**UNITED
      STATES**


**SECURITIES
      AND EXCHANGE COMMISSION**


**Washington,
      D.C. 20549**




**FORM
      10-K/A**


**Amendment
      No. 3**




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




For
      the
      fiscal year ended March 31, 2007




or




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
 
 Common
          Stock, par value $0.00001 per share




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




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




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




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




Large
                accelerated filer o
            Accelerated
                filer x
            Non-accelerated
                filer o




Indicate
      by check mark whether the registrant is a shell company (as defined in Rule
      12b-2 of the Exchange Act). Yes £ No 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, 2006 was $83,142,808.




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




**DOCUMENTS
      INCORPORATED BY REFERENCE**




Not
      Applicable.












**EXPLANATORY
      NOTE**





This
      Amendment No. 3 on Form 10-K/A (this “Amendment”) amends our Annual Report on
      Form 10-K for the fiscal year ended March 31, 2007, originally filed on June
      29,
      2007 (the “Original Annual Report”). This Amendment does not amend our Amendment
      No. 1 on Form 10-K/A for the fiscal year ended March 31, 2007 that was
      originally filed on July 27, 2007 to include the information required by Part
      III, and our Amendment No. 2 on Form 10-K/A for the fiscal year ended March
      31,
      2007 that was originally filed on September 7, 2007 to address matters that
      were
      raised by the Securities and Exchange Commission in their letter of August
      17,
      2007.





We
      are
      filing this Amendment to address matters that were raised by the Securities
      and
      Exchange Commission in its comment letter of September 26, 2007 as
      follows:





Item
      6 – Selected Financial Data has been revised to provide the correct
      Pre-Predecessor revenues, production taxes, lease operating expenses and excess
      of revenues over expenses; and





Item
      7 – Management’s Discussion and Analysis of Financial Condition and Results
      of Operations has been revised to provide a more detailed explanation of the
      variations in revenues, production taxes and lease operating expenses for the
      year ended March 31, 2007 compared to the year ended March 31, 2006, and the
      year ended March 31, 2006 compared to the year ended March 31, 2005. In
      addition, disclosures have been revised to address trends in the types of bridge
      financing reasonably likely to be available to fund planned operations,
      including capital expenditures for pipeline and field development, and the
      nature, terms and other features of such potential financing.





In
      addition, in connection with the filing of this Amendment, and pursuant to
      Rule
      12b-15 and 13a-14 under the Exchange Act, we are including with this Amendment
      currently dated certifications. As a result of the departure of Daniel P. Foley
      as our Chief Financial Officer, John Works, our Chief Executive Officer, has
      been appointed our interim Chief Financial Officer and thus has executed such
      certificates. **** Except
      as
      described above, no other changes have been made to the Original Annual Report,
      as amended. The Original Annual Report, as amended, continues to speak as of
      the
      date of the Original Annual Report, and we have not updated the disclosures
      contained therein to reflect any events which occurred at a date subsequent
      to
      the filing of the Original Annual Report. The Original Annual Report also
      included a Cautionary Statement concerning forward-looking statements, which
      is
      also applicable to this Amendment.




i




**TABLE
      OF CONTENTS**




**PAGE NO.**PART
                II
            1Item 6.
            Selected
                Financial Data.
            1Item 7.
            Management’s
                Discussion and Analysis of Financial Condition and Results of
                Operations.
            3PART
                IV
            22Item 15.
            Exhibits,
                Financial Statement Schedules.
            22




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 Amendment, the “Cole Creek South Field” also is referred to
      as the “South Cole Creek Field”.




ii




PART
      II




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




In
      addition to the GAAP presentation of Rancher Energy Corp.’s historical results
      for the years ended March 31, 2007, 2006, 2005, and 2004, we have provided
      the
      following results for 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 information is not presented
      on a
      GAAP basis and is not necessarily comparable between periods.




