UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


Washington,
D.C. 20549




FORM
10-K




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







For the
fiscal year ended March 31, 2009


or


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





For the
transition period from __________ to __________




Commission
file number: 000-51425




RANCHER
ENERGY CORP.


(Exact
name of registrant as specified in its charter)




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





999-18th
Street, Suite 3400


Denver,
Colorado 80202


(Address
of principal executive offices, including zip code)




(303)
629-1125


(Telephone
number, including area code)




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


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





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




Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. Yes oNo x




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




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





Indicate by check mark 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 during the preceding 12 months (or for
such shorter period that the registrant was required to submit and post such
files). YesoNoo





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




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




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




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




The
aggregate market value of the voting and non-voting common equity held by
non-affiliates computed by reference to the price at which the common equity was
last sold, or the average bid and asked price of such common equity, as of the
last business day of the registrant’s most recently completed second fiscal
quarter ended September 30, 2008 was $16,722,025.




The
number of shares outstanding of the registrant’s common stock as of June
30, 2009 was 119,516,723.




DOCUMENTS
INCORPORATED BY REFERENCE




Portions
of the Proxy Statement for the  2009 Annual Meeting of Stockholders
are incorporated by reference into Part III of this Form 10-K.










TABLE
OF CONTENTS





PAGE NO.PART
      IITEM
      1.
                BUSINESS
                
                2ITEM
      1A.
                RISK
      FACTORS
                
                8ITEM
      1B.
                UNRESOLVED
      STAFF COMMENTS
                
                13ITEM
      2.
                PROPERTIES
                
                13ITEM
      3.
                LEGAL
      PROCEEDINGS
                
                16ITEM
      4.
                SUBMISSION
      OF MATTERS TO A VOTE OF SECURITY HOLDERS
                
                16PART
      IIITEM
      5.
                MARKET
      FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
      PURCHASES OF EQUITY SECURITIES
                
                16ITEM
      6.
                SELECTED
      FINANCIAL DATA
                
                19ITEM
      7.
                MANAGEMENT’S
      DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
      OPERATIONS
                
                19ITEM
      7A.
                QUANTITATIVE
      AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
                
                30ITEM
      8.
                FINANCIAL
      STATEMENTS AND SUPPLEMENTARY DATA
                
                30ITEM
      9.
                CHANGES
      IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
      DISCLOSURE
                
                30ITEM
      9A(T).
                CONTROLS
      AND PROCEDURES
                
                31ITEM
      9B.
                OTHER
      INFORMATION
                
                32PART
      IIIITEM
      10.
                DIRECTORS,
      EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
                
                32ITEM
      11.
                EXECUTIVE
      COMPENSATION
                
                33ITEM
      12.
                SECURITY
      OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
      STOCKHOLDER MATTERS
                
                33ITEM
      13.
                CERTAIN
      RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
      INDEPENDENCE
                
                33ITEM
      14.
                PRINCIPAL
      ACCOUNTING FEES AND SERVICES
                
                33PART
      IVITEM
      15.
                EXHIBITS,
      FINANCIAL STATEMENT SCHEDULES
                
                34




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




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





i





PART
I




CAUTIONARY
STATEMENT REGARDING FORWARD-LOOKING STATEMENTS




The
statements contained in this Annual Report on Form 10-K that are not historical
are “forward-looking statements”, as that term is defined in Section 27A of the
Securities Act of 1933, as amended (the Securities Act), and Section 21E of the
Securities Exchange Act of 1934, as amended (the Exchange Act), that involve a
number of risks and uncertainties.




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




·
            business
      strategy;


·
            ability
      to 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
      CO2injection;


·
            ability to obtain permits and
      governmental approvals;


·
            technology;


·
            financial
      strategy;


·
            realized oil
      prices;


·
            production;


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


·
            availability and costs of
      drilling rigs and field
services;


·
            future operating results;
      and


·
            plans, objectives, expectations,
      and intentions.





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




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




1




ITEM
      1.  BUSINESS




The
Company




We are an
independent energy company engaged in the development, production, and marketing
of oil and gas in North America. Our business strategy is to use modern tertiary
recovery techniques on older, historically productive fields with proven
in-place oil and gas. Higher oil and gas prices and advances in technology such
as 3-D seismic acquisition and evaluation and carbon dioxide (CO2) injection
and sequestration, should position us to capitalize on attractive sources of
potentially recoverable oil and gas.




We
operate three fields in the Powder River Basin, Wyoming, which is located in the
Rocky Mountain region of the United States. The fields, acquired in December
2006 and January 2007, are the South Glenrock B Field, the Big Muddy Field, and
the Cole Creek South Field. All three fields currently produce some oil and are
CO2
tertiary recovery candidates. We plan to substantially increase production in
our fields by using CO2 injection
and other enhanced oil recovery (EOR) techniques. To fund the acquisition of the
three fields and our operating expenses, from June 2006 through January 2007, we
sold $89,300,000 of our securities in two private placements. In December 2006,
we also entered into an agreement with Anadarko Petroleum Corporation (Anadarko)
to supply us with CO2 needed to
conduct CO2 tertiary
recovery operations in our three fields. In February 2008, we entered into a
Carbon Dioxide Sale and Purchase Agreement with ExxonMobil Gas and Power
Marketing, (ExxonMobil), a division of ExxonMobil Corporation, to supply
additional CO2to the
three fields. We are seeking financing or strategic joint venture partners to
enable us to construct a pipeline to deliver CO2 to our
fields and to drill additional wells and construct necessary infrastructure
improvements in order to implement EOR techniques.




Led by an
experienced management team and complimented by a consultant with particular
knowledge in each aspect of the EOR process, our long term goal is to enhance
stockholder value by identifying and further developing productive oil and gas
assets across North America, particularly in the Rocky Mountains. Our
headquarters office is located in Denver, Colorado where we employ 5 persons and
our field office is located in Glenrock, Wyoming, where we employ 3
persons.




Incorporation and
Organization




We were
incorporated on February 4, 2004, as Metalex Resources, Inc., in the State of
Nevada. Prior to April 2006, we were engaged in the exploration of a gold
prospect in British Columbia, Canada. Metalex found no commercially exploitable
deposits or reserves of gold. During April 2006, our stockholders voted to
change our name to Rancher Energy Corp.




Business
Strategy





We need
substantial additional funding or to enter into another type of strategic
transaction to be able to repay our short term debt and to continue
operations.   In October 2007 we raised approximately $12.2
million in short-term debt financing to enhance production and provide cash
reserves. While we had intended to raise long-term debt in 2007 to further our
waterflood and CO2 EOR plans,
weakness in the capital market conditions contributed to our change in strategy
to raise short-term financing.  The raising of future funding is
dependent on many factors, some of which are outside our control and are not
assured. One major factor is the level of and projected trends in oil prices,
which we cannot protect against by using hedging at this time.  Our
short term debt was originally scheduled to mature on October 31,
2008.  On October 22, 2008, we and the Lender entered into an
amendment to the credit agreement to extend the maturity for six months until
April 30, 2009. One June 3, 2009, we and the Lender further extended the
maturity date of the credit agreement to October 15, 2009.





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




Our short
term business strategy includes the following





·
            Continue
      to explore the potential for a  strategic
      transaction  or financing to repay the Company’s debt and to
      continue operations;





·
            Minimize
      operating and administration costs;





·
            Enhance
      crude oil production and initiate development activities in our
      fields.





Longer
term, assuming we are successful in raising the needed capital, we believe in
these fundamental business strategies and principles:





·
            Commence
      the EOR development of our three oil
fields;





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




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




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




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




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




If we are unsuccessful in obtaining
substantial additional funding or entering into a strategic partnering
arrangement before (i) we exhaust our remaining cash on-hand, which is expected
to occur by the end of September 2009, and (ii) the maturity of our short term
debt in October 2009, we may need to cease operations, our secured lender could
foreclose on our properties and/or a bankruptcy filing could be
made.  If we enter bankruptcy there is no assurance that we will be
successful in emerging from bankruptcy.





Property
Acquisitions




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




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





2




Our
Development Program




We have
completed field studies and economic analysis of the Dakota, Lower Muddy, and
Upper Muddy horizons in the South Glenrock B Field and the Wall Creek horizon of
the Big Muddy Field and have entered into two CO2 supply
agreements. Subject to obtaining additional financing or entering into a
strategic partnering arrangement with experienced industry partners, we intend
to proceed with the tertiary development of our fields. The current planned
order of development is the South Glenrock B Field, the Big Muddy Field, and
then the Cole Creek South Field.




Oil
and Gas Operations




Our three
fields are oil producing, and as further described below in Item 2, are all
candidates for EOR operations including CO2 tertiary
recovery.




CO2Tertiary
Recovery




Our long
term business strategy is to employ modern EOR technology to recover
hydrocarbons that remain behind in mature reservoirs. The acquisition of the
South Glenrock B Field, the Big Muddy Field, and the Cole Creek South Field
located in the Powder River Basin and entry into the CO2 supply
contracts with Anadarko and ExxonMobil were important steps in executing our
business strategy. Important next steps are to either secure debt financing, or
to enter into a strategic partnering arrangement with an experienced industry
partner with the financial resources in a sufficient amount for our development
program, complete the required environmental and regulatory permitting, build a
pipeline to transport CO2 from an
existing CO2 trunk
pipeline to the Glenrock area, build out the field infrastructure appropriate
for CO2 flood
operations, shoot 3-D seismic, if appropriate, and complete the necessary
drilling and well work.




CO2 injection
is one of the most prevalent tertiary recovery mechanisms for producing light
oil. The CO2, at
sufficient pressure, acts as a solvent for the oil causing the oil to be
physically washed from the reservoir rock and produced. The CO2 is then
separated from the oil, compressed and re-injected into the reservoir. This
recycling process allows the reuse of the purchased CO2 several
times during the life of the tertiary operation. In a typical oil field, much of
the original oil in place (OOIP) is left behind after primary production and
waterflood operations. In many cases this is in the range of 50% to 75% of the
OOIP. This oil, in mature reservoirs with extensive data and historic
production, is the target of miscible EOR technology.




Subject
to obtaining additional financing or entering into a strategic partnering
arrangement with experienced industry partners, we plan to complete an
evaluation of the need to conduct a 3-D seismic survey on the South Glenrock B
and Big Muddy Fields in conjunction with the CO2
development program. If carried out the seismic information would be used to
further define reservoir configuration and trapping, thus filling in gaps in the
available information for our fields.




Anadarko CO2Supply
Agreement




As part
of our CO2 tertiary
recovery strategy, on December 15, 2006, we entered into a Product Sale and
Purchase Contract (Purchase Contract) with Anadarko for the purchase of CO2 (meeting
certain quality specifications). We intend to use the CO2 for our
EOR projects.




The
primary term of the Purchase Contract commences upon the later of January 1,
2008, or the date of the first CO2 delivery,
which as of June 30, 2009, had not yet occurred and terminates upon the earlier
of the day on which we have taken and paid for the Total Contract Quantity, as
defined, or 10 years from the commencement date. We have the right to terminate
the Purchase Contract at any time with notice to Anadarko, subject to a
termination payment as specified in the Purchase Contract.




During
the primary term, the “Daily Contract Quantity” is 40 Mmcf per day for a total
of 146 Bcf. CO2 deliveries
are subject to a 25 Mmcf per day take-or-pay provision. Anadarko has the right
to satisfy its own needs before sales to us, which reduces our take or pay
obligation. In the event the CO2 does not
meet certain quality specifications, we have the right to refuse delivery of
such CO2.




For
CO2
deliveries, we have agreed to pay $1.50 per thousand cubic feet, to be adjusted
by a factor that is indexed to the average posted price of Wyoming Sweet oil.
From oil that is produced by CO2 injection,
we have also agreed to convey to Anadarko an overriding royalty interest that
increases over time, not to exceed 5%.





As of the
date of this Annual 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.




3




ExxonMobil CO2Supply
Agreement




On
February 12, 2008 we entered into a Carbon Dioxide Sale and Purchase Agreement
with ExxonMobil Gas & Power Marketing Company (ExxonMobil) that is to
provide us with 70 MMscfd (million standard cubic feet per day) of CO2 for an
initial 10-year period (the “ExxonMobil Agreement”). We intend to use the
CO2for our EOR projects. The primary term of the agreement, which is ten
years, will begin the first day of the month following ExxonMobil’s notice to us
of the completion of the expansion of certain CO2 delivery
facilities by ExxonMobil and that it is prepared to deliver the required daily
quantity as required under the agreement. Either party may extend the agreement
for an additional ten year term following proper notice and agreement to certain
applicable terms of the agreement. Following the commencement of the primary
term, ExxonMobil is obligated to deliver to us at least 70 MMscfd of CO2 per day.
We have agreed to a “take-or-pay” provision under the agreement. For CO2 deliveries
from ExxonMobil, we have agreed to pay a base price plus an Oil Price Factor
which is indexed to the price of West Texas Intermediate crude
oil.





We may
terminate the agreement if ExxonMobil fails to meet our quantity nomination of
CO2
(not to exceed 70 MMscfd per day) for 30 consecutive days except under certain
circumstances. Either party has the right to terminate the agreement at any time
with notice to the other party based on certain circumstances described in the
agreement. ExxonMobil is not obligated to commence delivery of CO2 until we
provide a surety bond equal to four months’ supply of CO2.
ExxonMobil may also request additional financial performance assurances if it
has reasonable grounds for believing that we have ceased to have the financial
resources to meet our obligations under the agreement and ExxonMobil may suspend
delivery of CO2until the
appropriate assurances are provided. ExxonMobil may terminate the agreement if a
requested performance assurance is not provided by us within 30 days of a
request.





On April
3, 2009, we were informed by ExxonMobil that it was terminating the Agreement
based on our failure to provide performance assurances in the form of a letter
of credit.  We believe that the Agreement does not obligate us to
provide any performance assurances until the start-up of CO2 delivery,
which will not occur in 2009.  Accordingly, we disagree with
ExxonMobil’s rationale for purportedly terminating the Agreement and believe in
good faith that ExxonMobil’s termination of the Agreement has not occurred
pursuant to the terms of the Agreement and is unlawful.  We have
notified ExxonMobil of our position.





Merit Energy Company, LLC
Assignment Agreement





On March
18, 2009, we entered into an Assignment Agreement (the “Assignment”) with Merit
Energy Company, LLC, a Delaware limited liability company (“Merit”), for the
assignment by us of a portion of our right, title and interest in and to, and
the assumption by Merit of our obligations related to, the ExxonMobil Agreement
dated as of February 1, 2008. ExxonMobil has consented to the
Assignment.




Under the
terms of the Assignment, Merit may purchase up to 37.5 MMCF per day of carbon
dioxide from ExxonMobil for a two-year term beginning on the Start-up Date, as
defined in the ExxonMobil Agreement (the “Initial Merit Term”). ExxonMobil
will deliver the contract quantities to the existing delivery point at the
interconnect of the ExxonMobil and Merit pipelines near Bairoil,
Wyoming.




The terms
of the Assignment also provide Merit with an option to purchase an additional
6.5 MMCF per day during the Initial Merit Term.  Following the Initial
Merit Term, to the extent we are not using for our own tertiary recovery
purposes any volumes of carbon dioxide we are otherwise obligated, or able to
purchase from ExxonMobil under the Contract, Merit has the option to purchase
from us  so much of such volumes as is elected by Merit on a monthly
basis.  If, during any period in which Merit is purchasing carbon
dioxide volumes under either of these options, an Event of Default (as defined
in the Assignment) occurs, Merit will be entitled to continue to receive the
contracted amounts of carbon dioxide from ExxonMobil for the full term of the
Assignment and we will be required, at Merit’s sole discretion but subject to
ExxonMobil’s rights and remedies under the Contract, to assign our remaining
rights under the Contract to Merit.





CO2Pipeline
Construction and CO2EOR
Related Field Development




Under the
CO2
contracts described above, we have the responsibility for providing pipeline
transportation of purchased CO2 to our
project area. We plan to transport purchased CO2 through an
8 or 12-inch pipeline and we are evaluating alternatives to construct and
operate the pipeline. We have engaged an engineering firm to study potential
routes and configurations. Depending on the final route selection, the pipeline
may range from 50 to 132 miles in length and cost estimates range from $50 to
$132 million.




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




Pipeline
construction is expected to take approximately 4 months for the shorter route
and up to 9 months for the longer route. A number of long lead time items must
be commenced simultaneously to successfully implement our CO2 EOR plans,
including, commencing and completing right of way acquisition - estimated 7-12
months; ordering steel pipe, milling the steel pipe, and delivery of steel pipe
to the construction site - estimated 6 months; finalizing pipeline engineering -
estimated 4-8 months; completing various permitting processes - estimated 6-12
months, and completion of the environmental assessment for the longer route -
estimated 12 months. In addition, the CO2 surface
facilities equipment must be ordered and then constructed. The lead times for
surface facilities equipment can be 9-12 months the majority of which must be
installed prior to commencing the CO2 flood.
Typically, beginning in November and lasting through March, the Wyoming winter
conditions can freeze the ground and make installation and construction of
pipelines and surface facilities increasingly more difficult and significantly
more expensive.




We continue to evaluate two options to
finance construction of the pipeline assuming we are successful in raising
sufficient additional funding to continue operating. One option is to have a
third party build, own, and operate the CO2pipeline. This operator would be
reimbursed for operating expenses and capital investment by way of a
transportation tariff on the CO2delivered, with the tariff varying as
a function of throughput. The second option is for us to construct, own, and
operate the pipeline. We would require substantial additional capital for this
option. We continue to attempt to either borrow funds in a debt financing or to
enter into a strategic partnering arrangement with an experienced industry
partner to fund the development of our fields and, if necessary, to fund the
construction of the CO2pipeline.  There is no
assurance we will be successful either borrowing funds or entering into a
strategic partnering arrangement to fund the development of our fields
construction of the CO2pipeline.




