form 8-K filed on October 6,
                2006.




(10)
            Incorporated
                by reference from our Current Report on Form 8-K filed on November 9,
                2006.(11)
            Incorporated
                by reference from our Current Report on Form 8-K/A filed on
                November 14, 2006.(12)
            Incorporated
                by reference from our Current Report on Form 8-K filed on December 4,
                2006.(13)
            Incorporated
                by reference from our Current Report on Form 8-K filed on
                December 22, 2006.(14)
            Incorporated
                by reference from our Current Report on Form 8-K filed on
                December 27, 2006.(15)
            Incorporated
                by reference from our Current Report on Form 8-K filed on January 8,
                2007.(16)
            Incorporated
                by reference from our Current Report on Form 8-K filed on January 16,
                2007.(17)
            Incorporated
                by reference from our Current Report on Form 8-K filed on January 25,
                2007.(18)
            Incorporated
                by reference from our Annual Report on Form 10-K filed on June 29,
                2007.(19)
            Incorporated
                by reference from our Current Report on Form 8-K filed on March 20,
                2007.(20)
            Incorporated
                by reference from our Current Report on Form 8-K filed on August
                7,
                2007.(21)
            Incorporated
              by reference from our Current Report on Form 8-K filed on October 17,
              2007.




(22)
            Incorporated
                by reference from our Current Report on Form 8-K filed on February
                14,
                2008.




37





**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 30 th day of
      June, 2007.





**RANCHER
                ENERGY CORP.**/s/
                John WorksJohn
                Works, President, Chief Executive Officer,
              Principal
                Executive Officer, Chief Financial Officer,
              Principal
                Financial 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 30,
                2008/s/
                Richard E. Kurtenbach
            
            Chief
                Accounting OfficerRichard
                E. Kurtenbach
            
            
            
            June
                30, 2008/s/
                William A. AndersonWilliam
                A. Anderson
            
            Director
            
            June
                27, 2008/s/
                Joseph P. McCoyJoseph
                P. McCoy
            
            Director
            
            June
                27, 2008/s/
                Patrick M. MurrayPatrick
                M. Murray
            
            Director
            
            June
                30, 2008/s/
                Myron M. SheinfeldMyron
                M. Sheinfeld
            
            Director
            
            June
                27, 2008/s/
                Mark WortheyMark
                Worthey
            
            Director
            
            June
                28, 2008




38





**EXHIBIT
      INDEX**




**Exhibit**
            
            **Description**3.1
            
            Amended
                and Restated Articles of Incorporation(1)3.2
            
            Articles
                of Correction(2)3.3
            
            Amended
                and Restated Bylaws(3)4.1
            
            Form
                of Stock Certificate for Fully Paid, Non-Assessable Common Stock
                of the
                Company(4)4.2
            
            Form
                of Unit Purchase Agreement(3)4.3
            
            Form
                of Warrant Certificate(3)4.4
            
            Form
                of Registration Rights Agreement, dated December 21, 2006(5)4.5
            
            Form
                of Warrant to Purchase Common Stock(5)10.1
            
            Burke
                Ranch Unit Purchase and Participation Agreement between Hot Springs
                Resources Ltd. and PIN Petroleum Partners Ltd., dated February 6,
                2006(6)10.2
            
            Employment
                Agreement between John Works and Rancher Energy Corp., dated June 1,
                2006(7)10.3
            
            Assignment
                Agreement between PIN Petroleum Partners Ltd. and Rancher Energy
                Corp.,
                dated June 6, 2006(7)10.4
            
            Loan
                Agreement between Enerex Capital Corp. and Rancher Energy Corp.,
                dated
                June 6, 2006(7)10.5
            
            Letter
                Agreement between NITEC LLC and Rancher Energy Corp., dated June 7,
                2006(7)10.6
            
            Loan
                Agreement between Venture Capital First LLC and Rancher Energy Corp.,
                dated June 9, 2006(8)10.7
            
            Exploration
                and Development Agreement between Big Snowy Resources, LP and Rancher
                Energy Corp., dated June 15, 2006(7)10.8
            
            Assignment
                Agreement between PIN Petroleum Partners Ltd. and Rancher Energy
                Corp.,
                dated June 21, 2006(7)10.9
            
            Purchase
                and Sale Agreement between Wyoming Mineral Exploration, LLC and Rancher
                Energy Corp., dated August 10, 2006(6)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(9)10.11
            
            Rancher
                Energy Corp. 2006 Stock Incentive Plan(9)10.12
            
            Rancher
                Energy Corp. 2006 Stock Incentive Plan Form of Option Agreement(9)10.13
            
            Denver
                Place Office Lease between Rancher Energy Corp. and Denver Place
                Associates Limited Partnership, dated October 30, 2006(10)10.14
            
            Finder’s
                Fee Agreement between Falcon Capital and Rancher Energy Corp.(11)10.15
            
            Amendment
                to Purchase and Sale Agreement between Wyoming Mineral Exploration,
                LLC
                and Rancher Energy Corp.(12)10.16
            
            Letter
                Agreement between Certain Unit Holders and Rancher Energy Corp.,
                dated
                December 8, 2006(3)10.17
            
            Letter
                Agreement between Certain Option Holders and Rancher Energy Corp.,
                dated
                December 13, 2006(3)10.18
            
            Product
                Sale and Purchase Contract by and between Rancher Energy Corp. and
                the
                Anadarko Petroleum Corporation, dated December 15, 2006(13)10.19
            
            Amendment
                to Purchase and Sale Agreement between Nielson & Associates, Inc. and
                Rancher Energy Corp.(14)10.18
            
            Securities
                Purchase Agreement by and among Rancher Energy Corp. and the Buyers
                identified therein, dated December 21, 2006(5)10.19
            
            Lock-Up
                Agreement between Rancher Energy Corp. and Stockholders identified
                therein, dated December 21, 2006(5)10.20
            
            Voting
                Agreement between Rancher Energy Corp. and Stockholders identified
                therein, dated as of December 13, 2006(5)10.21
            
            Form
                of Convertible Note(15)10.22
            
            Employment
                Agreement between Daniel Foley and Rancher Energy Corp., dated
                January 12, 2007(16)10.23
            
            First
                Amendment to Securities Purchase Agreement by and among Rancher Energy
                Corp. and the Buyers identified therein, dated as of January 18, 2007(17)10.24
            
            Rancher
                Energy Corp. 2006 Stock Incentive Plan Form of Restricted Stock Agreement(18)10.25
            
            First
                Amendment to Employment Agreement by and between John Works and Rancher
                Energy Corp., dated March 14, 2007(19)10.26
            
            Employment
                Agreement between Richard Kurtenbach and Rancher Energy Corp., dated
                August 3, 2007(20)10.27
            
            Term
                Credit Agreement between Rancher Energy Corp. and GasRock Capital
                LLC,
                dated as of October 16, 2007(21)10.28
            
            Term
                Note made by Rancher Energy Corp. in favor of GasRock Capital LLC,
                dated
                October 16, 2007(21)10.29
            
            Mortgage,
                Security Agreement, Financing Statement and Assignment of Production
                and
                Revenues from Rancher Energy Corp. to GasRock Capital LLC, dated
                as of
                October 16, 2007(22)10.30
            
            Security
                Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated
                as
                of October 16, 2007(21)10.31
            
            Conveyance
                of Overriding Royalty Interest by Rancher Energy Corp. in favor of
                GasRock
                Capital LLC, dated as of October 16, 2007(21)10.32
            
            ISDA
                Master Agreement between Rancher Energy Corp. and BP Corporation
                North
                America Inc., dated as of October 16, 2007(21)10.33
            
            Restricted
                Account and Securities Account Control Agreement by and among Rancher
                Energy Corp., GasRock Capital LLC, and Wells Fargo Bank, National
                Association, dated as of October 16, 2007(21)










**Exhibit**
            
            **Description**10.34
            
            Intercreditor
                Agreement by and among Rancher Energy Corp., GasRock Capital LLC,
                and BP
                Corporation North America Inc., dated as of October 16, 2007(21)10.35
            
            First
                Amendment to Denver Place Office lease between Rancher Energy Corp.
                and
                Denver Place Associates Limited Partnership, dated March 6, 2007(19)10.36
            
            Carbon
                Dioxide Sale & Purchase Agreement between Rancher Energy Corp. and
                ExxonMobil Gas & Power Marketing Company, dated effective as of
                February 1, 2008 (Certain portions of this agreement have been redacted
                and have been filed separately with the Securities and Exchange Commission
                pursuant to a Confidential Treatment Request).(22)23.1
            
            Consent of
              Ryder Scott
              Company, L.P., Independent Petroleum Engineers.*31.1
            
            Certification
                Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Executive
                Officer)*31.2
            
            Certification
                Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Accounting
                Officer)*32.1
            
            Certification
                pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
                906 of
                the Sarbanes-Oxley Act of 2002*32.2
            
            Certification
                pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
                906 of
                the Sarbanes-Oxley Act of 2002*




*
      Filed
      herewith.