The
      following selected financial data reflects the following:




·
              Rancher
                  Energy Corp. revenues, production taxes, lease operating expenses,
                  loss
                  from continuing operations, and loss from continuing operations
                  per share
                  for the years ended March 31, 2007, 2006, 2005, and
                  2004;




·
                    Rancher
                        Energy Corp. total assets as of March 31, 2007, 2006, 2005, and
                        2004;




·
              Predecessor
                  revenues, production taxes, lease operating expenses, and income
                  (loss)
                  from continuing operations for the period from January 1, 2006
                  through December 21, 2006 (the date of acquisition of the Predecessor
                  by Rancher Energy Corp.), the year ended December 31, 2005, and for
                  the period from September 1, 2004 (the date that the Predecessor was
                  acquired from the Pre-Predecessor) through December 31,
                  2004;




·
              Predecessor
                  total assets as of December 21, 2006 and December 31, 2005;
                  and




·
              Our
                  Pre-Predecessor’s revenues, production taxes, lease operating expenses,
                  and excess of revenues over expenses for the period from January
                  1, 2004
                  through August 31, 2004.




1




Year
                Ended March 31,2007
            
            2006
            
            2005
            
            2004(1)(2)Rancher
                Energy Corp.:Revenues
            
            $
            1,161,819
            
            $
            -
            
            $
            -
            
            $
            -Production
                taxes
            
            
            136,305
            
            
            -
            
            
            -
            
            
            -Lease
                operating expenses
            
            
            700,623
            
            
            -
            
            
            -
            
            
            -Loss
                from continuing operations
            
            
            (8,702,255
            )
            
            (124,453
            )
            
            (27,154
            )
            
            (375,000
            )Loss
                from continuing operations per share
            
            
            (0.16
            )
            
            (0.00
            )
            
            (0.00
            )
            
            (0.01
            )Weighted
                average shares outstanding
            
            
            53,782,291
            
            
            32,819,623
            
            
            70,000,000
            
            
            70,000,000Total
                assets (as of period end)
            
            
            81,478,031
            
            
            46,557
            
            
            4,749
            
            
            -




For
                the Period
              from January 1,
              2006
                through December 21,
              2006
            
            Year
                Ended
              December 31,
              2005
            
            For the Period
              from
              September 1,
              2004
                through December 31,
              2004Predecessor:Revenues
            
            $
            4,488,315
            
            $
            3,713,973
            
            $
            772,449Production
                taxes
            
            
            493,956
            
            
            428,905
            
            
            81,868Lease
                operating expenses
            
            
            2,944,287
            
            
            1,537,992
            
            
            360,207Income
                (loss) from continuing operations
            
            
            (577,740
            )
            
            26,886
            
            
            (78,415
            )Total
                assets (as of period end)
            
            
            14,597,618
            
            
            13,058,437




For the Period
              from
              January
                1,
              2004
                through
              August
                31,
              2004Pre-Predecessor:Revenues
            
            $
            1,275,214Production
                taxes
            
            
            138,087Lease
                operating expenses
            
            
            583,942Excess
                of revenues over expenses
            
            
            553,185




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





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


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




2




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




**Organization**




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




**Oil
      & Gas Property Acquisitions**




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




Cole
      Creek South Field and South Glenrock B Field Acquisitions




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




The
      total
      adjusted purchase price was allocated as follows:




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





The
      Cole
      Creek South Field is located in Converse County, Wyoming approximately six
      miles
      northwest of the town of Glenrock. The field was discovered in 1948 by the
      Phillips Petroleum Company. In March 2007, production from the Cole Creek South
      Field was approximately 84 BOPD gross, and 66 BOPD net to our interests, of
      primarily 34 degree API sweet crude oil.




3




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. In March 2007, production from the South
      Glenrock B Field was approximately 199 BOPD gross, and 152 BOPD net to our
      interests, 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
                & gas properties:Unproved
            
            $
            24,151,745Proved
            
            
            1,870,086Asset
                retirement obligation
            
            
            (349,193
            )Total
            
            $
            25,672,638




Water
      flooding was initiated in the Frontier 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. Production in March
      2007 was approximately 18 BOPD gross, and 14 BOPD net to our interests, of
      primarily 36 degree API sweet crude oil.




**Outlook
      for the Coming Year**




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




·
              Borrow
                  funds on a short-term basis to enhance production in two of our
                  fields, to
                  initiate waterflood operations on one of our fields, to continue
                  permitting for our CO2pipeline project and to provide cash
                  reserves;




·
              Borrow
                  additional funds on a long-term fixed rate basis to conduct 3-D
                  seismic
                  surveys on our fields and to complete our waterflood plan on our
                  Big Muddy
                  Field;




·
              Continue
                  to seek long-term financing for our CO2 pipeline and EOR
                  development plan for all our fields.




