UNITED
STATES SECURITIES AND EXCHANGE COMMISSION


Washington,
D. C. 20549





FORM
10-Q





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





For the
quarterly period ended June 30, 2009





OR





oTRANSITION REPORT
UNDER 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 No.)999
      - 18th
      Street, Suite 3400
              Denver,
      CO 80202
              (Address
      of principal executive offices)
              
              (303)
      629-1125
              (Registrant’s
      telephone number, including area
code)





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 wasrequired to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.Yes xNo o




Indicate by check mark whether the registrant has
submitted electronically and posted on its corporate Web site, if any, every
Interactive Data File required to be submitted and posted pursuant to Rule 405
of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or
for such shorter period that the registrant was required to submit and post
suchfiles).Yes oNo o




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.


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


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


Yes oNo x





As of
August 18, 2009, 119,516,723 shares of Rancher Energy Corp. common stock,
$.00001 par value, were outstanding.









Rancher
Energy Corp.




Table
of Contents




PART
I - FINANCIAL INFORMATION




Item
      1.
            Financial
      StatementsUnaudited
      Balance Sheets as of June 30, 2009 and March 31, 2009
            03Unaudited
      Statements of Operations for the Three Months endedJune
      30, 2009 and 2008
            05Unaudited
      Statement of Changes in Stockholders’ Equity as ofJune
      30, 2009
            06Unaudited
      Statements of Cash Flows for the Three Months endedJune
      30, 2009 and 2008
            07Notes
      to Financial Statements
            08Item
      2.
            Management's
      Discussion and Analysis of Financial Condition and Results of
      Operations
            19Item
      3.
            Quantitative
      and Qualitative Disclosures About Market Risk
            25Item
      4.
            Controls
      and Procedures
            25PART
      II - OTHER INFORMATIONItem
      6.
            Exhibits
            26SIGNATURES
            29




2


PART
I.  FINANCIAL INFORMATION.




Item
1.   Financial Statements





Rancher
Energy Corp.


Balance
Sheets


(unaudited)





ASSETS





June 30,
              2009
            
            
            March 31,
              2009Current
      assets:Cash
      and cash equivalents
            
            $
            603,877
            
            
            $
            917,160Accounts
      receivable and prepaid expenses
            
            
            435,130
            
            
            
            584,139Derivative
      receivable
            
            
            44,438
            
            
            
            455,960Total
      current assets
            
            
            1,083,445
            
            
            
            1,957,259Oil
      and gas properties at cost (successful efforts method):Unproved
            
            
            53,077,682
            
            
            
            53,328,147Proved
            
            
            19,371,487
            
            
            
            20,631,487Less:  Accumulated
      depletion, depreciation, amortization and impairment
            
            
            (42,068,978
            )
            
            
            (41,840,978
            )Net
      oil and gas properties
            
            
            30,380,191
            
            
            
            32,118,656Other
      assets:Furniture
      and equipment net of accumulated depreciation of $429,349 and
       $381,396, respectively
            
            
            714,117
            
            
            
            770,354Deferred
      finance costs
            
            
            959,411
            
            
            
            387,414Other
      assets
            
            
            929,381
            
            
            
            546,178Total
      other assets
            
            
            2,602,909
            
            
            
            1,703,946Total
      assets
            
            $
            34,066,545
            
            
            $
            35,779,861





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




3





Rancher
Energy Corp.


Balance
Sheets


(unaudited)





LIABILITIES AND
STOCKHOLDERS’EQUITY





June 30,
              2009
            
            
            March 31,
              2009Current
      liabilities:Accounts
      payable and accrued liabilities
            
            $
            931,009
            
            
            $
            816,808Accrued
      oil and gas property costs
            
            
            -
            
            
            
            -Asset
      retirement obligation
            
            
            113,180
            
            
            
            108,884Note
      payable, net of unamortized discount of $-0- and $165,790,
      respectively
            
            
            10,067,892
            
            
            
            9,834,210Total
      current liabilities
            
            
            11,112,081
            
            
            
            10,759,902Long-term
      liabilities:Asset
      retirement obligation
            
            
            1,204,002
            
            
            
            1,171,796Total
      long-term liabilities
            
            
            1,204,002
            
            
            
            1,171,796Contingencies
      (Note 6)Stockholders’
      equity:Common
      stock, $0.00001 par value, 275,000,000 shares authorized June 30, 2009
      and  March 31, 2009; 119,516,700 and 119,016,700 shares
      issued and outstanding at June 30, 2009 and March 31,
      2009, respectively
            
            
            1,196
            
            
            
            1,191Additional
      paid-in capital
            
            
            92,724,170
            
            
            
            92,582,001Accumulated
      deficit
            
            
            (70,974,904
            )
            
            
            (68,735,029
            )Total
      stockholders’ equity
            
            
            21,750,462
            
            
            
            23,848,163Total
      liabilities and stockholders’ equity
            
            $
            34,066,545
            
            
            $
            35,779,861




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




4


Rancher
Energy Corp.


Statements
of Operations


(unaudited)





Three Months Ended
              June 30,Revenues:
            
            2009
            
            
            2008Oil
      & gas sales
            
            $
            696,295
            
            
            $
            1,898,967Derivative
      gains (losses)
            
            
            (316,409
            )
            
            
            (1,895,293
            )379,886
            
            
            
            3,674Operating
      expenses:Production
      taxes
            
            
            88,844
            
            
            
            230,283Lease
      operating expenses
            
            
            353,150
            
            
            
            623,421Depreciation,
      depletion and amortization
            
            
            279,202
            
            
            
            275,841Accretion
      expense
            
            
            36,502
            
            
            
            46,276Exploration
      expense
            
            
            2,505
            
            
            
            9,604General
      and administrative
            
            
            781,846
            
            
            
            1,048,376Total
      operating expenses
            
            
            1,542,049
            
            
            
            2,233,801Loss
      from operations
            
            
            (1,162,163
            )
            
            
            (2,230,127
            )Other
      income (expense):Amortization
      of deferred finance costs and discount on note payable
            
            
            (706,348
            )
            
            
            (1,309,175
            )Interest
      and other income
            
            
            (371,569
            )
            
            
            (371,295Interest
      expense
            
            
            205
            
            
            
            10,581Total
      other income (expense)
            
            
            (1,077,712
            )
            
            
            (1,669,889
            )Net
      loss
            
            $
            (2,239,875
            )
            
            $
            (3,900,016
            )Basic
      and diluted net loss per share
            
            $
            (0.02
            )
            
            $
            0.03
            )Basic
      and diluted weighted average shares outstanding
            
            
            119,239,227
            
            
            
            114,966,138





The
accompanying notes are an integral part of these financial
statements




5


Rancher
Energy Corp.


Statement
of Changes in Stockholders’ Equity


(Unaudited)





Shares
            
            
            Amount
            
            
            Additional
      Paid-In Capital
            
            
            Accumulated
              Deficit
            
            
            Total
      Stockholders’ EquityBalance,
      March 31, 2009
            
            
            119,016,700
            
            
            $
            1,191
            
            
            $
            92,582,001
            
            
            $
            (68,735,029
            )
            
            $
            23,848,163Common
      stock issued on exercise of options
            
            
            500,000
            
            
            
            5
            
            
            
            -
            
            
            
            -
            
            
            
            5Stock-based
      compensation
            
            
            -
            
            
            
            -
            
            
            
            142,169
            
            
            
            -
            
            
            
            142,169Net
      loss
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (2,239,875
            )
            
            
            (2,239,875
            )Balance, June
      30, 2009
            
            
            119,516,700
            
            
            $
            1,196
            
            
            $
            92,724,170
            
            
            $
            (70,974,904
            )
            
            $
            21,750,462




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




6


Rancher
Energy Corp.


Statements
of Cash Flows


(unaudited)





Three
      Months Ended
                June
      30,2009
              
              
              2008Cash
      flows from operating activities:Net
      loss
              
              $
              (2,239,875
              )
              
              $
              (3,900,016
              )Adjustments
      to reconcile net loss to cash used for operating
    activities:Depreciation,
      depletion, and amortization
              
              
              279,202
              
              
              
              275,841Accretion
      expense
              
              
              36,502
              
              
              
              46,276Interest
      expense converted to short-term debt
              
              
              67,892Amortization
      of deferred financing costs and discount on note payable
              
              
              706,348
              
              
              
              1,309,176Unrealized
      losses on derivative activities
              
              
              411,522
              
              
              
              1,544,814Stock-based
      compensation expense
              
              
              142,169
              
              
              
              117,890Services
      exchanged for common stock - directors
              
              
              -
              
              
              
              100,100Loss
      on asset sale
              
              
              -
              
              
              
              8,525Changes
      in operating assets and liabilities:Accounts
      receivable and prepaid expenses
              
              
              149,009
              
              
              
              68,654Other
      assets
              
              
              9,274
              
              
              
              -Accounts
      payable and accrued liabilities
              
              
              114,203
              
              
              
              (752,818
              )Net
      cash used for operating activities
              
              
              (323,754
              )
              
              
              (1,181,558
              )Cash
      flows from investing activities:Capital
      expenditures for oil and gas properties
              
              
              -
              
              
              
              (189,579
              )Proceeds
      from sale of other assets
              
              
              10,466
              
              
              
              -Increase
      in other assets
              
              
              -
              
              
              
              (158,063
              )Net
      cash used for investing activities
              
              
              10,466
              
              
              
              (347,642
              )Cash
      flows from financing activities:Payment
      of deferred financing costs
              
              
              -
              
              
              
              (113,253
              )Proceeds
      from issuance of common stock upon exercise of stock
    options
              
              
              5
              
              
              
              2Net
      cash used for financing activities
              
              
              5
              
              
              
              (113,251
              )Increase
      (decrease) in cash and cash equivalents
              
              
              (313,283
              )
              
              
              (1,642,451
              )Cash
      and cash equivalents, beginning of period
              
              
              917,160
              
              
              
              6,842,365Cash
      and cash equivalents, end of period
              
              $
              603,877
              
              
              $
              5,199,914Non-cash
      investing and financing activities:Cash
      paid for interest
              
              $
              371,569
              
              
              $
              371,280Payables
      settled for oil and gas properties
              
              $
              -
              
              
              $
              30,372Asset
      retirement asset and obligation
              
              $
              -
              
              
              $
              4,804Deferred
      finance costs, conveyance of net profits interest
              
              $
              1,500,000
              
              
              $
              -




7


Rancher
Energy Corp.