4




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




Financing
Plans




Due to
our limited capital resources, we must raise funds from external sources to
implement our development plans. In October 2007, we borrowed approximately $11
million (after fees and expenses) from GasRock Capital LLC. The loan bears
interest at a rate equal to the greater of (a) 12% per annum and (b) the LIBOR
rate plus 6% per annum. We are required to make monthly interest payments on the
amounts outstanding under this loan. All principal payments and any other unpaid
amounts were due on October 31, 2008, which was the maturity date of the loan.
Our obligations under the loan are secured by a first priority security interest
in all of our properties and assets, including all rights under our oil and gas
leases in our three producing fields and all of our equipment on those
properties. Prior to the October 31, 2008 maturity date we and the Lender agreed
to amend the credit agreement to extend the maturity date to April 30,
2009.  As partial consideration for the extended maturity date, we
repaid approximately $2.2 million of the outstanding balance leaving a principal
balance of $10 million.  As more fully discussed later in this annual
report, subsequent to March 31, 2009, we and the Lender amended the credit
agreement to further extend the maturity date to October 15, 2009.




Due to
difficulties in the capital debt markets, fixed term debt financing has been
unavailable to us to develop our fields. In November 2007 we began to explore
strategic alliances with experienced industry partners under which we would
assign a percentage of our interests in the three fields, in exchange for the
partner’s investment in the fields. We executed a letter of intent with such a
partner in February 2008, the terms of which called for the investment of up to
$83.5 million to earn up to a 55% interest in the fields. That letter of intent
expired on April 30, 2008. We subsequently entered into a second letter of
intent with two different parties which included similar terms for the
development of the fields, but which also included provisions for the
construction of a pipeline from the source of the ExxonMobil CO2to our
three fields. The letter of intent was terminated effective September 20,
2008.





In August
2008, we retained a financial advisor to consider 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 as an operating company is dependent upon raising substantial
additional financing or completing a strategic transaction before (i) we exhaust
our remaining cash on-hand, which is expected to occur by the end of September
2009, and (ii) the maturity or our short term debt in October 2009;however, there is no assurance
that any transaction will be completed.




Federal
and State Regulations




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




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




Regulation of Oil
Exploration and Production




Our
operations are subject to various types of regulation at the Federal, state, and
local levels. Such regulation includes requiring permits for drilling wells,
maintaining bonding requirements in order to drill or operate wells and
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilled, the
plugging and abandoning of wells, and the disposal of fluids used in connection
with operations. Our operations are also subject to various conservation laws
and regulations. These include the regulation of the size of drilling and
spacing units or proration units and the density of wells that may be drilled in
those units and the unitization or pooling of oil and gas properties. In
addition, state conservation laws establish maximum rates of production from oil
and gas wells and generally prohibit the venting or flaring of gas. The effect
of these regulations may limit the amount of oil and gas we can produce from our
wells and may limit the number of wells or the locations at which we can drill.
The regulatory burden on the oil and gas industry increases our costs of doing
business and, consequently, affects our profitability.




5




Federal Regulation of Sales
Prices and Transportation




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




Federal or State
Leases




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




Regulation of Proposed
CO2Pipeline




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




Environmental
Regulations




Public
interest in the protection of the environment has increased dramatically in
recent years. Our oil production and CO2 injection
operations and our processing, handling, and disposal of hazardous materials
such as hydrocarbons and naturally occurring radioactive materials (NORM) are
subject to stringent regulation. We could incur significant costs, including
cleanup costs resulting from a release of hazardous material, third-party claims
for property damage and personal injuries, fines and sanctions, as a result of
any violations or liabilities under environmental or other laws. Changes in or
more stringent enforcement of environmental laws could also result in additional
operating costs and capital expenditures.




Various
Federal, state, and local laws regulating the discharge of materials into the
environment, or otherwise relating to the protection of the environment,
directly impact oil and gas exploration, development, and production operations
and consequently may impact our operations and costs. These regulations include,
among others (i) regulations by the EPA and various state agencies regarding
approved methods of disposal for certain hazardous and nonhazardous wastes; (ii)
the Comprehensive Environmental Response, Compensation and Liability Act,
Federal Resource Conservation and Recovery Act, and analogous state laws that
regulate the removal or remediation of previously disposed wastes (including
wastes disposed of or released by prior owners or operators), property
contamination (including groundwater contamination), and remedial plugging
operations to prevent future contamination; (iii) the Clean Air Act and
comparable state and local requirements, which may result in the gradual
imposition of certain pollution control requirements with respect to air
emissions from our operations; (iv) the Oil Pollution Act of 1990, which
contains numerous requirements relating to the prevention of and response to oil
spills into waters of the United States; (v) the Resource Conservation and
Recovery Act, which is the principal Federal statute governing the treatment,
storage, and disposal of hazardous wastes; and (vi) state regulations and
statutes governing the handling, treatment, storage, and disposal of naturally
occurring radioactive material.




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





Competition
and Markets




We face
competition from other oil companies in all aspects of our business, including
acquisition of producing properties and oil and gas leases, marketing of oil and
gas, obtaining goods, services, and labor. Many of our competitors have
substantially larger financial and other resources. Factors that affect our
ability to acquire producing properties include available funds, available
information about prospective properties, and our standards established for
minimum projected return on investment. Competition is also presented by
alternative fuel sources, including ethanol and other fossil fuels.




The
demand for qualified and experienced field personnel to operate CO2 EOR
techniques, drill wells, and conduct field operations, such as geologists,
geophysicists, engineers, and other professionals in the oil industry, can
fluctuate significantly often in correlation with oil prices, causing periodic
shortages. There have also been shortages of drilling rigs and other equipment,
as demand for rigs and equipment has increased along with the number of wells
being drilled. These factors also cause significant increases in costs for
equipment, services, and personnel. Higher oil prices generally stimulate
increased demand and result in increased prices for drilling rigs, crews and
associated supplies, equipment, and services. We cannot be certain when we will
experience these issues and these types of shortages or price increases,
which could significantly decrease our profit margin, cash flow, and
operating results, or restrict our ability to drill those wells and conduct
those operations that we currently have planned and budgeted.





Available
Information




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




6




Glossary
of Abbreviations and Terms




Anadarko
              
              The
      Anadarko Petroleum Corporation.Bcf
              
              One
      billion cubic feet of natural gas at standard atmospheric
      conditions.CO2
              
              Carbon
      Dioxide.ExxonMobil
              
              ExxonMobil
      Gas & Power Marketing Company, a division of ExxonMobil
      Corporation.ExxonMobil
      Agreement
              
              The
      ExxonMobil Carbon Dioxide Sale and Purchase Agreement.EOR
              
              Enhanced
      oil recovery.Farmout
              
              The
      transfer of all or part of the working interest in a property, in exchange
      for the transferee assuming all or part of the cost of developing the
      property.Field
              
              An
      area consisting of either a single reservoir or multiple reservoirs all
      grouped on or related to the same individual geological structural feature
      and/or stratigraphic condition.Growth
      Capital
              
              Growth
      Capital Partners, L.PMMcf
              
              One
      million cubic feet of natural gas.MMscfd
              
              One
      million standard cubic feet per day of natural gas.Merit
              
              Merit
      Energy Company, LLC,Metalex
              
              Metalex
      Resources, Inc.Miscible
              
              Capable
      of being mixed in all proportions. Water and oil are not miscible. Alcohol
      and water are miscible. CO2 and
      oil can be miscible under the proper conditions.Proved
      reserves
              
              The
      estimated quantities of oil, natural gas, and natural gas liquids which
      geological and engineering data demonstrate with reasonable certainty to
      be commercially recoverable in future years from known reservoirs under
      existing economic and operating conditions.Purchase
      Contract
              
              The
      Anadarko Product Sale and Purchase Contract.Tertiary
      recovery
              
              The
      third process used for oil recovery. Usually primary recovery is the
      result of depletion drive, secondary recovery is from a waterflood, and
      tertiary recovery is an enhanced oil recovery process such as CO2
      flooding.Working
      interest
              
              An
      interest in an oil and gas lease that gives the owner of the interest the
      right to drill and produce oil and gas on the leased acreage and requires
      the owner to pay a share of the costs of drilling and production
      operations. The share of production to which a working interest owner is
      entitled will always be smaller than the share of costs that the working
      interest owner is required to bear, with the balance of the production
      accruing to the owners of
royalties.





7




ITEM
1A.     RISK FACTORS




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




Risks
Related to our Industry, Business and Strategy




If
we are unable to obtain additional financing we will be unable to continue
operations and to repay our short term debt, our secured lender may
foreclose on our properties and/or a bankruptcy filing could be
made.




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. Our current cash position will not be sufficient for us to continue
operations past September 2009,   to repay our short term debt on
the maturity date of October 15, 2009 or to fund the development of our three
properties for CO2 EOR
operations. As a result, we may need to cease operations, our secured
lender may foreclose on our properties and/or a bankruptcy filing could be
made.  There is no assurance that if we enter into the bankruptcy
process we will be successful in emerging from bankruptcy.





If
we are unable to obtain substantial additional funding or enter into a strategic
partnering arrangement, we will be unable to achieve our business
plan.





If we are
successful in obtaining additional financing to meet our cash requirements and
pay-off our short-term debt, we will still require substantial additional
funding or need to enter into a strategic partnering arrangement to achieve our
business plan . Our plan is to obtain financing or to farmout or enter into
another type of transaction to facilitate development of our properties. We have
engaged a financial advisor to assist in financing and other strategic
alternatives, including the possible sale of the Company. If we are unsuccessful
in completing such a strategic transaction, we will need to seek other financing
arrangements the availability of which is unknown. The terms of any financing
arrangement may be on terms unfavorable to us and could restrict our future
business activities and expenditures. A farmout will reduce our ultimate
ownership interest in and future cash flows from the properties. Insufficient
funds will prevent us from implementing our secondary and tertiary recovery
business strategy.




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





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 2008 we repaid
approximately $2.2 million of the debt and we entered into an amendment to the
credit agreement to, among other terms, extend the maturity date until April 30,
2009.  On April 30,2009, May 8, 2009, May 13, 2009, May 19,2009, May
21, 2009 and May 27, 2009 we entered into amendments that extended the maturity
date for short periods of time while we and the Lender finalized negotiations on
a longer term extension. On June 3, 2009 we entered into an amendment that,
among other things, extended 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.





ExxonMobil
has notified us they have terminated the CO2 Sale and
Purchase Agreement.





On April 3, 2009,ExxonMobil informedus, that ExxonMobilwasterminating, effective immediately, theCO2Sale & Purchase
Agreement.ExxonMobil’s purported termination is based on our failure to
provideperformance
assurances in the form of a letter of credit.Wedisagree with ExxonMobil’s rationale for
purportedly terminating the Agreement and believe in good faith that Exxon’s
termination of the Agreement has not occurred pursuant to the terms of the
Agreement and is unlawful.If ExxonMobil does not deliver
CO2in accordance with the Sale &
Purchase Agreement, we may not be able to fully carry out our EOR projects on
our three fields.




Our contracts with our
CO2 suppliers
include significant take-or-pay obligations.




Our
existing contracts with ExxonMobil and Anadarko contain provisions under which
we are required to take delivery of certain volumes of CO2or pay the
seller for the volume difference between the required quantity and the volume
actually purchased. If we are unable to secure sufficient financing to construct
a pipeline and to develop and prepare our properties for the injection of
CO2we
will be unable to take delivery of CO2and our
cash position at that time will not be sufficient to pay for the take-or-pay
volumes.




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




We have
never been profitable. We incurred net losses of $46,341,341 and $13,164,826 for
the fiscal years ended March 31, 2009 and 2008, respectively. We do not
expect to be profitable during the fiscal year ending March 31, 2010 Our
acquisition and development of prospects will require substantial additional
capital expenditures in the future. The uncertainty and factors described
throughout this section may impede our ability to economically acquire, develop,
and exploit oil reserves. As a result, we may not be able to achieve or sustain
profitability or positive cash flows from operating activities in the
future.





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




Our plans
to develop the properties are dependent on the construction of a CO2 pipeline
and a sufficient supply of CO2. We must
arrange for the construction of a CO2 pipeline
on acceptable terms and build related infrastructure. The achievement of these
objectives is subject to numerous uncertainties, including the raising of
sufficient funding for the construction of key infrastructure and working
capital and our reliance on a third party to provide us the requisite CO2, the
supply of which is beyond our control. We may not be able to achieve these
objectives on the schedule we anticipate or at all.




8




Our production is dependent upon
sufficient amounts of CO2and will decline if our access to
sufficient amounts of CO2is limited.




Assuming
we are successful in raising sufficient financing, our long-term growth strategy
is focused on our CO2 tertiary
recovery operations.  The crude oil production from our tertiary
recovery projects depends on having access to sufficient amounts of CO2.  Our
ability to produce this oil would be hindered if our supply of CO2 were
limited due to problems with the supply, delivery, quality of the supplied
CO2,problems with our facilities, including compression equipment, or
catastrophic pipeline failure.  We have
received no CO2to date.  We have agreements with two
CO2suppliers.Our agreement with one of our
suppliers of CO2is complex
and subject to differing interpretations.  It provides that before it
delivers CO2to us, it may satisfy its own CO2needs.  We also have had
discussions with that supplier regarding a different delivery point that is not
resolved.If we are not successful in obtaining the required
amount of CO2to
achieve crude oil production or the crude oil production in the future were to
decline as a result if a decrease in delivered CO2supply, it
could have a material adverse effect on our financial condition and results of
operations and cash flows.




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




The oil
industry is capital intensive. We have made and are required to make substantial
capital expenditures in our business and operations for the development,
production, and acquisition of oil and gas reserves. To date, we have financed
capital expenditures primarily with sales of our equity securities. We intend to
finance our capital expenditures with debt financing or to enter into a
strategic alliance with experienced operators who have access to sufficient
capital to carry out our EOR projects. As of the date of this Annual Report, we
have not been successful in achieving the foregoing.  Our access to
capital is subject to a number of variables, including:




·
            our proved
      reserves;


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


·
            the prices at which the oil is
      sold; and


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




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




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




We
operate three fields in the Powder River Basin, Wyoming. Oil in all three fields
was discovered over fifty years ago and production has been ongoing. Our
strategy is to substantially increase production and reserves in these fields by
using waterflood and CO2EOR
techniques. However, there is a risk that the properties may be significantly
depleted of oil, and if so, our future results could be impacted
negatively.




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




We were
organized in 2004 to explore a gold prospect and in 2006 changed our business
focus to oil and gas development using CO2 injection
technology. Our future financial results depend primarily on (i) our ability to
finance and complete development of the required infrastructure associated with
our three properties in the Powder River Basin, including having a pipeline
built to deliver CO2 to our
fields and the construction of surface facilities on our fields; (ii) the
success of our CO2 injection
program; and (iii) the market price for oil. We cannot predict that our future
operations will be profitable. In addition, our operating results may vary
significantly during any financial period.




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




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




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




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


9


We
may be unable to develop additional reserves.




Our
ability to develop future revenues will depend on whether we can successfully
implement our planned CO2 injection
program. We have no experience using CO2
technology. The Company's properties have not been injected with CO2 in the
past and recovery factors cannot be estimated with precision. Our planned
projects may not result in significant proved reserves or in the production
levels we anticipate.




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




Our
success is dependent, in large part, on the continued services of John Works,
our President & Chief Executive Officer, Richard Kurtenbach our Chief
Accounting Officer and Denise Greer our Land and Operations Manager. There is no
guarantee that any of the members of our management team will remain employed by
us. While we have employment agreements with them, their continued service
cannot be assured. The loss of our senior executives could harm our
business.




Oil
operations are inherently risky.




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




We
are subject to extensive government regulations.




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




·
            the prevention of
      waste;


·
            the discharge of materials into
      the environment;


·
            the conservation of
      oil;


·
            pollution;


·
            permits
      for drilling operations;


·
            underground gas injection
      permits;


·
            drilling bonds;
      and


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




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




Government
regulation and environmental risks could increase our costs.




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




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




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


10


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




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




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




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




Oil
prices may be impacted adversely by new taxes.




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




Shortages of equipment, supplies,
personnel, and delays in construction of the CO2pipeline, construction of surface
facilities, and delivery of CO2could delay or otherwise adversely
affect our cost of operations or our ability to operate according to our
business plans.




We may
experience shortages of field equipment and qualified personnel and delays in
the construction of the CO2 pipeline,
construction of surface facilities, and delivery of CO2, which may
cause delays in our ability to conduct tertiary recovery operations and drill,
complete, test, and connect wells to processing facilities. Additionally, these
costs have sharply increased in various areas. The demand for and wage rates of
qualified crews generally rise in response to the increased number of active
rigs in service and could increase sharply in the event of a shortage. Shortages
of field equipment or qualified personnel, delays in the construction of
the CO2 pipeline,
construction of surface facilities, and delivery of CO2 could
delay, restrict, or curtail our exploration and development operations, which
may materially adversely affect our business, financial condition, and results
of operations.




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




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




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




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


11


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




Risks
Related to our Common Stock




The
trading market for our common stock is very limited, so there is limited
liquidity in our common stock and investors may be unable to sell significant
numbers of shares of our stock.




Although our common stock is currently
traded on the OTC Bulletin Board, it is thinly traded. It has been traded on the
OTC Bulletin Board since early 2006. The average daily trading volume of our
common stock on the OTC Bulletin Board was approximately 152,000 shares per day
over the three month period ended March 31, 2009. We cannot be certain that more
of a market for our common stock will develop, or if developed, that it will be
sustained, or that our stock price will increase.  As a result,
investors cannot expect to liquidate their investments in an orderly manner
regardless of the necessity of doing so.    If we are unable
to sustain a market for our common stock, investors may be unable to sell the
common stock they own, and may lose the entire value of their
investment.




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




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




·
            Actual or anticipated quarterly
      variations in our operating
results;


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


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


·
            Conditions generally affecting
      the oil and gas industry;


·
            The success of our operating
      strategy; and


·
            The operating and stock
      performance of other comparable
  companies.




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




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




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


·
              discuss our future
      expectations;
 ·
              contain projections of our future
      results of operations or of our financial condition;
      and
 ·
              state other “forward-looking”
      information.


12


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




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




In our
annual reports on Form 10-K for the fiscal years ended March 31, 2009 and 2008,
we reported the determination of our management that we had a material weakness
in our internal control over financial reporting. The determination was made by
management that we did not adequately segregate duties of different personnel in
our accounting department due to an insufficient complement of staff and
inadequate management oversight. While we have made progress in remediating the
weakness, we have not completely remediated it, primarily due to limited
resources to add experienced staff.  Until we obtain sufficient
financing we will not be able to correct the material weakness in our
internal control over financial reporting, and our business could be harmed and
the stock price of our common stock could be adversely affected.