4




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




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




**Oil &
      Gas Properties Development Plans**




Our
      plans
      for production enhancement, waterflood
      and CO 2  EOR
      development of our oil fields are dependent on our obtaining substantial
      additional funding. The raising of that funding is dependent on many factors,
      some of which are outside our control, and is not assured. One major factor
      is
      the level of and projected trends in oil prices, which we cannot protect against
      by hedging at this time.




*Short
      term production enhancement plan - commencing late 2007*




By
      the
      end of October 2007, we plan to raise approximately $12 million in a short-term
      debt financing to enhance production and provide cash reserves. The term of
      this
      loan is expected to be one year. Specifically, we plan utilize these funds
      to:




·
              Install
                  downhole pumps in six wells in our Cole Creek South Field that
                  are
                  currently flowing oil wells, at an estimated cost of approximately
                  $1.7
                  million;




·
              Drill
                  two wells in our Big Muddy Field as part of the waterflood plan
                  and
                  evaluation to be conducted later in the year, at a cost of approximately
                  $2.1 million;




·
            Drill
                one well in our South Glenrock B Field to access oil reserves that
                are
                currently classified as proved undeveloped, at a cost of approximately
                $1
                million;




·
              Continue
                  permit process for CO2pipeline project at a cost of approximately $0.5 million; and


·
              Allocate
                  the remainder of the funds to offering costs, working capital and
                  cash
                  reserves.




*Waterflood
      development plan - Big Muddy Field -commencing 1* *st**or
      2**nd**quarter of 2008*




In
      late
      2007 or early 2008, we plan to raise between approximately $50 million in a
      long-term fixed rate debt financing to complete the Big Muddy Field waterflood.
      Specifically, we plan utilize these funds to:




·
              Conduct
                  up to 100 square miles of 3-D seismic surveys and processing to
                  better
                  determine injection pattern locations and alignment of the waterflood
                  and
                  CO2 EOR project, at a cost of approximately $3.5
                  million;


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




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




5




*CO* *2*  *EOR
      development plan - commencing 2009 to 2010*




Following
      the raising of additional funds, we plan to begin CO2 development
      operations in the Big
      Muddy
      Field followed by the South
      Glenrock B Field
      and
      then the Cole Creek South Field. C apital
      expenditures to
      implement our CO 2 EOR
      plans include:




·
              Construct
                  a pipeline to transport CO2from
                  the source to our Big Muddy Field at a cost of approximately $50
                  to $100
                  million;


·
              Acquire
                  and construct surface and compression facilities at our Big Muddy
                  Field to
                  compress, inject and recycle CO2at
                  a cost of approximately $20 to $30 million;


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


·
              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.


Since
      the
      acquisition of the three fields, other than the agreement with Anadarko for
      supply of CO 2 ,
      we have
      neither made any major capital expenditures nor any firm commitments for major
      future capital expenditures to date.




**Commitments**




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




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




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




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




**Results
      of Operations, Including Combined Results**




In
      addition to the GAAP presentation of Rancher Energy Corp.’s historical results
      for the years ended March 31, 2007. 2006 and 2005, we have provided 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.




6




The
      following data includes:




·
              Our
                  results of operations for the years ended March 31, 2007, 2006, and
                  2005;




·
              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.), the year ended December 31,
                  2005, and for the period from September 1, 2004 (the date that the
                  Predecessor was acquired from the Pre-Predecessor) through
                  December 31, 2004;




·
              Our
                  Pre-Predecessor’s revenues, production taxes, and lease operating expenses
                  for the period from January 1, 2004 through August 31,
                  2004;




·
              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, 2007, 2006 and
                2005.




Year
                Ended March 31, 2007 (Unaudited)RancherEnergy
                Corp.
            