Notes to
Financial Statements




Note
1 – Organization and Summary of Significant Accounting Policies




Organization




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




Basis of
Presentation




The
accompanying unaudited financial statements include the accounts of the
Company’s wholly owned subsidiary, Rancher Energy Wyoming, LLC, a Wyoming
limited liability company that was formed on April 24, 2007.  In
management’s opinion, the Company has made all adjustments, consisting of only
normal recurring adjustments, necessary for a fair presentation of financial
position, results of operations, and cash flows.  The financial
statements should be read in conjunction with financial statements included in
the Company’s Annual Report on Form 10-K for the year ended March 31, 2009. The
accompanying financial statements have been prepared in accordance with
accounting principles generally accepted in the United States for interim
financial information.  They do not include all information and notes
required by generally accepted accounting principles for complete financial
statements.  However, except as disclosed herein, there has been no
material change in the information disclosed in the notes to financial
statements included in the Company’s Annual Report on Form 10-K for the year
ended March 31, 2009.  Operating results for the periods presented are not
necessarily indicative of the results that may be expected for the full
year.




The
accompanying financial statements have been prepared on the basis of accounting
principles applicable to a going concern, which contemplates the realization of
assets and extinguishment of liabilities in the normal course of business. As
shown in the accompanying Statements of Operations, we have incurred a
cumulative net loss of $71.0 million for the period from inception (February 4,
2004) to June 30, 2009 and have a working capital deficit of approximately $10.1
million as of June 30, 2009. The Company’s current cash reserves are sufficient
to continue operations through the end of September 2009. We require significant
additional funding to repay the short term debt in the amount of $10 million,
scheduled to mature on October 15, 2009, to continue operations and for our
planned oil and gas development operations. The Company’s ability to continue as
going concern is dependent upon its ability to obtain additional funding in
order to finance its planned operations. The Company is seeking to raise
substantial financing through the sale of debt or equity, or to enter into a
strategic partnering arrangement with an experienced industry operator to enable
it to pay its short term debt, continue operations and to pursue its business
plan. There is no assurance the Company will be successful in these efforts. If
the Company is not successful in raising substantial funding or closing a
strategic partnering transaction to address its cash needs and its short-term
debt within the required timeframe, it may need to cease operations and its
secured lender may foreclose on its properties and/or a bankruptcy filing could
be made. If the Company enters the bankruptcy process, there is no assurance it
will be successful in emerging from bankruptcy.




Use of Estimates in the
Preparation of Financial
Statements




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




8




Oil and Gas Producing
Activities




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





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





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





The
Company reviews its long-lived assets for impairments when events or changes in
circumstances indicate that impairment may have occurred. The impairment test
for proved properties compares the expected undiscounted future net cash flows
on a property-by-property basis with the related net capitalized costs,
including costs associated with asset retirement obligations, at the end of each
reporting period. Expected future cash flows are calculated on all proved
reserves using a discount rate and price forecasts selected by the Company’s
management. The discount rate is a rate that management believes is
representative of current market conditions. The price forecast is based on
NYMEX strip pricing, adjusted for basis and quality differentials, for the first
three to five years and is held constant thereafter. Operating costs are also
adjusted as deemed appropriate for these estimates. When the net capitalized
costs exceed the undiscounted future net revenues of a field, the cost of the
field is reduced to fair value, which is determined using discounted future net
revenues. An impairment allowance is provided on unproved property when the
Company determines the property will not be developed or the carrying value is
not realizable. The Company recognized no impairment of proved or unproved
properties during the three months ended June 30, 2009 or 2008.




Capitalized
Interest




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




Commodity
Derivatives




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


The
objective is to reduce the Company’s exposure to commodity price risk associated
with expected crude oil production.





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




9





The
Company does not hold or issue commodity derivatives for speculative or trading
purposes. The Company is exposed to credit losses in the event of nonperformance
by the counterparty to its commodity derivatives. It is anticipated, however,
that its counterparty will be able to fully satisfy its obligations under the
commodity derivatives contracts. The Company does not obtain collateral or other
security to support its commodity derivatives contracts subject to credit risk
but does monitor the credit standing of the counterparty. The price the Company
receives for production in its three fields is indexed to Wyoming Sweet crude
oil posted price. The Company has not hedged the basis differential between the
NYMEX price and the Wyoming Sweet price. Under the terms of our Term Credit
Agreement issued in October 2007 the Company was required hedge a portion of its
expected future production, and it entered into a costless collar agreement for
a portion of its anticipated future crude oil production. The costless collar
contains a fixed floor price (put) and ceiling price (call). If the index price
exceeds the call strike price or falls below the put strike price, the Company
receives the fixed price and pays the market price. If the market price is
between the call and the put strike price, no payments are due from either
party. The table below summarizes the terms of the Company’s costless
collar:





Derivative
losses are included in cash flows from operating activities in the accompanying
Consolidated Statements of Cash Flows.  The table below summarizes the
realized and unrealized losses related to our derivative instruments for the
three months ended June 30, 2009.





ThreeEnded
      June 30,2009
            
            
            2008Realized
      gains (losses) on derivative instruments
            
            $
            95,113
            
            
            $
            (350,479
            )Unrealized
      losses on derivative instruments
            
            $
            (411,522
            )
            
            $
            (1,544,814
            )Total
      realized and unrealized losses recorded
            
            $
            (316,409
            )
            
            $
            (1,895,293
            )




The table
below summarizes the terms of the Company’s costless collar:




Contract
      Feature
            
            Contract Term
            
            Total
      Volume Hedged (Bbls)
            
            
            Remaining
      Volume Hedged (Bbls)
            
            Index
            
            Fixed
      Price ($/Bbl)
            
            
            Position
      at June 30, 2009 Due To (From) CompanyPut
            
            Nov
      07—Oct 09
            
            
            113,220
            
            
            
            18,231
            
            WTI
      NYMEX
            
            $
            65.00
            
            
            $
            44,438Call
            
            Nov
      07—Oct 09
            
            
            67,935
            
            
            
            10,939
            
            WTI
      NYMEX
            
            $
            83.50
            
            
            
            -




The
Company established the fair value of its derivative instruments using a
published index price, the Black-Scholes option-pricing model and other factors
including volatility, time value and the counterparty’s and the Company’s credit
adjusted risk free interest rate. The actual contribution to the Company’s
future results of operations will be based on the market prices at the time of
settlement and may be more or less than the value estimates used at June 30,
2009.




Net Profits
Interest




The Company assigned a 10% Net Profits
Interest (NPI) to its Lender, under the terms of the Eighth Amendment to the
Term Credit Agreement (see NOTE 5 – Short-term Note Payable).  Net
profit is defined as the excess of the sum of crude oil proceeds plus hedge
settlements, over the sum of lease operating, marketing, transportation and
production tax expenses.  The Company is obligated to pay to the
Lender 10% of such excess, if any, on a monthly basis, so long as the NPI
remains in effect.  The Company records amounts due under the NPI as
operating expense.  For the three months ended June 30, 2009 the
Company recognized $12,647 as NPI expense, including such amount as lease
operating expense in its Statement of Operations.




Net Loss Per
Share





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




10





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





For the Three Months Ended June
      30,2009
            
            
            2008Dilutive
            
            
            -
            
            
            
            -Anti-dilutive
            
            
            64,892,304
            
            
            
            77,401,402





Reclassification





Certain
amounts in the 2008 financial statements have been reclassified to conform to
the 2009 financial statement presentation. Such reclassifications had no effect
on net loss.




Other Significant Accounting
Policies




Other
accounting policies followed by the Company are set forth in Note 1 to the
Consolidated Financial Statements included in its Annual Report on Form 10-K for
the year ended March 31, 2009, and are supplemented in the Notes to Consolidated
Financial Statements in this Quarterly Report on Form 10-Q for the three months
ended June 30, 2009. These unaudited financial statements and notes should be
read in conjunction with the financial statements and notes included in the
Annual Report on Form 10-K for the year ended March 31, 2009.