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




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




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




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




ITEM
      1B.  UNRESOLVED STAFF
COMMENTS




None.




ITEM
      2.  PROPERTIES




Field
Summaries




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




South Glenrock B
Field




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




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


13


The South
Glenrock B Field is an active waterflood that currently produces approximately
80 BOPD of sweet 35 degree API crude oil. There are 10 active producing wells.
This waterflood unit was developed with a fairly regular 40 acre well spacing
and drilled with modern rotary equipment. The South Glenrock B Field is slated
to be the first of our fields for CO2
development because the waterflood has maintained the reservoir pressure high
enough for CO2 operations
and the relative condition of the facilities, regular well spacing, and
reservoir size make the field a good candidate for CO2
operations. Subject to obtaining financing, we plan to start CO2 injection
in the South Glenrock B Field in calendar year 2011




Big Muddy
Field




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




The Big
Muddy Field is currently producing about 30BOPD of 36 degree API sweet crude
oil, via a stripper operation, from four producing wells. The field was
developed with an irregular well spacing and drilled mostly with cable tools.
There are no facilities of any significance at the field.




The
current reservoir pressure is very low and not sufficient for effective CO2 flooding.
Pending financing, our near-term plans for the Big Muddy Field are to build
facilities and reactivate or drill new injection wells in order to inject
disposal water produced as a result of CO2 operations
in the South Glenrock B Field. The injection of this water should have the
effect of raising the Big Muddy reservoir pressure for the planned CO2 flood. We
also hope to drill or reactivate additional production wells in order to produce
more oil from this reactivated waterflood. The Big Muddy Field requires
unitization prior to a waterflood or a CO2 flood. The
State of Wyoming required us to form two separate units, one for the Wall Creek
formation and one for the Dakota formation, due to the different sizes of the
productive horizons. The unitization was completed in calendar year 2008 and
subject to obtaining financing; we plan to start CO2 injection
in the Big Muddy Field within one to two years after commencing CO2injection
in the South Glenrock B Field.





Cole Creek South
Field




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




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




Production
comes from two units at Cole Creek South. One unit is the Dakota Sand Unit which
is under active waterflood. The other unit is the Cole Creek South Unit which is
a primary production unit. Cole Creek South Field produces, in total,
approximately 100 BOPD of 34 degree API sweet crude oil from8 producing wells.
Production is from the Dakota Sand Unit waterflood and from the Shannon, First
Frontier, Second Frontier, Muddy, and Lakota formations.




The Cole
Creek South Field is presently at reservoir pressure sufficient for miscible
CO2
flooding and the wells are in good working condition. Due to the small size, in
comparison to the South Glenrock B Field and the Big Muddy Field, the Cole Creek
South Field is planned to be the last of these three fields to undergo CO2 flooding.
Subject to obtaining financing, we plan to start CO2 injection
in the Cole Creek South Field in within four to five years after commencing
CO2injection in the South Glenrock B Field.




Oil
and Gas Acreage and Productive Wells




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




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





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


14





Field
                      
                      Number of
                        Gross Oil Wells
                      
                      Number of
                        Net Oil WellsBig
      Muddy Field
                      
                      
                      6
                      
                      6.00South
      Glenrock B Field
                      
                      
                      13
                      
                      12.19Cole
      Creek South Field
                      
                      
                      8
                      
                      8.00Total
      Wells
                      
                      
                      27
                      
                      26.19




Production




The
following table summarizes average volumes and realized prices of oil produced
from our properties and our production costs per barrel of oil.




For
      the Year Ended
                    March 31,2009
                  
                  
                  For
      the Year Ended
                    March 31,2008Net
      oil production (barrels)
                  
                  
                  65,308
                  
                  
                  
                  86,626Average
      realized oil sales price per barrel
                  
                  $
                  78.71
                  
                  
                  $
                  73.24Production
      costs per barrel:Production
      taxes
                  
                  $
                  9.92
                  
                  
                  $
                  8.91Lease
      operating expenses
                  
                  $
                  37.10
                  
                  
                  $
                  33.55




Title
to Properties




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




Environmental
Assessments




We are
cognizant of our environmental responsibilities to the communities in which we
operate and to our shareholders. Prior to the closing of our acquisitions, we
obtained a Phase I environmental review of our properties from
industry-recognized environmental consulting firms. These environmental reviews
were commissioned and received prior to our acquisition of our three Wyoming
fields, which revealed no material environmental problems. As part of our plans
to construct a pipeline to transport CO2 to our
fields we will be required to perform either an environmental assessment or a
more comprehensive environmental impact study of the proposed
pipeline.




Geographic
Segments




All of
our operations are in the continental United States.




Significant
Oil and Gas Purchasers and Product Marketing




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




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


15


Oil
Marketing




The oil
production from our properties is relatively high quality, ranging in gravity
from 34 to 36 degrees, and is low in sulfur. We sell our oil to a crude
aggregator on a month-to-month term. The oil is transported by truck, with loads
picked up daily. The prices we currently receive are based on posted prices for
Wyoming Sweet crude oil, adjusted for gravity, plus approximately $1.70 to $2.30
per barrel.




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





ITEM
      3.   LEGAL PROCEEDINGS




On
December 31, 2008, we received a letter from an attorney representing Sergei
Stetsenko and other shareholders (the “Stetsenko Group”) stating that it was the
opinion of the Stetsenko Group that our Directors and Executive Officers have
acted negligently and contrary to their fiduciary duties.  The letter
threatens a lawsuit and demands that the Directors and our Executive Officers
return all cash and stock received from us, 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.  We deny the allegations and believe that they are without
merit. In February 2009, our Board of Directors established a Special Committee
of the Board (the “Special Committee”) to investigate the
allegations.  The Stetsenko Group has informed us that it intends to
propose an alternate slate of directors at the next meeting of
shareholders.  We 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 our Directors, attorneys
representing a group of persons who purchased approximately $1,800,000 of
securities (in the aggregate) in our private placement offering commenced in
late 2006 alleged that securities laws were violated in that
offering.  Subsequent to March 31, 2009, we entered into tolling
agreements with the purchasers to toll the statutes of limitations applicable to
any claims related to the private placement.  Our Board of Directors
directed the Special Committee to investigate these
allegations.   We believe  the allegations are without
merit.  We 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.




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




None.




PART
II







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




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




Fiscal
      Year 2009
                              
                              High
      Bid
                              
                              
                              Low
      BidFirst
      Quarter
                              
                              $
                              0.53
                              
                              
                              $
                              0.31Second
      Quarter
                              
                              $
                              0.30
                              
                              
                              $
                              0.11Third
      Quarter
                              
                              $
                              0.16
                              
                              
                              $
                              0.02Fourth
      Quarter
                              
                              $
                              0.04
                              
                              
                              $
                              0.02Fiscal Year
      2008First
      Quarter
                              
                              $
                              1.30
                              
                              
                              $
                              0.68Second
      Quarter
                              
                              $
                              0.75
                              
                              
                              $
                              0.31Third
      Quarter
                              
                              $
                              0.84
                              
                              
                              $
                              0.20Fourth
      Quarter
                              
                              $
                              0.69
                              
                              
                              $
                              0.26


16




Stock
Performance Graph




The first
day of public trading of our common stock was January 10, 2006. The graph below
matches the cumulative total return since January 10, 2006 (or December 31, 2005
for the indexes) of holders of our common stock with the cumulative total
returns of the NASDAQ Composite Index and the Dow Jones Wilshire MicroCap
Exploration and Production Index. The graph assumes that the value of the
investment in our common stock and in each of the indexes (including
reinvestment of dividends) was $100 on January 10, 2006 (or December 31, 2005
for the indexes) and tracks it through March 31, 2009. The reported closing
stock price for our common stock on January 10, 2006 was $0.012143, adjusting
for a stock dividend which occurred after that date in January 2006, noted under
“Dividends” below.











Stock Performance Graph
  Data1/10/06
                            
                            3/31/06
                            
                            3/31/07
                            
                            3/31/08
                            
                            3/31/09Rancher
      Energy
                            
                            100.0
                            
                            11,858.7
                            
                            10,952.8
                            
                            3,211.73
                            
                            164.83NASDAQ
      Composite
                            
                            100.0
                            
                            106.8
                            
                            112.3
                            
                            104.67
                            
                            69.83Dow
      Jones Wilshire –
                              MicroCap
      Exploration and
                              Production
                            
                            100.0
                            
                            108.3
                            
                            86.7
                            
                            69.50
                            
                            20.78





Holders





As of
June 17, 2009, there were approximately 201 record owners of our Common Stock.
This does not include any beneficial owners for whom shares may be held in
“nominee” or “street name”.


17


Dividends




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




Recent
Sales of Unregistered Securities




On
May 15, 2006, in conjunction with his employment, we granted John Works,
our President, Chief Executive Officer, and a member of our Board of Directors,
an option to purchase 4,000,000 shares of our common stock at a price of
$0.00001 per share. These options vested over time through May 31, 2009.
The table that follows summarizes the exercise of Mr. Works’ options during the
year ended March 31, 2009:




Exercise Date
                  
                  Number of
                    Options Exercised
                  
                  
                  Exercise Price
                  
                  
                  Aggregate
                    Purchase PriceJune
      2, 2008
                  
                  
                  250,000
                  
                  
                  $
                  0.00001
                  
                  
                  $
                  2.50September
      4, 2008
                  
                  
                  250,000
                  
                  
                  $
                  0.00001
                  
                  
                  $
                  2.50December
      12, 2008
                  
                  
                  250,000
                  
                  
                  $
                  0.00001
                  
                  
                  $
                  2.50





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


18


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




Date of Issue
                    
                    Number of Shares Issued
                    
                    
                    Fair Market Value Per
                      Share at Issue DateJun
      30, 2008
                    
                    
                    239,514
                    
                    
                    $
                    0.31Sep
      30, 2008
                    
                    
                    495,000
                    
                    
                    $
                    0.15Dec
      31, 2008
                    
                    
                    2,653,845
                    
                    
                    $
                    0.026Mar
      31, 2009
                    
                    
                    0
                    *
                    
                    $
                    N/A





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





*All of
the non-employee directors elected to forego stock compensation for the quarter
ended March 31, 2009.





ITEM
6.  SELECTED FINANCIAL DATA





Not
applicable.





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





We must raise substantial financing by
the end of September 2009 before we exhaust our cash on-hand to be able to
continue operations and to repay short term debt due in October
2009.  As noted elsewhere in this Annual Report, we continue to
attempt to raise debt or equity financing or to complete a strategic partnering
arrangement; however, there is no assurance we will be able complete a
transaction in the next three months.




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.




Oil
and Gas Property Acquisitions




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




Cole Creek South Field and
South Glenrock B Field Acquisitions




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




The total
adjusted purchase price was allocated as follows:




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


19


The Cole
Creek South Field is located in Converse County, Wyoming approximately six miles
northwest of the town of Glenrock. The field was discovered in 1948 by the
Phillips Petroleum Company. Current gross production from the Cole Creek South
Field is approximately 100 barrels of oil per day (BOPD) of primarily 34 degree
API sweet crude oil.




The South
Glenrock B Field is also located in Converse County, Wyoming. The field was
discovered in 1950 by Conoco, Inc. Bisected by Interstate 25, the field produces
from the Dakota and Muddy sandstone reservoirs that are draped over a structural
nose with 2,000 feet of relief. Production is maintained by secondary recovery
efforts that were initiated in 1961. Current gross production from the South
Glenrock B Field is approximately 80 BOPD of primarily 35 degree API sweet crude
oil.




Big Muddy Field
Acquisition




On
January 4, 2007, we acquired the Big Muddy Field, which is located in the Powder
River Basin east of Casper, Wyoming. The total purchase price was $25,000,000
and closing costs were $672,638. While the Big Muddy Field was discovered in
1916, future profitable operations are dependent on the application of tertiary
recovery techniques requiring significant amounts of CO2.




The total
adjusted purchase price was allocated as follows:




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





Water
flooding was initiated in the Wall Creek formation in 1957 and later expanded to
the Dakota and Lakota formations. Over 800 completions have occurred in the
field. At the current time, only a few wells are active. The current production
is approximately 30 BOPD of primarily 36 degree API sweet crude
oil.




Outlook
for the Coming Year




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;·
            Renew
      discussions with ExxonMobil to ensure sufficient quantities of CO2will be made available under the
      existing Sale and Purchase Agreement or negotiate a new contract with
      ExxonMobil for the supply of CO2to our three oil
      fields.·
            Continue
      dissussions with Anadarko to  amend  the Anadarko
      Purchase Contract to minimize or eliminate
  uncertainty.




In late
2006 we added operating staff and engaged consultants to conduct field studies
of tertiary development of the three Powder River Basin fields. Through the
early part of 2008 work has focused on field and engineering studies to prepare
for development operations. We also engaged an engineering firm to evaluate
routes and undertake the required front end engineering and design for the
required CO2 pipeline,
as well as another engineering firm to evaluate and design surface facilities
appropriate for CO2 injection.
In 2008 we entered into two separate letters of intent with experienced industry
partners, each of which called for them invest a significant amount to earn a
majority interest in our three fields.  Both letters of intent expired
before closing a transaction.   In anticipation of finalizing an
arrangement with industry partners, under which a partner would provide
financing and operational control of our fields, we reduced our operating staff
in late March 2008. If we are not successful in consummating a transaction with
an industry partner, we will need to obtain other sources of financing. Our
plans for EOR development of our oil fields are dependent on our obtaining
substantial additional funding. In October 2007 we raised approximately $12.2
million in short-term debt financing to enhance production and provide cash
reserves. While we had intended to raise a long-term debt financing in 2007 to
further our waterflood and CO2 EOR plans,
weakness in the capital market conditions contributed to our change in strategy
to raise the short-term financing first, followed by either long-term debt
financing, or a strategic partnering arrangement with experienced industry
partners. The raising of future funding is dependent on many factors, some of
which are outside our control and is not assured. One major factor is the level
of and projected trends in oil prices, which we cannot protect against by using
hedging at this time.





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.


20


If we are
successful in raising financing or closing a strategic partnering arrangement,
we plan to begin CO2
development operations in the South Glenrock B Field followed by the Big Muddy
Field and then Cole Creek South Field. Capital expenditures to implement our
CO2
EOR plan include:




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





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





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





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





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




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




Since the
acquisition of the three fields, other than the agreements with Anadarko and
ExxonMobil for supply of CO2, we have
made neither major capital expenditures nor any firm commitments for future
capital expenditures to date.




Commitments




Anadarko CO2Supply
Agreement




As part
of our CO2 tertiary
recovery strategy, on December 15, 2006, we entered into a Product Sale and
Purchase Contract with Anadarko for the purchase of CO2 (meeting
certain quality specifications) from Anadarko. We intend to use the CO2 for our
EOR projects.




The
primary term of the Purchase Contract commences upon the later of January 1,
2008, or the date of the first CO2 delivery
and terminates upon the earlier of the day on which we have taken and paid for
the Total Contract Quantity, as defined, or 10 years from the commencement date.
We have the right to terminate the Purchase Contract at any time with notice to
Anadarko, subject to a termination payment as specified in the Purchase
Contract.




During
the primary term the “Daily Contract Quantity” is 40 Mmcf per day for a total of
146 Bcf. Carbon dioxide (CO2)
deliveries are subject to a 25 Mmcf per day take-or-pay provision. Anadarko has
the right to satisfy its own needs before sales to us, which reduces our
take-or-pay obligation. In the event the CO2 does not
meet certain quality specifications, we have the right to refuse delivery of
such CO2.





As of the
date of this Annual 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.


21


For
CO2
deliveries we have agreed to pay $1.50 per thousand cubic feet, to be adjusted
by a factor that is indexed to the price of Wyoming Sweet oil. From oil that is
produced by CO2 injection,
we also agreed to convey to Anadarko an overriding royalty interest that
increases over time, not to exceed 5%.




ExxonMobil CO2Supply
Agreement




On
February 12, 2008 we entered into a Carbon Dioxide Sale and Purchase Agreement
with ExxonMobil Gas & Power Marketing Company, a division of ExxonMobil
Corporation, which is to provide us with 70 MMscfd (million standard cubic feet
per day) of CO2 for an
initial 10-year period. We intend to use the CO2for our
EOR projects. The primary term of the agreement, which is ten years, will begin
the first day of the month following ExxonMobil’s notice to us of the completion
of the expansion of certain CO2 delivery
facilities by ExxonMobil and that it is prepared to deliver the required daily
quantity as required under the agreement. Either party may extend the agreement
for an additional ten year term following proper notice and agreement to certain
applicable terms of the agreement. Following the commencement of the primary
term, ExxonMobil is obligated to deliver to us at least 70 MMscfd of CO2 per day.
We have agreed to a “take-or-pay” provision under the agreement. For CO2 deliveries
from ExxonMobil, we have agreed to pay a base price plus an Oil Price Factor
which is indexed to the price of West Texas Intermediate crude
oil.





We may
terminate the agreement if ExxonMobil fails to meet the Company’s quantity
nomination of CO2 (not to
exceed 70 MMscfd per day) for 30 consecutive days except under certain
circumstances. Either party has the right to terminate the agreement at any time
with notice to the other party based on certain circumstances described in the
agreement. ExxonMobil is not obligated to commence delivery of CO2 until we
provide a surety bond equal to four months’ supply of CO2.
ExxonMobil may also request additional financial performance assurances if it
has reasonable grounds for believing that we have ceased to have the financial
resources to meet our obligations under the agreement and ExxonMobil may suspend
delivery of CO2until the
appropriate assurances are provided. ExxonMobil may terminate the agreement if a
requested performance assurance is not provided by us within 30 days of a
request.





Under the
terms of the agreement, ExxonMobil is responsible for paying all taxes and
royalties up to the delivery point except that we are obligated to reimburse
ExxonMobil for 100% of any new, increased, or additional taxes or royalties
incurred up to the delivery point. The CO2 is to be
supplied from ExxonMobil’s LaBarge gas field in Wyoming.