(1)
            Incorporated
                by reference from our Current Report on Form 8-K filed on April 3,
                2007.(2)
            Incorporated
                by reference from our Form 10-Q for the quarterly period ended September
                30, 2007.




(3)
            Incorporated
                by reference from our Current Report on Form 8-K filed on
                December 18, 2006.




(4)
            Incorporated
                by reference from our Form SB-2 Registration Statement filed on
                June 9, 2004.(5)
            Incorporated
                by reference from our Current Report on Form 8-K filed on
                December 27, 2006.





(6)
            Incorporated
                by reference from our Quarterly Report on Form 10-Q/A filed on
                August 28, 2006.




(7)
            Incorporated
                by reference from our Annual Report on Form 10-K filed on June 30,
                2006.




(8)
              Incorporated
                  by reference from our Current Report on Form 8-K filed on June 21,
                  2006.


(9)
              Incorporated
                  by reference from our Current Report on Form 8-K filed on October 6,
                  2006.


(10)
              Incorporated
                  by reference from our Current Report on Form 8-K filed on November 9,
                  2006.




(11)
            Incorporated
                by reference from our Current Report on Form 8-K/A filed on
                November 14, 2006.


(12)
              Incorporated
                  by reference from our Current Report on Form 8-K filed on December 4,
                  2006.


(13)
              Incorporated
                  by reference from our Current Report on Form 8-K filed on
                  December 22, 2006.


(14)
              Incorporated
                  by reference from our Current Report on Form 8-K filed on
                  December 27, 2006.


(15)
              Incorporated
                  by reference from our Current Report on Form 8-K filed on January 8,
                  2007.


(16)
              Incorporated
                  by reference from our Current Report on Form 8-K filed on January 16,
                  2007.(17)
              Incorporated
                  by reference from our Current Report on Form 8-K filed on January 25,
                  2007.


(18)
              Incorporated
                  by reference from our Annual Report on Form 10-K filed on June 29,
                  2007.


(19)
              Incorporated
                  by reference from our Current Report on Form 8-K filed on March 20,
                  2007.


(20)
              Incorporated
                  by reference from our Current Report on Form 8-K filed on August
                  7,
                  2007.


(21)
              Incorporated
                  by reference from our Current Report on Form 8-K filed on October
                  17,
                  2007.


(22)
            Incorporated
                by reference from our Current Report on Form 8-K filed on February
                14,
                2008.









**INDEX
      TO FINANCIAL STATEMENTS**





**Audited
                Financial Statements - Rancher Energy Corp.**Report
                of Independent Registered Public Accounting Firm
            F-2Balance
                Sheets as of March 31, 2008 and 2007
            F-3Statements
                of Operations for the Years Ended March 31, 2008 and
                2007
            F-4Statement
                of Changes in Stockholders’ Equity (Deficit) for the Years Ended
                March 31, 2008, 2007 and 2006
            F-5Statements
                of Cash Flows for the Years Ended March 31, 2008 and 2007
            F-6Notes
                to Financial Statements
            F-7**Audited
                Carve Out Financial Statements - Cole Creek South and South Glenrock
                Operations**Report
                of Independent Registered Public Accounting Firm
            F-25Carve
                Out Statement of Operations for the Period from January 1, 2006 toDecember
                21, 2006
            F-26Carve
                Out Statement of Changes in Owner’s Net Investment for the Period December
                31,2005
                to December 21, 2006
            F-27Carve
                Out Statement of Cash Flows for the Period January 1, 2006 to December
                21,
                2006
            F-28Notes
                to Carve Out Financial Statements
            F-29


F-1


**REPORT
      OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**





To
      the
      Board of Directors and Stockholders


Rancher
      Energy Corp.





We
      have
      audited the accompanying balance sheets of Rancher Energy Corp. (the “Company”)
      as of March 31, 2008 and 2007, and the related statements of operations, changes
      in stockholders’ equity 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 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 financial position of Rancher Energy Corp. as of March
      31, 2008 and 2007, and the results of its operations and its cash flows for
      the
      years then ended, in conformity with U.S. generally accepted accounting
      principles.





We
      were
      not engaged to examine management’s assertion about the effectiveness of Rancher
      Energy Corp.’s internal control over financial reporting as of March 31, 2008
      included in the accompanying *Management
      Report on Internal Controls* and,
      accordingly, we do not express an opinion thereon.





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 has suffered recurring losses from operations and will
      require significant additional funding to repay its short-term debt and for
      planned oil and gas development operations. These factors raise substantial
      doubt about the Company’s ability to continue as a going concern. Management’s
      plans in regard to these matters are also described in Note 1. The financial
      statements do not include any adjustments that might result from the outcome
      of
      this uncertainty .





***HEIN*** ** ***&
      ASSOCIATES LLP***





Denver,
      Colorado


June
      27,
      2008





F-2




**Rancher
      Energy Corp.**




**Balance
      Sheets**





March 31,2008
            
            2007**ASSETS**Current
                assets:Cash
                and cash equivalents
            
            $
            6,842,365
            
            $
            5,129,883Accounts
                receivable and prepaid expenses
            
            
            1,170,641
            
            
            453,709Total
                current assets
            
            
            8,013,006
            
            
            5,583,592Oil
                and gas properties (successful efforts method):Unproved
            
            
            54,058,073
            
            
            56,533,934Proved
            
            
            20,734,143
            
            
            18,552,188Less:
                Accumulated depletion, depreciation, and amortization
            
            
            (1,531,619
            )
            
            (347,821
            )Net
                oil and gas properties
            
            
            73,260,597
            
            
            74,738,301Furniture
                and equipment, net of accumulated depreciation of $204,420 and $27,880
                respectively
            
            
            997,196
            
            
            513,556Other
                assets
            
            
            1,300,382
            
            
            642,582Total
                other assets
            
            
            2,297,578
            
            
            1,156,138Total
                assets
            
            $
            83,571,181
            
            $
            81,478,031**LIABILITIES
                AND STOCKHOLDERS’ EQUITY**Current
                liabilities:Accounts
                payable and accrued liabilities
            
            $
            2,114,204
            
            $
            1,542,840Accrued
                oil and gas property costs
            
            
            250,000
            
            
            250,000Asset
                retirement obligation
            
            
            337,685
            
            
            196,000Liquidated
                damages pursuant to registration rights arrangement
            
            
            -
            
            
            2,705,531Derivative
                liability
            
            
            590,480
            
            
            -Note
                payable, net of unamortized discount of $2,527,550
            
            
            9,712,450
            
            
            -Total
                current liabilities
            
            
            13,004,819
            
            
            4,694,371Long-term
                liabilities:Derivative
                liability
            
            
            246.553
            
            
            -Asset
                retirement obligation
            
            
            922,166
            
            
            1,025,567Total
                long-term liabilities
            
            
            1,168,719
            
            
            1,025,567Commitments
                and contingencies (Note 5)Stockholders’
                equity:Common
                stock, $0.00001 par value, 275,000,000 and 100,000,000 shares authorized
                at March 31, 2008 and 2007 ; 114,878,341 and 102,041,432 shares
                issued and outstanding at March 31, 2008 and 2007,
                respectively
            
            
            1,150
            
            
            1,021Additional
                paid-in capital
            
            
            91,790,181
            
            
            84,985,934Accumulated
                deficit
            
            
            (22,393,688
            )
            
            (
                9,228,862
            )Total
                stockholders’ equity
            
            
            69,397,643
            
            
            75,758,093Total
                liabilities and stockholders’ equity
            
            $
            83,571,181
            
            $
            81,478,031





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


F-3


**Rancher
      Energy Corp.**


**Statements
      of Operations**





For
                the Years Ended March 31,2008
            
            2007Revenue:Oil
                and gas sales
            
            $
            6,344,414
            
            $
            1,161,819Losses
                on derivative activities
            
            
            (956,142
            )
            