Recent Accounting
Pronouncements




In
September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS
No. 157, “Fair Value Measurements.” This Statement defines fair value as used in
numerous accounting pronouncements, establishes a framework for measuring fair
value in generally accepted accounting principles and expands disclosure related
to the use of fair value measures in financial statements. In February 2008, the
FASB issued FASB Staff Position (FSP) FAS 157-1, “Application of FASB Statement
No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That
Address Fair Value Measurements for Purposes of Lease Classification or
Measurement under Statement 13,” which removes certain leasing transactions from
the scope of SFAS No. 157, and FSP FAS 157-2, “Effective Date of FASB Statement
No. 157,” which defers the effective date of SFAS No. 157 for one year for
certain nonfinancial assets and nonfinancial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis. In October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair
Value of a Financial Asset When the Market for that Asset is Not Active”, which
clarified the application of SFAS No. 157 as it relates to the valuation of
financial assets in a market that is not active for those financial assets. On
April 1, 2008, we adopted without material impact on our consolidated financial
statements the provisions of SFAS No. 157 related to financial assets and
liabilities and to nonfinancial assets and liabilities measured at fair value on
a recurring basis. On April 1, 2009, we adopted the provisions for nonfinancial
assets and nonfinancial liabilities that are not required or permitted to be
measured at fair value on a recurring basis, which include, among others, those
nonfinancial long-lived assets measured at fair value for impairment assessment
and asset retirement obligations initially measured at fair value. We do not
expect the provisions of SFAS No. 157 related to these items to have a material
impact on our consolidated financial statements (see Note 4).





On
February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for
Financial Assets and Financial Liabilities.” This Statement establishes
presentation and disclosure requirements designed to facilitate comparisons
between companies that choose different measurement attributes for similar types
of assets and liabilities. SFAS No. 159 was effective for the Company’s
financial statements April 1, 2008 and the adoption had no material effect on
our financial position or results of operations.




11





In
December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business
Combinations” (“SFAS No. 141R”), which replaces FASB Statement No.
141.  SFAS No. 141R establishes principles and requirements for how an
acquirer recognizes and measures in its financial statements the identifiable
assets acquired, the liabilities assumed, any non controlling interest in the
acquiree and the goodwill acquired, and establishes that acquisition costs will
be generally expensed as incurred. This statement also establishes disclosure
requirements which will enable users to evaluate the nature and financial
effects of the business combination. On April 1, 2009 the FASB issued FSP
FAS 141R-1, “Accounting for Assets Acquired and Liabilities Assumed in a
Business Combination That Arise from Contingencies” (“FSP FAS 141R-1”). This FSP
amends and clarifies SFAS No. 141R to address application issues related to
initial recognition and measurement, subsequent measurement and accounting, and
disclosure of assets and liabilities arising from contingencies in a business
combination. The Company adopted SFAS No. 141R on April 1, 2009. The adoption of
SFAS No. 141R did not have a material impact on our financial
statements.





In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments
and Hedging Activities” which amends SFAS No. 133 by requiring expanded
disclosures about an entity’s derivative instruments and hedging activities, but
does not change SFAS No. 133’s scope or accounting. This statement is effective
for financial statements issued for fiscal years and interim periods beginning
after November 15, 2008, The Company adopted SFAS No. 161 on
January 1, 2009 and the adoption of SFAS No. 161 did not have an
impact on the Company’s financial position or results of
operations.





In June
2008, the Emerging Issues Task Force (“Task Force”) issued EITF 07-5,
“Determining Whether an Instrument (or Embedded Feature) Is Indexed to an
Entity’s Own Stock.” The objective of this Issue is to provide guidance for
determining whether an equity-linked financial instrument (or embedded feature)
is indexed to an entity’s own stock. The Task Force reached a consensus that
contingent and other adjustment features in equity-linked financial instruments
are consistent with equity indexation if they are based on variables that would
be inputs to a “plain vanilla” option or forward pricing model and they do not
increase the contract’s exposure to those variables. Additionally, denomination
of an equity contract’s strike price in a currency other than the entity’s
functional currency is inconsistent with equity indexation and precludes equity
treatment. The Company adopted EITF 07-5 on April 1, 2009 and the adoption had
no material effect on our financial position or results of
operations.





On
December 31, 2008, the SEC adopted a final rule that amends its oil and gas
reporting requirements. The revised rules change the way oil and gas companies
report their reserves in the financial statements. The rules are intended to
reflect changes in the oil and gas industry since the original disclosures were
adopted in 1978. Definitions were updated to be consistent with Petroleum
Resource Management System (PRMS). Other key revisions include a change in
pricing used to prepare reserve estimates, the inclusion of non-traditional
resources in reserves, the allowance for use of new technologies in determining
reserves, optional disclosure of probable and possible reserves and significant
new disclosures. The revised rules will be effective for our annual report on
Form 10-K for the fiscal year ending March 31, 2010. The SEC is precluding
application of the new rules in quarterly reports prior to the first annual
report in which the revised disclosures are required and early adoption is not
permitted. We are currently evaluating the effect the new rules will have on our
financial reporting and anticipate that the following rule changes could have a
significant impact on our results of operations as follows:





·
            The
      price used in calculating reserves will change from a single-day closing
      price measured on the last day of the company’s fiscal year to a 12-month
      average price, and will affect our depletion and ceiling test
      calculations.





·
            Several
      reserve definitions have changed that could revise the types of reserves
      that will be included in our year-end reserve
  report.





Many of
our financial reporting disclosures could change as a result of the new
rules.




In
June 2009, the FASB issued SFAS No. 165, “Subsequent Events”. SFAS
No.165 incorporates the subsequent events guidance contained in the auditing
standards literature into authoritative accounting literature. It also requires
entities to disclose the date through which they have evaluated subsequent
events and whether the date corresponds with the release of their financial
statements. SFAS No.165 is effective for all interim and annual periods ending
after June 15, 2009. The Company adopted SFAS No.165 upon its issuance and
it had no material impact on our consolidated financial statements. See Note 10
— Subsequent Events for this new disclosure.




12







In
June 2009, the FASB issued SFAS No. 168, “The FASB Accounting
Standards Codification and the Hierarchy of Generally Accepted Accounting
Principles, a replacement of FASB Statement No. 162,” (“Codification”), as
the single source of authoritative generally accepted accounting principles in
the United States (“US GAAP”) for all non-governmental entities, with the
exception of the SEC and its staff. The Codification, which launched
July 1, 2009, changes the referencing and organization of accounting
guidance and is effective for interim and annual periods ending after
September 15, 2009. Since it is not intended to change or alter existing US
GAAP, the Codification is not expected to have any impact on the Company’s
financial condition or results of operations.




Note
2—Oil and Gas Properties




The
Company’s oil and gas properties are summarized in the following
table:




June 30, 2009
            
            
            March 31, 2009Proved
      properties
            
            $
            19,371,487
            
            
            $
            20,631,487Unproved
      properties excluded from DD&A
            
            
            52,713,480
            
            
            
            52,953,185Equipment
      and other
            
            
            364,202
            
            
            
            374,962Subtotal
      Unevaluated Properties
            
            
            53,077,682
            
            
            
            53,328,147Total
      oil and gas properties
            
            
            72,449,169
            
            
            
            73,959,634Less
      accumulated depletion, depreciation, amortization and
      impairment
            
            
            (42,068,978
            )
            
            
            (41,840,978
            )$
            30,380,191
            
            
            $
            32,118,656





Assignment of Net Profits
Interest and Overriding Royalty Interest





In
conjunction with the issuance of short term debt in October 2007 (See Note 5),the Company assigned
the Lender a 2% Overriding Royalty Interest (ORRI), proportionally reduced when
the Company’s working interest is less than 100%, in all crude oil and natural
gas produced from its three Powder River Basin fields. The Company estimated
that the fair value of the ORRI granted to the Lender to be approximately
$4,500,000 and recorded this amount as a debt


discount
and a decrease of oil and gas properties. In October 2008 the Company extended
the maturity date of the short term debt by six months. As partial consideration
for the extension, the Company granted an increase the proportionate ORRI from
2% to 3%. The Company estimated that the fair value of the incremental ORRI
granted to the Lender to be approximately $1,050,000 and has recorded this
amount as a debt discount and a decrease of oil and gas properties. In June 2009
the Company extended the maturity date of the short term debt until October 15,
2009.  As partial consideration for the extension, the Company
assigned the Lender a 10% Net Profits Interest (the “NPI”) in all crude oil and
natural gas produced from its three Powder River Basin fields.  The
Company estimated the fair value of the NPI to be approximately $1,500,000 and
recorded this amount as deferred finance costs and a decrease of oil and gas
properties.





Impairment of Unproved
Properties





The
Company recorded no impairment of unproved properties in the three months ended
June 30, 2009 or 2008.




Note
3 – Asset Retirement Obligations




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




13




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




A
reconciliation of the Company’s asset retirement obligation liability during the
three months ended June 30, 2009 and 2008 is as follows:




2009
            
            
            2008Beginning
      asset retirement obligations
            
            $
            1,280,680
            
            
            $
            1,259,851Liabilities
      incurred
            
            
            -
            
            
            
            7,916Liabilities
      settled
            
            
            -
            
            
            
            -Changes
      in estimates
            
            
            -
            
            
            
            (3,112
            )Accretion
      expense
            
            
            36,502
            
            
            
            46,276Ending
      asset retirement obligation
            
            $
            1,317,182
            
            
            $
            1,310,931Current
            
            $
            113,180
            
            
            $
            366,319Long-term
            
            
            1,204,002
            
            
            
            944,612$
            1,317,182
            
            
            $
            1,310,931




Note 4 — Fair
Value Measurements




On April
1, 2008, the Company adopted SFAS No. 157, “Fair Value Measurements,” which
defines fair value, establishes a framework for using fair value to measure
assets and liabilities, and expands disclosures about fair value measurements.
The Statement establishes a hierarchy for inputs used in measuring fair value
that maximizes the use of observable inputs and minimizes the use of
unobservable inputs by requiring that the most observable inputs be used when
available. Observable inputs are inputs that market participants would use in
pricing the asset or liability developed based on market data obtained from
sources independent of the Company. Unobservable inputs are inputs that reflect
the Company’s assumptions of what market participants would use in pricing
the asset or liability developed based on the best information available in the
circumstances. The hierarchy is broken down into three levels based on the
reliability of the inputs as follows:




·
            Level
      1: Quoted prices are available in active markets for identical assets or
      liabilities;·
            Level
      2: Quoted prices in active markets for similar assets and liabilities that
      are observable for the asset or liability;
or




·
            Level
      3: Unobservable pricing inputs that are generally less observable from
      objective sources, such as discounted cash flow models or
      valuations.