Initially,
the source of funds to fulfill our commitment to purchase CO2from
Anadarko and ExxonMobil will be either the long term debt financing or our
strategic partner. As crude oil production from the fields into which CO2is
injected increases, we anticipate utilizing a portion of the proceeds from the
sale of such crude oil to pay for the CO2.





On April
3, 2009, we were informed by ExxonMobil that it was terminating the Agreement
based on our failure to provide performance assurances in the form of a letter
of credit.  We believe that the Agreement does not obligate us to
provide any performance assurances until the start-up of CO2 delivery,
which will not occur in 2009.  Accordingly, we disagree with
ExxonMobil’s rationale for purportedly terminating the Agreement and believes in
good faith that ExxonMobil’s termination of the Agreement has not occurred
pursuant to the terms of the Agreement and is unlawful.  We have
notified ExxonMobil of our position.


22


Results
of Operations





Rancher
Energy Corp.


Results
of Operations


Years Ended March
31,




2009
                  
                  
                  2008Revenue:Oil
      production (in barrels)
                  
                  
                  65,308
                  
                  
                  
                  86,626Oil
      price (per barrel)
                  
                  $
                  78.71
                  
                  
                  $
                  73.24Oil
      and gas sales
                  
                  $
                  5,140,660
                  
                  
                  $
                  6,344,414Derivative
      gains (losses)
                  
                  
                  1,020,672
                  
                  
                  
                  (956,142
                  )6,161,332
                  
                  
                  
                  5,388,272Operating
      expenses:Production
      taxes
                  
                  
                  647,755
                  
                  
                  
                  772,010Lease
      operating expenses
                  
                  
                  2,423,015
                  
                  
                  
                  2,906,210Depreciation,
      depletion, and amortization
                  
                  
                  1,196,970
                  
                  
                  
                  1,360,737Impairment
      of unproved properties
                  
                  
                  39,050,000Accretion
      expense
                  
                  
                  158,009
                  
                  
                  
                  121,740Exploration
      expense
                  
                  
                  20,108
                  
                  
                  
                  223,564General
      and administrative
                  
                  
                  3,631,581
                  
                  
                  
                  7,538,242Total
      operating expenses
                  
                  
                  47,127,438
                  
                  
                  
                  12,922,503Loss
      from operations
                  
                  
                  (40,966,105
                  )
                  
                  
                  (7,534,231
                  )Other
      income (expense):Liquidated
      damages pursuant to registration rights agreement
                  
                  
                  -
                  
                  
                  
                  (2,645,393
                  )Interest
      expense
                  
                  
                  (1,369,957
                  )
                  
                  
                  (794,693
                  )Amortization
      of deferred financing costs
                  
                  
                  (4,021,767
                  
                  
                  
                  (2,423,389
                  )Interest
      and other income
                  
                  
                  16,489
                  
                  
                  
                  232,880Total
      other income (expense)
                  
                  
                  (5,375,235
                  )
                  
                  
                  (5,630,595
                  )Net
      loss
                  
                  $
                  (46,341,341
                  )
                  
                  $
                  (13,164,826
                  )


23


Year Ended March 31, 2009
Compared to Year Ended March 31, 2008




Overview. For the year ended
March 31, 2009, we reflected a net loss of $46,341,341, or $0.40 per basic and
fully diluted share, as compared to a loss of $13,164,826, or $0.12 per basic
and fully diluted share, for the corresponding year ended March 31,
2008.




Revenue, production taxes, and lease
operating expenses. For the year ended March 31, 2009, we recorded crude
oil sales of $5,140,660 on 65,308 barrels of oil at an average price of $78.71,
as compared to revenues of $6,344,414 on 86,626 barrels of oil at an average
price of $73.24 per barrel in 2008. The year-to-year variance reflects a volume
variance of $(1,561,312) and a price variance of $357,558. The decreased volume
of crude oil sold in 2009 as compared to 2008 primarily reflects mechanical
problems encountered on producing wells and facilities resulting in periodic
production downtime on numerous wells, coupled natural decline in these mature
fields. Production taxes (including ad valorem taxes) of $647,755 in 2009 as
compared to $772,010 in 2008, remained constant at 12% of crude oil sales
revenues. Lease operating expenses decreased in absolute dollar amounts
to $2,423,015 in 2009 as compared to $2,906,210 in 2008; however operating
costs per barrel increased to $37.10 per barrel in 2009 compared to $33.55 per
barrel in 2008. The per barrel increase in  primarily reflects the
costs associated with  the repair and maintenance work carried out on
wells and facilities in our effort to maintain and increase production
levels.




Derivative gains
(losses).In connection with short term debt
financing entered into in October 2007we entered into a crude oil derivative
contract with an unrelated counterparty to set a price floor of $65per 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 theyearendedMarch 31, 2009we recorded totalgainson thederivativeactivities of$1,020,672 comprised of $206,895 of
realized lossesand$1,227,567 of unrealized
gains of  reflecting the reversal of previously recorded unrealized
losses.For the comparable
2008 periods we recorded derivative losses of $956,142  comprised of
realized losses of  $184,535 and unrealized losses of
$771,607




Depreciation, depletion, and
amortization. Depreciation, depletion, and amortization increased
(DD&A) to $1,196,970 in 2009 as compared to $1,360,737 in 2008. In 2009
DD&A is comprised of $1,009,359 of DD&A of oil and gas properties
($15.45/ bbl) and depreciation of furniture and fixtures of $187,610.
Corresponding amounts for 2008 were $1,183,798 of DD&A of oil and gas
properties ($13.66/ bbl) and depreciation of furniture and fixtures of
$176,939.  The per barrel increase in 2009 reflects lower crude oil
reserve volumes in 2009 as compared to 2008.




Impairment of unproved
properties. In conjunction with the periodic assessment of impairment of
unproved properties, we-evaluated the carrying value of our unproved properties
giving consideration to lower crude oil prices and the difficulties encountered
in securing capital to develop the properties.  Accordingly, during
the year ended March 31, 20098 we recorded $39,050,000 of impairment expense of
unproved properties, reflecting the excess of the carrying value over estimated
realizable value of the assets. No such impairment of unproved properties was
recorded for the year ended March 31, 2008. .




Exploration expense. For the
year ended March 31, 2009, we reflected exploration expense. of $20,108 compared
to  of $223,564 in 2008.  The decrease reflects reduced
emphasis on preparation for seismic work in the 2009 period.




General and administrative
expense. For the year ended March 31, 2009 we reflected general and
administrative expenses of $3,631,581 as compared to $7,538,242 for the
corresponding year ended March 31, 2008. Significant components of the 2008-2009
year-to-year variance include:




·
            Salaries
      and benefits - decrease  of $1,984,000 reflecting staff
      reductions carried out in the March-August 2008 time
      period.  Overall staff count was reduced from 24 in March 2008
      to 7 in March 2009;





·
            Share
      based payments – decrease of $680,000 reflecting expenses associated with
      qualified stock options forfeited  by terminated
      employees;





·
            Consultants
      and contractors – decrease of $795,000
  including:


-
      accounting and financial reporting consulting - decrease of $409,000
      compared to  2008 expenses which  included costs
      associated with completion of our S-1 registration statement, not incurred
      in FY 2009;


-consulting
      fees for recruiting services - decrease of $297,000 compared to 2008
      expenses which included costs associated with selection of Board Members
      and certain other staff – no such expenses incurred in FY
      2009;


-IT
      related consulting - decrease of $88,000,
      -reflecting  significantly lower levels of activity and staff
      count  FY 2009 as compared to FY
2008;





·
            Office
      rent – increase of $85,000 reflecting full year effect of larger office
      space commencing mid-year FY
2008


24





·
            Audit
      and professional accounting fees – decrease of $359,000  - FY
      2008  amount included costs associated with the audit of the
      Company’s internal control over financial reporting; costs associated with
      review of our S-1 registration statement and the costs associated with
      predecessor and pre-predecessor audits. FY 2009 expense include only
      routine audit and tax prep fees;





·
            .Investor
      relations – decrease of $74,000 – lower level of activity and termination
      of investor relations consultant in FY
2009;





·
            Travel
      and Entertainment- decrease of $99,000 reflecting lower level of activity
      and lower staff count in FY 2009.




Liquidated damages pursuant to
registration rights agreement.  Our Registration Statement on
Form S-1 was declared effective by the SEC on October 31, 2007 and has been
maintained effective since that date.  Accordingly, we recorded no
liquidated damages pursuant to the registration rights arrangement in the year
ended March 31, 2009, as compared to $2,645,393 in the comparable period in
2008.





Amortization of deferred financing
costs. For the year ended March 31, 2009, we reflected amortization of
deferred financing costs of $4,021,767 as compared to $2,423,389 for the
corresponding year ended March 31, 2008. The amounts include amortization of
deferred finance costs and amortization of the discount on the note payable
related to  the issuance of short term debt in October 2007. The
year-to-year increase reflects a full year of such costs in 2009 as compared to
only 5 months in 2008.).




Interest expense.For the
year ended March 31, 2009 we reflected interest expense of $1,369,957 as
compared to $794,693 reflected in the comparable period of 2008, reflecting the
full year effect of the outstanding debt in2009  compared to only six
months in 2008.




Interest income. For the year
ended March 31, 2009, we reflected interest income of $16,489 as compared to
$232,880 for the corresponding year ended March 31, 2008 reflecting lower
interest earning cash balances in 2009 as compared to 2008.





Liquidity
and Capital Resources




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.




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 $68.7 million
for the period from inception (February 4, 2004) to March 31, 2009. As of March
31, 2009 we had cash on hand of $0.9 million, short term debt of $10 million and
we have a working capital deficit of approximately $8.8 million. The short
term debt which had a scheduled maturity date of  April 30, 2009, has
been extended to 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.


25


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.   The collapse of crude oil prices
commencing in August 2008 and continuing to date has exacerbated the situation,
such that 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.





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. As
discussed in Item 1. BUSINESS, 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 Annual
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 2008,
we retained a financial advisor to consider 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 will be dependent upon completing a strategic transaction;
however, there is no assurance that any transaction will be
completed.





Change in Financial
Condition




In
October 2007 we issued short term debt in the amount of $12.24 million the
proceeds of which were intended to enhance our existing production and to
provide cash reserves for operations. In October 2008, we repaid $2.24 million
of the outstanding balance  and we and the lender amended the credit
agreement to, among other things, extend the maturity date to April 30,
2009.  Subsequent to the end of our fiscal year, March 31, 2009, we
and the lender amended the credit agreement to further extend the maturity date
to October 15, 2009. The debt bears interest at 16% per annum and is secured by
all of our assets.


26


Cash
Flows
 
 The
following is a summary of Rancher Energy’s comparative cash flows:
 
 FortheYearEndedMarch31,2009
                    
                    
                    2008Cash
      flows from (used for)::Operating
      activities
                    
                    $
                    (2,964,942
                    )
                    
                    $
                    (4,586,423
                    )Investing
      activities
                    
                    $
                    (618,791
                    )
                    
                    $
                    (4,681,280
                    )Financing
      activities
                    
                    $
                    (2,341,470
                    )
                    
                    $
                    10,980,185
 
 Analysis of cash flow
changes between 2009 and 2008
  Cash
flows used for operating activities decreased as a result of lower general and
administrative expenses as discussed above, partially offset by payments to
settle derivative activity losses and interest expense incurred in connection
with the October 2007 short term financing.
  Cash
flows used for investing activities decreased in the 2009 period compared to the
2008 period as we expended significantly less on oil and gas properties,
$260,000 in 2009 compared to $4,245,000 in 2008.  In response to our
lack of success in securing additional financing during the period, we have
curtailed capital spending to the minimum required to maintain current levels of
crude oil production.
 
 Cash
flows used for financing activities in 2009 includes the repayment of a portion
of the debt incurred in 2007 ($2,240,000) and financing costs incurred to
complete requirements of the short term debt agreement.  The source of
cash in 2007 represents the proceeds for the short term debt, net of offering
and finance costs.
  27
 
 Capital
Expenditures
  The
following table sets forth certain historical information regarding costs
incurred in oil and gas property acquisition, exploration and development
activities, whether capitalized or expensed.
 
 For the Years Ended March 31,2009
                        
                        
                        2008Exploration
                        
                        $
                        20,108
                        
                        
                        $
                        223,564Development
                        
                        $
                        245,102
                        
                        
                        $
                        4,758,783Acquisitions:Unproved
                        
                        $
                        -
                        
                        
                        $
                        43,088Proved
                        
                        $
                        -
                        
                        
                        $
                        -Total
                        
                        
                        265,280
                        
                        
                        
                        5,025,435Capitalized
      costs associates with asset retirement obligations.
                        
                        $
                        10,481
                        
                        
                        $
                        213,756
 
 Off-Balance
Sheet Arrangements
 
 Under the
terms of the Term Credit Agreement entered into in October 2007 we were required
hedge a portion of our expected production and we entered into a costless collar
agreement for a portion of our anticipated future crude oil production. The
costless collar contains a fixed floor price (put) and ceiling price
(call). If the index price exceeds the call strike price or falls below the put
strike price, we receive the fixed price and pay the market price. If the market
price is between the call and the put strike price, no payments are due from
either party. During the year ended March 31, 2009 we reflected realized losses
of $206,895 and unrealized gains of $1,227,567 from the hedging activity, as
compared to realized losses of $184,535 and unrealized losses of $771,607 for
the comparable 2008 period.
 
 We have
no other off-balance sheet financing nor do we have any unconsolidated
subsidiaries.
 
 Critical
Accounting Policies and Estimates
  We are
engaged in the exploration, exploitation, development, acquisition, and
production of natural gas and crude oil. Our discussion of financial condition
and results of operations is based upon the information reported in our
financial statements. The preparation of these financial statements requires us
to make assumptions and estimates that affect the reported amounts of assets,
liabilities, revenues, and expenses as well as the disclosure of contingent
assets and liabilities as of the date of our financial statements. We base our
decisions, which affect the estimates we use, on historical experience and
various other sources that are believed to be reasonable under the
circumstances. Actual results may differ from the estimates we calculate due to
changing business conditions or unexpected circumstances. Policies we believe
are critical to understanding our business operations and results of operations
are detailed below. For additional information on our significant accounting
policies see Note 1—Organization and Summary of Significant Accounting Policies,
Note 3—Asset Retirement Obligations, and Note 10—Disclosures About Oil and Gas
Producing Activities to the Notes to Financial Statements of our audited
financial statements for the fiscal year ended March 31, 2009 in Part IV, Item
15, of this Annual Report.
  28
 
 Oil and Gas reserve
quantities. Estimated reserve quantities and the related estimates of
future net cash flows are the most important estimates for an exploration and
production company because they affect our perceived value, are used in
comparative financial analysis ratios and are used as the basis for the most
significant accounting estimates in our financial statements. This includes the
periodic calculations of depletion, depreciation, and impairment for our proved
oil and gas assets. Proved oil and gas reserves are the estimated quantities of
crude oil, natural gas, and natural gas liquids which geological and engineering
data demonstrate with reasonable certainty to be recoverable in future periods
from known reservoirs under existing economic and operating conditions. Future
cash inflows and future production and development costs are determined by
applying benchmark prices and costs, including transportation, quality, and
basis differentials, in effect at the end of each period to the estimated
quantities of oil and gas remaining to be produced as of the end of that period.
Expected cash flows are reduced to present value using a discount rate that
depends upon the purpose for which the reserve estimates will be used. For
example, the standardized measure calculation required by SFAS No.69,
Disclosures About Oil and Gas Producing Activities, requires a 10% discount rate
to be applied. Although reserve estimates are inherently imprecise and estimates
of new discoveries and undeveloped locations are more imprecise than those of
established producing oil and gas properties, we make a considerable effort in
estimating our reserves, which are prepared by independent reserve engineering
consultants. We expect that periodic reserve estimates will change in the future
as additional information becomes available or as oil and gas prices and
operating and capital costs change. We evaluate and estimate our oil and gas
reserves at March 31 of each year. For purposes of depletion, depreciation, and
impairment, reserve quantities are adjusted at all interim periods for the
estimated impact of additions and dispositions. Changes in depletion,
depreciation, or impairment calculations caused by changes in reserve quantities
or net cash flows are recorded in the period that the reserve estimates
change.
  Successful efforts method of
accounting. Generally accepted accounting principles provide for two
alternative methods for the oil and gas industry to use in accounting for oil
and gas producing activities. These two methods are generally known in our
industry as the full cost method and the successful efforts method. Both methods
are widely used. The methods are different enough that in many circumstances the
same set of facts will provide materially different financial statement results
within a given year. We have chosen the successful efforts method of accounting
for our oil and gas producing activities and a detailed description is included
in Note 1– Organization and Summary of Significant Accounting Policies to the
Notes to Financial Statements of our audited financial statements for the fiscal
year ended March 31, 2009 in Part IV, Item 15, of this Annual
Report.
  Revenue recognition. Our
revenue recognition policy is significant because revenue is a key component of
our results of operations and our forward-looking statements contained in our
analysis of liquidity and capital resources. We derive our revenue primarily
from the sale of produced crude oil. We report revenue as the gross amounts we
receive for our net revenue interest before taking into account production taxes
and transportation costs, which are reported as separate expenses. Revenue is
recorded in the month our production is delivered to the purchaser, but payment
is generally received between 30 and 90 days after the date of production. No
revenue is recognized unless it is determined that title to the product has
transferred to a purchaser. At the end of each month we make estimates of the
amount of production delivered to the purchaser and the price we will receive.
We use our knowledge of our properties, their historical performance, , NYMEX
and local spot market prices, and other factors as the basis for these
estimates. Variances between our estimates and the actual amounts received are
recorded in the month payment is received.
  Asset retirement obligations.
We are required to recognize an estimated liability for future costs associated
with the abandonment of our oil and gas properties. We base our estimate of the
liability on our historical experience in abandoning oil and gas wells projected
into the future based on our current understanding of Federal and state
regulatory requirements. Our present value calculations require us to estimate
the economic lives of our properties, assume what future inflation rates apply
to external estimates and determine what credit adjusted risk-free rate to use.
The statement of operations impact of these estimates is reflected in our
depreciation, depletion, and amortization and accretion calculations and occurs
over the remaining life of our oil and gas properties.
  Valuation of long-lived and
intangible assets. Our property and equipment is recorded at cost. An
impairment allowance is provided on unproved property when we determine that the
property will not be developed or the carrying value will not be realized. We
evaluate the realizability of our proved properties and other long-lived assets
whenever events or changes in circumstances indicate that impairment may be
appropriate. Our impairment test compares the expected undiscounted future net
revenues from a property, using escalated pricing, with the related net
capitalized costs of the property at the end of each period. When the net
capitalized costs exceed the undiscounted future net revenue of a property, the
cost of the property is written down to our estimate of fair value, which is
determined by applying a discount rate that we believe is indicative of the
current market. Our criteria for an acceptable internal rate of return are
subject to change over time. Different pricing assumptions or discount rates
could result in a different calculated impairment.
  29
 