            -Total
                revenues
            
            
            5,388,272
            
            
            1,161,819Operating
                expenses:Production
                taxes
            
            
            772,010
            
            
            136,305Lease
                operating expenses
            
            
            2,906,210
            
            
            668,457Depreciation,
                depletion, and amortization
            
            
            1,360,737
            
            
            375,701Impairment
                of unproved properties
            
            
            -
            
            
            734,383Accretion
                expense
            
            
            121,740
            
            
            29,730Exploration
                expense
            
            
            223,564
            
            
            333,919General
                and administrative
            
            
            7,538,242
            
            
            4,512,427Total operating expenses
            
            
            12,922,503
            
            
            6,790,922Loss
                from operations
            
            
            (7,534,231
            )
            
            (5,629,103
            )Other
                income (expense):Liquidated
                damages pursuant to registration rights arrangement
            
            
            (2,645,393
            )
            
            (
                2,705,531
            )Amortization
                of deferred financing costs and discount on note payable
            
            
            (2,423,389
            )
            
            (
                537,822
            )Interest
                expense
            
            
            (794,693
            )
            
            (37,647
            )Interest
                and other income
            
            
            232,880
            
            
            207,848Total other income (expense)
            
            
            (5,630,595
            )
            
            (
                3,073,152
            )Net
                loss
            
            $
            (13,164,826
            )
            $
            (
                8,702,255
            )Basic
                and diluted net loss per share
            
            $
            (0.12
            )
            $
            (0.16
            )Basic
                and diluted weighted average shares outstanding
            
            
            109,942,627
            
            
            53,782,291





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


F-4


**Rancher
      Energy Corp.**


**Statement
      of Changes in Stockholders’ Equity**




Shares
            
            Amount
            
            Additional
              Paid-
                In
              Capital
            
            Accumulated
              Deficit
            
            Total
              Stockholders’
              EquityBalance,
                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 and 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
            )
            $
            75,758,093Common
                stock issued pursuant to registration rights agreement
            
            
            9,731,569
            
            
            97
            
            
            5,463,315
            
            
            -
            
            
            5,463,412Common
                stock issued on exercise of stock options
            
            
            1,750,000
            
            
            18
            
            
            -
            
            
            -
            
            
            18Common
                stock issued to directors for services rendered
            
            
            1,248,197
            
            
            13
            
            
            503,787
            
            
            -
            
            
            503,800Common
                stock issued to non-employee consultant for services
                rendered
            
            
            107,143
            
            
            1
            
            
            112,499
            
            
            -
            
            
            112,500Offering
                costs incurred pursuant to registration rights agreement
            
            
            -
            
            
            -
            
            
            (300,365
            )
            
            -
            
            
            (300,365
            )Stock-based
                compensation
            
            
            -
            
            
            -
            
            
            1,025,011
            
            
            -
            
            
            1,025,011Net
                loss
            
            
            -
            
            
            -
            
            
            -
            
            
            (
                13,164,826
            )
            
            (
                13,164,826
            )Balance
                March 31, 2008
            
            
            114,878,341
            
            $
            1,150
            
            $
            91,790,181
            
            $
            (22,393,688
            )
            $
            69,397,643





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


F-5


**Rancher
      Energy Corp.**


**Statements
      of Cash Flows**





For
                the Years Ended March 31,2008
            
            2007Cash
                flows from operating activities:Net
                loss
            
            $
            (13,164,826
            )
            $
            (
                8,702,255
            )Adjustments
                to reconcile net loss to net cash used for operating
                activities:Liquidated
                damages pursuant to registration rights arrangements
            
            
            2,645,393
            
            
            2,705,531Imputed
                interest on registration rights arrangement payments
            
            
            112,489
            
            
            -Depreciation,
                depletion, and amortization
            
            
            1,360,737
            
            
            375,701Impairment
                of unproved properties
            
            
            -
            
            
            734,383Accretion
                expense
            
            
            121,740
            
            
            29,730Asset
                retirement obligation
            
            
            (278,739
            )
            
            -Stock-based
                compensation expense
            
            
            1,025,011
            
            
            1,501,908Amortization
                of deferred financing costs and discount on notes payable
            
            
            2,423,389
            
            
            537,822Unrealized
                losses on crude oil hedges
            
            
            771,607
            
            
            -Services
                exchanged for common stock, directors
            
            
            503,800
            
            
            -Services
                exchanged for common stock, non-employee
            
            
            112,500
            
            
            -Interest
                expense on convertible note payable beneficial conversion
            
            
            -
            
            
            30,000Interest
                expense on debt converted to equity
            
            
            -
            
            
            3,453Changes
                in operating assets and liabilities:Accounts
                receivable and prepaid expenses
            
            
            (102,374
            )
            
            (453,709
            )Other
                assets
            
            
            (484,561
            )
            
            (588,764
            )Accounts
                payable and accrued liabilities
            
            
            367,411
            
            
            1,540,770Net cash used for operating activities
            
            
            (4,586,423
            )
            
            (2,285,430
            )Cash
                flows from investing activities:Acquisition
                of oil and gas properties
            
            
            -
            
            
            (72,746,295
            )Capital
                expenditures for oil and gas properties
            
            
            (4,245,011
            )
            
            (841,993
            )Proceeds
                from conveyance of unproved oil and gas properties
            
            
            491,500
            
            
            -Increase
                in other assets
            
            
            (927,769
            )
            
            (769,018
            )Net
                cash used for investing activities
            
            
            (4,681,280
            )
            
            (74,357,306
            )Cash
                flows from financing activities:Increase
                in deferred financing costs
            
            
            (959,468
            )
            
            (
                921,981
            )Proceeds
                from issuance of convertible notes payable
            
            
            -
            
            
            11,144,582Proceeds
                from borrowings
            
            
            12,240,000
            
            
            -Payment
                of convertible note payable
            
            
            -
            
            
            (150,000
            )Proceeds
                from sale of common stock and warrants
            
            
            -
            
            
            71,653,937Proceeds
                from issuance of common stock upon exercise of stock
                options
            
            
            18
            
            
            -Payment
                of offering costs
            
            
            (300,365
            )
            
            -Net
                cash provided by financing activities
            
            
            10,980,185
            
            
            81,726,538Increase
                in cash and cash equivalents
            
            
            1,712,482
            
            
            5,083,802Cash
                and cash equivalents, beginning of year
            
            
            5,129,883
            
            
            46,081Cash
                and cash equivalents, end of year
            
            $
            6,842,365
            
            $
            5,129,883Non-cash
                investing and financing activities:Cash
                paid for interest
            
            
            682,204
            
            
            -Payables
                for purchase of oil and gas properties
            
            $
            -
            
            $
            250,000Asset
                retirement asset and obligation
            
            $
            213,757
            
            $
            1,191,837Value
                of warrants issued in connection with acquisition of Cole Creek South
                and
                South Glenrock B Fields
            
            $
            -
            
            $
            616,140Common
                stock and warrants issued on conversion of notes payable
            
            $
            -
            
            $
            10,613,876Issuance
                of common stock in settlement of registration rights arrangement
                and
                imputed interest
            
            $
            5,463,412
            
            $
            -Discount
                on note payable, conveyance of overriding royalty interest
            
            $
            4,500,000
            
            $
            -





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


F-6


**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 and 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 and 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.




The
      accompanying financial statements have been prepared on the basis of accounting
      principles applicable to a going concern, which contemplates the realization
      of
      assets and extinguishment of liabilities in the normal course of business.
      As
      shown in the accompanying Statements of Operations, we have incurred a
      cumulative net loss of $22.4  million for the period from inception
      (February 4, 2004) to March 31, 2008, have a working capital deficit of
      approximately $5.0  million as of March 31, 2007. We require significant
      additional funding to repay the short term debt in the amount of $12.2 million,
      scheduled to mature on October 31, 2008, and for our planned oil and gas
      development operations. Our ability to continue the Company as a going concern
      is dependent upon our ability to obtain additional funding in order to finance
      our planned operations.




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 and 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 and 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 and 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-7





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 and 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
      and Gas Producing Activities




The
      Company uses the successful efforts method of accounting for its oil and 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 and 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 and 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, adjusted for basis and quality differentials, 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.