SFAS
No. 157 requires financial assets and liabilities to be classified based on
the lowest level of input that is significant to the fair value measurement. The
Company’s assessment of the significance of a particular input to the fair value
measurement requires judgment, and may affect the valuation of the fair value of
assets and liabilities and their placement within the fair value hierarchy
levels. The following table presents the company’s financial assets and
liabilities that were accounted for at fair value on a recurring basis as of
June 30, 2009 by level within the fair value hierarchy:




14




Fair Value Measurements
    UsingLevel 1
            
            
            Level 2
            
            
            Level 3Assets:Derivative
      instrument
            
            $
            -
            
            
            $
            -
            
            
            $
            44,438Liabilities
            
            $
            -
            
            
            $
            -
            
            
            $
            -




The
Company’s sole derivative financial instrument is a participating cap costless
collar agreement. The fair value of the costless collar agreement is determined
based on both observable and unobservable pricing inputs and therefore, the data
sources utilized in these valuation models are considered level 3 inputs in the
fair value hierarchy. In the Company’s adoption of SFAS No. 157, it considered
the impact of counterparty credit risk in the valuation of its assets and its
own credit risk in the valuation of its liabilities that are presented at fair
value. The Company established the fair value of its derivative instruments
using a published index price, the Black-Scholes option-pricing model and other
factors including volatility, time value and the counterparty’s credit adjusted
risk free interest rate. The actual contribution to the Company’s future results
of operations will be based on the market prices at the time of settlement and
may be more or less than the value estimates used at June 30, 2009.





The
following table sets forth a reconciliation of changes in the fair value of
financial assets and liabilities classified as level 3 in the fair value
hierarchy:





Derivativesas of June 30,2009
            
            
            2008Balance
      as of April 1
            
            $
            455,960
            
            
            $
            (837,033
            )Total
      gains (losses) (realized or unrealized):Included
      in earnings
            
            
            (316,412
            )
            
            
            (1,895,293
            )Included
      in other comprehensive income
            
            
            -
            
            
            
            -Purchased,
      issuances and settlements
            
            
            (95,113
            )
            
            
            272,206Transfers
      in and out of Level 3
            
            
            
            
            
            
            -Balance
      as of June 30
            
            
            44,435
            
            
            $
            (2,460,120
            )Change
      in unrealized gains (losses) included in earnings relating to derivatives
      still held as of June 30
            
            $
            44,435
            
            
            $
            (2,460,120
            )





Note
5 – Short-term Note Payable





On
October 16, 2007, the Company issued a Note Payable (the “Note”) in the amount
of $12,240,000 pursuant to a Term Credit Agreement with a financial institution
(the “Lender”). All amounts outstanding under the Note were originally due and
payable on October 31, 2008 (the “Maturity Date”) and bore interest at a rate
equal to the greater of (a) 12% per annum and (b) the one-month LIBOR rate plus
6% per annum. The Note was amended on October 22, 2008, (the “First Amendment”),
to extend the Maturity Date by six months from October 31, 2008 to April 30,
2009. In consideration of the six month extension and other terms included in
First Amendment, the Company made a principal payment to the Lender in the
amount of $2,240,000, resulting in a new loan balance of $10,000,000. The Note
was amended six times between April 30, and May 27, 2009 to extend the Maturity
Date for short periods of time while the Lender and the Company finalized the
terms of a longer extension.





On June
3,2009 the Note was again amended (the “Eighth Amendment”) to among other things
extend the maturity date until October 15, 2009.  Under the provisions
of the Eighth Amendment the Company executed and delivered a Conveyance of Net
Profits, granting to the Lender a net profits interest in and to the Company’s
properties equal to 10% of the net profit attributable to the Company’s interest
in and to all hydrocarbons produced or saved from its
properties.  Under the terms of the Eighth Amendment, the Company had
the right to purchase from the Lender: (a) two-thirds (2/3), but not less, of
the net profits interest for the period beginning on June 3, 2009 and ending on
August 7, 2009 for the sum of $2,000,000 in cash (the Company did not exercise
this purchase option); or (b) for the period beginning August 8, 2009 and ending
on October 15, 2009, one-third (1/3), but not less, for the sum of $1,333,333 in
cash.




15





Under the terms of the
Eighth Amendment, all amounts outstanding under the Term Credit Agreement, as
amended, bear interest at a rate equal to the greater of (a) 16% per annum and
(b) the LIBOR rate, plus 6% per annum.  Furthermore, the Eighth
Amendment specifies that 4% of the interest rate shall be capitalized so that it
is added to and becomes a part of the Principal Amount in lieu of payment in
cash. Under the terms of the Term Credit Agreement, as amended, the Company is
required to make monthly interest payments on the amounts outstanding but is not
required to make any principal payments until the Maturity Date. The Company may
prepay the amounts outstanding under the Term Credit Agreement at any time
without penalty.





The
Company’s obligations under the Term Credit Agreement, as amended, are
collateralized by a first priority security interest in its properties and
assets, including all rights under oil and gas leases in its three producing oil
fields in the Powder River Basin of Wyoming and all of its equipment on those
properties. Under the terms of the original Term Credit Agreement, the Company
granted the Lender a 2% Overriding Royalty Interest (ORRI), proportionally
reduced when the Company’s working interest is less than 100%, in all crude oil
and natural gas produced from its three Powder River Basin fields. The First
Amendment granted an increase in the proportionate overriding royalty interests
(“ORRI”) assigned to the Lender from 2% to 3%. The Company estimated the fair
value of the 2% ORRI granted to the Lender to be approximately $4,500,000 and
the value of the increase ORRI to be approximately $1,050,000. These amounts
were recorded as discounts to the Note Payable and as decreases of oil and gas
properties.  The Eighth Amendment granted a Conveyance of Net Profits
to the Lender.  The Company estimates the fair value of the 10% NPI to
be approximately $1,500,000.  This amount was recorded as deferred
finance costs and is being amortized over the term of the Note, as
amended.  The Company recorded total amortization of discounts and
deferred finance costs of $706,348 and $1,309,175 for the three month ended June
30, 2009 and 2008 respectively.





The Term
Credit Agreement, as amended, contains several events of default, including if,
at any time after closing, the Company’s most recent reserve report indicates
that its projected net revenue attributable to proved reserves is insufficient
to fully amortize the amounts outstanding under the Term Credit Agreement within
a 48-month period and it is unable to demonstrate to the Lender’s reasonable
satisfaction that it would be able to satisfy such outstanding amounts through a
sale of its assets or a sale of equity. Upon the occurrence of an event of
default under the Term Credit Agreement, the Lender may accelerate the Company’s
obligations under the Term Credit Agreement. Upon certain events of bankruptcy,
obligations under the Term Credit Agreement would automatically accelerate. In
addition, at any time that an event of default exists under the TermCredit
Agreement, the Company will be required to pay interest on all amounts
outstanding under the Term Credit Agreement at a default rate, which is equal to
the then-prevailing interest rate under the Term Credit Agreement plus four
percent per annum.





The
Company is subject to various restrictive covenants under the Term Credit
Agreement, including limitations on its ability to sell properties and assets,
pay dividends, extend credit, amend material contracts, incur indebtedness,
provide guarantees, effect mergers or acquisitions (other than to change its
state of incorporation), cancel claims, create liens, create subsidiaries, amend
its formation documents, make investments, enter into transactions with its
affiliates, and enter into swap agreements. The Company must maintain (a) a
current ratio of at least 1.0 (excluding from the calculation of current
liabilities any loans outstanding under the Term Credit Agreement) and (b) a
loan-to-value ratio greater than 1.0 to 1.0 for the term of the loan. As of
March 31, 2009, the Company was not in compliance with the loan-to-value ratio
covenant, primarily due to a lower crude oil price deck used in computing the
reserve value. The lender has waived this non-compliance from March 31, 2009
through the amended maturity date, October 15, 2009.







16


Note
6 – Contingencies
 
 Threatened
Litigation


On
December 31, 2008, the Company received a letter from an attorney representing
Sergei Stetsenko. Andrei Stytsenko, and other shareholders (the “Stytsenko
Group”) stating that it was the opinion of the Stytsenko Group that the
Company’s  Directors and Executive Officers have acted negligently and
contrary to their fiduciary duties.  The letter threatens a lawsuit
and demands that the Directors and Executive Officers return all cash and stock
received from the Company, cease payment of any cash or stock compensation for
their services, resign their positions as Directors and Executive Officers and
call a shareholders’ meeting to elect Andrei Stytsenko as the sole director of
the Company.  No suit has been filed.  The Company denies
the allegations and believes  they are without merit. In February
2009, the Company’s Board of Directors established a Special Committee of the
Board (the “Special Committee”) to investigate the allegations.  The
Stytsenko Group has filed proxies with the SEC, proposing an alternate slate of
directors for election at the Company’s next meeting of
shareholders.  The Company cannot predict the likelihood of a lawsuit
being filed, its possible outcome, or estimate a range of possible losses, if
any, that could result in the event of an adverse verdict in any such
lawsuit.