 Income taxes. We provide for
deferred income taxes on the difference between the tax basis of an asset or
liability and its carrying amount in our financial statements in accordance with
SFASNo.109, Accounting for
Income Taxes. This difference will result in taxable income or deductions
in future years when the reported amount of the asset or liability is recovered
or settled, respectively. Considerable judgment is required in determining when
these events may occur and whether recovery of an asset is more likely than not.
Additionally, our Federal and state income tax returns are generally not filed
before the financial statements are prepared, therefore we estimate the tax
basis of our assets and liabilities at the end of each period as well as the
effects of tax rate changes, tax credits, and net operating and capital loss
carryforwards and carrybacks. Adjustments related to differences between the
estimates we used and actual amounts we reported are recorded in the period in
which we file our income tax returns. These adjustments and changes in our
estimates of asset recovery could have an impact on our results of operations.
Deferred tax assets are reduced by a valuation allowance when, in the opinion of
management, it is more likely than not that some portion or all of the deferred
tax assets will not be realized. To date, we have not recorded any deferred tax
assets because of the historical losses that we have incurred.
  Stock-based compensation. As
of April 1, 2006, we adopted the provisions of SFAS No.123(R). This statement
requires us to record expense associated with the fair value of stock-based
compensation.
  Commodity
Derivatives.  The Company accounts for derivative instruments
or hedging activities under the provisions of Statement of Financial Accounting
Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging
Activities”. SFASNo.133 requires the Company to record derivative instruments at
their fair value. The Company’s risk management strategy is to enter into
commodity derivatives that set “price floors” and “price ceilings” for its crude
oil production. The objective is to reduce the Company’s exposure to commodity
price risk associated with expected crude oil production.
  The
Company has elected not to designate the commodity derivatives to which they are
a party as cash flow hedges, and accordingly, such contracts are recorded at
fair value on its consolidated balance sheets and changes in such fair value are
recognized in current earnings as income or expense as they occur.
  The
Company does not hold or issue commodity derivatives for speculative or trading
purposes. The Company is exposed to credit losses in the event of nonperformance
by the counterparty to its commodity derivatives. It is anticipated, however,
that its counterparty will be able to fully satisfy its obligations under the
commodity derivatives contracts. The Company does not obtain collateral or other
security to support its commodity derivatives contracts subject to credit risk
but does monitor the credit standing of the counterparty. The price we receive
for production in our three fields is indexed to Wyoming Sweet crude oil posted
price. The Company has not hedged the basis differential between the NYMEX price
and the Wyoming Sweet price.
  As of
March 31, 2009, we had a net derivative asset of $455,960 which was
measured based upon our valuation model and, as such, is classified as a Level 3
fair value measurement. We value these Level 3 contracts using a model that
considers various inputs including (a) quoted forward prices for
commodities, (b) time value, (c) volatility factors (d) notional
quantities (e) current market and contractual prices for the underlying
instruments and (f) the counterparty’s and the Company’s credit ratings.
The unobservable inputs related to the volatility of the oil and gas commodity
market are very significant in these calculations. Continued volatility in
these markets could have a significant impact on the fair value of our
derivative contracts.
  ITEM
7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
  Commodity
Price Risk
  Because
of our relatively low level of current oil and gas production, we are not
exposed to a great degree of market risk relating to the pricing applicable to
our oil production. However, our ability to raise additional capital at
attractive pricing, our future revenues from oil and gas operations, our future
profitability and future rate of growth depend substantially upon the market
prices of oil and natural gas, which fluctuate widely. With increases to our
production, exposure to this risk will become more significant. We expect
commodity price volatility to continue. Under the terms of our Term Credit
Agreement we entered into in October 2007, we were required hedge a portion of
our expected future production.
  ITEM
8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
  Our
Consolidated Financial Statements and Supplementary Data required by this Item 8
are set forth following the signature page and exhibit index of this Annual
Report and are incorporated herein by reference.
  ITEM
9.  CHANGES IN AND
DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
 
 None.
 
 30
 ITEM
9A(T).  CONTROLS AND PROCEDURES
 
 Controls
and Procedures.
 
 We
conducted an evaluation under the supervision and with the participation of our
management, including our Chief Executive Officer and Chief Accounting Officer,
of the effectiveness of the design and operation of our disclosure controls and
procedures. The term “disclosure controls and procedures,” as defined in Rules
13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended
(Exchange Act), means controls and other procedures of a company that are
designed to ensure that information required to be disclosed by the company in
the reports it files or submits under the Exchange Act is recorded, processed,
summarized and reported, within the time periods specified in the Securities and
Exchange Commission’s rules and forms. Disclosure controls and procedures also
include, without limitation, controls and procedures designed to ensure that
information required to be disclosed by a company in the reports that it files
or submits under the Exchange Act is accumulated and communicated to the
company’s management, including its principal executive and principal financial
officers, or persons performing similar functions, as appropriate to allow
timely decisions regarding required disclosure. We identified a material
weakness in our internal control over financial reporting and, as a result of
this material weakness, we concluded as of March 31, 2009 that our disclosure
controls and procedures were not effective.
 
 Management’s
Annual Report on Internal Control Over Financial Reporting
 
 Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting. Internal control over financial reporting (as
defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) is defined as a process
designed by, or under the supervision of, a company’s principal executive and
financial officers, or persons performing similar functions, and effected by a
company’s board of directors, management and other personnel, to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external reporting purposes in
accordance with generally acceptable accounting principles and includes those
policies and procedures that:
 
 a)
              pertain to the maintenance of
      records that, in reasonable detail, accurately and fairly reflect the
      transactions and dispositions of the assets of the
      company;
 b)
              provide reasonable assurance that
      transactions are recorded as necessary to permit preparation of financial
      statements in accordance with generally accepted accounting principles,
      and that receipts and expenditures of the company are being made only in
      accordance with authorizations of management and directors of the company;
      and
 c)
              provide reasonable assurance
      regarding prevention or timely detection of unauthorized acquisition, use
      or disposition of the company’s assets that could have a material effect
      on the financial statements.
 
 Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
  31
  Management
assessed the effectiveness of the Company’s internal control over financial
reporting as of March 31, 2009. In making this assessment, management used the
criteria set forth by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO) in Internal
Control-Integrated Framework.
 
 A
material weakness is a control deficiency, or combination of control
deficiencies, that result in more than a remote likelihood that a material
misstatement of annual or interim financial statements will not be prevented or
detected. As of March 31, 2009, the Company identified the following material
weakness:
 
 We
did not adequately segregate the duties of different personnel within our
Accounting Department due to an insufficient complement of staff and inadequate
management oversight.
 
 We have
limited accounting personnel with sufficient expertise in generally accepted
accounting principles to enable effective segregation of duties with respect to
recording journal entries and to allow for appropriate monitoring of financial
reporting matters and internal control over financial reporting. Specifically,
the Chief Accounting Officer has involvement in the creation and review of
journal entries and note disclosures without adequate independent review and
authorization. This control deficiency is pervasive in nature and impacts all
significant accounts. This control deficiency also affects the financial
reporting process including financial statement preparation and the related note
disclosures.
  As a
result of the aforementioned material weakness, management concluded that the
Company’s internal control over financial reporting as of March 31, 2009 was not
effective.
 
 Management’s
Planned Corrective Actions
 
 In
relation to the material weakness identified above, and subject to obtaining
permanent financing, our management and the board of directors intend to work to
remediate the risk of a material misstatement in financial reporting. Subject to
obtaining permanent financing, we intend to implement the following plan to
address the risk of a material misstatement in the financial
statements:
 
 ·
              Engage
      qualified accounting staff to prepare  journal entries and note
      disclosures thereby enabling our Chief Accounting Officer the opportunity
      to independently review and authorize such entries and disclosures prior
      to entering the information into the accounts and financial statement
      disclosures,
 
 ·
              Engage qualified third-party
      accountants and consultants to assist us in the preparation and review of
      our financial information,
 
 ·
              Ensure employees, third-party
      accountants and consultants who are performing controls understand
      responsibilities and how to perform said responsibilities,
      and
 
 ·
              Consult with qualified
      third-party accountants and consultants on the appropriate application of
      generally accepted accounting principles for complex and non-routine
      transactions.
 
 Auditors
Attestation
 
 This
annual report does not include an attestation report of the Company’s registered
public accounting firm regarding internal control over financial reporting.
Management’s report was not subject to attestation by the Company’s registered
public accounting firm pursuant to temporary rules of the Securities and
Exchange Commission that permit the Company to provide only management’s report
in this annual report.
 
 Changes
in Internal Control over Financial Reporting
  There
have been no changes in our internal control over financial reporting during the
most recently completed fiscal quarter that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.
 
 ITEM
9B.  OTHER INFORMATION
  None.
  PART
III
  ITEM
10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE
  Information
required by this Item with respect to the Company’s directors, executive
officers, certain family relationships, and compliance by the Company’s
directors, executive officers and certain beneficial owners of the Company’s
common stock with Section 16(a) of the Exchange Act is incorporated by
reference to all information under the captions entitled “Directors, Officers
and Corporate Governance” and “Compliance with Section 16(a) of the Securities
Act of 1934” from our Proxy Statement relating to our  2009 Annual
Meeting of Stockholders.  (“Proxy Statement”) that is expected to be
filed in July 2009.
  32
 
 The
information regarding our Audit Committee, including our audit committee
financial expert and our director nomination process, is incorporated herein by
reference to all information under the caption entitled “Audit Committee”
included in our Proxy Statement.
  We have
adopted a Code of Business Conduct and Ethics for Directors, Officers, and
Employees. We undertake to provide any person, without charge, a copy of the
Code of Business Conduct and Ethics. Requests should be submitted in writing to
the attention of our Chief Accounting Officer, Rancher Energy Corp.,
999-18th Street, Suite 3400, Denver, Colorado 80202.
  ITEM
11.  EXECUTIVE COMPENSATION
  The
information required by Item 11 is hereby incorporated herein by reference to
the information under the caption “Executive Compensation” included in the Proxy
Statement.
 
 ITEM 12.  SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
  The
information required by Item 12, as to certain beneficial owners and management,
is hereby incorporated herein by reference to the information under the caption
“Security Ownership of Directors and Executive Officers” included in the Proxy
Statement.
  ITEM
13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
INDEPENDENCE
  The
information required by Item 13 is hereby incorporated herein by reference to
the information under the caption “Certain Relationships and Related
Transactions” and “Director Independence” included in the Proxy
Statement.
  ITEM
14.  PRINCIPAL ACCOUNTING FEES AND SERVICES
  The
information required by Item 14 is hereby incorporated herein by reference to
the information under “Proposal #2 - Ratification of the Appointment of
Independent Registered Accountant” included in the Proxy
Statement.
  33
  PART
IV
  ITEM
15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES
  (a) Documents filed as a part of the
report:
  (1)
              Index to Consolidated Financial
      Statements of the Company
  An “Index to
Consolidated Financial Statements” has been filed as a part of this Report
beginning on page F-1 hereof.
  (2)
              All schedules for which provision
      is made in the applicable accounting regulation of the SEC have been
      omitted because of the absence of the conditions under which they would be
      required or because the information required is included in the
      consolidated financial statements of the Registrant or the notes
      thereto.
  (3)
              Exhibits
  Exhibit
              
              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)
  34
  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)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)23.1
                              
                              Consent
      of Ryder Scott Company, L.P., Independent Petroleum
      Engineers*31.1
                              
                              Certification
      Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Executive
      Officer)*31.2
                              
                              Certification
      Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Accounting
      Officer)*32.1
                              
                              Certification
      pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
      the Sarbanes-Oxley Act of 2002*32.2
                              
                              Certification
      pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
      the Sarbanes-Oxley Act of
2002*
 
 * Filed
herewith.
  35
  (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.
  36
  SIGNATURES
  Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this Annual Report to be signed on its
behalf by the undersigned, thereunto duly authorized, this 14th day of July,
2009.
 
 RANCHER
      ENERGY CORP./s/ John WorksJohn
      Works, President, Chief Executive Officer,Principal
      Executive Officer, Chief Financial Officer,Principal
      Financial Officer, Director, Secretary,and
      Treasurer
 
 Pursuant
to the requirements of the Securities Exchange Act of 1934, this Annual Report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
  Signature
                  
                  Title
                  
                  Date/s/ John Works
                  
                  President,
      Chief Executive Officer,
                  
                  7/14/2009John
      Works
                  
                  Principal
      Executive Officer, Chief Financial
      Officer,

                      Principal Financial
      Officer, Director,
                    Secretary,
      and Treasurer/s/Richard KurtenbachRichard
      E. Kurtenbach
                  
                  Chief
      Accounting Officer and Principal Accounting Officer
                  
                  7/14/2009/s/ William A. AndersonWilliam
      A. Anderson
                  
                  Director
                  
                  7/14/2009/s/ Joseph P. McCoyJoseph
      P. McCoy
                  
                  Director
                  
                  7/14/2009/s/ Patrick M. MurrayPatrick
      M. Murray
                  
                  Director
                  
                  7/14/2009/s/ Myron M. SheinfeldMyron
      M. Sheinfeld
                  
                  Director
                  
                  7/14/2009/s/ Mark WortheyMark
      Worthey
                  
                  Director
                  
                  7/14/2009
  37
  EXHIBIT
INDEX
  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)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)23.1
                
                Consent
      of Ryder Scott Company, L.P., Independent
      Petroleum Engineers*31.1
                
                Certification
      Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Executive
      Officer)*31.2
                
                Certification
      Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Accounting
      Officer)*32.1
                
                Certification
      pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
      the Sarbanes-Oxley Act of 2002*32.2
                
                Certification
      pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
      the Sarbanes-Oxley Act of
2002*
  * Filed
herewith.
  (1)
                Incorporated by reference from
      our Current Report on Form 8-K filed on April 3,
      2007.
 
 (2)
                Incorporated by reference from
      our Form 10-Q for the quarterly period ended September 30,
      2007.
 
 (3)
                Incorporated by reference from
      our Current Report on Form 8-K filed on December 18,
      2006.
 
 (4)
                Incorporated by reference from
      our Form SB-2 Registration Statement filed on June 9,
      2004.
 
 (5)
                Incorporated by reference from
      our Current Report on Form 8-K filed on December 27,
      2006.
 
 (6)
                Incorporated by reference from
      our 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.




INDEX
TO FINANCIAL STATEMENTS





Audited
      Financial Statements - Rancher Energy Corp.Report
      of Independent Registered Public Accounting Firm
              F-2Balance
      Sheets as of March 31, 2009 and 2008
              F-3Statements
      of Operations for the Years Ended March 31, 2009 and
    2008
              F-4Statement
      of Changes in Stockholders’ Equity (Deficit) for the Years Ended
      March 31, 2009 and 2008
              F-5Statements
      of Cash Flows for the Years Ended March 31, 2009 and
    2008
              F-6Notes
      to Financial Statements
              F-7


F-1


REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM







To the
Board of Directors and Stockholders
 Rancher
Energy Corp.
 
 
 We have
audited the accompanying balance sheets of Rancher Energy Corp. (the
“Company”) as of March 31, 2009 and 2008, and the related statements of
operations, stockholders’ equity, and cash flows for each of the two years in
the period ended March 31, 2009.  These financial statements are the
responsibility of the Company’s management.  Our responsibility is to
express an opinion on these financial statements based on our
audits.
 
 We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States).  Those standards require
that we plan and perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement.  An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements.  An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement
presentation.  We believe that our audits provide a reasonable basis
for our opinion.
 
 In our
opinion, the financial statements referred to above present fairly, in all
material respects, the financial position of Rancher Energy Corp. as of March
31, 2009 and 2008, and the results of its operations and its cash flows for
each of the two years in the period ended March 31, 2009, in conformity with
U.S. generally accepted accounting principles.
 
 We were
not engaged to examine management’s assessment of the effectiveness of Rancher
Energy Corp.’s internal control over financial reporting as of March 31, 2009,
included in the accompanying Management Report on Internal Controls and,
accordingly, we do not express an opinion thereon.
 
 The
accompanying financial statements have been prepared assuming that the Company
will continue as a going concern.  As discussed in Note 1 to the
financial statements, the Company has suffered recurring losses from operations
and has a working capital deficit and will require significant additional
funding to repay its short-term debt and for planned oil and gas development
operations.  These factors raise substantial doubt about the Company’s
ability to continue as a going concern.  Management’s plans in regard
to these matters are also described in Note 1.  The financial
statements do not include any adjustments that might result from the outcome of
this uncertainty.
 
 
 HEIN & ASSOCIATES
LLP
 
 Denver,
Colorado
 July 13,
2009







F-2




Rancher
Energy Corp.