            Predecessor
            
            Adjustments
            
            CombinedRevenue:Oil
                production (in barrels)
            
            
            23,838
            
            
            73,076
            
            
            (18,631
            )
            
            78,283Oil
                price (per barrel)
            
            
            48.74
            
            
            61.42
            
            
            61.66
            
            
            57.50Oil
                & gas sales
            
            $
            1,161,819
            
            $
            4,488,315
            
            $
            (1,148,825
            )
            $
            4,501,309Operating
                expenses:Production
                taxes
            
            
            136,305
            
            
            493,956
            
            
            (120,313
            )
            
            509,948Lease
                operating expenses
            
            
            700,623
            
            
            2,944,287
            
            
            (574,756
            )
            
            3,070,154Depreciation,
                depletion, and amortization
            
            
            375,701
            
            
            952,784Impairment
                of unproved properties
            
            
            734,383
            
            
            -Accretion
                expense
            
            
            29,730
            
            
            107,504Exploration
                expense
            
            
            333,919
            
            
            -General
                and administrative
            
            
            4,501,737
            
            
            567,524Total
                operating expenses
            
            
            6,812,398
            
            
            5,066,055(5,650,579
            )
            
            (577,740
            )Other
                income (expense):Liquidated
                damages pursuant to registration rights agreement
            
            
            (2,705,531
            )
            
            -Interest
                expense
            
            
            (37,654
            )
            
            -Amortization
                of deferred financing costs
            
            
            (537,822
            )
            
            -Interest
                and other income
            
            
            229,331
            
            
            -Total
                other income (expense)
            
            
            (3,051,676
            )
            
            -$
            (8,702,255
            )
            $
            (577,740
            )




7




**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.




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




8






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




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




**Rancher
      Energy Corp.**




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




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




*Revenue,
      production taxes, and lease operating expenses* .
      For the
      year ended March 31, 2007, we reflected oil & gas sales of $1,161,819
      on 23,838 barrels of oil at $48.74 per barrel, production taxes (including
      ad
      valorem taxes) of $136,305 and lease operating expenses of $700,623, as compared
      to $0, $0 and $0, respectively, for the corresponding year ended March 31,
      2006. Lease operating expenses per barrel of production were $29.39 and
      production taxes were $5.72 per barrel for the fiscal year ended March 31,
      2007. Results for the year ended March 31, 2007 reflect ownership of the three
      fields from the acquisition dates in December 2006 and January 2007 through
      the
      end of the fiscal year.




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




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




9




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




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




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




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




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




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




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




10




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




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




*Revenue,
      production taxes, and lease operating expenses* .
      For the
      year ended March 31, 2007 (2007), oil & gas sales were $4,501,309 on
      78,283 barrels of oil at $57.50 per barrel, as compared to $3,713,973 on 67,321
      barrels of oil at $55.17 per barrel, for the year ended March 31, 2006 (2006).
      The year to year increase in sales of $787,336 reflects a price variance of
      $157,016 and a volume variance of $630,320. The increased volumes in 2007
      resulted from successful recompletions, workovers, re-stimulations and other
      remedial operational activities on approximately thirty producing wells,
      completed by the Predecessor prior to our acquisition of the properties.
      Production taxes (including ad valorem taxes) were $509,948, or $6.51 per barrel
      in 2007 compared to $428,905, or $6.37 per barrel in 2006. Production taxes
      correlate directly with the value of oil sold and remained consistent at
      approximately 11% of sales. Lease operating expenses increased in 2007 to
      $3,070,154, or $39.22 per barrel, as compared to $1,537,992, or $22.85 per
      barrel, in 2006. This year to year increase of $1,532,162, is comprised of
      $250,434 of volume variance and $1,281,728 of cost variance. The cost variance
      primarily reflects the costs associated with workovers, restimulation and
      repairs carried out the by the Predecessor prior to our acquisition of the
      properties.




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




*Revenue,
      production taxes, and lease operating expenses* .
      For the
      year ended March 31, 2006 (2006), oil & gas sales were $3,713,973 on
      67,321 barrels of oil at $55.17 per barrel, as compared to $1,997,663 on 52,116
      barrels of oil at $38.33 per barrel for the year ended March 31, 2005 (2005).
      The year to year increase in sales of $1,736,310, reflects a price variance
      of
      $897,479 and a volume variance of $838,831. The increased volumes in 2006
      reflect successful recompletions, workovers, re-stimulations and other remedial
      operational activities on approximately thirty producing wells carried out
      by
      the Predecessor following their acquisition of the properties from the
      Pre-Predecessor effective September 1, 2004. Production taxes (including ad
      valorem taxes) were $428,905, or $6.37 per barrel in 2006 compared to $219,955,
      or $4.22 per barrel in 2005. Production taxes correlate directly with the value
      of oil sold and remained consistent at approximately 11 % of sales. Lease
      operating expenses were $1,537,992, or $22.85 per barrel in 2006, as compared
      to
      $944,149, or $18.12 per barrel in 2005. This year to year increase of $593,843,
      consists of $275,458 of volume variance and $318,385 of cost variance. The
      cost
      increase primarily reflects the workovers, re-stimulations and repairs carried
      out the by the Predecessor after their acquisition of the properties. In
      addition, the Predecessor utilized third party contractors to conduct operations
      throughout all of 2006 as compared to only six months of 2005, which third
      party
      contractors were significantly more expensive than using company operators.