Sales
      of Proved and Unproved Properties




The
      sale
      of a partial interest in a proved oil and 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. During the year ended March 31, 2008, the Company
      received proceeds on the sale of unproved properties of $491,500, for which
      no
      gain or loss was recognized.




Capitalized
      Interest





The
      Company’s policy is to capitalize interest costs to oil and gas properties on
      expenditures made in connection with exploration, development and construction
      projects that are not subject to current DD&A and that require greater than
      six months to be readied for their intended use (“qualifying projects”).
      Interest is capitalized only for the period that such activities are in
      progress. To date the Company has had no such qualifying projects during periods
      when interest expense has been incurred. Accordingly the Company has recorded
      no
      capitalized interest.


F-8





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.





Deferred
      Financing Costs





Costs
      incurred in connection with the Company’s debt issuances are capitalized and
      amortized over the term of the debt, which approximates the effective interest
      method. Amortization of deferred financing costs of $351,685 and $537,822 was
      recognized for the years ended March 31, 2008 and 2007 and has been charged
      to
      operations as an expense in the Statement of Operations. Unamortized balances
      of
      deferred financing costs of $508,529 and $0 are included in other assets on
      the
      Balance Sheets as of March 31, 2008 and 2007, respectively.




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. 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





The
      Company uses the liability method of accounting for income taxes under which
      deferred tax assets and liabilities are recognized for the future tax
      consequences of temporary differences between the accounting bases and the
      tax
      bases of the Company’s assets and liabilities. The deferred tax assets and
      liabilities are computed using enacted tax rates in effect for the year in
      which
      the temporary differences are expected to reverse.





The
      Company adopted the provisions of FIN 48 on April 1, 2007. FIN 48 provides
      detailed guidance for the financial statement recognition, measurement and
      disclosure of uncertain tax positions recognized in the financial statements
      in
      accordance with SFAS No. 109. Tax positions must meet a
“more-likely-than-not” recognition threshold at the effective date to be
      recognized upon the adoption of FIN 48 and in subsequent periods. The adoption
      of FIN 48 had an immaterial impact on the Company’s financial position and did
      not result in unrecognized tax benefits being recorded. Subsequent to adoption,
      there have been no changes to the Company’s assessment of uncertain tax
      positions. Accordingly, no corresponding interest and penalties have been
      accrued. The Company’s policy is to recognize penalties and interest, if any,
      related to uncertain tax positions as general and administrative expense. The
      Company files income tax returns in the U.S. Federal jurisdiction and various
      states. The Company’s tax years of 2004 and forward are subject to examination
      by the Federal and state taxing authorities.




Net
      Loss per Share




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




Diluted
      net income per common share is calculated by dividing adjusted net loss 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-9




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 31,2008
              
              2007Dilutive
              
              
              -
              
              
              -Anti-dilutive
              
              
              80,665,639
              
              
              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 31,2008
                
                2007Net
                    loss
                
                $
                (13,164,826
                )
                $
                (
                    8,702,255
                )Basic
                    weighted average common shares outstanding
                
                
                109,942,627
                
                
                53,782,291Basic
                    and diluted net loss per common share
                
                
                (0.12
                )
                
                (0.16
                )
  Share-Based
        Payment
  Effective
        April 1, 2006, Rancher Energy adopted Statement of Financial Accounting
        Standard 123(R) “ Accounting
        for Stock-Based Compensation”  using
        the
        modified prospective transition method. SFAS No. 123R requires companies to
        recognize compensation cost for stock-based awards based on estimated fair
        value
        of the award, effective April 1, 2006. See Note 7 for further discussion .
        The Company accounts for equity instruments issued in exchange for the receipt
        of goods or services from other than employees in accordance with SFAS No.123(R)
        and the conclusions reached by the Emerging Issues Task Force ("EITF") in
        Issue
        No. 96-18. Costs are measured at the estimated fair market value of the
        consideration received or the estimated fair value of the equity instruments
        issued, whichever is more reliably measurable. The value of equity instruments
        issued for consideration other than employee services is determined on the
        earliest of a performance commitment or completion of performance by the
        provider of goods or services as defined by EITF 96-18.
  Commodity
        Derivatives
 
 The
        Company accounts for derivative instruments or hedging activities under the
        provisions of Statement of Financial Accounting Standards (“SFAS”) No. 133,
“Accounting for Derivative Instruments and Hedging Activities.”
SFAS No. 133 requires the Company to record derivative instruments at
        their fair value. The Company’s risk management strategy is to enter into
        commodity derivatives that set “price floors” and “price ceilings” for its crude
        oil production. The objective is to reduce the Company’s exposure to commodity
        price risk associated with expected crude oil production.
  The
        Company has elected not to designate the commodity derivatives to which they
        are
        a party as cash flow hedges, and accordingly, such contracts are recorded
        at
        fair value on its balance sheets and changes in such fair value are recognized
        in current earnings as income or expense as they occur.
  The
        Company does not hold or issue commodity derivatives for speculative or trading
        purposes. The Company is exposed to credit losses in the event of nonperformance
        by the counterparty to its commodity derivatives. It is anticipated, however,
        that its counterparty will be able to fully satisfy its obligations under
        the
        commodity derivatives contracts. The Company does not obtain collateral or
        other
        security to support its commodity derivatives contracts subject to credit
        risk
        but does monitor the credit standing of the counterparty. The
        price
        we receive for production in our three fields is indexed to Wyoming Sweet
        crude
        oil posted price. The
        Company has not hedged the basis differential between the NYMEX price and
        the
        Wyoming Sweet price. Under the terms of our Term Credit Agreement issued
        in
        October 2007 the Company was required hedge a portion of its expected future
        production, and it entered into a costless collar agreement for a portion
        of its
        anticipated future crude oil production. The costless collar contains a fixed
        floor price (put) and ceiling price (call). If the index price exceeds the
        call strike price or falls below the put strike price, the Company receives
        the
        fixed price and pays the market price. If the market price is between the
        call
        and the put strike price, no payments are due from either party. The table
        below
        summarizes the terms of the Company’s costless collar:
  F-10
  Contract
                  Feature
              
              Contract
                  Term
              
              Total
                  Volume
                Hedged
                  (Bbls)
              
              Remaining
                Volume
                  Hedged
                (Bbls)
              
              Index
              
              Fixed
                  Price
                ($/Bbl)
              
              Position
                  at March
                31,
                  2008 Due To
                (From)
                  CompanyPut
              
              
              Nov
                  07—Oct 08
              
              
              113,220
              
              
              88,629
              
              
              WTI
                  NYMEX
              
              $
              65.00
              
              
              -Call
              
              
              Nov
                  07—Oct 08
              
              
              67,935
              
              
              53,180
              
              
              WTI
                  NYMEX
              
              $
              83.50
              
              $
              (837,033
              )
 
 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
        years ended March 31, 2008 and 2007, one customer accounted for 100% of the
        Company’s oil and gas sales. The Company did not have revenue for the year ended
        March 31, 2006. 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. As of March 31, 2008 and 2007 accounts
        receivable from this customer account for 41% and 77%, respectively of the
        Company’s total accounts receivable and prepaid expense balances.
  Industry
        Segment and Geographic Information
  The
        Company operates in one industry segment, which is the exploration,
        exploitation, development, acquisition, and production of crude oil and 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, 2008, the Company has not been involved in any
        unconsolidated SPE transactions.
 
 Reclassification
 
 Certain
        amounts in the 2007 financial statements have been reclassified to conform
        to
        the 2008 financial statement presentation. Such reclassifications had no
        effect
        on net loss.
 