In a
letter dated February 18, 2009 sent to each of the Company’s Directors,
attorneys representing a group of persons who purchased approximately $1,800,000
of securities (in the aggregate) in the Company’s private placement offering
commenced in late 2006, alleged that securities laws were violated in that
offering.  In April 2009, the Company entered into tolling agreements
with the purchasers to toll the statutes of limitations applicable to any claims
related to the private placement.  The Company’s Board of Directors
directed the Special Committee to investigate these
allegations.   The Company denies the allegations and believes
they are without merit.  The Company cannot predict the likelihood of
a lawsuit being filed, its possible outcome, or estimate a range of possible
losses, if any, that could result in the event of an adverse verdict in any such
lawsuit.





Note
7 – Income Taxes





As of
June 30, 2009, because the Company believes that it is more likely than not that
its net deferred tax assets, consisting primarily of net operating losses, will
not be utilized in the future, the Company has fully provided for a valuation of
its net deferred tax assets.





The
Company is subject to United States federal income tax and income tax from
multiple state jurisdictions. Currently, the Internal Revenue Service is not
reviewing any of the Company’s federal income tax returns, and agencies in
states where the Company conducts business are not reviewing any of the
Company’s state income tax returns. All tax years remain subject to examination
by tax authorities, including for the period from February 4, 2004 through March
31, 2008.





Note
8—Common Stock





The
Company’s capital stock as of June 30, 2009 and 2008 consists of 275,000,000
authorized shares of common stock, par value $0.00001 per share.




Issuance of Common
Stock




For
the Three Months Ended June 30, 2009




During
the three months ended June 30, 2009, the Company issued 500,000 shares to an
officer of the Company upon the exercise of stock options.  No other
shares of stock were issued during the period.




Note
9—Share-Based Compensation




Chief Executive Officer
(CEO) Options




During
the three months ended June 30, 2009, the Company’s CEO exercised options to
acquire 500,000 shares of common stock, for a cumulative exercise price of $5.00
($0.00001/share).




17







2006 Stock Incentive
Plan




There
were no options to purchase shares of common stock granted during the three
months ended June 30, 2009.  During the three months ended June 30,
2009, options to purchase 5,000 shares of common stock granted to employees
expired. The options had exercise prices of $1.18.




Total
estimated unrecognized compensation cost from unvested stock options as of June
30, 2009 was approximately $85,000 which the Company expects to recognize over
three years. As of June 30, 2009 there were 571,000 options outstanding
under the 2006 Stock Incentive Plan and 9,429,000 options are available for
issuance.




Restricted Stock
Award




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




On May
22, 2007, the Company issued 400,000 shares of common stock to the four new
board members, and on June 26, 2007, the Company issued 100,000 shares of common
stock to the remaining independent Board member. Pursuant to the vesting
discussed above, for the three months ended June 30, 2009, $25,850 has been
reflected as a charge to general and administrative expense in the statement of
operations, with a corresponding credit to additional paid-in
capital.




Board of Director
Fees




On
April 20, 2007, the Board of Directors approved a resolution whereby
members may receive stock in lieu of cash for Board meeting fees, Committee
meeting fees and Committee Chairman fees.




Board
members elected to forego stock compensation for the quarter ended June 30,
2009.




Note
10—Subsequent Events




The Company has evaluated subsequent
events through August19, 2009, the filing date of this Form
10-Q.On August 7, 2009, the Company filed an Application for
Financial Assistance  under the U.S. Department of Energy Funding
Opportunity Announcement No. DE-FOA-0000015, Carbon Capture and Sequestration
from Industrial Sources and Innovative Concepts for Beneficial CO2Use(the
“FOA”).  The Company applied for a grant under Phase 1 of the FOA,
which if awarded, will be utilized to complete reservoir engineering studies,
drilling and surface facility design and pipeline design and permitting for one
of the Company’s Powder River Basin EOR oil fields The Company applied for a
grant equal to 80% of the $4.65 million Phase 1 budget, or $3.72
million.  The Company proposed, as its 20% cost share, a “contribution
in kind” of costs previously incurred on pipeline, surface facilities and
reservoir studies equal to $0.93 million.   If the Company is
awarded a Phase 1 Grant, it plans to apply for  a Phase 2
grant  in an amount of up to $175 million to undertake a comprehensive
CO2
capture, transportation, EOR, and sequestration project in thatfield.




The
Company believes its EOR project is well qualified for awards under
the provisions of the FOA; however, there can be no assurance that the Company
will obtain a Phase 1 grant, or if the Company does obtain a Phase 1 grant,
there can be no assurance the Company will be successful in obtaining a Phase 2
grant.  Further, there can be no assurance that if the Company obtains
a Phase 2 grant, that its CO2 capture,
transportation, EOR, and sequestration project will be technically or
commercially successful.




18




Item
2. Management's Discussion and Analysis of Financial Conditions and Results of
Operations




Forward-Looking
Statements




The
statements contained in this Quarterly Report on Form 10-Q that are not
historical are “forward-looking statements”, as that term is defined in Section
21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), that
involve a number of risks and uncertainties. These forward-looking statements
include, among others, the following:





·
            business
      strategy;




·
            ability
      to complete a sale of the Company, all or a significant portion of its
      assets or financing or other strategic
  alternatives;




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




·
            water
      availability and waterflood production
targets;




·
            carbon
      dioxide (CO2)
      availability, deliverability, and tertiary production
    targets;




·
            construction
      of surface facilities for waterflood and  CO2operations
      and a CO2pipeline;




·
            inventories,
      projects, and programs;




·
            other
      anticipated capital expenditures and
budgets;




·
            future
      cash flows and borrowings;




·
            the
      availability and terms of
financing;




·
            oil
      reserves;




·
            reservoir
      response to water and CO2
      injection;




·
            ability
      to obtain permits and governmental
approvals;




·
            technology;




·
            financial
      strategy;




·
            realized
      oil prices;




·
            production;




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




·
            availability
      and costs of drilling rigs and field
services;




·
            future
      operating results;




·
            plans,
      objectives, expectations, and intentions;
and




These
statements may be found under “Management’s Discussion and Analysis of Financial
Condition and Results of Operations”, and other sections of this Quarterly
Report on Form 10-Q. Forward-looking statements are typically identified by use
of terms such as “may”, “could”, “should”, “expect”, “plan”, “project”,
“intend”, “anticipate”, “believe”, “estimate”, “predict”, “potential”, “pursue”,
“target” or “continue”, the negative of such terms or other comparable
terminology, although some forward-looking statements may be expressed
differently.




The
forward-looking statements contained in this Quarterly Report are largely based
on our expectations, which reflect estimates and assumptions made by our
management. These estimates and assumptions reflect our best judgment based on
currently known market conditions and other factors. Although we believe such
estimates and assumptions to be reasonable, they are inherently uncertain and
involve a number of risks and uncertainties that are beyond our control. In
addition, management’s assumptions about future events may prove to be
inaccurate. Management cautions all readers that the forward-looking statements
contained in this Quarterly Report on Form 10-Q are not guarantees of future
performance, and we cannot assure any reader that such statements will be
realized or the forward-looking events and circumstances will occur. Actual
results may differ materially from those anticipated or implied in the
forward-looking statements due to the factors listed in the “Risk Factors”
section and elsewhere in our Annual Report on Form 10-K for the year ended March
31, 2009. All forward-looking statements speak only as of the date of this
Quarterly Report on Form 10-Q. We do not intend to publicly update or revise any
forward-looking statements as a result of new information, future events or
otherwise. These cautionary statements qualify all forward-looking statements
attributable to us or persons acting on our behalf.




19




Organization




We are an
independent energy company that explores for and develops, produces, and markets
oil and gas in North America. We were known as Metalex Resources, Inc. until
April 2006 when our name was changed to Rancher Energy Corp. We operate three
oil fields in the Powder River Basin, Wyoming. Our business plan is to use
CO2
injection to increase oil production in these oil fields.




Outlook for the
ComingYear




We must
raise substantial financing by the end of September 2009 to be able to continue
operations. Assuming we are successful in raising sufficient financing to meet
our cash needs and repay our short-term debt due in October 2009, the following
summarizes our goals and objectives for the next twelve months:





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


·
            Secure
      long term financing or strategic partnering arrangements with experienced
      industry partners to enable us to initiate development activities in our
      fields;


·
            After
      securing financing or strategic partnering arrangements, renew discussions
      with ExxonMobil to ensure sufficient quantities of CO2 will be made
      available under the existing Sale and Purchase Agreement or negotiate a
      new contract with ExxonMobil for the supply of CO2 to our three oil
      fields.


·
            Continue
      discussions with Anadarko to amend the Anadarko Purchase Contract to
      minimize or eliminate uncertainty.





In 2008,
we retained a financial advisor to assist in financing and other strategic
alternatives, including the possible sale of the Company.  We have
been unsuccessful in completing a strategic transaction.  Our ability
to continue operations is dependent upon completing a strategic transaction;
however, there is no assurance that any transaction will be
completed.