Balance
Sheets





March 31,2009
                    
                    
                    2008ASSETSCurrent
      assets:Cash
      and cash equivalents
                    
                    $
                    917,160
                    
                    
                    $
                    6,842,365Accounts
      receivable and prepaid expenses
                    
                    
                    584,139
                    
                    
                    
                    1,170,641Derivative
      receivable
                    
                    
                    455,960
                    
                    
                    
                    -Total
      current assets
                    
                    
                    1,957,259
                    
                    
                    
                    8,013,006Oil
      and gas properties (successful efforts method):Unproved
                    
                    
                    53,328,147
                    
                    
                    
                    54,058,073Proved
                    
                    
                    20,631,487
                    
                    
                    
                    20,734,143Less:
      Accumulated depletion, depreciation, amortization and
      impairment
                    
                    
                    (41,840,978
                    )
                    
                    
                    (1,531,619
                    )Net
      oil and gas properties
                    
                    
                    32,118,656
                    
                    
                    
                    73,260,597Furniture
      and equipment, net of accumulated depreciation of $381,396 and $204,420,
      respectively
                    
                    
                    770,354
                    
                    
                    
                    997,196Other
      assets
                    
                    
                    933,592
                    
                    
                    
                    1,300,382Total
      other assets
                    
                    
                    1,703,946
                    
                    
                    
                    2,297,578Total
      assets
                    
                    $
                    35,779,861
                    
                    
                    $
                    83,571,181LIABILITIES AND STOCKHOLDERS’
      EQUITYCurrent
      liabilities:Accounts
      payable and accrued liabilities
                    
                    $
                    816,808
                    
                    
                    $
                    2,114,204Accrued
      oil and gas property costs
                    
                    
                    -
                    
                    
                    
                    250,000Asset
      retirement obligation
                    
                    
                    108,884
                    
                    
                    
                    337,685Derivative
      liability
                    
                    
                    -
                    
                    
                    
                    590,480Note
      payable, net of unamortized discount of $165,790 and $2,527,550,
      respectively
                    
                    
                    9,834,210
                    
                    
                    
                    9,712,450Total
      current liabilities
                    
                    
                    10,759,902
                    
                    
                    
                    13,004,819Long-term
      liabilities:Derivative
      liability
                    
                    
                    -
                    
                    
                    
                    246.553Asset
      retirement obligation
                    
                    
                    1,171,796
                    
                    
                    
                    922,166Total
      long-term liabilities
                    
                    
                    1,171,796
                    
                    
                    
                    1,168,719Commitments
      and contingencies (Note 6)Stockholders’
      equity:Common
      stock, $0.00001 par value, 275,000,000 and 100,000,000 shares authorized
      at March 31, 2009 and 2008 ; 119,016,700  and 114,878,341 shares
      issued and outstanding at March 31, 2009 and 2008,
      respectively
                    
                    
                    1,191
                    
                    
                    
                    1,150Additional
      paid-in capital
                    
                    
                    92,582,001
                    
                    
                    
                    91,790,181Accumulated
      deficit
                    
                    
                    (68,735,029
                    )
                    
                    
                    (22,393,688
                    )Total
      stockholders’ equity
                    
                    
                    23,848,163
                    
                    
                    
                    69,397,643Total
      liabilities and stockholders’ equity
                    
                    $
                    35,779,861
                    
                    
                    $
                    83,571,181





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


F-3


Rancher
Energy Corp.


Statements
of Operations





For the Years Ended
      March 31,2009
                  
                  
                  2008Revenue:Oil
      and gas sales
                  
                  $
                  5,140,660
                  
                  
                  $
                  6,344,414Gains
      (losses)s on derivative activities
                  
                  
                  1,020,672
                  
                  
                  
                  (956,142
                  )Total
      revenues
                  
                  
                  6,161,332
                  
                  
                  
                  5,388,272Operating
      expenses:Production
      taxes
                  
                  
                  647,755
                  
                  
                  
                  772,010Lease
      operating expenses
                  
                  
                  2,423,015
                  
                  
                  
                  2,906,210Depreciation,
      depletion, and amortization
                  
                  
                  1,196,970
                  
                  
                  
                  1,360,737Impairment
      of unproved properties
                  
                  
                  39,050,000
                  
                  
                  
                  -Accretion
      expense
                  
                  
                  158,009
                  
                  
                  
                  121,740Exploration
      expense
                  
                  
                  20,108
                  
                  
                  
                  223,564General
      and administrative
                  
                  
                  3,631,580
                  
                  
                  
                  7,538,242Total
      operating expenses
                  
                  
                  47,127,437
                  
                  
                  
                  12,922,503Loss
      from operations
                  
                  
                  (40,966,105
                  )
                  
                  
                  (7,534,231
                  )Other
      income (expense):Liquidated
      damages pursuant to registration rights arrangement
                  
                  
                  -
                  
                  
                  
                  (2,645,393
                  )Amortization
      of deferred financing costs and discount on note payable
                  
                  
                  (4,021,767
                  )
                  
                  
                  (2,423,389
                  )Interest
      expense
                  
                  
                  (1,369,957
                  )
                  
                  
                  (794,693
                  )Interest
      and other income
                  
                  
                  16,488
                  
                  
                  
                  232,880Total
      other income (expense)
                  
                  
                  (5,375,236
                  )
                  
                  
                  (5,630,595
                  )Net
      loss
                  
                  $
                  (46,341,341
                  )
                  
                  $
                  (13,164,826
                  )Basic
      and diluted net loss per share
                  
                  $
                  (0.40
                  )
                  
                  $
                  (0.12
                  )Basic
      and diluted weighted average shares outstanding
                  
                  
                  116,398,755
                  
                  
                  
                  109,942,627





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


F-4


Rancher
Energy Corp.


Statement
of Changes in Stockholders’ Equity




Shares
                  
                  
                  Amount
                  
                  
                  Additional
                    Paid-
      In
                    Capital
                  
                  
                  Accumulated
                    Deficit
                  
                  
                  Total
                    Stockholders’
                    EquityBalance,
      March 31, 2007
                  
                  
                  102,041,432
                  
                  
                  $
                  1,021
                  
                  
                  $
                  84,985,934
                  
                  
                  $
                  (
      9,228,862
                  )
                  
                  $
                  75,758,093Common
      stock issued pursuant to registration rights agreement
                  
                  
                  9,731,569
                  
                  
                  
                  97
                  
                  
                  
                  5,463,315
                  
                  
                  
                  -
                  
                  
                  
                  5,463,412Common
      stock issued on exercise of stock options
                  
                  
                  1,750,000
                  
                  
                  
                  18
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  18Common
      stock issued to directors for services rendered
                  
                  
                  1,248,197
                  
                  
                  
                  13
                  
                  
                  
                  503,787
                  
                  
                  
                  -
                  
                  
                  
                  503,800Common
      stock issued to non-employee consultant for services
    rendered
                  
                  
                  107,143
                  
                  
                  
                  1
                  
                  
                  
                  112,499
                  
                  
                  
                  -
                  
                  
                  
                  112,500Offering
      costs incurred pursuant to registration rights agreement
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (300,365
                  )
                  
                  
                  -
                  
                  
                  
                  (300,365
                  )Stock-based
      compensation
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  1,025,011
                  
                  
                  
                  -
                  
                  
                  
                  1,025,011Net
      loss
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (
      13,164,826
                  )
                  
                  
                  (
      13,164,826
                  )Balance
      March 31, 2008
                  
                  
                  114,878,341
                  
                  
                  $
                  1,150
                  
                  
                  $
                  91,790,181
                  
                  
                  $
                  (22,393,688
                  )
                  
                  $
                  69,397,643Common
      stock issued on exercise of stock options
                  
                  
                  750,000
                  
                  
                  
                  7
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  7Common
      stock issued to directors for services rendered
                  
                  
                  3,388,359
                  
                  
                  
                  34
                  
                  
                  
                  217,466
                  
                  
                  
                  -
                  
                  
                  
                  217,500Stock-based
      compensation
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  574,354
                  
                  
                  
                  -
                  
                  
                  
                  574,354Net
      loss
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (46,341,341
                  )
                  
                  
                  (46,341,341
                  )Balance
      March 31, 2009
                  
                  
                  119,016,700
                  
                  
                  $
                  1,191
                  
                  
                  $
                  92,582,001
                  
                  
                  $
                  (68,735,029
                  )
                  
                  $
                  23,848,163





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


F-5


Rancher
Energy Corp.


Statements
of Cash Flows





For the Years Ended
      March 31,2009
                
                
                2008Cash
      flows from operating activities:Net
      loss
                
                $
                (46,341,341
                )
                
                $
                (13,164,826
                )Adjustments
      to reconcile net loss to net cash used for operating
      activities:Liquidated
      damages pursuant to registration rights arrangements
                
                
                -
                
                
                
                2,645,393Imputed
      interest on registration rights arrangement payments
                
                
                -
                
                
                
                112,489Depreciation,
      depletion, and amortization
                
                
                1,196,970
                
                
                
                1,360,737Impairment
      of unproved properties
                
                
                39,050,000
                
                
                
                -Accretion
      expense
                
                
                158,009
                
                
                
                121,740Asset
      retirement obligations settled
                
                
                (147,662
                )
                
                
                (278,739Stock-based
      compensation expense
                
                
                470,953
                
                
                
                1,025,011Amortization
      of deferred financing costs and discount on notes payable
                
                
                4,021,767
                
                
                
                2,423,389Unrealized
      (gains) losses on crude oil hedges
                
                
                (1,227,567
                )
                
                
                771,607Common
      stock issued for services, directors
                
                
                320,900
                
                
                
                503,800Common
      stock issued for services, non-employee
                
                
                -
                
                
                
                112,500Loss
      on sale of assets
                
                
                39,972Changes
      in operating assets and liabilities:Accounts
      receivable and prepaid expenses
                
                
                586,501
                
                
                
                (586,935
                )Accounts
      payable and accrued liabilities
                
                
                (1,093,445
                )
                
                
                367,411Net
      cash used for operating activities
                
                
                (2,964,943
                )
                
                
                (4,586,423
                )Cash
      flows from investing activities:Capital
      expenditures for oil and gas properties
                
                
                (260,735
                )
                
                
                (4,245,011
                )Proceeds
      from conveyance of unproved oil and gas properties
                
                
                -
                
                
                
                491,500Increase
      in other assets
                
                
                (358,056
                )
                
                
                (927,769
                )Net
      cash used for investing activities
                
                
                (618,791
                )
                
                
                (4,681,280
                )Cash
      flows from financing activities:Increase
      in deferred financing costs
                
                
                (101,478
                )
                
                
                (959,468
                )Proceeds
      from borrowings
                
                
                -
                
                
                
                12,240,000Proceeds
      from issuance of common stock upon exercise of stock
    options
                
                
                7
                
                
                
                18Repayment
      of debt
                
                
                (2,240,000
                )Payment
      of offering costs
                
                
                -
                
                
                
                (300,365Net
      cash provided by (used for) financing activities
                
                
                (2,341,471
                )
                
                
                10,980,185Increase
      (decrease) in cash and cash equivalents
                
                
                (5,925,205
                )
                
                
                1,712,482Cash
      and cash equivalents, beginning of year
                
                
                6,842,365
                
                
                
                5,129,883Cash
      and cash equivalents, end of year
                
                $
                917,160
                
                
                $
                6,842,365Non-cash
      investing and financing activities:Cash
      paid for interest
                
                $
                1,369,733
                
                
                $
                682,204Payables
      for purchase of oil and gas properties
                
                $
                53,799
                
                
                $
                -Asset
      retirement asset and obligation
                
                $
                10,481
                
                
                $
                213,757Issuance
      of common stock in settlement of registration rights arrangement and
      imputed interest
                
                $
                -
                
                
                $
                5,463,412Discount
      on note payable, conveyance of overriding royalty interest
                
                $
                1,050,000
                
                
                $
                4,500,000





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


F-6


Rancher
Energy Corp.


Notes
to Financial Statements




Note
1—Organization and Summary of Significant Accounting Policies




Organization




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




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





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




The
accompanying financial statements have been prepared on the basis of accounting
principles applicable to a going concern, which contemplates the realization of
assets and extinguishment of liabilities in the normal course of business. As
shown in the accompanying Statements of Operations, we have incurred a
cumulative net loss of $68.7 million for the period from inception (February 4,
2004) to March 31, 2009 and have a working capital deficit of approximately $8.8
million as of March 31, 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 transcation 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.




Revenue
Recognition




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





Crude oil
sales proceeds and proceeds from derivative settlements are remitted by the
crude oil purchaser and the derivative counterparty directly to the Lender under
the provisions of the Term Credit Agreement as amended.  So long as
the Company is current on its obligations to the Lender, the proceeds are then
paid by the Lender to the Company on or before the last day of the month of
receipt.


F-7


Cash and Cash
Equivalents




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




Concentration of Credit
Risk





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





Oil and Gas Producing
Activities




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




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




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




The
Company reviews its long-lived assets for impairments when events or changes in
circumstances indicate that impairment may have occurred. The impairment test
for proved properties compares the expected undiscounted future net cash flows
on a property-by-property basis with the related net capitalized costs,
including costs associated with asset retirement obligations, at the end of each
reporting period. Expected future cash flows are calculated on all proved
reserves using a discount rate and price forecasts selected by the Company’s
management. The discount rate is a rate that management believes is
representative of current market conditions. The price forecast is based on
NYMEX strip pricing, adjusted for basis and quality differentials, for the first
three to five years and is held constant thereafter. Operating costs are also
adjusted as deemed appropriate for these estimates. When the net capitalized
costs exceed the undiscounted future net revenues of a field, the cost of the
field is reduced to fair value, which is determined using discounted future net
revenues. An impairment allowance is provided on unproved property when the
Company determines the property will not be developed or the carrying value is
not realizable.  Recent global market conditions and declining
commodity prices have negatively impact the valuation of the Company’s unproved
oil and gas properties.  During the year ended March 31, 2009, the
Company recognized impairment of $39,050,000, representing the excess of the
carrying value over the estimated realizable value of such
properties.  The Company recognized no impairment of unproved
properties during the year ended March 31, 2008.




Sales of Proved and Unproved
Properties




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




The sale
of a partial interest in an unproved property is accounted for as a recovery of
cost when substantial uncertainty exists as to recovery of the cost applicable
to the interest retained. A gain on the sale is recognized to the extent the
sales price exceeds the carrying amount of the unproved property. A gain or loss
is recognized for all other sales of nonproducing properties and is reflected in
results of operations. During the year ended March 31, 2008, the Company
received proceeds on the sale of unproved properties of $491,500, for which no
gain or loss was recognized.





F-8




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.





Other Property and
Equipment




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





Deferred Financing
Costs





Costs
incurred in connection with the Company’s debt issuances are capitalized and
amortized over the term of the debt, which approximates the effective interest
method. Amortization of deferred financing costs of $610,006 and $351,685 was
recognized for the years ended March 31, 2009 and 2008 and has been charged to
operations as an expense in the Statement of Operations. Unamortized balances of
deferred financing costs of $-0- and $508,529 are included in other assets on
the Balance Sheets as of March 31, 2009 and 2008, respectively.




Fair Value of Financial
Instruments




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




Income
Taxes





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





The
Company adopted the provisions of FIN 48 on April 1, 2007. FIN 48 provides
detailed guidance for the financial statement recognition, measurement and
disclosure of uncertain tax positions recognized in the financial statements in
accordance with SFAS No. 109. Tax positions must meet a
“more-likely-than-not” recognition threshold at the effective date to be
recognized upon the adoption of FIN 48 and in subsequent periods. The adoption
of FIN 48 had an immaterial impact on the Company’s financial position and did
not result in unrecognized tax benefits being recorded. Subsequent to adoption,
there have been no changes to the Company’s assessment of uncertain tax
positions. Accordingly, no corresponding interest and penalties have been
accrued. The Company’s policy is to recognize penalties and interest, if any,
related to uncertain tax positions as general and administrative expense. The
Company files income tax returns in the U.S. Federal jurisdiction and in the
state of Colorado. The Company’s tax years of 2005and forward for Federal, and
2004 and forward for Colorado, are subject to examination by the respective
taxing authorities.




Net Loss per
Share




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




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


F-9


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




For the Years Ended March 31,2009
                
                2008Dilutive
                
                
                -
                
                
                -Anti-dilutive
                
                
                68,091,225
                
                
                80,665,639




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




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




For the Year Ended
      March 31,2009
                
                2008Net
      loss
                
                $
                (46,341,341
                )
                
                $
                (13,164,826
                )Basic
      weighted average common shares outstanding
                
                
                116,398,755
                
                
                
                109,942,627Basic
      and diluted net loss per common share
                
                $
                (0.40
                )
                
                $
                (0.12
                )




Share-Based
Payment




Effective
April 1, 2006, Rancher Energy adopted Statement of Financial Accounting
Standard 123(R) “Accounting for Stock-Based Compensation” using the
modified prospective transition method. SFAS No. 123R requires companies to
recognize compensation cost for stock-based awards based on estimated fair value
of the award, effective April 1, 2006. See Note 7 for further discussion.
The Company accounts for equity instruments issued in exchange for the receipt
of goods or services from other than employees in accordance with SFAS No.123(R)
and the conclusions reached by the Emerging Issues Task Force ("EITF") in Issue
No. 96-18. Costs are measured at the estimated fair market value of the
consideration received or the estimated fair value of the equity instruments
issued, whichever is more reliably measurable. The value of equity instruments
issued for consideration other than employee services is determined on the
earliest of a performance commitment or completion of performance by the
provider of goods or services as defined by EITF 96-18.




Commodity
Derivatives





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




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




The
Company does not hold or issue commodity derivatives for speculative or trading
purposes. The Company is exposed to credit losses in the event of nonperformance
by the counterparty to its commodity derivatives. It is anticipated, however,
that its counterparty will be able to fully satisfy its obligations under the
commodity derivatives contracts. The Company does not obtain collateral or other
security to support its commodity derivatives contracts subject to credit risk
but does monitor the credit standing of the counterparty. The price 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:




F-10





The table below summarizes
the realized and unrealized losses related to the Company’s derivative
instruments for the years ended March 31, 2009 and 2008.