 Recent
        Accounting Pronouncements
  In
        September 2006, the Financial Accounting Standards Board (FASB) issued
        Statement of Financial Accounting Standards No. 157, *Fair
        Value Measurements* (SFAS 157).
        This statement clarifies the definition of fair value, establishes a framework
        for measuring fair value, and expands the disclosures on fair value
        measurements. SFAS 157 is effective for fiscal years beginning after
        November 15, 2007. We have not determined the effect, if any, the adoption
        of this statement will have on our financial position or results of
        operations.
  In
        February 2007, the FASB issued Statement of Financial Accounting Standards
        No. 159, *The
        Fair Value Option for Financial Assets and Financial
        Liabilities* (SFAS 159). This statement permits entities to choose to measure many
        financial instruments and certain other items at fair value. This statement
        expands the use of fair value measurement and applies to entities that elect
        the
        fair value option. The fair value option established by this Statement permits
        all entities to choose to measure eligible items at fair value at specified
        election dates. SFAS 159 is effective for fiscal years beginning after
        November 15, 2007. We have not determined the effect, if any, the adoption
        of this statement will have on our financial position or results of operations.
  In
        April 2007, the FASB issued FSP FIN 39-1, “Amendment of FASB
        Interpretation No. 39” (FSP FIN 39-1). FSP FIN 39-1 defines “right of
        setoff” and specifies what conditions must be met for a derivative contract to
        qualify for this right of setoff. It also addresses the applicability of
        a right
        of setoff to derivative instruments and clarifies the circumstances in which
        it
        is appropriate to offset amounts recognized for those instruments in the
        statement of financial position. In addition, this FSP permits offsetting
        of
        fair value amounts recognized for multiple derivative instruments executed
        with
        the same counterparty under a master netting arrangement and fair value amounts
        recognized for the right to reclaim cash collateral (a receivable) or the
        obligation to return cash collateral (a payable) arising from the same master
        netting arrangement as the derivative instruments. This interpretation is
        effective for fiscal years beginning after November 15, 2007, with early
        application permitted. We are currently evaluating the potential impact,
        if any,
        of the adoption of FSP FIN 39-1 on our financial statements.
  F-11
  In
        December 2007, the FASB issued FASB Statement No. 141 (Revised 2007), *Business
        Combination* (SFAS
        141R). SFAS 141R will significantly change the accounting for business
        combinations. Under Statement 141R, an acquiring entity will be required
        to
        recognize all the assets acquired and liabilities assumed in a transaction
        at
        the acquisition-date fair value with limited exceptions and includes a
        significant number of new disclosure requirements. SFAS 141R applies
        prospectively to business combinations for which the acquisition date is
        on or
        after the beginning of the first annual reporting period beginning on or
        after
        December 15, 2008. We have not determined the effect, if any, the adoption
        of
        this statement will have on our financial position or results of operations.
  In
        December 2007, the FASB issued FASB Statement No. 160, *Noncontrolling
        Interests in Consolidated Financial Statements* (SFAS
        160). SFAS 160 establishes new accounting and reporting standards for the
        noncontrolling interest in a subsidiary and for the deconsolidation of a
        subsidiary. SFAS 160 is effective for fiscal years, and interim periods within
        those fiscal years, beginning on or after December 15, 2008. We have not
        determined the effect, if any, the adoption of this statement will have on
        our
        financial position or results of operations.
  In
        March
        2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments
        and
        Hedging Activities. SFAS 161 is intended to improve financial reporting about
        derivative instruments and hedging activities by requiring enhanced disclosures
        to enable investors to better understand their effects on an entity's financial
        position, financial performance, and cash flows. SFAS 161 achieves these
        improvements by requiring disclosure of the fair values of derivative
        instruments and their gains and losses in a tabular format. It also provides
        more information about an entity’s liquidity by requiring disclosure of
        derivative features that are credit risk-related. Finally, it requires
        cross-referencing within footnotes to enable financial statement users to
        locate
        important information about derivative instruments. SFAS 161 will be effective
        for financial statements issued for fiscal years and interim periods beginning
        on March 1, 2009, will be adopted by the Company beginning for the fiscal
        year
        ended March 31, 2009. The Company does not expect there to be any significant
        impact of adopting SFAS 161 on its financial position, cash flows and results
        of
        operations.
  **Note
        2—Oil and Gas Properties**
 
 The
        Company’s oil and gas properties are summarized in the following
        table:
 
 **As
                  of March 31,****2008**
              
              **2007**Proved
                  properties
              
              $
              20,734,143
              
              $
              18,552,188Unimproved
                  properties excluded from DD&A
              
              
              53,655,471
              
              
              56,079,133Equipment
                  and other
              
              
              402,602
              
              
              454,801Subtotal
                  Unevaluated Properties
              
              
              54,058,073
              
              
              56,533,934Total
                  oil and gas properties
              
              
              74,792,216
              
              
              75,086,122Less
                  accumulated depletion, depreciation, amortization and impairment
              
              
              (1,531,619
              )
              
              (347,821
              )$
              73,260,597
              
              $
              74,738,301
 
 **Assignment
        of Overriding Royalty Interest**
 
 In
        conjunction with the issuance of short term debt in October 2007 (See **Note
        4** ),the
        Company assigned the Lender a 2% Overriding Royalty Interest (ORRI),
        proportionally reduced when the Company’s working interest is less than 100%, in
        all crude oil and natural gas produced from its three Powder River Basin
        fields.
        The Company estimated that the fair value of the ORRI granted to the Lender
        is
        approximately $4,500,000 and has recorded this amount as a debt discount
        and a
        decrease of oil and gas properties
  F-12
  **Acquisitions**
  Cole
        Creek South Field and South Glenrock B Field Acquisitions
  On
        December 22, 2006, the Company purchased certain oil and gas properties for
        $46,750,000, before adjustments for the period from the effective date to
        the
        closing date, and closing costs. The oil and 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
                  and 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 and 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:
  Volatility
              
              
              76.00
              %Expected
                  option term
              
              
              5
                  yearsRisk-free
                  interest rate
              
              
              4.51
              %Expected
                  dividend yield
              
              
              0.00
              %
  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
                  and gas properties:Unproved
              
              $
              24,151,745Proved
              
              
              1,870,086Asset
                  retirement obligation
              
              
              (349,193
              )Total
              
              $
              25,672,638
  F-13
 
 Carbon
        Dioxide (“CO 2 ”)
        Enhanced Oil Recovery Project
  The
        Company’s business plan includes the injection of CO 2 into its
        three oil fields in the Powder River Basin. To ensure an adequate supply
        of
        CO2 the Company has entered into two separate supply agreements
        as
        follows:
  On
        December 15, 2006, the Company executed 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
        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. Carbon
        Dioxide (CO2) 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.
  On
        February 12, 2008 the Company entered into a Sale and Purchase Agreement
        with
        ExxonMobil Gas & Power Marketing Company (“ExxonMobil”), a division of Exxon
        Mobil Corporation, under which ExxonMobil will provide Rancher Energy with 70
        MMscfd (million standard cubic per day) of CO 2 for an
        initial 10-year period, with an option for a second 10 years. The CO 2 will be
        supplied from ExxonMobil’s LaBarge gas field in Wyoming. For CO 2 deliveries from ExxonMobil, the Company has agreed to pay a base price plus
        an
        Oil Price Factor which is indexed to the price of West Texas Intermediate
        crude
        oil.
 
 **Impairment
        of Unproved Properties**
  The
        Company has recorded no impairment of unproved properties in the year ended
        March 31, 2008.
 
 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 and 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 and gas
        properties in the balance sheets. The Company depletes the amount added to
        proved oil and gas property costs and recognizes accretion expense in connection
        with the discounted liability over the remaining estimated economic lives
        of the
        respective oil and 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.
  A
        reconciliation of the Company’s asset retirement obligation liability during the
        years ended March 31, 2008 and 2007 is as follows:
 
 2008
              
              2007Beginning
                  asset retirement obligation
              
              $
              1,221,567
              
              $
              --Liabilities
                  incurred
              
              
              18,473
              
              
              1,191,837Liabilities
                  settled
              
              
              (297,212
              )
              
              -Changes
                  in estimates
              
              
              195,283
              
              
              -Accretion
                  expense
              
              
              121,740
              
              
              29,730Ending
                  asset retirement obligation
              
              $
              1,259,851
              
              $
              1,221,567Current
              
              $
              337,685
              
              $
              196,000Long-term
              
              
              922,166
              
              
              1,025,567$
              1,259,851
              
              $
              1,221,567
  F-14
  **Note
        4—Short Term Note Payable**
  On
        October 16, 2007, the Company issued a Note Payable (the Note) in the amount
        of
        $12,240,000 pursuant to a Term Credit Agreement with a financial institution
        (the Lender), resulting in net proceeds of $11,622,800 after the deduction
        of
        the Lender’s fees, expenses, and three months of interest to be held in escrow.
        In addition, the Company incurred approximately $390,000 in investment banking,
        legal, and other fees and expenses in connection with the transaction. The
        Company recorded total capitalized financing costs associated with the issuance
        of the Note in the amount of $835,685 as deferred financing costs. Amortization
        of the deferred financing costs in the amount of $326,685 is included in
        interest expense for year ended March 31, 2008.
 