In August
2009, we filed an Application for Financial Assistance  under the U.S.
Department of Energy Funding Opportunity Announcement No. DE-FOA-0000015,
Carbon Capture and
Sequestration from Industrial Sources and Innovative Concepts for
Beneficial CO2Use(the “FOA”). We
applied for a grant under Phase 1 provisions of the FOA which if awarded, will
be utilized to complete reservoir engineering studies, drilling and surface
facility design and pipeline design and permitting for one of our Powder River
Basin EOR oil fields. We requested a grant in the amount of $3.72 million,
which is equal to 80% of the $4.65 million Phase 1 budget.  In the
application, we proposed, as our 20% cost share, a “contribution in kind” of
costs previously incurred on pipeline, surface facilities and reservoir studies
equal to $0.93 million.   If we are awarded a Phase 1 Grant, we
plan to apply for  a Phase 2 grant  in an amount of up to
$175 million to undertake a comprehensive CO2 capture,
transportation, EOR, and sequestration project in thatfield. We believe
our EOR project is well qualified for awards under the provisions of
the FOA; however, there is no assurance that we will obtain a Phase 1 grant, or
if we do obtain a Phase 1 grant, there is no assurance we will be
successful in obtaining a Phase 2 grant.  Further, there is no
assurance that if we obtain a Phase 2 grant, that our CO2 capture,
transportation, EOR, and sequestration project will be technically or
commercially successful.




20




Results of
Operations





Three
months ended June 30, 2009 Compared to Three Months June 30, 2007.





The
following is a comparative summary of our results of operations:





Three Months Ended June 30,2009
            
            
            2008Revenues:Oil
      production (in barrels)
            
            
            13,135
            
            
            
            16,083Net
      oil price (per barrel)
            
            $
            53.01
            
            
            $
            118.07Oil
      sales
            
            $
            696,295
            
            
            $
            1,898,967
            )Derivative
      losses
            
            
            (316,409
            )
            
            
            (1,895,293
            )Total
      revenues
            
            
            379,886
            
            
            
            3,674Operating
      expenses:Production
      taxes
            
            
            88,844
            
            
            
            230,283Lease
      operating expenses
            
            
            353,150
            
            
            
            623,421Depreciation,
      depletion, amortization and accretion
            
            
            279,202
            
            
            
            275,841Accretion
      expense
            
            
            36,502
            
            
            
            46,276Exploration
      expense
            
            
            2,505
            
            
            
            9,604General
      and administrative expense
            
            
            781,846
            
            
            
            1,048,376Total
      operating expenses
            
            
            1,542,049
            
            
            
            2,233,801Loss
      from operations
            
            
            (1,162,163
            )
            
            
            (2,230,127
            )Other
      income (expense):Interest
      expense and financing costs
            
            
            (1,077,917
            )
            
            
            (1,680,470
            )Interest
      and other income
            
            
            205
            
            
            
            10,581Total
      other income (expense)
            
            
            (1,077,712
            )
            
            
            (1,669,889
            )Net
      loss
            
            $
            (2,239,875
            )
            
            $
            (3,900,016
            )





Overview. For the three
months ended June 30, 2009, we reported a net loss of $2,239,875, or $0.02 per
basic and fully-diluted share, compared to a net loss of $3,900,016 or $0.03 per
basic and fully-diluted share, for the corresponding three months of 2008.
Discussions of individually significant period to period variances
follow.




Revenue, production taxes, and lease
operating expenses. For the three months ended June 30, 2009, we recorded
crude oil sales of $696,295 on 13,135 barrels of oil at an average price of
$53.01, as compared to revenues of $1,898,967 on 16,083 barrels of oil at an
average price of $118.07 per barrel in 2008. The year-to-year variance reflects
a volume variance of $(348,079) and a price variance of $(854,592). The
decreased volume in 2009 reflects the loss of several producing wells due to
mechanical problems in late 2008 and early 2009, coupled with routine production
decline from year to year. Production taxes (including ad valorem and property
taxes) of $88,844 in 2009 as compared to $230,283 in 2008, remained constant at
approximately 12.5% of crude oil sales revenues. Lease operating expenses
decreased to $353,150 ($26.89/bbl) in 2009 as compared to $623,421
($38.76/bbl) in 2008. The year to year variance reflects a volume variance of
$114,273 and a cost variance of $155,998. The per barrel decrease in 2009
compared to 2008 reflects costs saving efforts undertaken to preserve capital,
coupled with a lack of significant well or surface facility repair work in the
2009 quarter as compared to the 2008 quarter




21





Derivative losses..In
connection with short term debt financing entered into in October 2007, we
entered into a crude oil derivative contract with an unrelated counterparty to
set a price floor of $63 per barrel for 75% of our estimated crude oil
production for the next two years, and a price ceiling of $83.50 for 45% of the
same level of production. During the three months ended June 30,
2009  and 2008 we recorded total losses on the derivative activities
of $316,409 and $1,895,293, respectively.  The 2009 losses were
comprised of $95,113 of realized gains and $411,552 of unrealized losses,
compared to $350,479 of realized losses and $1,544,814 of unrealized losses for
the comparable 2008 quarter.




Depreciation, depletion,
amortization and accretion. For the three months ended June 30, 2009, we
reflected total depreciation, depletion, and amortization of $279,202 comprised
of $227,999 ($17.36/bbl) related to oil and gas properties, and $51,203 related
to other assets. The comparable amounts for the 2008 period were
$275,841comprised of $225,784 ($17.15/bbl), related to oil and gas properties,
and $50,057 related to other assets) for the corresponding three months ended
June 30, 2008.





General and administrative
expense. For the three months ended June 30, 2009, we reflected general
and administrative expenses of $781,846 as compared to $1,048,376 for the
corresponding three months ended June 30, 2008. Period to period comparisons and
explanations of significant variances follow:





Three
      Months EndedExpense
      Category
                      
                      2009
                      
                      
                      2008
                      
                      
                      DiscussionSalaries,
      payroll taxes and benefits
                      
                      $
                      285,500
                      
                      
                      $
                      400,100
                      
                      
                      Decrease
      reflects lower staff count in 2009 vs. 2008. 2009 period included 24
      man-months, compared to 35 man-months in 2008 periodConsultants
                      
                      
                      29,600
                      
                      
                      
                      125,400
                      
                      
                      Decrease
      reflects cost cutting measures, including decrease in contract accounting
      $53,400; contract land and operations, $22,100 and contract engineering,
      $19,000Travel
      & entertainment
                      
                      
                      2,800
                      
                      
                      
                      31,200
                      
                      
                      Cost
      cutting measure imposed.IT
                      
                      
                      12,400
                      
                      
                      
                      52,500
                      
                      
                      Cancelation
      of software maintenance agreements, $20,000; reduction in outside IT
      consulting and maintenance, $17,500Legal
      fees
                      
                      
                      133,600
                      
                      
                      
                      13,200
                      
                      
                      Increase
      reflects efforts to address threatened lawsuits, contested proxy contest,
      and numerous amendments to amend our Term Credit Agreement with our
      Lender.Audit,
      SOX and tax compliance
                      
                      
                      34,800
                      
                      
                      
                      77,600
                      
                      
                      Decrease
      reflects audit efficiencies in the third year of review and lower costs of
      SOX documentation and testing efforts.Investor
      relations
                      
                      
                      -0-
                      
                      
                      
                      33,600
                      
                      
                      Cancelation
      of contract with outside investor relation firmOffice
      rent, communication  & other office expenses
                      
                      
                      133,300
                      
                      
                      
                      198,600
                      
                      
                      Reduced
      staff count and cost saving measures enacted to conserve
      capitalInsurance
                      
                      
                      57,400
                      
                      
                      
                      38,100
                      
                      
                      Increased
      premiums, primarily D&O insuranceStock
      based compensation
                      
                      
                      142,100
                      
                      
                      
                      143,700
                      
                      
                      
                      -Director
      fees
                      
                      
                      73,300
                      
                      
                      
                      74,200
                      
                      
                      
                      -Field
      overhead recoveries
                      
                      
                      (123,000
                      )
                      
                      
                      (139,800
                      )
                      
                      Fewer
      producing wells in 2009 as compared to 2008, generating overhead
      recoveriesTOTAL
      G&A
                      
                      $
                      781,800
                      
                      
                      $
                      1,048,400




Interest expense and financing
costs.For the three months ended June 30, 2009, we reflected interest
expense and financing costs of $1,077,918 as compared to $1,680,470 for the
corresponding three months ended June 30, 2008. The 2009 amount is comprised of
interest paid on the Note Payable issued in October 2007, as amended, of
$371,569 and amortization of deferred financing costs and discount on Note
Payable of $706,348.  Comparable amounts for the 2008 period
were$371,280 of interest on the Note Payable and $1,309,190 of deferred finance
discount amortization.




Liquidity and CapitalResources




Our
current cash reserves are sufficient to continue operations through the end of
September 2009. Our short-term debt is due in October 2009. If we are not
successful in raising substantial funding or closing a strategic partnering
transaction to address our cash needs and our short-term debt within the
required timeframe, we may need to cease operations.




22




Going
Concern




The
report of our independent registered public accounting firm on the financial
statements for the year ended March 31, 2009 and 2008 includes an explanatory
paragraph relating to the uncertainty of our ability to continue as a going
concern. We have incurred a cumulative net loss of $71.0 million for the period
from inception (February 4, 2004) to June 30, 2009. As of June 30, 2009 we had
cash on hand of $0.6 million, short term debt of $10.1 million and
we


have a
working capital deficit of approximately $10.0 million. Our short term debt in
the amount of $10.1 million has a scheduled maturity date of October 15, 2009.
We require significant additional funding to repay the short term debt and
sustain our current operations. Our ability to continue the Company as a going
concern is dependent upon our ability to obtain additional funding in order to
pay our short term debt and finance our planned operations.