**Liquidity
      and Capital Resources**




As
      of
      March 31, 2007, we had working capital of $889,221. Current liabilities
      included $2,705,531 for penalty payments pursuant to the Registration Rights
      Agreement, all of which was paid in stock.




We
      have
      revenue from production operations in our three fields.  However, we
      currently have negative cash flow from operating activities.  Monthly oil
& gas production revenue is adequate to cover monthly field operating costs
      and production taxes at the current time.  Only a portion of the remaining
      cash costs, which consist primarily of general and administrative expenses,
      are
      covered by cash flow.




Our
      currently available cash sources are not sufficient to fund our planned
      expenditures for the secondary and tertiary development of our three fields.
      Essentially all of the necessary funding for their development is expected
      to
      come from, and is dependent on, successful completion of a debt financing.
      As of
      June 30, 2007, the Company was debt-free.




11




We
        are
        making plans for a short-term
        debt financing
        to commence our waterflood plan on our Big Muddy Field and
        to
        further enhance production on our Cole Creek South Field and
        South Glenrock B Field ,
        which we expect to be followed by a larger long-term debt
        financing in
        one or
        more facilities in an
        amount sufficient to fund the
        remainder of the Big Muddy Field waterflood project. We then plan to raise
        additional funds in
        furtherance of our CO 2  EOR
        plans.
  *Short-Term
        Financing*
  We
        expect
        to close a
        short-term debt financing by the
        end of October 2007 in the approximate principal amount of $12 million. The
        interest rate is expected to be approximately 12%, plus 2% in origination
        fees,
        and a 2% overriding royalty interest on Rancher Energy’s property
        interests .
        The
        term of the loan is expected to be one year and the loan will be secured
        by a
        security interest in our three fields. We intend to use approximately half
        the
        funds from this loan to further enhance production in our Cole Creek South
        Field
        and South Glenrock B Field and to begin a waterflood project in our Big Muddy
        Field. We intend to use the other half of the funds from this loan for offering
        costs, working capital, and general corporate purposes to enhance our cash
        reserves .
  *Long-Term
        Debt Financings*
  We
        anticipate raising approximately $50 million
        in late 2007 or early 2008, in one or more long-term debt financings, to
        carry
        out the waterflood program on our Big Muddy Field . There is
        substantial potential for oil recovery via waterflood at our Big Muddy Field,
        and the waterflood strategy will stand alone as a project separate and apart
        from our overall CO 2 flood
        strategy. The waterflood development implemented on the Big Muddy Field also
        is
        a precursor to eventual CO 2 flooding
        of the field, as the work necessary to prepare the field for waterflood is
        similarly needed for the comprehensive CO 2  flood.
        We anticipate
        that the short-term
        debt financing will be
        refinanced or rolled into the long-term
        debt financing . We also
        anticipate that the Big Muddy Field will be the first field targeted for
        our
        comprehensive CO 2 flood,
        followed by the South Glenrock B field.
  Following
        the financing for the Big Muddy Field waterflood project, we plan to
        raise additional financing in 2008 to proceed with our CO 2 EOR
        tertiary development plans of our three fields.
  Completion
        of the short-term debt financing and long-term debt financings will be subject
        to market conditions and Company-specific factors.  Without receipt of
        proceeds from these facilities, the Company’s negative cash flow is projected to
        be covered by available cash through the third quarter of calendar year
        2007.  However, in the event we are not successful in raising the the
        short-term debt financing, we do not plan to allow negative monthly cash
        flow to
        remain at current levels. Rather, we plan to address the situation at that
        time
        by reducing staffing levels to reduce cash requirements to levels supported
        by
        current operations.
  12


Change
      in Financial Condition




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




*Convertible
      Debt Transactions*




Venture
      Capital First LLC




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




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




Private
      Placement –
      Convertible Notes Payable




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




Consistent
      with the terms and conditions of the Units sold in the private placement (as
      further discussed below under the heading “Private Placement” and in Note 6 –
Sale of Common Stock and Warrants to the Notes to Financial Statements of our
      audited financial statements for the fiscal year ended March 31, 2007 in
      Part IV, Item 15 of the Original 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.