 All
        amounts outstanding under the Note are due and payable on October 31, 2008
        (Maturity Date) and bear interest at a rate equal to the greater of (a) 12%
        per annum and (b) the one-month LIBOR rate plus 6% per annum. The Company
        is required to make monthly interest payments on the amounts outstanding
        under
        the Credit Agreement, but is not required to make any principal payments
        until
        the Maturity Date. The Company may prepay the amounts outstanding under the
        Credit Agreement at any time without penalty. As of March 31, 2008 the interest
        rate on the Note is 12% per annum.
  The
        Company’s obligations under the Credit Agreement are collateralized by a first
        priority security interest in its properties and assets, including all rights
        under oil and gas leases in its three producing oil fields in the Powder
        River
        Basin of Wyoming and all of its equipment on those properties. The Company
        also
        granted the Lender a 2% Overriding Royalty Interest (ORRI), proportionally
        reduced when the Company’s working interest is less than 100%, in all crude oil
        and natural gas produced from its three Powder River Basin fields. The Company
        estimates that the fair value of the ORRI granted to the Lender is approximately
        $4,500,000 and has recorded this amount as a discount to the Note Payable
        and as
        a decrease of oil and gas properties. Amortization of the discount based
        upon
        the effective interest method in the amount of $1,972,450 is included in
        interest expense for year ended March 31, 2008. As long as any of its
        obligations remain outstanding under the Credit Agreement, the Company will
        be
        required to grant the same ORRI to the Lender on any new working interests
        acquired after closing. Prior to the Maturity Date, the Company may re-acquire
        50% of the ORRI granted to the Lender at a repurchase price calculated to
        ensure
        that total payments by the Company to the Lender of principal, interest,
        ORRI
        revenues, and ORRI repurchase price will equal 120% of the loan
        amount.
 
 The
        Credit Agreement contains several events of default, including if, at any
        time
        after closing, the Company’s most recent reserve report indicates that its
        projected net revenue attributable to proved reserves is insufficient to
        fully
        amortize the amounts outstanding under the Credit Agreement within a 48-month
        period and it is unable to demonstrate to the Lender’s reasonable satisfaction
        that it would be able to satisfy such outstanding amounts through a sale
        of its
        assets or an sale of equity. Upon the occurrence of an event of default under
        the Credit Agreement, the Lender may accelerate the Company’s obligations under
        the Credit Agreement. Upon certain events of bankruptcy, obligations under
        the
        Credit Agreement would automatically accelerate. In addition, at any time
        that
        an event of default exists under the Credit Agreement, the Company will be
        required to pay interest on all amounts outstanding under the Credit Agreement
        at a default rate, which is equal to the then-prevailing interest rate under
        the
        Credit Agreement plus four percent per annum.
 
 The
        Company is subject to various restrictive covenants under the Credit Agreement,
        including limitations on its ability to sell properties and assets, pay
        dividends, extend credit, amend material contracts, incur indebtedness,
        provide guarantees, effect mergers or acquisitions (other than to change
        its
        state of incorporation), cancel claims, create liens, create subsidiaries,
        amend
        its formation documents, make investments, enter into transactions with its
        affiliates, and enter into swap agreements. The Company must maintain (a) a
        current ratio of at least 1.0 (excluding from the calculation of current
        liabilities any loans outstanding under the Credit Agreement) and (b) a
        loan-to-value ratio greater than 1.0 to 1.0 for the term of the loan. As
        of
        March 31, 2008 and the date of this Annual Report, the Company is in compliance
        with all covenants under the Credit Agreement.
  F-15
  **Note
        5—Commitments and Contingencies**
 The
          Company may be subject to legal proceedings, claims, and litigation arising
          from
          its financing and business activities in the ordinary course. Although
          there can
          be no assurance that unfavorable outcomes in any matter would not have
          a
          material adverse effect on the Company’s operating results, liquidity or
          financial position, the Company does not know of any threatened claims
          that it
          believes to be of merit, and the Company intends to vigorously defend any
          actions that would be asserted. 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.
  The
        Company leases office space under a non-cancelable operating lease that expires
        July 31, 2012. Rent expense was $278,625, $35,766 and $0 during the
        years ended March 31, 2008, 2007 and 2006, respectively. The annual minimum
        lease payments for the next five fiscal years and thereafter are presented
        below:
  Years Ending March 31,2009
              
              
              359,0782010
              
              
              367,3342011
              
              
              371,4602012
              
              
              123,820Thereafter
              
              
              -Total
              
              $
              1,221,692
  The
        Company has entered into CO2 supply agreements with Anadarko and
        ExxonMobil as discussed in Note 2 above. The Company has also entered into
        a
        Registration Rights Agreement as discussed in Note 6 below.
  **Note
        6—Stockholders’ Equity**
  The
        Company’s capital stock as of March 31, 2008 and 2007 consists of 275,000,000
        authorized shares of common stock, par value $0.00001 per share.
 
 Issuance
        of Common Stock and Warrants
 
 *For
        the Year Ended March 31, 2008*
  During
        the year ended March 31, 2008, the Company issued common stock as
        follows:
  -
              9,731,569
                  shares to holders of registrable shares of the December 2006 and
                  January
                  2007 private placements, as liquidated damages in settlement of
                  registration rights deficiencies (see Registration Rights and Other
                  Payment Arrangements below);
 -
              1,750,000
                  shares to an officer of the Company upon the exercise of stock
                  options;
 -
              1,248,197
                  shares to directors of the Company in exchange for
                  services; -
              107,143
                shares to independent consultant in exchange for
                services
 
 *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.
  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.
  F-16
  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, as discussed further
        below.
 
 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 were not
        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, the Company opted to pay the liquidated damages in shares of common
        stock. The number of shares issued was 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.
  Using
        the
        above formula, the Company made delay registration effectiveness payments
        May
        18, 2007 through October 31, 2007 as follows:
 
 Date
              
              Total Shares
              
              Price Per ShareMay
                  18, 2007
              
              
              933,458
              
              $
              0.85June
                  19, 2007
              
              
              946,819
              
              $
              0.84July
                  19, 2007
              
              
              1,321,799
              
              $
              0.60August
                  17, 2007
              
              
              1,757,212
              
              $
              0.45September
                  17, 2007
              
              
              2,467,484
              
              $
              0.32October
                  17, 2007
              
              
              1,443,712
              
              $
              0.55October
                  31, 2007
              
              
              861,085
              
              $
              0.43
 
 The
        Company’s registration statement was declared effective on October 31, 2007.
        Since that date the Company has maintained the effectiveness of the registration
        statement and complied with all other provisions of the Registration Rights
        Agreement. No further liquidated damages have been assessed or paid.  In
        accordance with FSP EITF 00-19-2, *Accounting
        for Registration Payment Arrangements* ,
        as of
        the date of this Annual Report, the Company believes the likelihood it will
        incur additional obligations to pay liquidated damages is remote, as defined
        in
        SFAS 5, *Accounting
        for Contingencies.* Accordingly
        as of March 31, 2008, the Company has not recorded a liability for future
        liquidated damages under the Registration Rights Agreement. **
  F-17
  *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.
  The
        following is a summary of warrants as of March 31, 2008
  Warrants
              
              Exercise Price
              
              Expiration DateWarrants
                  issued in connection with thefollowing:Sale
                  of common stock pursuant toRegulation
                  S
              
              
              18,133,500
              
              $
              0.75
              
              
              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 and gas properties
              
              
              250,000
              
              $
              1.50
              
              
              December
                  22, 2011Total
                  warrants outstanding at March 31, 2008
              
              
              75,960,550
 
 **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 years ended March 31, 2008 and 2007 of $1,025,011 and $1,501,908,
        respectively. 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 years ended
        March 31, 2008 and 2007 .
  F-18
  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
        allowed to exercise all options that are vested. All unvested options shall
        be
        forfeited. The options have no expiration date.
 
 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 date of grant of the options.
        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
        $423,500 and $741,125 for the years ended March 31, 2008 and 2007,
        respectively. The Company expects to recognize the remaining compensation
        expense of $529,375 related to the unvested shares over the next 1.3
        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 years ended March 31, 2008 and 2007 , options to purchase up to
        753,000 and 3,335,000 shares of common stock, respectively were granted under
        the 2006 Stock Incentive Plan to officers, directors, employees and a
        consultant. The options granted have exercise prices ranging from $0.39 to
        $1.64
        generally vest over three years, and have a maximum term of ten
        years.
 