Our
primary source of liquidity to meet operating expenses and fund capital
expenditures is our access to debt and equity markets. The debt and equity
markets, public, private, and institutional, have been our principal source of
capital used to finance a significant amount of growth, including property
acquisitions. We will need substantial additional funding to continue operations
and to pursue our business plan. The recent unprecedented events in global
financial markets have had a profound impact on the global economy. Many
industries, including the oil and natural gas industry, are impacted by these
market conditions. Some of the key impacts of the current financial market
turmoil include contraction in credit markets resulting in a widening of credit
risk, devaluations and high volatility in global equity, commodity, natural
resources and foreign exchange markets, and a lack of market liquidity. A
continued or worsened slowdown in the financial markets or other economic
conditions, including but not limited to, employment rates, business conditions,
lack of available credit, the state of the financial markets and interest rates
may adversely affect our opportunities.





In
October 2007, we issued $12,240,000 of short term debt the proceeds of which
were intended to enhance our existing production and to provide cash reserves
for operations. The debt was scheduled to mature on October 31, 2008. We had
planned to secure longer term fixed rate financing to repay the short term debt
and to commence our EOR development activities in the three fields of the Powder
River Basin; however, due to difficulties in the capital debt markets, we have
been unable to secure such financing. On October 22, 2008 we and the lender
entered into an amendment to the credit agreement to, among other terms, extend
the maturity date by six months, until April 30, 2009. In consideration for the
extension and other terms, we made a principal payment of $2,240,000 reducing
the outstanding balance to $10,000,000. Subsequent the end of our fiscal year we
and the lender entered into a series amendments to the credit agreement
ultimately extending the maturity date to October 15, 2009. We do not have cash
available to repay this loan. If we are not successful in repaying this debt
within the term of the loan, or default under the terms of the loan, the lender
will be able to foreclose one or more of our three properties and other assets
and we could lose the properties. A foreclosure could significantly reduce or
eliminate our property interests or force us to alter our business strategy,
which could involve the sale of properties or working interests in the
properties. A foreclosure would adversely affect our results of operations and
financial condition including a possible termination of business
activities.





Beginning
in March 2008, we reduced our level of staffing by laying off several employees
whose positions were considered to be redundant based upon the anticipated
closing of a farmout transaction with experienced industry operators. Neither
the original nor a subsequently identified farmout transaction was completed;
however we continued field and corporate operations utilizing the remaining
staff and, on a very limited contract basis, the utilization of contract
consultants. At that time our monthly oil and gas production revenue was
adequate to cover monthly field operating costs, production taxes and general
and administrative expenses; however, interest payments on short term debt and
payments relating to our crude oil hedging position resulted in negative cash
flow each month. Crude oil prices which collapsed commencing in August 2008 have
recovered somewhat recently; however at current NYMEX strip prices our expected
future cash flows from crude oil sale are inadequate to cover monthly field
operating costs, production taxes and general and administrative expenses. This
negative cash flow is offset to some extent by proceeds realized from our crude
oil hedging position. This hedge expires in October 2009. Our current cash
reserves are not adequate to fund our operations for the next fiscal
year.




23





We have
executed two agreements to purchase CO2 for use in
EOR operations in our fields. Each contract contains provisions for a take or
pay obligation for the purchase of CO2.  ExxonMobil
has given us notice of termination of their supply agreement. We disagree with
their position and have notified them of our disagreement. As of the date of
this Quarterly Report, we are currently in discussions with Anadarko to amend
the Purchase Contract to minimize or eliminate certain uncertain provisions and
terms of the agreement that are subject to differing interpretations. There is
no assurance we will successfully complete any such amendment and in the event
we do not, we will likely be unable to sustain operations or meet our
obligations under the supply agreement




In August
2009, we filed an Application for Financial Assistance under the U.S. Department
of Energy Funding Opportunity Announcement No. DE-FOA-0000015, Carbon Capture and Sequestration from
Industrial Sources and Innovative Concepts for Beneficial CO2Use(the “FOA”). We
applied for a grant under Phase 1 provisions of the FOA which, if awarded, will
be utilized to complete reservoir engineering studies, drilling and surface
facility design and pipeline design and permitting for one of our Powder River
Basin EOR oil fields. We requested a grant in the amount of $3.72 million,
which is equal to 80% of the $4.65 million Phase 1 budget.  In the
application, we proposed, as our 20% cost share, a “contribution in kind” of
costs previously incurred on pipeline, surface facilities and reservoir studies
equal to $0.93 million.  .   If we are awarded a Phase 1
Grant, we plans to apply for  a Phase 2 grant  in an amount
of up to $175 million to undertake a comprehensive CO2 capture,
transportation, EOR, and sequestration project in thatfield.
We believes our EOR project is well qualified for awards
under the provisions of the FOA; however, there is no assurance that we will
obtain a Phase 1 grant, or if we do obtain a Phase 1 grant, there is no
assurance we will be successful in obtaining a Phase 2
grant.  Further, there is no assurance that if we obtain a Phase 2
grant, that our CO2 capture,
transportation, EOR, and sequestration project will be technically or
commercially successful.




The
following is a summary of Rancher Energy’s comparative cash flows:




For
      the Three Months Ended
              June
      30,2009
            
            
            2008Cash
      flows from (used for):Operating
      activities
            
            $
            (323,754
            )
            
            $
            (1,181,558
            )Investing
      activities
            
            
            10,466
            
            
            
            (347,642
            )Financing
      activities
            
            
            5
            
            
            
            (113,250
            )





Cash
flows used for operating activities decreased substantially as a result of lower
general and administrative and lease operating expenses as discussed above,
coupled with realized derivative gains in the quarter




Investing
activities ion 2009 reflect a modest positive cash flow resulting
from  the sale of surplus field equipment in the period, compared to
oil and gas capital expenditures of $189,579 and expenditures to increase bonds
of $158,063 in the 2008 period.





Cash
flows from financing activities in 2009 reflect proceeds from the exercise of
common stock options, compared to expenditures incurred on deferred financing
costs in the 2008 period.




Off-Balance Sheet
Arrangements




Under the
terms of the Term Credit Agreement entered into in October 2007 we were required
to hedge a portion of our expected production and we entered into a costless
collar agreement for a portion of our anticipated future crude oil production.
The costless collar contains a fixed floor price (put) and ceiling price (call).
If the index price exceeds the call strike price or falls below the put strike
price, we receive the fixed price and pay the market price. If the market price
is between the call and the put strike price, no payments are due from either
party. During the three months ended June 30, 2009, we reflected realized gains
of $95,113 and unrealized gains of $411,522 from the hedging activity, as
compared to realized losses of $350,479 and unrealized losses of $1,544,814 for
the comparable 2008 period.




We have
no other off-balance sheet financing nor do we have any unconsolidated
subsidiaries.




24




Critical Accounting Policies
and Estimates




Critical
accounting policies and estimates are provided in Part II, Item 7, Management’s
Discussion and Analysis of Financial Condition and Results of Operations, to the
Annual Report on Form 10-K for the fiscal year ended March 31, 2009. Additional
footnote disclosures are provided in Notes to Consolidated Financial Statements
in Part I, Financial Information, Item 1, Financial Statements to this Quarterly
Report on Form 10-Q for the three months ended June 30, 2009.




Item
3.  Quantitative and Qualitative Disclosure About Market Risk.




Commodity Price
Risk




Because
of our relatively low level of current oil and gas production, we are not
exposed to a great degree of market risk relating to the pricing applicable to
our oil production. However, our ability to raise additional capital at
attractive pricing, our future revenues from oil and gas operations, our future
profitability and future rate of growth depend substantially upon the market
prices of oil and natural gas, which fluctuate widely. With increases to our
production, exposure to this risk will become more significant. We expect
commodity price volatility to continue. Under the terms of our Term Credit
Agreement we entered into in October 2007, we were required hedge a portion of
our expected future production.




Financial Market
Risk




The debt
and equity markets have recently exhibited adverse conditions. The unprecedented
volatility and upheaval in the capital markets may impact our ability to
refinance or extend our existing short term debt when it matures on October 15,
2009.  Alternatively, market conditions may affect the availability of
capital for prospective purchasers of our assets or equity.




Item
4T.  Controls and Procedures.




Disclosure Controls and
Procedures




We
conducted an evaluation under the supervision and with the participation of our
management, including our Chief Executive Officer and Chief Accounting Officer,
of the effectiveness of the design and operation of our disclosure controls and
procedures. The term “disclosure controls and procedures,” as defined in Rules
13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended
(Exchange Act), means controls and other procedures of a company that are
designed to ensure that information required to be disclosed by the company in
the reports it files or submits under the Exchange Act is recorded, processed,
summarized and reported, within the time periods specified in the Securities and
Exchange Commission’s rules and forms. Disclosure controls and procedures also
include, without limitation, controls and procedures designed to ensure that
information required to be disclosed by a company in the reports that it files
or submits under the Exchange Act is accumulated and communicated to the
company’s management, including its principal executive and principal financial
officers, or persons performing similar functions, as appropriate to allow
timely decisions regarding required disclosure. We identified a material
weakness in our internal control over financial reporting and, as a result of
this material weakness, we concluded as of March 31, 2009 and as of the end of
the period covered by this Quarterly Report that our disclosure controls and
procedures were not effective.




Changes in Internal Control over
Financial Reporting




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




25




PART
II. OTHER INFORMATION.




Item
6.  EXHIBITS.