Year Ended March 31,2009
                
                
                2008Realized
      gains (losses) on derivative instruments
                
                $
                (206,895
                )
                
                $
                (184,535
                )Unrealized
      gains (losses) on derivative instruments
                
                
                1,227,567
                
                
                
                (771,607
                )Total
      realized and unrealized gains (losses) recorded
                
                $
                1,020,672
                
                
                $
                (956,142
                )





Contract Feature
                    
                    Contract Term
                    
                    Total Volume
                      Hedged (Bbls)
                    
                    
                    Remaining
                      Volume Hedged
                      (Bbls)
                    
                    Index
                    
                    Fixed Price
                      ($/Bbl)
                    
                    
                    Position at March
                      31, 2009 Due To
                      (From) CompanyPut
                    
                    Nov
      07—Oct 09
                    
                    
                    113,220
                    
                    
                    
                    31,908
                    
                    WTI
      NYMEX
                    
                    $
                    65.00
                    
                    
                    $
                    455,960Call
                    
                    Nov
      07—Oct 09
                    
                    
                    67,935
                    
                    
                    
                    19,146
                    
                    WTI
      NYMEX
                    
                    $
                    83.50
                    
                    
                    $
                    -





Comprehensive Income
(Loss)




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




Major
Customers




For the
years ended March 31, 2009 and 2008, one customer accounted for 100% of the
Company’s oil and gas sales. The loss of that customer would not be expected to
have a material adverse effect upon our sales and would not be expected to
reduce the competition for our oil production, which in turn would not be
expected to negatively impact the price we receive. As of March 31, 2009 and
2008 accounts receivable from this customer account for 31% and 41%,
respectively of the Company’s total accounts receivable and prepaid expense
balances.




Industry Segment and
Geographic Information




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




Off—Balance Sheet
Arrangements




As part
of its ongoing business, the Company has not participated in transactions that
generate relationships with unconsolidated entities or financial partnerships,
such as entities often referred to as structured finance or special purpose
entities (SPEs), which would have been established for the purpose of
facilitating off-balance sheet arrangements or other contractually narrow or
limited purposes. From February 4, 2004 (inception) through
March 31, 2009, the Company has not been involved in any
unconsolidated SPE transactions.





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.




F-11





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.





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. SFAS No. 141R is effective for the
Company’s fiscal  year beginning April 1, 2009. We do not expect
the adoption of SFAS No. 141R to have a material impact on our consolidated
financial statements.





In
April 2007, the FASB issued FSP FIN 39-1, “Amendment of FASB Interpretation
No. 39” (FSP FIN 39-1). FSP FIN 39-1 defines “right of setoff” and
specifies what conditions must be met for a derivative contract to qualify for
this right of setoff. It also addresses the applicability of a right of setoff
to derivative instruments and clarifies the circumstances in which it is
appropriate to offset amounts recognized for those instruments in the statement
of financial position. In addition, this FSP permits offsetting of fair value
amounts recognized for multiple derivative instruments executed with the same
counterparty under a master netting arrangement and fair value amounts
recognized for the right to reclaim cash collateral (a receivable) or the
obligation to return cash collateral (a payable) arising from the same master
netting arrangement as the derivative instruments. We adopted this
interpretation on April 1, 2008 and the adoption of FSP FIN 39-1 had no
material effect on our financial position or results of operations.





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, with early adoption
permitted. We are currently evaluating the potential impact, if any, of the
adoption of SFAS No. 161 on our future financial reporting.





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. We adopted EITF 07-5 on April 1, 2009 and the adoption had no
material effect on our financial position or results of operations.




F-12





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.




Note
2—Oil and Gas Properties





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





As
      of March 31,2009
                
                
                2008Proved
      properties
                
                $
                20,631,487
                
                
                $
                20,734,143Unimproved
      properties excluded from DD&A
                
                
                52,953,185
                
                
                
                53,655,471Equipment
      and other
                
                
                374,962
                
                
                
                402,602Subtotal
      Unevaluated Properties
                
                
                53,328,147
                
                
                
                54,058,073Total
      oil and gas properties
                
                
                73,959,634
                
                
                
                74,792,216Less
      accumulated depletion, depreciation, amortization and impairment
                
                
                (41,840,978
                )
                
                
                (1,531,619
                )$
                32,118,656
                
                
                $
                73,260,597





Assignment
of 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.





Acquisitions




Cole Creek South Field and
South Glenrock B Field Acquisitions




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




In
addition to the cash consideration paid of the two fields, the Company issued
the seller of the oil and gas properties warrants to acquire 250,000 shares of
its common stock for $1.50 per share for a period of five years. The fair value
of the warrants to purchase common stock as of the grant date was estimated to
be $616,140 using the Black-Scholes option pricing.




Big Muddy Field
Acquisition




On
January 4, 2007, Rancher Energy acquired the Big Muddy Field, consisting of
approximately 8,500 acres located in the Powder River Basin east of Casper,
Wyoming. The total purchase price was $25,000,000, before adjustments for the
period from the effective date to the closing date, and closing costs. While the
Big Muddy Field was discovered in 1916, future profitable operations are
dependent on the application of tertiary recovery techniques requiring
significant amounts of  CO2.




F-13





Carbon
Dioxide (“CO2”) Enhanced
Oil Recovery Project




The
Company’s business plan includes the injection of CO2 into its
three oil fields in the Powder River Basin. To ensure an adequate supply of
CO2
the Company has entered into two separate supply agreements as
follows:





Anadarko
Agreement





On
December 15, 2006, the Company executed a Product Sale and Purchase
Contract (Purchase Contract) with the Anadarko Petroleum Corporation (Anadarko)
for the purchase of CO2 (meeting
certain quality specifications identified in the agreement) from Anadarko. The
primary term of the Agreement commences upon the later of January 1, 2008,
or the date of the first CO2 delivery,
and terminates upon the earlier of the day on which the Company has taken and
paid for the Total Contract Quantity, as defined, or 10 years from the
commencement date. The Company has the right to terminate the Purchase Contract
at any time with notice to Anadarko, subject to a termination payment as
specified in the Purchase Contract. During the primary term the “Daily Contract
Quantity” is 40 MMcf per day for a total of 146 Bcf. Carbon Dioxide (CO2)
deliveries are subject to a 25 MMcf per day take-or-pay provision. Anadarko has
the right to satisfy its own needs before sales to the Company, which reduces
our take-or-pay obligation. In the event the CO2 does not
meet certain quality specifications, we have the right to refuse delivery of
such CO2 For
CO2
deliveries, the Company has agreed to pay $1.50 per thousand cubic feet, to be
adjusted by a factor that is indexed to the average posted price of Wyoming
Sweet oil. From oil that is produced by CO2 injection,
the Company also agreed to convey to Anadarko an overriding royalty interest of
1% in year one, increasing 1% on each of the next four anniversaries to a
maximum of 5% for the remainder of the 10-year term.




Exxon/Mobil
Agreement





On
February 12, 2008 the Company entered into a Carbon Dioxide Sale and Purchase
Agreement (Sale and Purchase Agreement) with ExxonMobil Gas & Power
Marketing Company (“ExxonMobil”), a division of Exxon Mobil Corporation, under
which ExxonMobil will provide Rancher Energy with 70 MMscfd (million standard
cubic per day) of CO2 for an
initial 10-year period, with an option for a second 10 years. The CO2 will be
supplied from ExxonMobil’s LaBarge gas field in Wyoming. For CO 2 deliveries
from ExxonMobil, the Company has agreed to pay a base price plus an Oil Price
Factor which is indexed to the price of West Texas Intermediate crude
oil.





On March
18, 2009, the Company, entered into an Assignment Agreement (the “Assignment”)
with an unrelated third party operator (the “Operator”), for the assignment by
the Company  of a portion of its right, title and interest in and to,
and the assumption by the Operator of the Company’s obligations related thereto,
the Sale and Purchase Agreement.  ExxonMobil has consented to the
Assignment.   Under the terms of the Assignment, the Operator may
purchase up to 37.5 MMCF per day of carbon dioxide from ExxonMobil for a
two-year term beginning on the Start-up Date, as defined in the Contract (the
“Initial Term”). ExxonMobil will deliver the contract quantities to the
existing delivery point at the interconnect of the ExxonMobil and the Operator’s
pipelines near Bairoil, Wyoming.




The terms
of the Assignment also provide the Operator with an option to purchase an
additional 6.5 MMCF per day during the Initial Term.  Following the
Initial Term, to the extent the Company is not using for its own tertiary
recovery purposes any volumes of carbon dioxide the Company  is
otherwise obligated, or able to purchase from ExxonMobil under the Sale and
Purchase Agreement, the Operator  has the option to purchase from the
Company so much of such volumes as it elects on a monthly basis.  If,
during any period in which the Operator  is purchasing carbon dioxide
volumes under either of these options, an Event of Default (as defined in the
Assignment) occurs, the Company  will be required, at the Operator’s
sole discretion but subject to ExxonMobil’s rights and remedies under the Sale
and Purchase Agreement, to assign its remaining rights under the Contract to the
Operator.





See Note
12, Subsequent Events, for further discussion of ExxonMobil’s purported
termination of the Sale and Purchase Agreement subsequent to March 31,
2009.





Impairment
of Unproved Properties




In
conjunction with the regular periodic assessment of impairment of unproved
properties, the Company re-evaluated the carrying value of its unproved
properties giving consideration to lower commodity prices and the
difficulties encountered in raising capital to develop the
properties.  Accordingly, during the year ended March 31, 2009 the
Company recorded $39,050,000 of impairment expense on unproved properties,
reflecting the excess of the carrying value over estimated realizable value of
the assets.  The Company recorded no impairment of unproved properties
in the year ended March 31, 2008.


F-14





Exploration
of Strategic Alternatives





In
August 2008, the Company retained a financial advisor to assist in exploring
financing and other strategic alternatives, including the possible sale of the
Company.    The Company has not been successful in
completing such a strategic transaction.  Our ability to survive will
be dependent upon completing a strategic transaction; however, there is no
assurance any such transaction will be completed.




Note 3—Asset Retirement
Obligations




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





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




A
reconciliation of the Company’s asset retirement obligation liability during the
years ended March 31, 2009 and 2008 is as follows:





2009
                
                
                2008Beginning
      asset retirement obligation
                
                $
                1,259,851
                
                
                $
                1,221,567Liabilities
      incurred
                
                
                -
                
                
                
                18,473Liabilities
      settled
                
                
                (147,662
                )
                
                
                (297,212Changes
      in estimates
                
                
                10,482
                
                
                
                195,283Accretion
      expense
                
                
                158,009
                
                
                
                121,740Ending
      asset retirement obligation
                
                $
                1,280,680
                
                
                $
                1,259,851Current
                
                $
                108,884
                
                
                $
                337,685Long-term
                
                
                1,171,796
                
                
                
                922,166$
                1,280,680
                
                
                $
                1,259,851





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.




F-15


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
December 31, 2008 by level within the fair value hierarchy:





Fair Value Measurements UsingLevel 1
                  
                  Level 2
                  
                  Level 3Assets:Derivative
      instrument
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  455,960Liabilities
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  -





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 March 31,
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:




Derivatives
                          
                          TotalBalance
      as of April 1, 2008, asset, (liability)
                          
                          $
                          (836,907
                          )
                          
                          $
                          (836,907
                          )Total
      gains (losses) (realized or unrealized):Included
      in earnings
                          
                          
                          1,020,673
                          
                          
                          
                          1,020,673Included
      in other comprehensive incomePurchases,
      issuances and settlements
                          
                          
                          272,194
                          
                          
                          
                          272,194Transfers
      in and out of Level 3Balance
      as of March 31, 2009
                          
                          $
                          455,960
                          
                          
                          $
                          455,960Change
      in unrealized gains (losses) included in earnings relating to derivatives
      still held as of March 31, 2009
                          
                          $
                          1,292,867
                          
                          
                          $
                          1,292,867





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 (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.  As more fully discussed in Note 12,
Subsequent Events, after March 31, 2009, the Company and the Lender entered into
several amendments to the Term Credit Agreement to further extend the
term.





Under the
terms of the 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 Credit Agreement at any time without penalty. As
of March 31, 2009 the interest rate on the Note is 12% per annum.




The
Company’s obligations under the 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. Amortization of the discounts based upon the effective
interest method in the amounts of $ 3,411,761 and $1,972,450 is included in
interest expense for years ended March 31, 2009 and 2008, respectively. As long
as any of its obligations remain outstanding under the Credit Agreement, as
amended,, the Company will be required to grant the same ORRI to the Lender on
any new working interests acquired after closing. Under the terms of the First
Amendment, the Company has the right to buy back one-third (1/3) of the ORRI at
a repurchase price calculated to ensure that total payments by the Company to
the Lender of principal, interest, ORRI revenues, and ORRI repurchase price will
equal 140% of the original loan amount.


F-16


The
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 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 Credit Agreement, the Lender may accelerate the Company’s
obligations under the Credit Agreement. Upon certain events of bankruptcy,
obligations under the Credit Agreement would automatically accelerate. In
addition, at any time that an event of default exists under the Credit
Agreement, the Company will be required to pay interest on all amounts
outstanding under the Credit Agreement at a default rate, which is equal to the
then-prevailing interest rate under the Credit Agreement plus four percent per
annum.





The
Company is subject to various restrictive covenants under the Credit Agreement,
including limitations on its ability to sell properties and assets, pay
dividends, extend credit, amend material contracts, incur indebtedness,
provide guarantees, effect mergers or acquisitions (other than to change its
state of incorporation), cancel claims, create liens, create subsidiaries, amend
its formation documents, make investments, enter into transactions with its
affiliates, and enter into swap agreements. The Company must maintain (a) a
current ratio of at least 1.0 (excluding from the calculation of current
liabilities any loans outstanding under the Credit Agreement) and (b) a
loan-to-value ratio greater than 1.0 to 1.0 for the term of the loan. As of
March 31, 2009 and the date of this Annual Report, 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.





Note
6—Commitments and Contingencies





The
Company leases office space under a non-cancelable operating lease that expires
July 31, 2012. Rent expense was $363,700 and $278,625 during the years
ended March 31, 2009 and 2008 respectively. The annual minimum lease
payments for the next five fiscal years and thereafter are presented
below:




Years Ending March 31,202       2010
                      
                      $
                      367,334201       2011
                      
                      
                      379,715201       2012
                      
                      
                      383,842T           Thereafter
                      
                      
                      127,947Total
                      
                      $
                      1,258,838




The
Company has entered into CO2 supply
agreements with Anadarko and ExxonMobil as discussed in Note 2 above. The
Company has also entered into a Registration Rights Agreement as discussed in
Note 7 below.





Threatened
Litigation





On
December 31, 2008, we received a letter from an attorney representing Sergei
Stetsenko and other shareholders (the “Stetsenko Group”) stating that it was the
opinion of the Stetsenko Group that our Directors and Executive Officers have
acted negligently and contrary to their fiduciary duties.  The letter
threatens a lawsuit and demands that the Directors and our Executive Officers
return all cash and stock received from us, 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.  We deny the allegations and believe that they are without
merit. In February 2009, our Board of Directors established a Special Committee
of the Board (the “Special Committee”) to investigate the
allegations.  The Stetsenko Group has informed us that it intends to
propose an alternate slate of directors at the next meeting of
shareholders.  We 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.


F-17


In a
letter dated February 18, 2009 sent to each of our Directors, attorneys
representing a group of persons who purchased approximately $1,800,000 of
securities (in the aggregate) in our private placement offering commenced in
late 2006 alleged that securities laws were violated in that
offering.  Subsequent to March 31, 2009, we entered into tolling
agreements with the purchasers to toll the statutes of limitations applicable to
any claims related to the private placement.  Our Board of Directors
directed the Special Committee to investigate these
allegations.   The Company believes the allegations are without
merit.  We 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—Stockholders’ Equity




The
Company’s capital stock as of March 31, 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 Year Ended March 31, 2009




During
the year ended March 31, 2009, the Company issued common stock as
follows:




-
            750,000
      shares to an officer of the Company upon the exercise of stock
      options;





-
            3,388,359
      shares to directors of the Company in exchange for
    services;





For
the Year Ended March 31, 2008




During
the year ended March 31, 2008, the Company issued common stock as
follows:




-
            9,731,569
      shares to holders of registrable shares of the December 2006 and January
      2007 private placements, as liquidated damages in settlement of
      registration rights deficiencies (see Registration Rights and Other
      Payment Arrangements below);-
            1,750,000
      shares to an officer of the Company upon the exercise of stock
      options;





-
            1,248,197
      shares to directors of the Company in exchange for
    services;





-
            107,143
      shares to independent consultant in exchange for
  services




Warrants




In
connection with sale of common stock and other securities in the fiscal year
ended March 31, 2007, the Company issued warrants to purchase shares of common
stock. The following is a summary of warrants outstanding as of March 31,
2009








Warrants
                        
                        Exercise Price
                        
                        Expiration DateWarrants
      issued in connection with the following:Private
      placement of common stock
                        
                        45,940,510
                        
                        $
                        1.50
                        
                        March
      30, 2012Private
      placement of convertible notes payable
                        
                        6,996,322
                        
                        $
                        1.50
                        
                        March
      30, 2012Private
      placement agent commissions
                        
                        1,445,733
                        
                        $
                        1.50
                        
                        March
      30, 2012Acquisition
      of oil and gas properties
                        
                        250,000
                        
                        $
                        1.50
                        
                        December
      22, 2011Total
      warrants outstanding at March 31, 2008
                        
                        54,632,565


F-18


Registration and Other
Payment Arrangements




In
connection with the private placement sale of the Company’s common stock and
other securities during the fiscal year ended March 31, 2007,  the
Company entered into Registration Rights Agreements (the “Agreements”) under
which the Company agreed to register for resale the shares of common stock
issued in the private placement as well as the shares underlying the other
securities. Under the terms of the Agreements the Company must pay the holders
of the registrable securities issued in the private placement, liquidated
damages if the registration statement that was filed in conjunction with the
private placement was not declared effective by the U.S. Securities and Exchange
Commission (SEC) within 150 days of the closing of the private placement
(December 21, 2006). The liquidated damages were due on or before the day
of the failure (May 20, 2007) and every 30 days thereafter, or three
business days after the failure is cured, if earlier. The amount due was 1% of
the aggregate purchase price, or $794,000 per month. If the Company fails to
make the payments timely, interest accrues at a rate of 1.5% per month. Payments
pursuant to the Registration Rights Agreement and the private placement
agreement are limited to 24% of the aggregate purchase price, or $19,057,000 in
total. The payment may be made in cash, notes, or shares of common stock, at the
Company’s option, as long as the Company does not have an equity condition
failure. The Company’s registration statement was not declared effective prior
to the May 20, 2007 failure date and pursuant to the terms of the Registration
Rights Agreement, the Company opted to pay the liquidated damages in shares of
common stock. The number of shares issued was based on the payment amount of
$794,000 divided by 90% of the volume weighted average price of the Company’s
common stock for the 10 trading days immediately preceding the payment
due.