13




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.




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




14




Summary
      of Warrants




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




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




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




Cash
      Flows




The
      following is a summary of our comparative cash flows:




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





Analysis
      of Cash Flow Changes between 2007 and 2006




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




15




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




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




Capital
      Expenditures




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




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




Schedule
      of Contractual Obligations




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




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




Off-Balance
      Sheet Arrangements




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




**Critical
      Accounting Policies and Estimates**




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




16




*Oil
      & gas reserve quantities* *.* We
      recorded our first proved oil and gas reserves in the year ended March 31,
      2007.
      Our estimates of proved reserves are based on the quantities of oil and natural
      gas that engineering and geological analyses demonstrate, with reasonable
      certainty, to be recoverable from established reservoirs in the future under
      current operating and economic parameters. Ryder Scott Company L.P. (Ryder
      Scott), our independent reserve engineer, prepares a reserve and economic
      evaluation of all of our properties. Assumptions used by the independent reserve
      engineers in calculating reserves or regarding the future cash flows or fair
      value of our properties are subject to change in the future. The accuracy of
      reserve estimates is a function of:




Ÿ
                the
                    quality and quantity of available
                    data;
  Ÿ
                the
                    interpretation of that data;
  Ÿ
                the
                    accuracy of various mandated economic
                    assumptions; and
  Ÿ
                the
                    judgment of the independent reserve
                    engineer.


Future
      prices received for production and future production costs may vary, perhaps
      significantly, from the prices and
      costs assumed for purposes of calculating reserve estimates. We may not be
      able
      to develop proved reserves within the periods estimated. Furthermore, prices
      and
      costs will not remain constant. Actual production may not equal the estimated
      amounts used in the preparation of reserve projections. As these estimates
      change, the amount of calculated reserves changes. Any change in reserves
      directly impacts our estimate of future cash flows from the property, the
      property’s fair value and the depreciation, depletion and amortization
      (DD&A) rate.




*Successful
      efforts method.* We
      use the successful efforts method of accounting for our oil and natural gas
      properties under Statement of Financial Accounting Standards
      No. 19, *Financial Accounting and Reporting by Oil and Gas Producing
      Companies.* Under
      this method, all costs associated with productive and nonproductive development
      wells are capitalized. Exploration expenses, including geological and
      geophysical expenses and delay rentals, are charged to expense as incurred.
      Costs associated with drilling exploratory wells are initially capitalized
      pending determination of whether or not 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 would be expensed in the Statement of Operations and shown
      as
      a non-cash adjustment to net income in the “Operating activities” section of the
      Statement of Cash Flows in the period in which the determination was made.
      If a
      determination cannot be made within one year of the exploration 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 would be expensed and shown as a non-cash adjustment to
      net
      income in the “Operating activities” section of the Statement of Cash Flows in
      the period in which the determination was made. Re-drilling or directional
      drilling in a previously abandoned well would be classified as development
      or
      exploratory based on whether it is in a proved or unproved reservoir for
      determination of capital or expense. 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 would
      be charged to expense.




17




DD&A
      expense is directly affected by our reserve estimates. Any change in reserves
      directly impacts the amount of DD&A expense that we recognize in a given
      period. Assuming no other changes, such as an increase in depreciable base,
      as
      our reserves increase, the amount of DD&A expense in a given period
      decreases and vice versa. Changes in future commodity prices would likely result
      in increases or decreases in estimated recoverable reserves. DD&A expense
      associated with lease and well equipment and intangible drilling costs are
      based
      upon only proved developed reserves, while DD&A expense for capitalized
      leasehold costs is based upon total proved reserves. As a result, changes in
      the
      classification of our reserves could have a material impact on our DD&A
      expense. Ryder Scott, our independent petroleum engineers, estimate our reserves
      once a year at March 31.