Exhibit
              
              Description3.1
              
              Amended
      and Restated Articles of Incorporation (1)3.2
              
              Articles
      of Correction (2)3.3
              
              Amended
      and Restated Bylaws (3)4.1
              
              Form
      of Stock Certificate for Fully Paid, Non-Assessable Common Stock of the
      Company (4)4.2
              
              Form
      of Registration Rights Agreement, dated December 21, 2006 (5)4.3
              
              Form
      of Warrant to Purchase Common Stock (5)10.1
              
              Employment
      Agreement between John Works and Rancher Energy Corp., dated June 1, 2006
      (6)10.2
              
              Assignment
      Agreement between PIN Petroleum Partners Ltd. and Rancher Energy Corp.,
      dated June 6, 2006 (6)10.3
              
              Loan
      Agreement between Enerex Capital Corp. and Rancher Energy Corp., dated
      June 6, 2006 (6)10.4
              
              Letter
      Agreement between NITEC LLC and Rancher Energy Corp., dated June 7, 2006
      (6)10.5
              
              Loan
      Agreement between Venture Capital First LLC and Rancher Energy Corp.,
      dated June 9, 2006 (7)10.6
              
              Exploration
      and Development Agreement between Big Snowy Resources, LP and Rancher
      Energy Corp., dated June 15, 2006 (6)10.7
              
              Assignment
      Agreement between PIN Petroleum Ltd. and Rancher Energy Corp., dated June
      6, 2006 (6)10.8
              
              Rancher
      Energy Corp. 2006 Stock Incentive Plan (8)10.9
              
              Rancher
      Energy Corp. 2006 Stock Incentive Plan Form of Option Agreement (8)10.10
              
              Denver
      Place Office Lease between Rancher Energy Corp. and Denver Place
      Associates Limited Partnership, dated October 30, 2006 (9)10.11
              
              Amendment
      to Purchase and Sale Agreement between Wyoming Mineral Exploration, LLC
      and Rancher Energy Corp. (10)10.12
              
              Product
      Sale and Purchase Agreement by and between Rancher Energy Corp. and the
      Anadarko Petroleum Corporation, dated December 15, 2006(11)10.13
              
              Voting
      Agreement between Rancher Energy Corp. and Stockholders identified
      therein, dated as of December 13, 2006 (5)10.14
              
              Rancher
      Energy Corp. 2006 Stock Incentive Plan Form of Restricted Stock Agreement
      (12)10.15
              
              First
      Amendment to Employment Agreement by and between John Works and Rancher
      Energy Corp., dated March 14, 2007 (13)10.16
              
              Employment
      Agreement between Richard Kurtenbach and Rancher Energy Corp., dated
      August 3, 2007(14)10.17
              
              Term
      Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC,
      dated as of October 16, 2007 (15)10.18
              
              Term
      Note made by Rancher Energy Corp. in favor of GasRock Capital LLC, dated
      October 16, 2007 (15)10.19
              
              Mortgage,
      Security Agreement, Financing Statement and Assignment of Production and
      Revenues
      from Rancher Energy Corp. to GasRock Capital LLC, dated as of October 16,
      2007 (16)10.20
              
              Security
      Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated as
      of October 16, 2007 (15)10.21
              
              Conveyance
      of Overriding Royalty Interest by Rancher Energy Corp. in favor of GasRock
      Capital LLC, dated as of October 16, 2007 (15)10.22
              
              ISDA
      Master Agreement between Rancher Energy Corp. and BP Corporation North
      America Inc., dated as of October 16, 2007 (15)10.23
              
              Restricted
      Account and Securities Account Control Agreement by and among Rancher
      Energy Corp., GasRock Capital LLC, and Wells Fargo Bank, National
      Association, dated as of October 16, 2007 (15)10.24
              
              Intercreditor
      Agreement by and among Rancher Energy Corp., GasRock Capital LLC, and BP
      Corporation North America Inc., dated as of October 16, 2007 (15)
  26
  10.25
              
              First
      Amendment to Denver Place Office lease between Rancher Energy Corp. and
      Denver Place Associates Limited Partnership, dated March 6, 2007
      (13)10.26
              
              Carbon
      Dioxide Sale & Purchase Agreement between Rancher Energy Corp. and
      ExxonMobil Gas &  Power Marketing Company, dated effective as of
      February 1, 2008 (Certain portions of this agreement have been redacted
      and have been filed separately with the Securities and Exchange Commission
       pursuant to a Confidential Treatment Request). (16)10.27
              
              Stay
      Bonus Agreements between Rancher Energy Corp. and John Works and Richard
      E. Kurtenbach and all of the Company’s employees, dated October 2,
      2008.(17)10.28
              
              First
      Amendment to Term Credit Agreement between Rancher Energy Corp. and
      GasRock Capital LLC, dated October 22, 2008.(18)10.29
              
              Assignment
      Agreement between Rancher Energy Corp. and Merit Energy Company, LLC,
      dated March 18, 2009.(19)10.30
              
              Termination
      of Carbon Dioxide Sale & Purchase Agreement between Rancher Energy
      Corp. and ExxonMobil Gas & Power Marketing Company, dated April 3,
      2009.(20)10.31
              
              Second
      Amendment to Term Credit Agreement between Rancher Energy Corp. and
      GasRock Capital LLC, dated April 30, 2009.(21)10.32
              
              Third
      Amendment to Term Credit Agreement between Rancher Energy Corp. and
      GasRock Capital LLC, dated May 8, 2009.(22)10.33
              
              Fourth
      Amendment to Term Credit Agreement between Rancher Energy Corp. and
      GasRock Capital LLC, dated May 13, 2009.(23)10.34
              
              Fifth
      Amendment to Term Credit Agreement between Rancher Energy Corp. and
      GasRock Capital LLC, dated May 19, 2009.(24)10.35
              
              Sixth
      Amendment to Term Credit Agreement between Rancher Energy Corp. and
      GasRock Capital LLC, dated May 21, 2009.(25)10.36
              
              Seventh
      Amendment to Term Credit Agreement between Rancher Energy Corp. and
      GasRock Capital LLC, dated May 27 2009.(26)10.37
              
              Eighth
      Amendment to Term Credit Agreement between Rancher Energy Corp. and
      GasRock Capital LLC, dated June 3, 2009.(27)31.1
              
              Certification
      Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Executive
      Officer)*31.2
              
              Certification
      Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Accounting
      Officer)*32.1
              
              Certification
      Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
      the Sarbanes- Oxley Act of 2002*32.2
              
              Certification
      Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
      the Sarbanes- Oxley Act of
2002*




* Filed
herewith.




27




(1)
              Incorporated
      by reference from our Current Report on Form 8-K filed on April 3,
      2007.


(2)
            Incorporated
      by reference from our Form 10-Q for the quarterly period ended September
      30, 2007.


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


(4)
            Incorporated
      by reference from our Form SB-2 Registration Statement filed on June 9,
      2004.


(5)
            Incorporated
      by reference from our Current Report on Form 8-K filed on December 27,
      2006.


(6)
            Incorporated
      by reference from our Annual Report on Form 10-K filed on June 30,
      2006.


(7)
            Incorporated
      by reference from our Current Report on Form 8-K filed on June 21,
      2006.


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


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


(10)
            Incorporated
      by reference from our Current Report on Form 8-K filed on December 4,
      2006.


(11)
            Incorporated
      by reference from our Current Report on Form 8-K filed on December 22,
      2006.


(12)
            Incorporated
      by reference from our Annual Report on Form 10-K filed on June 29,
      2007.


(13)
            Incorporated
      by reference from our Current Report on Form 8-K filed on March 20,
      2007.


(14)
            Incorporated
      by reference from our Current Report on Form 8-K filed on August 7,
      2007.


(15)
            Incorporated
      by reference from our Current Report on Form 8-K filed on October 17,
      2007.


(16)
            Incorporated
      by reference from our Current Report on Form 8-K filed on February 14,
      2008.


(17)
            Incorporated
      by reference from our Current Report on Form 8-K filed on October 3,
      2008.


(18)
            Incorporated
      by reference from our Current Report on Form 8-K filed on October 23,
      2008.


(19)
            Incorporated
      by reference from our Current Report on Form 8-K filed on March 24,
      2009.


(20)
            Incorporated
      by reference from our Current Report on Form 8-K filed on April 9,
      2009.


(21)
            Incorporated
      by reference from our Current Report on Form 8-K filed on April 30,
      2009.


(22)
            Incorporated
      by reference from our Current Report on Form 8-K filed on May 11,
      2009.


(23)
            Incorporated
      by reference from our Current Report on Form 8-K filed on May 14,
      2009.


(24)
            Incorporated
      by reference from our Current Report on Form 8-K filed on May 20,
      2009.


(25)
            Incorporated
      by reference from our Current Report on Form 8-K filed on May 22,
      2009.


(26)
            Incorporated
      by reference from our Current Report on Form 8-K filed on May 28,
      2009.


(27)
            Incorporated
      by reference from our Current Report on Form 8-K filed on June 5,
      2009.





28




SIGNATURES




Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized.




RANCHER ENERGY CORP.,
      RegistrantDated: August 19,
      2009
            By:
            /s/ John WorksJohn
      Works, President, Chief Executive Officer,Chief
      Financial Officer, Secretary and Treasurer(Principal
      Executive Officer)Dated: August 19,
      2009
            By:
            /s/ Richard E.
    KurtenbachRichard
      E. Kurtenbach, Chief Accounting Officer(Principal
      Accounting Officer)





29