 The
        fair
        value of the options granted during fiscal 2008 and 2007, under the 2006
        Stock
        Incentive Plan was estimated as of the grant date using the Black-Scholes
        option
        pricing model with the following assumptions:
 
 **2008**
              
              **2007**Expected
                  Volatility
              
              
              59.80% - 62.75%
              
              
              76.00%Expected option term
              
              
              3.0 - 6.25 years
              
              
              5 yearsRisk-free interest rate
              
              
              4.39% to 4.68
              
              
              4.34% to 4.75%Expected
                  dividend yield
              
              
              0.00%
              
              
              0.00%
  F-19
 
 Because
        the Company is newly public with an insufficient history of stock price for
        the
        expected term, the expected volatility was based on an average of the volatility
        disclosed by other comparable companies who had similar expected option terms.
        The expected term of options granted was estimated in accordance with the
        simplified method prescribed in SEC Staff Accounting Bulletin (“SAB”) No. 107
        and SAB No 110. The risk free rate was based on the five-year U.S Treasury
        bond
        rate.
  The
        following table summarizes stock option activity for the year ended
        March 31, 2008 and 2007:
  2008
              
              
              
              2007Number
                  of
                Options
              
              Weighted
                Average
                Exercise
                Price
              
              Number
                  of
                Options
              
              Weighted
                Average
                Exercise
                PriceOutstanding
                  at beginning of yearCEO
              
              
              3,000,000
              
              $
              0.00001
              
              
              -
              
              $
              -Plan
              
              
              3,335,000
              
              $
              2.34
              
              
              -
              
              $
              -GrantedCEO
              
              
              -
              
              $
              -
              
              
              4,000,000
              
              $
              0.00001Plan
              
              
              753,000
              
              $
              0.73
              
              
              3,335,000
              
              $
              2.34ExercisedCEO
              
              
              (1,750,000
              )
              $
              0.00001
              
              
              (1,000,000
              )
              $
              0.00001Plan
              
              
              -
              
              $
              -
              
              
              -
              
              $
              -CancelledCEO
              
              
              -
              
              $
              -
              
              
              -
              
              $
              -Plan
              
              
              (2,657,000
              )
              $
              2.46
              
              
              -
              
              $
              -Outstanding
                  at March 31CEO
              
              
              1,250,000
              
              $
              0.00001
              
              
              3,000,000
              
              $
              0.00001Plan
              
              
              1,431,000
              
              $
              1.28
              
              
              3,335,000
              
              $
              2.34Exercisable
                  at March 31,CEO
              
              
              -
              
              $
              0.00001
              
              
              750,000
              
              $
              0.00001Plan
              
              
              430,000
              
              $
              1.74
              
              
              187,500
              
              $
              1.75
 
 The
        following table summarizes information related to the outstanding and vested
        options as of March 31, 2008.
 
 Outstanding
                Options
              
              Vested
                OptionsNumber
                  of SharesCEO
              
              
              1,250,000
              
              
              -Plan
              
              
              1,431,000
              
              
              430,000Weighted
                  Average Remaining Contractual Life in YearsCEO
              
              
              NA
                  - CEO Options Do Not ExpirePlan
              
              
              3.77
              
              
              3.54Weighted
                  Average Exercise PriceCEO
              
              $
              .00001
              
              
              -Plan
              
              $
              1.28
              
              $
              1.74Aggregate
                  Intrinsic ValueCEO
              
              $
              487,488
              
              
              -Plan
              
              $
              (1,269,990
              )
              $
              (581,450
              )
  F-20
 
 The
        following table summarizes changes in the unvested options for the years
        ended
        March 31, 2008 and 2007:
 
 Number
                  of
                Options
              
              Weighted
                Average
                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
              
              $
              1.07Granted—Plan
              
              
              753,000
              
              $
              0.34Vested—CEO
              
              
              (1,000,000
              )
              $
              0.42Plan
              
              
              (742,500
              )
              $
              0.75Total
              
              
              (1,742,500
              )
              $Cancelled
                  - Plan
              
              
              (2,157,000
              )
              $
              0.67Non-vested,
                  March 31, 2008CEO
              
              
              1,250,000
              
              $
              0.42Plan
              
              
              1,001,000
              
              $
              0.50Total
              
              
              2,251,000
              
              
              0.46
  The
        weighted-average grant-date fair values of the stock options granted during
        the
        year ended March 31, 2008 was $0.34. For the year ended March 31, 2007 the
        weighted average grant date fair values of the stock options granted during
        the
        year 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 years ended March 31, 2008 and 2007, was
        approximately $1,410,000 and $1,450,000, respectively. The Company received
        $18
        and $10 from stock options exercised during the year ended March 31, 2008
        and 2007, respectively. 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, 2008 was approximately $499,400 which the Company expects to
        recognize over four years.
  F-21


**Note
      8—Income Taxes**





The
      effective income tax rate for the years ended March 31, 2008 and 2007 differs
      from the U.S. Federal statutory income tax rate due to the
      following:




For the Year Ended March 31,2008
            
            2007Federal
                statutory income tax rate
            
            $
            4,608,000
            
            $
            3,046,000State
                income taxes, net of Federal benefit
            
            
            33,000
            
            
            -Permanent
                items
            
            
            (362,000
            )
            
            (184,000
            )Other
            
            
            129,000
            
            
            128,000Change
                in valuation allowance
            
            
            (4,408,000
            )
            
            (2,990,000
            )$
            -
            
            $
            -





The
      components of the deferred tax assets and liabilities as of March 31, 2008
      and
      2007 are as follows:




For
                the Year Ended March 31,2008
            
            2007Current
                deferred tax assets:Liquidated
                damages pursuant to registration rights agreement
            
            $
            -
            
            $
            947,000Valuation
                allowance
            
            
            -
            
            
            (947,000
            )Net
                current deferred tax assets
            
            
            -
            
            
            -Long-term
                deferred tax assets:Federal
                net operating loss carryforwards
            
            
            5,984,000
            
            
            1,786,000Asset
                retirement obligation
            
            
            444,000
            
            
            428,000Stock-based
                compensation
            
            
            469,000
            
            
            245,000Accrued
                vacation
            
            
            23,000Unrealized
                hedging losses
            
            
            272,000Property
                , plant and equipment
            
            
            261,000Valuation
                allowance
            
            
            (7,453,000
            )
            
            (2,099,000
            )Net
                long-term deferred tax assets
            
            
            -
            
            
            360,
                000Long-term
                deferred tax liabilities:Oil
                and gas properties
            
            
            -
            
            
            360,000Net
                long-term deferred tax liabilities
            
            $
            -
            
            $
            -




The
      Company has approximately $16,977,000 net operating loss carryover as of March
      31, 2008. The net operating losses begin to expire in 2024




The
      Company has provided a full valuation allowance for the deferred tax assets
      as
      of March 31, 2008 and 2007, based on the likelihood of the realization of the
      deferred tax assets will not be utilized in the future.




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




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




*Costs
      Incurred in Oil and Gas Producing Activities:*




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




F-22





For the Year Ended March 31,2008
            
            2007Exploration
            
            $
            223,564
            
            $
            333,919Development
            
            
            4,758,783
            
            
            -Acquisitions:Unproved
            
            
            43,088
            
            
            56,813,516Proved
            
            
            -
            
            
            18,552,188Total
            
            
            5,025,435
            
            
            75,699,623Costs
                associated with asset retirement obligations
            
            $
            213,756
            
            $
            1,191,837




*Oil
      and Gas Reserve Quantities (Unaudited):*




For
      the
      years ended March 31, 2008 and 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 and
      gas
      reserves as of and for the year ended March 31, 2006.





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 and gas properties. Accordingly,
      these estimates are expected to change as future information becomes
      available.




Proved
      oil and gas reserves, as defined in Regulation S-X, Rule 4-10(a)(2)(3)(4),
      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 and 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 years ended March 31, 2008 and 2007 (the Company did not
      have any natural gas reserves).