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
      over
      the remaining life of total proved developed reserves or proved reserves, as
      applicable. Natural gas volumes are converted to BOE at the rate of six Mcf
      to
      one barrel of oil. Significant revisions to reserve estimates can be and are
      made by our reserve engineers each year. Mostly these are the result of changes
      in price, but as reserve quantities are estimates, they can also change as
      more
      or better information is collected, especially in the case of estimates in
      newer
      fields. Downward revisions have the effect of increasing our DD&A rate,
      while upward revisions have the effect of decreasing our DD&A
      rate.




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
      DD&A reserve. Gains or losses from the disposal of other properties are
      recognized in the current period.




*Valuation
      of long-lived and intangible assets.* In
      accordance with Statement of Financial Accounting Standards
      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 reserve and production
      information and pricing assumptions that management believes are reasonable.
      Any
      impairment charge incurred is expensed and reduces our recorded basis in the
      asset pool. Management currently aggregates proved property for impairment
      testing for the Company using only one pool of assets due to the geologic
      similarity and proximity of the properties. The price assumptions used to
      calculate undiscounted cash flows are based on judgment. We use prices
      consistent with the prices used in bidding on acquisitions and/or assessing
      capital projects. These price assumptions are critical to the impairment
      analysis as lower prices could trigger impairment while higher prices would
      have
      the opposite effect.




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




18




*Asset
      retirement obligations.* We
      are required to estimate our eventual obligations associated with the retirement
      of tangible long-lived assets that result from the acquisition, construction
      and
      development of our oil and natural gas wells and related facilities. We
      recognize the fair value of a liability for an asset retirement obligation
      in
      the period in which the liability 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 our oil and natural
      gas properties at its discounted fair value. The liability is then accreted
      up
      by recording expense each period until it is settled or the well is sold, at
      which time the liability is reversed.




The
      fair
      value of the liability associated with the asset retirement obligation is
      determined using significant assumptions, including current estimates of the
      plugging and abandonment costs, annual expected inflation of these costs, the
      productive life of the asset and our credit-adjusted risk-free interest rate
      used to discount the expected future cash flows. Changes in any of these
      assumptions can result in significant revisions to the estimated asset
      retirement obligation. Revisions to the obligation are recorded with an
      offsetting change to the carrying amount of the related oil and natural gas
      properties, resulting in prospective changes to DD&A and accretion expense.
      Because of the subjectivity of assumptions and the relatively long life of
      most
      of our oil and natural gas properties, the costs to ultimately retire these
      assets may vary significantly from our estimates.




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




*Stock-based
      compensation.* ** As
      of
      April 1, 2006, we adopted the provisions of SFAS No. 123(R), *Accounting
      for Stock-Based Compensation* ,
      which
      requires companies to recognize compensation cost for stock-based awards based
      on the estimated fair value of the award. Compensation cost is measured at
      the
      grant date based on the fair value of the award and is recognized as an expense
      over the service period, which generally represents the vesting period. The
      Company uses the Black-Scholes option valuation model to calculate the fair
      value disclosures under SFAS 123(R). This model requires the Company to estimate
      a risk free interest rate, the volatility of the Company’s common stock price
      and anticipated forfeitures of options on a going forward basis. The use of
      a
      different estimate for any one of these components could have a material impact
      on the amount of calculated compensation expense. As
      a
      result of adoption of SFAS No 123(R), we recorded compensation expense
      associated with stock options totaling $1,501,908 under the modified-prospective
      adoption method.




19




*Registration
      Payment Arrangements.* In
      connection with the sale of certain Units, the Company has entered into
      agreements that require the transfer of consideration under registration and
      other payment arrangements, if certain conditions are not met. The following
      is
      a description of the conditions and those that have not been met.




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




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




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




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




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


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


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


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


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


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






20




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


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




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




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




Currently,
      there are no equity conditions failures.