Using the
above formula, the Company made delay registration effectiveness payments
between May 18, 2007 and October 31, 2007 by issuing a total of 9,731,569 shares
of its common stock at prices ranging from $0.85- $0.43 per share.





The
Company’s registration statement was declared effective on October 31, 2007.
Since that date the Company has maintained the effectiveness of the registration
statement and complied with all other provisions of the Registration Rights
Agreement. No further liquidated damages have been assessed or paid. In
accordance with FSP EITF 00-19-2, Accounting for Registration Payment
Arrangements, as of the date of this Annual Report, the Company believes
the likelihood it will incur additional obligations to pay liquidated damages is
remote, as defined in SFAS 5, Accounting for Contingencies.Accordingly as of March 31, 2009 and 2008, the Company has not recorded a
liability for future liquidated damages under the Registration Rights
Agreement.





Note
8—Share-Based Compensation




Effective
April 1, 2006, the Company adopted Statement of Financial Accounting
Standard 123(R) (SFAS 123(R)), Share-Based Payment . SFAS
No. 123(R) requires companies to recognize share-based payments to employees as
compensation expense using a fair value method. Under the fair value recognition
provisions of SFAS No. 123(R), stock-based compensation cost is measured at
the grant date based on the fair value of the award and is recognized as an
expense over the service period on a straight-line basis, which generally
represents the vesting period. The Company did not recognize a tax benefit from
the stock compensation expense because it is more likely than not that the
related deferred tax assets, which have been reduced by a full valuation
allowance, will not be realized.





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





Prior to
the adoption of SFAS 123(R), the Company reflected tax benefits from deductions
resulting from the exercise of stock options as operating activities in the
statements of cash flows. SFAS 123(R) requires tax benefits resulting from tax
deductions in excess of the compensation cost recognized for those options
(excess tax benefits) be classified and reported as both an operating cash
outflow and a financing cash inflow upon adoption of SFAS 123(R). As a result of
the Company’s net operating losses, the excess tax benefits, which would
otherwise be available to reduce income taxes payable, have the effect of
increasing the Company’s net operating loss carry forwards. Accordingly, because
the Company is not able to realize these excess tax benefits, such benefits have
not been recognized in the statements of cash flows for the years ended
March 31, 2009 and 2008 .


F-19


Chief
Executive Officer (CEO) Option Grant





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





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




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




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





The
Company recognized stock compensation expense attributable to the CEO options of
$423,500 for each of the fiscal  years ended March 31, 2009 and
2008. The Company expects to recognize the remaining compensation expense of
$105,875 related to the unvested shares in the next fiscal year ending March 31,
2010.





2006 Stock Incentive
Plan





On
March 30, 2007, the 2006 Stock Incentive Plan (the 2006 Stock Incentive
Plan) was approved by the shareholders and was effective October 2, 2006.
The 2006 Stock Incentive Plan had previously been approved by the Company’s
Board of Directors. Under the 2006 Stock Incentive Plan, the Board of Directors
may grant awards of options to purchase common stock, restricted stock, or
restricted stock units to officers, employees, and other persons who provide
services to the Company or any related company. The participants to whom awards
are granted, the type of awards granted, the number of shares covered for each
award, and the purchase price, conditions and other terms of each award are
determined by the Board of Directors, except that the term of the options shall
not exceed 10 years. A total of 10,000,000 shares of Rancher Energy common stock
are subject to the 2006 Stock Incentive Plan. The shares issued for the 2006
Stock Incentive Plan may be either treasury or authorized and unissued shares.
During the year ended March 31, 2009 no options were granted under the 2006
Stock Incentive Plan. During the year ended March 31, 2008 , options to purchase
up to 753,000 shares of common stock were granted under the 2006 Stock Incentive
Plan to officers, directors, employees and a consultant. The options granted
have exercise prices ranging from $0.39 to $1.64 generally vest over three
years, and have a maximum term of ten years.





The fair
value of the options granted during fiscal 2008, under the 2006 Stock Incentive
Plan was estimated as of the grant date using the Black-Scholes option pricing
model with the following assumptions:





2008Expected
      Volatility
                            
                            59.80% - 62.75%Expected option term
                            
                            3.0 - 6.25 yearsRisk-free interest rate
                            
                            4.39% to 4.68Expected
      dividend yield
                            
                            0.00%




F-20


Because
the Company is newly public with an insufficient history of stock price for the
expected term, the expected volatility was based on an average of the volatility
disclosed by other comparable companies who had similar expected option terms.
The expected term of options granted was estimated in accordance with the
simplified method prescribed in SEC Staff Accounting Bulletin (“SAB”) No. 107
and SAB No 110. The risk free rate was based on the five-year U.S Treasury bond
rate.




The
following table summarizes stock option activity for the year ended
March 31, 2009 and 2008:




2009
                
                
                2008Number of
                  Options
                
                
                Weighted
                  Average
                  Exercise Price
                
                
                Number of
                  Options
                
                
                Weighted
                  Average
                  Exercise PriceOutstanding
      at beginning of year:CEO
                
                
                1,250,000
                
                
                $
                0.00001
                
                
                
                3,000,000
                
                
                $
                0.00001Plan
                
                
                1,431,000
                
                
                $
                1.74
                
                
                
                3,335,000
                
                
                $
                2.34GrantedCEO
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -Plan
                
                
                -
                
                
                
                -
                
                
                
                753,000
                
                
                $
                0.73ExercisedCEO
                
                
                (750,000
                )
                
                $
                0.00001
                
                
                
                (1,750,000
                
                
                $
                0.00001Plan
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -CancelledCEO
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -Plan
                
                
                (855,000
                )
                
                $
                1.73
                
                
                
                (2,657,000
                
                
                $
                2.46Outstanding
      at March 31CEO
                
                
                500,000
                
                
                $
                0.00001
                
                
                
                1,250,000
                
                
                $
                0.00001Plan
                
                
                576,000
                
                
                $
                0.61
                
                
                
                1,431,000
                
                
                $
                1.28Exercisable
      at March 31,CEO
                
                
                250,000
                
                
                $
                0.00001
                
                
                
                -
                
                
                $
                0.00001Plan
                
                
                210,000
                
                
                $
                0.71
                
                
                
                430,000
                
                
                $
                1.74





The
following table summarizes information related to the outstanding and vested
options as of March 31, 2009





Outstanding
                  Options
                
                Vested
                  OptionsNumber
      of SharesCEO
                
                
                500,000
                
                
                
                250,000Plan
                
                
                576,000
                
                
                
                210,000Weighted
      Average Remaining Contractual Life in YearsCEO
                
                NA
      - CEO Options Do Not ExpirePlan
                
                
                3.77
                
                
                
                3.54Weighted
      Average Exercise PriceCEO
                
                $
                0.00001
                
                
                $
                0.00001Plan
                
                $
                0.61
                
                
                $
                0.71Aggregate
      Intrinsic ValueCEO
                
                $
                9,995
                
                
                $
                4,997Plan
                
                $
                (337,410
                )
                
                $
                (144,871
                )




F-21


The
following table summarizes changes in the unvested options for the years ended
March 31, 2009 and 2008:





Number of
                  Options
                
                
                Weighted
                  Average
                  Grant Date
                  Fair ValueNon-vested,
      April 1, 2007CEO
                
                
                2,250,000
                
                
                $
                0.42Plan
                
                
                3,147,500
                
                
                $
                1.54Total
                
                
                5,397,500
                
                
                $
                1.07Granted—Plan
                
                
                753,000
                
                
                $
                0.34Vested—CEO
                
                
                (1,000,000
                )
                
                $
                0.42Plan
                
                
                (742,500
                )
                
                $
                0.75Total
                
                
                (1,742,500
                )
                
                $Cancelled
      - Plan
                
                
                (2,157,000
                )
                
                $
                0.67Non-vested,
      March 31, 2008CEO
                
                
                1,250,000
                
                
                $
                0.42Plan
                
                
                1,001,000
                
                
                $
                0.50Total
                
                
                2,251,000
                
                
                
                0.46Granted—CEO
                
                
                -
                
                
                
                -Plan
                
                
                -
                
                
                
                -Total
                
                
                -
                
                
                
                -Vested—CEO
                
                
                (1,000,000
                )
                
                $
                0.42Plan
                
                
                (190,000
                )
                
                $
                0.28Total
                
                
                (1,190,000
                )
                
                $
                0.40Cancelled
      - Plan
                
                
                (445,000
                )
                
                $
                0.78Non-vested,
      March 31, 2009CEO
                
                
                250,000
                
                
                $
                0.42Plan
                
                
                366,000
                
                
                $
                0.27Total
                
                
                616,000
                
                
                $
                0.33




The
weighted-average grant-date fair values of the stock options granted during the
year ended March 31, 2008 was $0.34. The total intrinsic value, calculated
as the difference between the exercise price and the market price on the date of
exercise of all options exercised during the years ended March 31, 2009 and
2008, was approximately $162,500 and $1,410,000, respectively. The Company
received $8 and $18 from stock options exercised during the year ended
March 31, 2009 and 2008, respectively. The Company did not realize any tax
deductions related to the exercise of stock options during year.





Total
estimated unrecognized compensation cost from unvested stock options as of
March 31, 2009 was approximately $204,200 which the Company expects to
recognize over the next three years.


F-22


Note
9—Income Taxes





The
effective income tax rate for the years ended March 31, 2009 and 2008 differs
from the U.S. Federal statutory income tax rate due to the
following:




For the Year Ended March 31,2009
                      
                      
                      2008Federal
      statutory income tax rate
                      
                      $
                      (16,219,000
                      )
                      
                      $
                      (4,608,000
                      )State
      income taxes, net of Federal benefit
                      
                      
                      (49,000
                      )
                      
                      
                      (33,000
                      )Permanent
      items
                      
                      
                      18,000
                      
                      
                      
                      362,000Other
                      
                      
                      35,000
                      
                      
                      
                      (129,000
                      )Change
      in valuation allowance
                      
                      
                      16,215,000
                      
                      
                      
                      4,408,000$
                      -
                      
                      
                      $
                      -





The
components of the deferred tax assets and liabilities as of March 31, 2009 and
2008 are as follows:




For the Year Ended March 31,2009
                      
                      
                      2008Long-term
      deferred tax assets:Federal
      net operating loss carryforwards
                      
                      
                      9,266,000
                      
                      
                      
                      5,984,000Asset
      retirement obligation
                      
                      
                      449,000
                      
                      
                      
                      444,000Stock-based
      compensation
                      
                      
                      616,000
                      
                      
                      
                      469,000Accrued
      vacation
                      
                      
                      22,000
                      
                      
                      
                      23,000Unrealized
      hedging losses (gains)
                      
                      
                      (160,000
                      )
                      
                      
                      272,000Property
      , plant and equipment
                      
                      
                      13,475,000
                      
                      
                      
                      261,000Valuation
      allowance
                      
                      
                      (23,668,000
                      )
                      
                      
                      (7,453,000
                      )Net
      long-term deferred tax assets
                      
                      $
                      -
                      
                      
                      $
                      -




The
Company has approximately $26,400,000 of net operating loss carryovers as of
March 31, 2009. The net operating losses begin to expire in 2024.




The
Company has provided a full valuation allowance for the deferred tax assets as
of March 31, 2009 and 2008, based on the likelihood of the realization of the
deferred tax assets will not be utilized in the future.




Note
10—Disclosures about Oil and Gas Producing Activities





Costs
Incurred in Oil and Gas Producing Activities:




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





For the Year Ended March 31,2009
                    
                    
                    2008Exploration
                    
                    $
                    20,108
                    
                    
                    $
                    223,564Development
                    
                    
                    245,172
                    
                    
                    
                    4,758,783Acquisitions:Unproved
                    
                    
                    -
                    
                    
                    
                    43,088Proved
                    
                    
                    -
                    
                    
                    
                    -Total
                    
                    
                    265,280
                    
                    
                    
                    5,025,435Costs
      associated with asset retirement obligations
                    
                    $
                    10,481
                    
                    
                    $
                    213,756




F-23


Oil
and Gas Reserve Quantities (Unaudited):




For the
years ended March 31, 2009 and 2008, Ryder Scott Company, L.P. prepared the
reserve information for the Company’s Cole Creek South, South Glenrock B, and
Big Muddy Fields in the Powder River Basin.





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




Proved
oil and gas reserves, as defined in Regulation S-X, Rule 4-10(a)(2)(3)(4), are
the estimated quantities of crude oil, natural gas, and natural gas liquids that
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed oil and gas reserves are those expected
to be recovered through existing wells with existing equipment and operating
methods. All of the Company’s proved reserves are located in the continental
United States.




Presented
below is a summary of the changes in estimated oil reserves (in barrels) of the
Company for the years ended March 31, 2009 and 2008 (the Company does not
have any natural gas reserves).




Total
      proved:
                                
                                2009
                                
                                2008Beginning
      of year
                                
                                
                                1,300,396
                                
                                1,279,164Purchases
      of minerals in-place
                                
                                
                                -
                                
                                -Production
                                
                                
                                (65,308
                                )
                                (86,626
                                )Revisions
      of previous estimates
                                
                                
                                (68,386
                                )
                                107,858End
      of year
                                
                                
                                1,166,702
                                
                                1,300,396Proved
      developed reserves:
                                
                                
                                955,151
                                
                                1,074,830





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




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




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




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





The
assumptions used to compute the standardized measure are those prescribed by the
FASB and the SEC. These assumptions do not necessarily reflect the Company’s
expectations of actual revenues to be derived from those reserves, nor their
present value. The limitations inherent in the reserve quantity estimation
process, as discussed previously, are equally applicable to the standardized
measure computations since these estimates are the basis for the valuation
process. The price, as adjusted for transportation, quality, and basis
differentials, used in the calculation of the standardized measure was $44.75
and $95.49 per barrel of oil for the years ended March 31, 2009 and 2008,
respectively. The Company does not have natural gas reserves.


F-24


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




As of
                        March 31,
                        2009
                      
                      
                      As of
                        March 31,
                        2008Future
      cash inflows
                      
                      $
                      52,217,000
                      
                      
                      $
                      124,164,000Future
      production costs
                      
                      
                      (29,024,000
                      )
                      
                      
                      (58,283,000
                      )Future
      development costs
                      
                      
                      (2,007,000
                      )
                      
                      
                      (2,007,000
                      )Future
      income taxes
                      
                      
                      -
                      
                      
                      
                      -Future
      net cash flows
                      
                      
                      21,186,000
                      
                      
                      
                      63,874,00010%
      annual discount
                      
                      
                      (12,462,000
                      )
                      
                      
                      (32,946,000
                      )Standardized
      measure of discounted future net cash flows
                      
                      $
                      8,724,000
                      
                      
                      $
                      30,928,000





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




For the year
                        ended
                        March 31,
                        2008
                      
                      
                      For the year
                        ended
                        March 31,
                        2007Standardized
      measure of discounted future net cash flows, beginning of
    year
                      
                      $
                      30,928,000
                      
                      
                      $
                      13,119,000Sales
      of oil and gas produced, net of production costs
                      
                      
                      (2,070,000
                      )
                      
                      
                      (2,666,
      000
                      )Net
      changes in prices and production costs
                      
                      
                      (20,285,000
                      )
                      
                      
                      17,737,000Purchase
      of minerals in-place
                      
                      
                      -
                      
                      
                      
                      -Revisions
      of previous quantity estimates
                      
                      
                      (666,000
                      )
                      
                      
                      2,464,000Accretion
      of discount
                      
                      
                      3,093,000
                      
                      
                      
                      1,312,000Changes
      in timing and other
                      
                      
                      (2,276,000,
                      )
                      
                      
                      (1,038,000
                      )Standardized
      measure of discounted future net cash flows, end of year
                      
                      $
                      8,724,000
                      
                      
                      $
                      30,928,000




Note
11—Related Party Transaction




There
were no related party transactions during the years ended March 31, 2009 or
2008.





Note
12—Subsequent Events





As discussed in Note 5, Short Term Note
Payable, the Company’s short term debt was scheduled to mature on April 30,
2009.  Subsequent to March 31, 2009, the Company and the Lender
entered into a series of five amendments (the Second Amendment through the
Seventh Amendment)each of which included
short term extensions of the maturity date while the definitive terms of the
Eighth Amendment were finalized.On June 3, 2009
the Company and the Lenderentered into an Eighth
Amendment to Term Credit Agreement (“Eighth Amendment”) that amends certain
provisions of the Term Credit Agreement dated as of October 16, 2007 pursuant to
which Rancher Energy borrowed $12,240,000 from GasRock, certain provisions of
the First Amendment to Term Credit Agreement dated October 22, 2008 pursuant to
which Rancher Energy repaid $2,240,000, and certain provisions of the Second
through Seventh Amendments.




The
Eighth Amendment extends the maturity date under the Seventh Amendment from June
3, 2009 to October 15, 2009.  In consideration of the amendments
contemplated by the Eighth Amendment, the Company executed and delivered a Net
Profit Interest Conveyance 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 has
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; 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.  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 (the LIBOR
Margin).  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. The Eighth Amendment also
includes waivers by the Lender of certain events of default including the Loan
to Value Ratio and the Projected Net Revenue 48 month test as set forth in the
Term Credit Agreement, for the period beginning March 31, 2009 and ending on the
maturity date.




On April
3, 2009, ExxonMobil informed the Company, that ExxonMobil was terminating,
effective immediately, the Sale & Purchase Agreement. ExxonMobil’s
purported termination is based on the Company not providing performance
assurances in the form of a letter of credit.  The Company believes
that the Agreement does not obligate the Company to provide any performance
assurances until the start-up of CO 2 delivery, which will not occur in
2009.  Accordingly, the Company disagrees with ExxonMobil’s rationale
for purportedly terminating the Agreement and believes in good faith that
Exxon’s termination of the Agreement has not occurred pursuant to the terms of
the Agreement and is unlawful. The Company has informed ExxonMobil of its
position.   If ExxonMobil does not deliver CO2 in
accordance with the Sale & Purchase Agreement, the Company may not be able
to fully carry out its EOR projects on our three fields.


F-25