Total
                proved:
            
            2008
            
            2007Beginning
                of year
            
            
            1,279,164Purchases
                of minerals in-place
            
            
            -
            
            
            1,073,138Production
            
            
            (86,626
            )
            
            (23,838
            )Revisions
                of previous estimates
            
            
            107,858
            
            
            229,864End
                of year
            
            
            1,300,396
            
            
            1,279,164Proved
                developed reserves:
            
            
            1,074,830
            
            
            1,062,206





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




SFAS
      No. 69, *Disclosures
      about Oil and 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 and 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 and 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.





F-23




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 $95.49
      and $53.47 per barrel of oil for the years ended March 31, 2008 and 2007,
      respectively. The Company did not have natural gas reserves during the year
      ended March 31, 2008, and did not have crude oil or natural gas reserves
      during the year ended March 31, 2006.





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




As
                of
              March 31,
              2008
            
            As
                of
              March 31,
              2007Future
                cash inflows
            
            $
            124,164,000
            
            $
            68,397,000Future
                production costs
            
            
            (58,283,000
            )
            
            (38,185,000
            )Future
                development costs
            
            
            (2,007,000
            )
            
            (2,005,000
            )Future
                income taxes
            
            
            -
            
            
            -Future
                net cash flows
            
            
            63,874,000
            
            
            28,207,00010%
                annual discount
            
            
            (32,946,000
            )
            
            (15,088,000
            )Standardized
                measure of discounted future net cash flows
            
            $
            30,928,000
            
            $
            13,119,000




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




For
                the year
              ended
              March 31,
              2008
            
            For
                the year
              ended
              March 31,
              2007Standardized
                measure of discounted future net cash flows, beginning of
                year
            
            $
            13,119,000
            
            $
            -Sales
                of oil and gas produced, net of production costs
            
            
            (2,666,
                000
            )
            
            (325,000)
            )Net
                changes in prices and production costs
            
            
            17,737,000
            
            
            3,413,000Purchase
                of minerals in-place
            
            
            -
            
            
            8,479,000Revisions
                of previous quantity estimates
            
            
            2,464,000
            
            
            2,611,000Accretion
                of discount
            
            
            1,312,000
            
            
            212,000Changes
                in timing and other
            
            
            (1,038,000
            )
            
            (1,271,000
            )Standardized
                measure of discounted future net cash flows, end of year
            
            $
            30,928,000
            
            $
            13,119,000




**Note
      10—Related Party Transaction**




There
      were no related party transactions during the year ended March 31, 2008. In
      December 2006, the Company acquired artwork for $7,500 from the Company’s
      President, Chief Executive Officer and a member of the Board of
      Directors.





**Note
      11—Subsequent Events**





On
      April
      21, 2008 we executed
      a letter of intent with two experienced oil and gas operators, the terms of
      which called for the investment of up to $83.5 million to earn up to a 55%
      interest in the fields and provisions for the construction of a pipeline from
      the source of the ExxonMobil CO 2 to
      our
      three fields. Due diligence and formal contract negotiations are ongoing with
      these potential partners.




F-24




**Report
        of Independent Registered Public Accounting Firm**
 
 
 The
        Board
        of Directors and Stockholders
 Nielson
        & Associates, Inc.:
 
 We
        have
        audited the accompanying carve out statement of operations, changes in owner’s
        net investment, and cash flows of South Cole Creek and South Glenrock operations
        for the period from January 1, 2006 to December 21, 2006. 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 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 carve out results of operations and cash flows of
        South
        Cole Creek and South Glenrock operations for the period from January 1, 2006
        to
        December 21, 2006, in conformity with U.S. generally accepted accounting
        principles.
 
 
 /s/
        KPMG
        LLP
  Billings,
        Montana
 June
        29,
        2007


F-25




**South
      Cole Creek and South Glenrock Operations**




**Carve
      Out Statement of Operations**




From
              January 1, 2006
              to
              December 21,
              2006Revenue:Oil
                sales
            
            $
            4,488,315Operating
                expenses:Lease
                operating expense
            
            
            2,944,287Production
                taxes
            
            
            493,956General
                and administrative
            
            
            567,524Depreciation,
                depletion, and amortization
            
            
            952,784Accretion
                of asset retirement obligations
            
            
            107,504Total
                operating expenses
            
            
            5,066,055Net
                income (loss)
            
            $
            (577,740
            )




F-26





**South
      Cole Creek and South Glenrock Operations**




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




Balance
                at December 31, 2005
            
            $
            10,951,264Owner’s
                contributions, net
            
            
            2,059,445Net
                loss
            
            
            (577,740
            )Balance
                at December 21, 2006
            
            $
            12,432,969




F-27





**South
      Cole Creek and South Glenrock Operations**




**Carve
      Out Statement of Cash Flows**




From January 1,
                2006 to
                December 21,
                2006Operating
                  activities:Net
                  (loss)
              
              $
              (577,740
              )Adjustments
                  to reconcile net (loss) to net cash provided by operating
                  activitiesDepreciation,
                  depletion and amortization
              
              
              952,784Accretion
                  of asset retirement obligations
              
              
              107,504Change
                  in operating assets and liabilities:Accounts
                  receivable
              
              
              (227
              )Accounts
                  payable and accrued expenses
              
              
              304,603Production
                  taxes payable
              
              
              127,738Settlement
                  of asset retirement obligations
              
              
              (482,369
              )Net
                  cash provided by operating activities
              
              
              432,293Investing
                  activities:Acquisition
                  of oil and gas properties
              
              
              -Exploration
                  and development expenditures
              
              
              (2,491,738
              )Net
                  cash used for investing activities
              
              
              (2,491,738
              )Financing
                  activities:Contributions
                  from owner, net
              
              
              2,059,445Net
                  cash provided by financing activities
              
              
              2,059,445Net
                  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
              
              $
              -




F-28




**Note
      1 – Basis of Presentation**





The
      accompanying Historical Financial Statements (the “Historical Statements”) and
      related notes thereto are presented on an accrual basis, and represent the,
      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**





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





The
      Company recognizes revenues from oil sales based upon actual volumes sold to
      purchasers.





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-29





**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-30





**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,
              2006ARO
                liability- beginning of period
            
            $
            1,343,804ARO
                liabilities assumed in acquisitions
            
            
            -ARO
                liabilities incurred in the current period
            
            
            -ARO
                liabilities settled in the current period
            
            
            (482,369
            )Accretion
                expense
            
            
            107,504ARO
                liability - end of period
            
            $
            968,939




F-31





**Note
      4 – Concentrations**





Major
      purchasers, and the approximate percentage of revenue for each, during the
      period is as follows:





From
              January 1, 2006
              to
              December 21,
              2006Customer
                A
            
            
            -Customer
                B
            
            
            58
            %Customer
                C
            
            
            42
            %




**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 31,
              2006Acquisition
                of proved properties
            
            $
            -Acquisition
                of unproved properties
            
            
            -Exploration
                costs
            
            
            -Development
                costs
            
            
            2,491,738Total
                costs incurred for acquisition, exploration and development
                activities
            
            $
            2,491,738




F-32








**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
                Ended
              December
                31,
              2006Beginning
                of period
            
            
            1,588,713Purchases
                of minerals in place
            
            
            -Revisions
                of estimates
            
            
            (487,469
            )Extensions
                and discoveries
            
            
            -Production
            
            
            (73,076
            )End
                of period
            
            
            1,028,168Proved
                Developed Reserves
            
            
            827,487





***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
      were
      $47.94, 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 flows amounts are discounted
      at 10
      percent.





F-33





**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, 2006is shown below:





December
                31, 2006Future
                cash inflows
            
            $
            47,317,344Future
                production costs
            
            
            (29,851,344
            )Future
                development costs
            
            
            (2,004,287
            )Future
                net cash flows
            
            
            15,461,71310
                percent annual discount
            
            
            (7,666,089
            )Standardized
                measure of discounted future net cash flows relating to proved
                reserves
            
            $
            7,795,624




F-34





**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 period ended December 31, 2006 :





From
              January
                1, 2006 to
              December
                31, 2006Beginning
                of period
            
            $
            16,972,799Purchases
                of reserves in place
            
            
            -Revisions
                of previous estimates
            
            
            (3,763,013
            )Extensions
                and discoveries
            
            
            -Changes
                in future development costs, net
            
            
            300,000Net
                change in prices
            
            
            (5,731,580
            )Sales
                of oil, net of production costs
            
            
            (1,050,072
            )Changes
                in timing and other
            
            
            (629,790
            )Accretion
                of discount
            
            
            1,697,280End
                of period
            
            $
            7,795,624




F-35