Uncertainties
      involved in applying this principle, the variability that may result from its
      application, measurement methods, and the accuracy of estimates and underlying
      assumptions follow:




·
            Uncertainty
                exists as to when the registration statement filed with the SEC will
                be
                declared effective and, consequently, variability exists as to the
                amount
                of liquidated damages that may be ultimately required. We have had
                extensive discussions with the SEC, our Board of Directors, management,
                legal counsel and our independent registered public accounting firm
                in an
                effort to determine when effectiveness might occur. These discussions
                were
                the basis for derivation of the amount reflected as liquidated damages
                pursuant to registration rights arrangement in our financial statements.
                The amount of the actual expense is subject to the number of shares
                issued
                and the fair market value of those shares when
                issued.




·
            Uncertainty
                exists as to the Company’s ability to maintain effectiveness, provide the
                information necessary for sale of shares to be made, register a sufficient
                number of shares, and maintain the listing of the shares once the
                SEC
                declares the Company’s registration statement effective. We believe we
                have the ability to comply with these requirements and, consequently,
                have
                not reflected any impact in our financial
                statements.




·
            Uncertainty
                exists as to whether or not the SEC will object to and reduce the
                number
                of shares being registered. We are not aware of any matters that
                would
                lead us to believe that that could occur and, consequently, have
                not
                reflected any impact in our consolidated financial
                statements.




·
            Uncertainty
                exists as to whether or not the Company will meet the applicable
                listing
                requirements on an approved exchange or market, and that the registrable
                shares will be listed by December 21, 2007 on an approved exchange or
                market. We believe we have the ability to comply with these requirements
                and, consequently, have not reflected any impact in our financial
                statements.




21




**PART
      IV**




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




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





(3)
            Exhibits.
                The exhibits filed as part of this Amendment No. 3 on Form 10-K/A are
                reflected on the Exhibit Index following the signature
                page.




22




SIGNATURES





In
      accordance with Section 13 or 15(d) of the Exchange Act, the Registrant caused
      this report to be signed on its behalf by the undersigned, thereunto duly
      authorized.




RANCHER
                  ENERGY CORP.(Registrant)Date:
                  October 10, 2007
              By:
              /s/
                  John WorksJohn
                  WorksPresident,
                  Chief Executive Officer, Principal Executive Officer, Chief Financial
                  Officer, Principal Financial Officer, Director, Secretary, and
                  Treasurer




23




**EXHIBIT
      INDEX**





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




E-1




**Exhibit**
              
              **Description**


10.23
            
            Lock-Up
                Agreement between Rancher Energy Corp. and Stockholders identified
                therein, dated December 21, 2006(3)10.24
            
            Voting
                Agreement between Rancher Energy Corp. and Stockholders identified
                therein, dated as of December 13, 2006(3)10.25
            
            Form
                of Convertible Note(14)10.26
            
            Employment
                Agreement between Daniel Foley and Rancher Energy Corp., dated
                January 12, 2007(15)10.27
            
            First
                Amendment to Securities Purchase Agreement by and among Rancher Energy
                Corp. and the Buyers identified therein, dated as of January 18, 2007(16)10.28
            
            Rancher
                Energy Corp. 2006 Stock Incentive Plan Form of Restricted Stock Agreement(20)10.29
            
            First
                Amendment to Employment Agreement by and between John Works and Rancher
                Energy Corp., dated March 14, 2007(20)10.30
            
            Employment
                Agreement between Richard Kurtenbach and Rancher Energy Corp., dated
                August 3, 2007(22)14.1
            
            Code
                of Business Conduct and Ethics(18)16.1
            
            Letter
                from Williams & Webster, P.S. regarding change in certifying
                accountant(19)21.1
            
            List
                of Subsidiaries(21)23.1
            
            Consent
                of Ryder Scott Company, L.P., Independent Petroleum Engineers(23)31.1
            
            Certification
                Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Executive Officer)(23)31.2
            
            Certification
                Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Financial Officer)(23)32.1
            
            Certification
                pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
                906 of
                the Sarbanes-Oxley Act of 2002(23)





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




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




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




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




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




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




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




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




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




E-2




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




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




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




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




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




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




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




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




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




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




(20)
            Incorporated
                by reference from our Current Report on Form 8-K filed on March 20,
                2007 (File No. 000-51425).




(21)
            Incorporated
                by reference from our Annual Report on Form 10-K filed on June 29,
                2007 (File No. 000-51425).




(22)
            Incorporated
                by reference from our Current Report on Form 8-K filed on August
                7, 2007
                (File No. 000-51425).




(23)
            Filed
                herewith.




E-3